ECOLOGICAL AND ECONOMIC ASSESSMENT OF COMPRESSED GAS MARINE TRANSPORTATION UDC 656.6.073.41:661.91 LBC 39.486.4+33.362.087 I‘78

This publication has been prepared by Scientific-Research Institute for Environmental Issues Autonomous Non-profit Organization, jointly with Vernadsky Nongovernmental Ecological Foundation. Ecological and Economic Assessment of Compressed Gas Marine Transportation. - Moscow, 2017. – 240 p., ill. ISBN 978-5-9907508-8-3 The publication presents the results of reviewing of compressed (CNG) marine transportation by ecological and economic criteria and defines the most thrifty as well as environment- and climate-friendly methods of natural gas transportation.

The publication contributes to enhancing of knowledge of specialists and general audience of cost-efficient and ecological aspects of natural gas transportation methods and, consequently, to making competent management decisions as well as popularization of natural gas utilization as an environment-friendly fuel. Coordinator of IBC projects: D. Wessling, Leader of Juniper S.E. Technical Cooperation.

The Project Coordinator: Industry, Innovations and Prospective Development Committee of International Business Congress. Academic supervisors of the research project: A.G. Ishkov, Dr. Chem. Sc., Prof., Deputy Chairman of Ecology and Health Care Committee of International Business Congress; V.A. Grachev, Dr. Tech. Sc., Prof., Associate Member of Russia Academy of Sciences, Deputy Chairman of Industry, Innovations and Prospective Development Committee of International Business Congress. Operating organization: Scientific-Research Institute of Environmental Problems Autonomous Non-profit Organization (NIIPE), Director O.V. Plyamina. Experts: I.V. Stepanov, Cand. Tech. Sc., Assistant Professor; I.Ye. Valiullina, Dr. Econ. Sc., Prof.; A.L. Novoselov, Cand. Econ. Sc.; Ye.V. Varfolomeyev, Cand. Econ. Sc.; O.V. Maryin, Cand. Econ. Sc.; L.V. Sharikhina; Ye.V. Kosolapova Cand. Tech. Sc; V.A. Lobkovsky, Cand. Geol. Sc.

ISBN 978-5-9907508-8-3 © NIIPE, 2017 © the V.I. Vernadsky Nongovernmental Ecological Foundation,, 2017 CONTENT INTRODUCTION...... 6 CHAPTER 1. ANALYTICAL REVIEW OF NATURAL GAS MARINE TRANSPORTATION...... 7 1.1. History of natural gas transportation development...... 7 1.2. Review of routes and means of natural gas transportation by sea...... 12 1.2.1. Today‘s structure of natural gas transportation flows...... 12 1.2.2. The role of natural gas transportation by sea...... 30 1.2.3. Natural gas transportation by marine pipelines...... 38 1.2.4. Marine transportation of ...... 43 1.2.5. Marine transportation of ...... 53 1.2.6. Qualitative comparison of technologies of natural gas marine transportation...... 59 1.3. Realized projects and prospects of natural gas marine transportation...... 60 1.3.1. Transportation of natural gas via marine pipelines...... 61 1.3.2. Marine transportation of liquefied natural gas...... 67 1.3.2.1. Plants for natural gas liquefaction...... 67 1.3.2.2. The world tanker fleet...... 72 1.3.2.3. terminals...... 75 1.3.3. Marine transportation of compressed natural gas...... 79 CHAPTER 2. COMPARATIVE ECONOMIC ANALYSIS OF NATURAL GAS TRANSPORTATION TECHNOLOGIES...... 81 2.1. Methodology for Economic Analysis of Natural Gas Transportation Technologies...... 82 2.2. Algorithm of Economic Efficiency Comparative Analysis for Various Methods of Gas Transportation...... 86 2.3. Design Premise and Assumptions to Simulate the Economic Feasibility of Natural Gas Offshore Transportation Technologies...... 89

3 CONTENT

2.4. Systematization of Options for Multi-Choice Calculations to Analyze Effectiveness of Natural Gas Offshore Transportation Technologies...... 91 2.5. Characteristics of Technical Solutions for Natural Gas Transportation...... 92 2.5.1. Characteristics of an Onshore Gas Pipeline Usage...... 92 2.5.2. Characteristics of an Offshore Gas Pipeline Usage...... 95 2.5.3. Characteristics of Liquefied Gas Offshore Transportation...... 97 2.5.4. Characteristics of Compressed Gas Offshore Transportation...... 101 2.6. Capital Investments into Implementation of Technical Solutions for Natural Gas Transportation...... 108 2.6.1. Capital Investments into the Onshore Pipeline...... 108 2.6.2. Capital Investments into the Offshore Gas Pipeline...... 111 2.6.3. Capital Investments into Offshore Transportation of Liquefied Natural Gas...... 113 2.6.4. Capital Investments into Marine Transportation of Compressed Natural Gas...... 115 2.7. Gas Transportation Tariffs...... 117 2.7.1. Onshore Gas Pipeline Tariffs...... 117 2.7.2. Offshore Gas Pipeline Tariffs...... 118 2.7.3. Characteristics of Marine Transportation of Liquefied Gas...... 119 2.7.4. Compressed Gas Marine Transportation Tariffs...... 120 2.8. Matrix of Effectiveness: Comparison of Technologies by Economic Criteria...... 121 CHAPTER 3. SELECTING AN ALTERNATIVE METHOD FOR TRANSPORTING NATURAL GAS OVERSEAS IN TERMS OF THE POTENTIAL PROJECTS...... 129 3.1. Analytical Review of Freight Traffic Flows in the Black and Baltic Sea Regions...... 129 3.2. Analysis of Alternative Engineering Solutions for Transporting Gas in the Black Sea and the Baltic Sea Regions...... 132

4 CONTENT

3.3. Estimated Natural Gas Offshore Transportation Tariffs for Alternative Projects...... 135 CHAPTER 4. ENVIRONMENTAL IMPACT ASSESMENT IN THE PROCESS OF MARINE TRENSPORTATION OF NATURAL GAS...... 138 4.1. Methodological Aspects of the Carbon Footprint Assessment Technique...... 138 4.2. Environmental Aspects of Natural Gas Offshore Transportation...... 142 4.3. Natural Gas Offshore Transportation Effect on the Atmosphere...... 145 4.4. Environment Analysis of Natural Gas Offshore Transportation Effect on the Atmosphere...... 153 4.5. Calculating a Carbon Footprint of Natural Gas Offshore Transportation...... 159 CONCLUSIONS AND RECOMMENDATIONS...... 170 BIBLIOGRAPHY...... 172 Appendix A INDICATORS OF ECONOMIC EFFICIENCY...... 175 Appendix B INDICATORS OF ECONOMIC EFFICIENCY OF THE GAS SUPPLY THROUGH THE BLACK AND BALTIC SEA...... 218 ABBREVIATIONS...... 238

5 INTRODUCTION

Ensuring of stable supply of natural gas to customers is one of the most topical economic and political issues of today. At the same time, strengthening of security of energy supply and ensuring of continuous gas supplies must not cause deterioration of the environment. Different methods of gas supply (as liquefied natural gas (LNG), by marine and land pipelines) possess various specific effect indicators. In addition to the methods of supply existing at present, new methods of marine transportation of natural gas are being developed now, e.g. in form of compressed natural gas (CNG). In this connection, the International Business Congress (IBC) initiated realization of the Project «Ecologic-Economic Estimation of Compressed Gas Marine Transportation» aiming at determining of the most thrifty and environment- and climate-friendly methods of natural gas transportation. Realization of this project matches the aims of IBC, specifically, assistance in development of international economic cooperation and international assistance to economic development. The published work presents results of the conducted analysis of marine transportation of compressed natural gas (CNG) by ecological and economical criteria and defines the most thrifty and environment- and climate-friendly methods of natural gas transportation. CNG technique is a new breakthrough technology of marine transportation of natural gas in compressed state in cylinders by special vessels, that is, CNG vessels. Complete gas treatment is not required before loading of gas on the CNG vessel, which allows loading thereof on CNG vessels directly from the deposit by using rock pressure of gas («by natural flow»). As a result, a CNG vessel can be used for servicing of hard- accessible non-equipped deposits and destination points. Availability of well-assimilated technologies of great depth subsea tieback is one of prerequisites for realization of projects of compressed natural gas transportation by CNG vessels directly from shelf deposits. Another prerequisite is systemic world-wide application of the technology of non-mooring loading of hydrocarbon raw materials on vessels from offshore terminals. When conducting the analysis, we estimated environment friendliness and economic efficiency of various methods of gas supplies depending on amounts of supplies and length of routes, on real conditions examples: at gas supplies of coastal European countries, Asia-Pacific Region countries, etc. The paper contributes to enhancing of knowledge of specialists and wide audience in scope of cost-efficient and ecological aspects of different methods of natural gas transportation and, consequently, to making competent management decisions as well as popularization of natural gas utilization as an environment-friendly fuel.

6 CHAPTER 1. ANALYTICAL REVIEW OF MARINE TRANSPORTATION OF NATURAL GAS Natural gas is a mixture of gases generated in the depth of the Earth in result of anaerobic decomposition of organic substances. Natural gas is on of the most important combustible minerals. Under reservoir conditions, it is in gaseous state: as separate accumulations (gas reservoirs), as gas cap of oil-gas deposits, or in dissolved state in oil or water. Methane is the basic component of natural gas (70-98%). The composition of natural gas also includes heavier hydrocarbons (for example, , , butane), plus nitrogen, carbon dioxide, hydrogen sulfide, helium, etc. Pure natural gas is a colorless and odorless substance. An odorant is added into the gas to detect gas leakages. The most used odorant for this purpose is ethylmercaptan. The gas is practically twice as light as air, so it goes up in a case of a leakage. Natural gas is flammable and explosive. The gas-air mixture becomes explosion capable if the gas content in the air is 5 – 15%; when the gas content exceeds 15% it burns while air is supplied.

1.1. History of development of natural gas transportation

Fuel gases are known from ancient times. It was Marco Polo who described utilization of natural gas in China where in the year of 200 BC the first bamboo wells for gas were drilled. This gas was used for lighting, heating and salt evaporation. In the 14th century, the gas was used on the Apsheron Peninsula for heating, lighting, cooking and lime kilning. At the end of the 18th century, a method of producing synthetic gas from coal was invented. In 1888, D.I. Mendeleyev was the first in the world who theoretically substanted the possibility of coal underground gasification. An English scientist Murdoch was the first to use the produced gas for lighting his own house and a machine-building plant in Birmingham. At the end of the 19th century discoveries of natural gas deposits were quite casual – they happened in course of drilling water wells and, later on, oil wells. People began to use associated oil gas excavated together with oil. First oil wells were drilled in 1848 near Baku by a mining engineer A.F. Semenov, and later on in 1859 in Pennsylvania by Major Drake. From this moment a new era of oil geology extraction of associated oil gas began. It is the city of Fredonia, the state of New York, which is associated with beginning of industrial producing of natural gas (1825). William Aaron Hart drilled a well 27 feet deep to achieve a gas flow larger than one that was just percolating from under the earth.1 In pre-revolution Russia natural gas was not utilized although its availability was

1 http://www.ems.psu.edu/~pisupati/ACSOutreach/Natural_Gas.html

7 CHAPTER 1 noted. Only after the Revolution of 1917 the Soviet government set a task of potential gas uage excavated together with oil. Up to the end of 1930s, Soviet Russia did not have the gas industry of its own, it was just a complement to the oil industry, and gas deposits were only discovered in process of oil exploration and extraction. Exploration of gas deposits began in 1939 in Saratov Region; the gas was found in 1940 and in 1941 the first working well was drilled. And already in 1941 when industrial extraction of natural gas was started in Saratov and Kuybyshev Regions. The discovery of useful economic deposits of natural gas in three large regions of the world (the USSR, the USA, Canada) initiated switching of the gas supply system all over the world to natural gas. Unlike oil, gas cannot be kept accumulated for a long time, thus development of gas pipeline networks is of high importance. Gas pipelines are first mentioned in the beginning of Christian era. In that time bamboo tubes were used for transporting natural gal (in China). At the end of the 18th century, gas pipes from grey iron began to be utilized in Europe, which were replaced for steel in the 19-20th centuries, as the latter ensured transportation of gas under higher pressures than grey iron pipes could withstand. Along with extraction of natural gas at the end of the 19th century, transportation via pipelines to consumers began in the USA. For instance, in 1859 a gas pipeline of 5 cm in diameter and about 9 km long was built in the state of Pennsylvania which connected the gas deposit and the nearest to it city of Tightesville. The first large pipeline from the field works in the north of Indiana State to the city of Chicago, 195 km long and 200 mm in diameter, was built in 1891. The first pipeline Tennessee for a distant gas supply was erected in the USA in 1944; its was about 600 mm in diameter and about 2000 km long. The peak value of natural gas extraction was reached by the beginning of the 20th century in the USA where the total length of numerous short gas pipelines was 22 thousand km by 1918. In 1928 – 1931 gas pipelines were built in the USA, 800 – 1500 km long and 508 – 660 mm in diameter. Saratov – Moscow gas pipeline became the first trunk gas line in the USSR which was commissioned in 1946 for gas supply from gas deposits in Saratov Region to Moscow, and from Precarpathia deposits to Kiev and other cities of Ukraine. The broad utilization of natural gas in Russia and all over the world began only as late as in 1950s. During this period, a number of trunk gas pipelines of dia. 300 – 1000 mm were built. In the beginning of 1960s, the construction of the entire gas pipeline systems for gas supply started. The Unified System of Gas Supply is the world largest system of gas pipelines. The first attempt of shelf exploitation of hydrocarbons in Russia was made in the in 1897. In 1910, for the first time in the global practice, ground filling of the sea in the area of Baku Bay had started with the aim of assimilating the oil deposit. Further on, in 1934, construction of the world‘s first metallic base of the oil field was performed where the first well was drilled which produced oil. In 1935, the first marine

8 CHAPTER 1 oil pipeline was put into operation. The after-war time became a period when marine extraction of hydrocarbons began to be broadly developed. Beginning from the year of 1950, dozens of oil-gas trunks were constructed each year, first of all, intra-field ones. The first multi-kilometer trunk gas pipeline on the sea bottom from 219x10 pipes, being 18 km long, was constructed in 1964 from the Zhiloy Island oil-field to Shakhovaya Kosa in the Caspian Sea on depths up to 9 – 10 m2. In 1941, in the State of Ohio, the first full-featured LNG plant was built, which became a beginning of development of this segment of energy materials market. Liquefied natural gas, or LNG in the abbreviated form, is a cryogenic liquid, actually it is natural gas purified from admixtures and refrigerated to its transition into the liquid state under the atmospheric pressure. This process results in diminishing of the gas volume by approx. 600 times. The temperature of liquefaction is minus 162°C. Liquefied natural gas is a multi-component mixture of light hydrocarbons with a small amount of heavier hydrocarbons and certain impurities (nitrogen, carbon dioxide, etc.). Methane is the main LNG component, its content is over 85%. Liquefied natural gas does not have color and odor, it is neither combustible nor toxic; moreover, it is not explosive, flammable and corrosive. LNG density is twice as low as that of water, which ensures that in a case of spillage it will occur on the water surface and become converted into gaseous state in a short time. The considerable reducing of LNG volume makes its storage and transportation more convenient. In Russia, LNG began to be used in 1950s. As early as in 1954, a facility was commissioned at the Moscow Plant for natural gas liquefaction which was designed for producing of 25 K tons of LNG per year. However, thereafter the interest to LNG had significantly reduced due to discovery of large natural gas deposits in Western Siberia and construction of trunk pipelines. In 2006, in Prigorodnoye settlement on the Island of Sakhalin, within Sakhalin-2 project, the construction of the first Russian LNG plant started was and the Plant was commissioned in 2009. In 1959, the first tanker suitable for LNG transportation was built in Louisiana. It allowed to deliver liquefied natural gas to consumers outside the US and UK. Later, in 1964, the first commercial deal was entered into – CAMEL project, which contemplated supplies of Algerian liquefied natural gas to the Great Britain and France. Three more trade deals were concluded in 1969, which contemplated additional supplies from Algeria to France, from Libya to Italy and Spain, plus supplies from Cook Bay (Alaska) to . The initial stage of development of LNG trading is related to the Atlantic Ocean basin. In 1979, when LNG import supplies of the initial period reached its peak, the Atlantic Ocean basin contributed to 44% of the LNG global trade, the remaining percentage being after Japan, the only Pacific market. At present, the interest to LNG has shifted

2 Gas Industry: Yesterday, Today & Tomorrow. A.A. Narimanov, A.N. Frolov, Moscow, Nedra Publishers, 1993.

9 CHAPTER 1 from the Atlantic to the Pacific Region. Besides Japan, Korea began to import LNG in 1986 and in 1990. Compressed natural gas, or CNG in the abbreviated form, is high pressure gas capable to be delivered to a customer by special marine vessels. The basic component of CNG is methane (70-98%). The composition of CNG also includes heavier hydrocarbons (for example, ethane, propane, butane), plus nitrogen, carbon dioxide, hydrogen sulfide, helium, etc. CNG is a colorless and odorless substance. It is flammable and explosive. It can be compressed to pressure of 20 – 25 MPa which leads to reducing of its volume by 200 – 250 times. The first CNG tanker was built in the USA and tested in the late 1960s. The tanker had to deliver CNG in vertical pressure vessels. A number of voyages were performed but a high price of the ship combined with very low prices of the gas made then this project unviable. The world‘s first LNG carrier Jayanti Baruna was successfully floated out in Jiangsu province (the east of China) on January 25, 2016. This project was implemented by Enric Shijiazhuang Gas Machinery Co., Ltd. (Enric Shijiazhuang), an affiliate company of CIMC Enric. Natural gas is mostly transported for the peak load power plant of South-Eastern Asia islands; the is able to deliver 700.000 m3 LNG for one voyage.

10 CHAPTER 1 Fig. 1.1. Milestones of development of natural gas transportation natural of development of 1.1. Milestones Fig.

11 CHAPTER 1

1.2. Overview of routes and means of natural gas marine transportation

1.2.1. Today’s structure of natural gas transportation flows3

According to BP‘s data published in the annual Statistical Review 2015, the world proven reserves of natural gas are equal to 186.9 trillion cubic meters. Russia (17.3%), (18.2%) and (13.1%) are among top countries in terms of explored reserves (which grow year after year). As for African countries, one can note Algeria and Nigeria; Norway and the Netherlands among European countries. In Fig. 1.2 countries with the world proven reserves of natural gas of 1 trillion cubic meters and over are shown (BP, year 2015). Natural gas plays an important role in the global energy balance. Iran is the top among the richest in reserves of natural gas: its proven reserves are equal to 34 trillion cubic meters (According to BP Statistical Review of World Energy, June 2016). Russia is the second largest country in terms of gas reserves (32.3 trillion m3), with 11 world largest gas deposits (shown in Table 1.1 below).

Fig. 1.2. The world proven reserves of natural gas, breakdown by countries

3 The following data are presented in this section: 1) BP Statistical Review of World Energy June 2016; 2) IGU 2016 World LNG Report; 3) European Commission Quarterly Report Energy on European Gas Markets DG Energy Volume 9 (issue 1; fourth quarter of 2015 and first quarter of 2016)

12 CHAPTER 1

Table 1.1. The world’s largest gas fields4 No. Deposit Country Year of discovery Reserves, billion m3 1 Northern Qatar 1971 10 640 2 Urengoyskoye Russia 1966 10 200 3 Yamburgskoye Russia 1969 5 242 4 Bovanenkovskoye Russia 1971 4 385 5 Zapolyarnoye Russia 1965 3 532 6 South Pars Iran 1991 2 810 7 Shtokmanovskoye Russia 1988 2 762 8 Arkticheskoye Russia 1968 2 762 9 Astrakhanksoye Russia 1973 2 711 10 Groningen The Netherlands 1959 2 680 11 Hassi R Mel Algeria 1956 2 549 12 Medvezhye Russia 1967 2 270 13 Panhandle-Yugoton USA 1910 2 039 14 Orenburgskoye Россия 1966 1 898 15 Dauletbad-Dolmez 1974 1 602 16 Ghavar Saudi Arabia 1948 1 500 17 Pasanan Iran 1961 1 414 18 Karaganchak 1978 1 345 19 Pars Iran 1965 1 326 20 Troll Norway 1979 1 308 21 Kharasaveyskoye Russia 1974 1 260 22 Yuzhno-Tambeyskoye Russia 1982 1 006 23 Dorra Separated territory 1967 1 000

Shown in Fig. 1.3 are regions of location of the world largest gas deposits. The largest gas-producing countries are the USA, the Russian Federation, Iran, Qatar, Canada, China, Norway, Saudi Arabia, Algeria, Turkmenistan, , Malaysia, Australia and UAE. The world‘s output of gas is growing continuously. According to BP‘s data, the level of the world‘s output of gas grew by 27% for the recent decade and was equal to 3.5 trillion m3 in 2015. Shown in Fig. 1.4 are gas production and consumption per regions.

4 Source: http://www.geofiz.ru/123/page_gaz.php

13 CHAPTER 1

5 1 Fig. 1.3. The world’s major gas exporters and importers and gas exporters major world’s 1.3. The Fig. The diagram is composed on basis of the data from BP Statistical Review of World Energy June 2016 report 2016 June Energy World Statistical Reviewof BP of from data the on basis is composed diagram The 5

14 CHAPTER 1

Fig. 1.4. The world production of natural gas per regions North America is the leader in the world gas extraction (28%), where 78% of the amount of produced gas relate to the USA (it is the world largest producer in terms of gas extraction); then CIS countries follow (21%) with Russia contributing to 76% of the total gas extraction (the world second largest producer in terms of gas extraction), and Middle East (17%) where Iran and Qatar are major producers. Fig. 1.5 presents a diagram with top 10 countries – natural gas producers (according to BP‘s data).

Fig. 1.5. Breakdown of the world production of natural gas by countries

15 CHAPTER 1

Fig. 1.6. The world gas traffic streams per regions

Import-export streams of gas traffic represent approximately 30% of the world gas extraction, out of which about 68% are transported via trunk pipelines, while the remaining gas is transported in liquefied form. Fig. 1.6 shows the world gas traffic streams per region in 2015 (according to BP‘s data). Table 1.2 shows world volumes of gas pipeline transport. Over 60% of gas traffic streams are concentrated in Europe and CIS countries. The major volume of the world gas traffic streams (57%) is directed to Europe. Russia is the main supplier of gas to Europe; other significant suppliers are Norway and the Netherlands. Also, gas is transported to Europe from Algeria and Libya. Fig. 1.7 shows existing and perspective flows of gas supplies to Europe. According to the Eurocommission‘s data, volumes of import supplies of gas to Europe grew by 9% in 2015, as compared to the previous year, mainly due to increasing of supply from Russia and Algeria. This situation is caused by a sharp decrease of amounts of extracted gas (from 53 down to 27 billion m3 per year) on Groningen deposit in Holland which is one of the world‘s largest and used to satisfy over 10% of European needs in gas. The Dutch government was forced to do it because of increasing earthquakes in the homonymous area in the north of the country and plans to continue reducing the output volumes in future. The Eurocommission pays great attention to increasing of security of energy supply lately by diversification of the sources of gas supplies. In particular, necessity in the diversification is substantiated by the fact that a number of Eastern Europe and Baltic Region countries have just a single gas supplier, that is, Russia.

16 5,4 2,1 6,0 7,7 2,7 2,5 4,3 Totalimport 5,8 74,4 19,8 29,9 11,0 23,7 35,9 50,2 124,1 104,0

Rest of APR

Myanmar

Indonesia

Rest of Africa

Libya 6,5

Algeria 6,6

Qatar (BP's data, 2015) data, (BP's 3

Iran

Uzbekistan

Turkmenistan 4,3 4,1 2,7 9,5 1,9 Russia 5,8 10,9 45,2 24,0

Kazakhastan Exporter countries

Azerbaijan 0,6 3,6 4,5 0,9 0,6 Rest of Europe 0,2 7,3 U.K. 4,3 1,7 2,1 Norway 7,0 17,2 34,9 2,9 4,7 Nehterlands 6,0 23,0 0,2 Rest of S.America 2,1

Bolivia 5,4 10,8

Mexico Table 1.2. The world volumes of gas pipeline trasport,pipeline of gas billion volumes m world 1.2. The Table Canada 74,3 74,3

USA 19,8 29,9 49,7 Importer countries Canada Mexico America North USA South of Rest America Argentina Brazil Austria Belgium Czech Rep. Czech Finland France Germany Greece Hungary Italy Ireland

17 7,9 5,1 7,5 Totalimport 2,1 30,2 11,1 12,9 15,2 39,7 29,0 20,4 16,8 16,9 16,2 62,9 27,3 17,7 401,4

Rest of APR

Myanmar

Indonesia

Rest of Africa

Libya 6,5

Algeria 2,0 12,0 20,7

Qatar 2,1 19,8 17,7 (BP's data, 2015) data, (BP's 3 7,8 7,8 0,5 Iran 0,5 5,9 Uzbekistan 2,6 3,3 3,1 0,3 2,8 7,2 Turkmenistan 7,2 8,8 3,7 2,3 9,8 7,0 4,4 Russia 5,0 26,6 16,8 33,2 159,8 0,1 Exporter countries Kazakhastan 10,9 11,0 5,3 2,1 7,4 0,2 0,2 2,3 9,1 1,1 8,1 0,2 4,5 Rest of Europe 9,2 9,2 35,7

U.K. 1,8 13,4 2,1 Norway 1,1 17,9 25,7 109,5 3,1 Nehterlands 0,9 40,6

Rest of S.America

Bolivia

Mexico Table 1.2. The world volumes of gas pipeline trasport,pipeline of gas billion volumes m world 1.2. The Table Canada

USA Importer countries Netherlands Poland Slovakia Spain U.K. Rest of Europe of Rest Europe Belarus Kazakhstan Russia Ukraine CIS of Rest CIS countries Iran UAE Mid East Mid

18 4,0 4,9 8,9 6,4 2,6 Totalimport 9,1 9,4 33,6 61,2 704,1 6,4 1,3 7,7 Rest of APR 7,7 3,9 Myanmar 9,4 13,4 13,4

Indonesia 2,6 7,9 10,5 10,5 4,0 0,6 4,6 Rest of Africa 4,6

Libya 6,5

Algeria 4,3 4,3 25,0

Qatar 19,8 (BP's data, 2015) data, (BP's 3

Iran 8,4 1,5 1,5 Uzbekistan 7,5

Turkmenistan 27,7 27,7 38,1

Russia 193,0 0,4 Kazakhastan 0,4 Exporter countries 11,3

Azerbaijan 7,6

Rest of Europe 45,0

U.K. 13,4

Norway 109,5

Nehterlands 40,6

Rest of S.America 2,3

Bolivia 16,2

Mexico 0,0 Table 1.2. The world volumes of gas pipeline trasport,pipeline of gas billion volumes m world 1.2. The Table Canada 74,3

USA 49,7 Importer countries Rest of Africa of Rest Africa Australia China South AfricaSouth Malaysia Singapore Thailand countries APR Total export Total

19 CHAPTER 1

Fig. 1.7. Main directions of gas supply to Europe

Europe also pays considerable attention to the development of the gas-transportation infrastructure inside the region. A great number of interconnectors between countries are under construction now, with the aim of creating of the unified gas market, which would allow the ability to control gas prices. Realization of the Southern Gas Corridor project is one of the nearest prospects in the framework of diversification of the sources of gas supplies to Europe; it will provide delivery of gas from Azerbaijan (Shah Deniz deposit) to Europe and in future, as the network will be expanding – from Turkmenistan (at present, the mentioned expansion is prevented by the fact that the legal status of the Caspian Sea has not been defined). It is planned that the new gas pipeline be connected to the existing system of the South Caucasian countries. It consists of two parts; the pipeline over the territory of Turkey (TANAP) and the Trans-Adriatic pipeline (TAP).

20 CHAPTER 1

The Trans-Adriatic gas pipeline begins at the boundary between Greece and Turkey and goes via Albania to Italy. Construction of the gas pipeline was started in 2016, and the first supplies are expected in 2018 in the amount of 10 billion m3/year, with possibility of a further increase of supplies up to 20 billion m3/year, according to the official website of TAP AG Company. Egypt, , Iraq and Iran can also be regarded as prospective sources of supply of pipeline gas to Europe. Speaking about perspectives of development of the gas-transportation infrastructure, one should also mention the Nord Stream-2 and Turkish Stream projects. The Nord Stream-2 implies installation of the 3rd and 4th leg of the trunk gas pipeline within one corridor with the line of the Nord Stream project. It is planned that the throughput capacity of this gas pipeline will be also equal to 55 billion m3/year. In October 2016, the Russian and Turkish governments signed a contract for construction of a marine gas pipeline via the Black Sea, with the throughout capacity 31 billion m3/year. The first leg of this pipeline (15.75 billion m3/year) is destined for gas supply to Turkish consumers, while the second leg is designed for gas supply to European countries, provided duly warranties from relevant statutory authorities are presented. One more perspective export project is a land gas pipeline from Russia to China. At present, according to the information from Gazprom PJSC, broad-scale works are conducted aimed at formation of Yakut Gas Extraction Centre (on the basis of Chayadinskoye gas deposit), creation of Sila Sibiri (Siberia‘s Force) gas pipeline and the Amur Gas Processing Plant, realization whereof would allow to perform gas supply to China by means of the world largest project. Apart from pipeline transport, 13% of European needs in gas are accommodated by supplies of liquefied «blue flame gas». Qatar remains the main exporter here contributing to 56% of the European LNG import. Europe is planning a further increase of LNG reception capacities in the framework of diversification of sources of gas supplies for strengthening of the security of energy supply. Middle East and the countries of the Asia-Pacific Region provide about 70% of the volume of LNG import-export traffic flows. According to the data of the International Gas Union, the annual volume of LNG trade in 2015 was equal to 244.9 million metric tons. Table 1.3 shows the world volumes of liquefied gas traffic flows. Fig. 1.8 shows the data on the world capacities of LNG production and reception, with accounting for their utilization rate in 2015 (data from Table 1.4). Tables 1.4 and 1.5 contain information about the existing world capacities of liquefied gas production and reception, with breakdown by countries and with accounting for their utilization rate in 2015.

21 1,6 3,0 2,1 0,6 2,6 0,3 3,0 4,6 0,4 4,2 1,1 Import, total 1,9 32,8 15,2 19,8 14,7 85,6 175,4

Re-export (shipped) 0,0 -0,2 -0,8 -0,3 -0,4 -0,3 -0,8 -0,7 0,1 0,6 0,5 0,6 0,1 0,1 0,4 1,7 0,0 0,1 Re-export (received) 0,5 0,2 0,0 1,3 1,5 0,1 7,0 4,0 0,1 3,7 0,0 2,4 0,1 3,0 Malaysia 0,1 25,0 15,6 0,3 3,9 0,0 2,3 0,1 2,9 0,3 Indonesia 6,0 15,8 0,2 1,3 0,0 0,7 6,5 Brunei 4,3 0,3 0,7 0,1 1,9 0,1 0,3 0,2 5,7 0,8 Australia 0,2 28,8 18,7 0,0 0,5 0,3 0,3 1,4 Yemen 0,2 0,0 0,1 5,5 UAE 5,4 0,1 4,1 0,0 0,1 0,6 7,3 Oman 2,4 0,1 0,5 1,7 0,6 1,7 7,0 2,1 4,9 8,8 0,3 4,1 0,4 Qatar 2,6 12,4 50,8 14,6 Exporter countries 0,2 0,1 1,3 0,1 0,1 0,1 0,4 2,2 9,1 0,8 0,1 Nigeria 0,2 4,6 0,1 0,7 0,1 0,7 0,1 0,1 0,2 0,8 3,2 0,1 Equatorial Guinea 0,2 0,5 0,0 Egypt 0,0 0,0 Angola 0,0 (International Gas Union's data, 2015) data, Gas Union's (International 0,4 0,4 0,4 0,4 0,2 1,9 0,4 3,3 0,3 0,0 Algeria 0,8 0,0 0,3 2,7 0,2 Russia 7,8 10,9 0,1 0,1 0,1 0,1 0,7 0,3 0,3 0,1 0,4 Norway 0,1 0,1 0,1 0,1 0,1 0,5 0,1 0,2 Trinidad and Tobago 0,1 Table 1.3. The world volumes of liquefied tons/year volumes gas flows, traffic world 1.3. The million Table 0,0 0,2 0,1 0,2 Peru 0,2 0,0 0,2 0,3 USA 0,2 Importer countries Singapore Egypt Malausia Africa Korea Taiwan Thailand countries APR Netherlands China Greece Italy Lithuania Pakistan Japan Belgium France

22 0,1 1,2 8,9 5,6 4,2 5,2 3,0 1,0 1,2 0,1 1,8 2,9 2,0 Import, total 6,9 37,5 14,6 0,0 Re-export (shipped) 0,0 -0,2 -1,3 -0,2 -3,6 0,1 0,2 0,5 0,4 0,1 1,0 0,0 0,3 0,4 0,3 Re-export (received) 1,0 0,0 0,0 Papua New Guinea 0,0 0,0 0,0 0,1 Malaysia 0,1 0,0 0,0 0,1 0,1 Indonesia 0,1 0,0 0,0 0,1 Brunei 0,1 0,0 0,0 0,1 0,2 0,2 Australia 0,5 0,0 0,0 Yemen 0,0 0,0 1,3 0,1 UAE 0,0 0,1 0,1 0,0 0,5 Oman 0,5 0,1 0,2 2,3 1,2 9,4 0,3 1,3 1,6 0,6 0,7 1,3 Qatar 2,5 20,7 Exporter countries 0,9 2,9 1,1 5,8 0,8 1,8 0,2 2,8 0,7 0,4 Nigeria 1,1 0,1 0,1 0,2 0,1 0,4 0,1 Equatorial Guinea 0,1 0,0 0,0 Egypt 0,0 0,0 0,0 Angola 0,0 (International Gas Union's data, 2015) data, Gas Union's (International 0,2 2,8 2,9 9,9 0,3 0,0 Algeria 0,0 0,0 0,0 Russia 0,0 0,1 0,5 0,1 2,3 0,1 0,5 0,6 0,1 1,3 Norway 0,0 0,1 0,8 0,1 1,2 0,2 1,9 1,0 2,7 1,0 0,9 7,5 0,1 0,2 0,4 Trinidad and Tobago 0,2 0,9 Table 1.3. The world volumes of liquefied tons/year volumes gas flows, traffic world 1.3. The million Table 0,7 0,9 0,0 Peru 0,0 0,0 0,0 USA 0,0 Importer countries Poland Portugal Spain Turkey Europe UK Argentina Brazil Chile Dominican Dominican Republic Puerto Rico America South Israel Jordan Kuwait UAE EastMiddle

23 0,5 5,2 1,8 Import, total 7,4 244,9

Re-export (shipped) -0,2 -0,2 -4,6 0,1 0,1 0,1 Re-export (received) 4,6 0,0 Papua New Guinea 7,0

Malaysia 0,0 25,0 0,2 Indonesia 0,2 16,1 0,0 Brunei 6,6

Australia 0,0 29,4 0,2 0,2 Yemen 1,5 0,0 UAE 5,6 0,0 Oman 7,8 0,5 Qatar 0,5 77,8 Exporter countries 1,5 Nigeria 1,5 20,4 0,0 Equatorial Guinea 3,9 0,0 Egypt 0,0 0,0 Angola 0,0 (International Gas Union's data, 2015) data, Gas Union's (International

Algeria 0,0 12,2

Russia 0,0 10,9 0,1 0,3 0,3 Norway 4,2 0,4 0,3 1,6 Trinidad and Tobago 2,3 12,5 Table 1.3. The world volumes of liquefied tons/year volumes gas flows, traffic world 1.3. The million Table 2,5 2,5 Peru 3,7 0,0 USA 0,3 Importer countries Canada Mexico USA North America North Total Export Total

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Fig. 1.8 The world capacities of LNG production and reception per regions

Table 1.4. The world capacities of liquefied gas production Existing Export Capacities Country capacities volumes utilization USA 1,5 0,3 22% North America 1,5 0,3 22% Peru 4,5 3,7 83% Trinidad and Tobago 15,3 12,5 82% South America 19,8 16,2 82% Norway 4,2 4,2 100% Europe 4,2 4,2 100% Russia 9,6 10,9 114% CIS countries 9,6 10,9 114% Oman 10,8 7,8 72% Qatar 77,0 77,8 101% UAE 5,8 5,6 97%

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Yemen 7,2 1,5 21% Middle East 100,8 92,7 92% Algeria 25,3 12,2 48% Angola 5,2 0,0 0% Brunei 7,2 6,6 92% Egypt 12,2 0,0 0% Equatorial Guinea 3,7 3,9 104% Libya 3,2 0,0 0% Nigeria 21,9 20,4 93% Africa 78,7 43,0 55% Australia 32,8 29,4 90% Indonesia 26,5 16,1 61% Malaysia 23,9 25,0 105% Papua New Guinea 6,9 7,0 101% APR countries 90,1 77,5 86% TOTAL 304,7 244,9 80%

Table 1.5. The world capacities of liquefied gas reception Existing Export Capacities Country capacities volumes utilization Canada 7,5 0,5 6% USA 128,8 1,8 1% North America 136,3 2,3 2% Argentina 7,6 4,2 55% Brazil 11,7 5,2 45% Chile 4,2 3,0 71% Dominican Republic 1,9 1,0 50% Mexico 16,7 5,2 31% Puerto Rico 1,2 1,2 100% South America 43,3 19,7 46% Belgium 6,6 1,9 29% France 17,3 4,6 26% Greece 3,3 0,4 13% Italy 11,0 4,2 38% Lithuania 3,0 0,3 11%

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Netherlands 8,8 0,6 7% Poland 3,6 0,1 2% Portugal 5,8 1,2 20% Spain 49,3 8,9 18% UK 38,0 9,8 26% Turkey 10,3 5,6 54% Europe 157,0 37,5 24% Israel 3,0 0,1 4% Jordan 3,8 1,8 48% Kuwait 5,8 2,9 50% UAE 3,0 2,0 68% Middle East 15,6 6,9 44% Egypt 9,8 3,0 31% Africa 9,8 3,0 31% China 39,4 19,8 50% India 22,0 14,7 67% Indonesia 8,6 0% Japan 191,2 85,6 45% Korea 98,1 32,8 33% Singapore 6,0 2,1 35% Taiwan 13,0 15,2 117% Thailand 5,0 2,6 52% Malaysia 3,8 1,6 41% 0,0 Pakistan 3,8 1,1 29% APR countries 390,9 175,4 45% TOTAL 752,9 244,9 33%

According to the data from the International Gas Union, the rated world gas liquefaction capacities are equal to 304.7 million tons/year. Middle East (38%) and countries of the Asia-Pacific Region (APR) (34%) possess the largest gas liquefaction capacities and perform 72% of the world LNG export supplies, whereas Qatar provides for 31% (77.8 million tons/year) of the world export. Following after Qatar are Australia (29.4 million tons/year) and Malaysia (25 million tons/year). Among African countries one can single out Nigeria (20.4 million tons/year) and Algeria (12.2 million tons/year), and Trinidad and Tobago in South America (12.5 million tons/ year).

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In general, the utilization rate of the global LNG production capacity is equal to 80%. The largest capacity underutilization is in North America (22%) and in Africa (55%). The low regional capacity utilization in Africa is conditioned, first, by operating failures at the LNG plant in Angola which caused a halt to business, and second, by an interruption of LNG production in Egypt due to fuel deficit. Low capacity utilization is also observed in Yemen (21%) because of the political turmoil in the country. This decline in LNG production has been balanced out by commissioning and high capacity utilization of new projects in Australia and Papua New Guinea. An increase of existing capacities by 141,5 million tons/year is expected by 2019 owing to completion of new LNG plants construction. A large capacity increment is anticipated in North America, specifically, in the USA (62 million tons/year) and in Asia-Pacific Region (APR) countries (61 million tons/year) where liquefaction capacities in Australia are to be increased by 53.8 million tons/year with the total resulting figure 86.6 million tons/year. It is expected that upon completion of construction of six new LNG plants Australia will come out on top in the list of LNG producers leaving Qatar behind. Expansion of liquefaction capacities is planned in Russia (16.5 million tons/year), Malaysia (6.5 million tons/year) and Cameroon (2.1 million tons/year). LNG regasification capacities all over the world are equal to 752.9 million tons/ year and continue to be expanded. New regasification terminals appear both in the territory of existing LNG importing countries and on the emerging markets – in 2015 Egypt, Jordan and Pakistan began to import LNG via gas pressure reduction stations, thus increasing the number of LNG importing countries up to 33. In addition to the three countries mentioned above, first LNG supplies from Qatar were made to Poland (the terminal in Świnoujście). The countries of the Asia-Pacific Region are the world leading region in LNG imports with the amount of liquefied gas supplies being as large as 390.9 million tons/year (72%), with Japan contributing to 35% of the global LNG import (85.6 million tons/year). The second largest LNG importer after Japan is the Republic of Korea with the annual amount of liquefied gas supplies 32.8 million tons/year. In 2015 the growth of LNG supplies to Europe and Middle East was registered, and in the same year of 2015 new LNG importing countries appeared in the both regions. The lowest capacity utilization is observed in North America (2%); it is related to the discovery of large-scale shale gas deposits in the USA which allowed avoiding LNG import. Speaking about the region of South and North Americas, it is also worth noting a considerable decline in LNG consumption by Canada and Mexico, the largest LNG importer in South America, owing to supplies of cheaper pipeline gas from the USA. The Asia-Pacific Region demonstrates the largest decline in LNG demand. It was conditioned, in particular, by re-commissioning, after the two-year downtime, of Sendai

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NPP nuclear units, decline in electric power demand and the growing competition ability of alternative fuels in Japan. The last factor played a critical role in the decline of demand in where coal has been a preferable type of raw stock. Due to these trends, a further decline of demand in the region is anticipated in the nearest future. The utilization rate of European regasification capacities was equal to 24% in average in 2015, with the variation from 7% to 54%, depending on a country. Although Europe possesses 20% of the world‘s regasification capacities, during the recent years LNG encountered hard competition from pipeline gas, coal and renewable power sources. Nevertheless, new markets of liquefied gas import continue to develop, as these countries strive for diversification of gas supply sources. Upon commissioning of two gas pressure reduction stations in Egypt, Africa became an LNG importer for the first time. In the beginning of 2016 the construction of new 15 regasification terminals was announced, eight of them being in China. By 2019 it is anticipated that the increase of the world LNG reception capacities will grow by 71.9 million tons/year (10%), of them capacities of 51.6 million tons/year will appear in APR countries where China will contribute to the increase by 28.9 million tons/year and Japan by 15 million tons/year. Except for North America, the rest regions of the world increased their regasification capacities for the last recent years, especially due to development of gas pressure reduction stations in the Middle East and Latin America. In recent times gas pressure reduction stations are becoming the most acceptable way of entering of new countries into the LNG market. 14 countries of 33 which import liquefied gas possess buoyant capacities for LNG reception. In 2016 a contractor for construction of three new gas pressure reduction stations was announced, the mentioned stations having the total capacity of 12.3 million tons/year which will be located in Columbia, Ghana (new LNG markets) and Puerto Rico. A large number of buoyant terminals are planned to be built by 2017 in countries which will begin import of LNG for the first time – Bangladesh, Benin and Uruguay, should these projects be realized. According to the data for 2015, the total capacity of buoyant terminals in the world (20 gas pressure reduction stations) is equal to 77 million tons/year. Due to many reasons, LNG import is intensely developing all over the world. At APR‘s largest markets, geographical and geological peculiarities of the region make LNG the only accessible way of gas supply. In such countries as South Korea, Japan and Taiwan, which do not possess gas extraction of their own and do not receive pipeline gas supplies, liquefied gas import contributes to covering of their demand for this type of fuel almost by 100%. Liquefied gas is also a means of enhancing the security of energy supply in countries with an instable pipeline supply of gas, specifically Israel and Jordan, which practically have lost their pipeline communication with Egypt. For several latest years, the offer sharply grew on the world LNG production market.

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The aggregate capacity of offered projects is equal to 890 million tons/year, as by the data for January 2016. The location of the predominant amount of these projects is the USA and Canada (75%). Australia, East Africa and Russia also presented a number of new LNG projects. However, only a part of these will be realized, as the LNG market is over- saturated at present and the anticipated growth rate of LNG demand is much lower than the amount of the abovementioned offer. The key developing LNG production markets are the US Mexican Gulf Coast and Canada (where the offer growth is ensured by shale gas extraction), buoyant LNG installations all over the world (advantages to hard-extracted gas and lower specific costs of liquefaction). It is also planned to broaden existing productions in the countries of the Asia-Pacific Region and to realize Arctic shelf projects in Russia and Alaska. The discovery of large-scale gas reserves in the West Africa offshore strip led to a great amount of offered capacities in (44) and Tanzania (20). Among the risks of realization of these projects one can mention the instable internal demand, under-developed infrastructure and uncertain statutory provisions. In the APR, 96 million tons/year of the new offered capacities are offshore ones. Taking into account that these projects are quite expensive, especially in Australia, and minding a large amount of competitive offers all over the world, this projects may be regarded today as but distant prospects. Over 35% of the offered capacities are expansions of existing productions or of those under construction, while about one half of them (44.1%) are buoyant installations. Fig. 1.9 presents major flows of LNG marine transportation traffic.

1.2.2. The role of natural gas transportation by sea

Pipeline transportation remains to be the basic method of transfer of natural gas. However, the remote location of gas extraction regions from regions of selling thereof is becoming more and more serious problem. 60 – 70% of the world gas reserves are lo- cated in the territories of six states, whereas gas deposits in the territories of the Russian Federation and Iran contribute to more than a half of gas volume. On the other hand, the USA and EU countries contribute to almost 50% of consumption amount. Besides, China and countries of the Asia-Pacific Region are dynamically developing as well. Under the conditions of changeability of the world energy production due to extraction at hard-accessible deposits, active trade and industrial interference (sanctions, price dumping) and military-political conflicts, instability of markets of power resources grew up which forced many importers to obligatorily diversify suppliers and delivery channels. Gas supplies by pipes are still predominant in scope of international gas transactions. The major suppliers of pipeline gas are the Russian Federation (24.7%), Norway (15.6%), Canada (10.6%), plus the USA and Holland which supply over 12%.

30 CHAPTER 1 (International Gas Union's data, 2015) data, Gas Union's (International Fig. 1.9. Major traffic flows and amounts (million tons/year) of LNG supplies LNG of tons/year) (million amounts and flows traffic 1.9. Major Fig.

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Upon the background of emerging complications, the amount of the world LNG trade somehow grew up on the energy production market. The leader of liquefied gas world-wide export is Qatar which makes shipments of about 31% of LNG world supplies, possessing 14 terminals and 15% of the world tanker fleet; then follow Malaysia and Australia (the latter continuously increasing its LNG production) – about 10% each, Indonesia, Nigeria, Trinidad & Tobago (5-7% each), Algeria (the oldest player in this sphere) (4.8%) and Russia (4.3%) which resolutely entered this club of LNG exporters. About 75% of all LNG supplies are delivered to APR countries; 16% to Europe, first of all to Spain and the UK. Japan (35.3%) is the largest LNG purchaser; thereafter follow South Korea (13.1%) and China (7.8%). Presented in Table 1.6 and Figs. 1.10 – 1.11 are the data on amounts of export supplies of pipeline and liquefied natural gas for years 2014 and 2015 (according to the data from BP Statistical Review of World Energy June 2016).

Table 1.6. Amount of gas export in 2014-2015, billion m3 Gas pipelines LNG Country 2014 2015 increment, % 2014 2015 increment, % North America 117,05 124,07 6,00 0,46 0,82 77,59 USA 42,41 49,69 17,17 0,46 0,82 77,59 Canada 74,60 74,35 -0,33 - - - Mexico 0,04 0,03 -34,57 - - - Central & South America 18,66 18,49 -0,93 24,21 22,02 -9,06 Trinidad & Tobago - - - 18,41 17,03 -7,47 Other countries 18,66 18,49 -0,93 5,81 4,99 -14,09 Europe 189,97 208,44 9,73 13,51 10,83 -19,79 France 1,88 1,55 -17,62 0,55 0,43 -20,30 Germany 19,96 29,01 45,36 - - - Italy 0,22 0,20 -6,59 - - - Netherlands 46,06 40,58 -11,90 0,56 1,17 108,94 Norway 102,37 109,55 7,01 5,28 5,96 12,95 Spain 0,03 0,48 1279,26 5,05 1,57 -68,95 Turkey 0,58 0,57 -1,37 - - - UK 9,97 13,36 34,02 - - - Others 8,89 13,14 47,77 2,07 1,41 -31,88 CIS 256,68 257,48 0,31 14,34 14,55 1,44 Russia 187,72 192,99 2,81 14,34 14,55 1,44 Ukraine ------

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Others 68,96 64,49 -6,48 - - - Middle East 30,08 28,15 -6,40 129,96 126,16 -2,92 Qatar 20,50 19,79 -3,47 102,85 106,36 3,41 Others 9,58 8,37 -12,68 27,11 19,80 -26,95 Africa 36,23 36,01 -0,63 49,42 48,71 -1,42 Algeria 25,38 24,95 -1,69 17,49 16,19 -7,45 Others 10,85 11,05 1,86 31,93 32,53 1,88 APR 28,42 31,51 10,87 100,37 115,20 14,77 China ------Japan ------Indonesia 9,68 10,47 8,14 21,79 21,88 0,43 South Korea - - - 0,18 0,29 62,07 Others 18,74 21,04 12,28 78,40 93,03 18,65 TOTAL 677,09 704,15 4,00 332,26 338,29 1,81

Shown in Table 1.7 and Figs. 1.12 – 1.13 are data on amounts of imported pipeline and liquefied natural gas for years 2014 and 2015, with the breakdown by countries - gas importers (according to the data from BP Statistical Review of World Energy June 2016).

Fig. 1.10. Share of pipeline gas exports in 2015

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Fig. 1.11. Share of LNG exports in 2015

Table 1.7. Amount of gas import in 2014-2015, billion m3 Gas pipelines LNG Country 2014 2015 increment, % 2014 2015 increment, % North America 117,05 124,07 6,00 11.60 10.31 -11.19 USA 74.64 74.38 -0.35 1.68 2.58 53.51 Canada 21.78 19.84 -8.92 0.53 0.62 16.35 Mexico 20.63 29.85 44.72 9.39 7.11 -24.33 Central & South America 18,66 18,49 -0,93 20.93 20.00 -4.46 Trinidad & Tobago ------Other countries 18,66 18,49 -0,93 20.93 20.00 -4.46 Europe 376.53 401.39 6.60 51.63 55.03 6.58 France 28.56 35.92 25.78 7.20 6.57 -8.73 Germany 88.41 104.04 17.68 - - - Italy 46.58 50.20 7.78 4.55 5.96 30.75 Netherlands 23.19 30.17 30.09 1.08 2.01 86.12 Norway ------Spain 16.99 15.22 -10.39 15.49 13.07 -15.63 Turkey 41.09 39.69 -3.40 7.26 7.49 3.19 UK 29.35 28.97 -1.31 10.66 12.85 20.54 Other countries 102.36 97.17 -5.07 5.39 7.09 31.41 CIS 71.92 62.93 -12.51 - - - Russia 24.17 16.92 -29.98 - - -

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Ukraine 17.49 16.21 -7.30 - - - Other countries 30.26 29.79 -1.56 - - - Middle East 27.36 27.26 -0.38 5.44 10.54 93.75 Qatar ------Other countries 27.36 27.26 -0.38 5.44 10.54 93.75 Africa 8.83 8.87 0.41 0.00 3.82 Algeria ------Other countries 8.83 8.87 0.41 0.00 3.82 APR 56.74 61.16 7.79 242.66 238.60 -1.67 China 31.31 33.57 7.21 26.55 26.20 -1.30 Japan - - - 122.91 118.04 -3.96 Indonesia ------South Korea - - - 48.64 43.69 -10.18 Other countries 25.43 27.59 8.49 44.56 50.66 13.70 TOTAL 677,09 704,15 4,00 332,26 338,29 1,81

Presented in Table 1.8 and Fig. 1.14 are basic indicators of the world's natural gas trade market. According to the data from the International Gas Union, realization of new LNG projects will allow to considerably rise LNG production in future. Australia began reali- zation of seven projects aimed at increasing of LNG supply three-fold (the capacity of new terminals is estimated as 57.6 million tons/year); the USA began realization of four projects, and Russia of three (in Yamal, Sakhalin and Ust-Luga).

Fig. 1.12. Share of pipeline gas imports in 2015

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Fig. 1.13. Share of LNG imports in 2015

Table 1.8. Basic indicators of the world’s natural gas market, billion m3 Years Indicator 2004 2009 2013 2014 2015 Natural gas extraction 2711 2983 3411 3463 3539 International trade 680 817 1034 1009 1042 Share of international trade, % 25,1 29,3 30,3 29,1 29,4 Supplies via pipelines 502 634 708 677 704 Supplies in liquefied form 178 243 326 332 338 Share of LNG in supplies, % 26,2 27,7 31,1 32,9 32,4

According to the International Energy Agency‘s forecast, outstripping growth rate of LNG supplies, as compared to volumes of pipeline transportation, will maintain in the mid-range period (to 2020). The major growth of LNG export is supposed to be due to expansion of capacities of LNG plants in Australia and the USA. However, due to deceleration of economic growth of such LNG importing countries as Japan and South Korea, the market of liquefied gas drops. Moreover, China also reduces the amounts of LNG purchases because of the deceleration of its economic growth rate and shifting to pipeline gas supplies (e.g. within realization of Sila Sibiri project). Against the background of the falling demand for gas on Japan's, South Korea's and China's part, a certain increase of LNG import in India and Pakistan may be anticipated. In perspective, it is expected that amounts of gas consumption in the world would grow. A positive increase of consumption is shown by Africa. In 2015, gas consumption therein reached approximately 130 billion m3/year and it continues to go up by 4.3% annually, whereas the average growth rate in the world is equal to 2.3%. Besides, due to

36 CHAPTER 1

Fig. 1.14. Natural gas supply – Breakdown by years intensive development of electric power generation on the African continent and intense replacement of coal, by 2030 the share of gas in the structure of electric power generation may reach 47%. Large gas deposits are discovered in the eastern part of Africa (Mozambique, Tanzania), which are able to fully satisfy Africa‘s growing demand in natural gas and to ensure for increase of gas export supplies in the liquefied form. In perspective, Iran can become an exporter on the gas market. By estimates of the European Center for Energy and Resource Security, Iran occupies the second place in terms of natural gas reserves and the third in consumption thereof. However, despite large gas reserves, the share of export is but minimum for a while. It is explained by consequences of sanctions (limitation in gas extraction) and the growth of domestic consumption. The government encourages gas consumption in the country, in order to release oil for export. So, in the mid-range period it is not expected that Iran would provide any significant amounts of gas for export purposes. The demand of Europe in imported gas, by estimates of Gazprom Export LLC, will be increased by 149 billion m3 by 2025 and by 195 billion m3 by 2035, as compared to 2014. The new projects are expected to have been realized by that time, such as the «Nord Stream-2» with its throughput capacity of 55 billion m3/year and the «Turkish Stream» with 31.5 billion m3/year. Gas supplying countries from Middle Asia and the Caspian Region are oriented rather to China‘s, India‘s and Pakistan‘s markets. The amount of gas supplies from Turkmenistan to China achieves 65 billion m3. Uzbekistan and Kazakhstan supply 10 billion m3 each to China. Azerbaijan signed contracts for gas supply to India and Pakistan in amount of 28 billion m3 (that is, 14 billion m3 to each country).

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1.2.3. Natural gas transportation by marine pipelines

As was said above, the share of gas delivered by gas pipelines exceeds that of liquefied gas. Realization of projects of gas supply by marine pipelines played a significant role in increasing of the share of pipeline gas transportation. The major gas traffic flows by marine pipelines are directed to European countries, the Russian Federation and Norway being basic suppliers of this type of gas. The following are large-scale projects of marine pipelines from Russia which are realized by now: • The «Blue Stream» constructed in 2002 and designed for gas supply to Turkey via the Black Sea aquatory. Annual throughput capacity of the pipeline: 16 billion m3 (48.2 million m3/day). • The «Nord Stream» constructed in 2011-2012 and connecting Russia‘s Baltic shore (in the area of the city of Vyborg) with Germany‘s Baltic shore (in the area of the city of Greifswald). Annual throughput capacity of the pipeline: 55 billion m3 (167.4 million m3/day). Prepared for realization are the «Turkish Stream» and «Nord Stream-2» projects, which are also oriented to gas delivery to European countries. The following are large-scale projects of marine pipelines from Norway realized by now: • «Langeled» constructed in 2007 and connecting Norwegian gas deposit Ormen Lange with British terminal Easington. The amount of daily gas supply to Great Britain is equal to 72,1 million m3; • «Europipe I» and «Europipe II» supplying gas to Germany in amounts of 45,7 и 71,9 million m3 daily, respectively; • «Zeepipe» supplying gas to Belgium in amounts of 42,2 million m3 • «Franpipe» supplying gas to France in amounts of 54,8 million m3. Gas is supplied to Europe from Africa as well, on the bottom, e.g.: • «TransMed» (Trans-Mediterranean Pipeline): gas is supplied from Algeria via Tunisia to Italy (to the island of Sicily). The throughput capacity of the pipeline is 30 billion m3/year. • «Greenstream» is designed for natural gas transportation from Libya to Italy (to the island of Sicily). The annual amount of gas supply is 8 – 11 billion 3m . Detailed information about the realized and perspective projects of marine pipelines – refer Section 1.3. Apart from natural gas, marine pipelines can transfer two-phase (gas and condensate) and multi-phase (gas, condensate and water) gas flows. Gas is fed into a marine pipeline from a trunk land gas pipeline in the coastline area or directly from an offshore or onshore deposit. Let us consider the first variant of a marine gas pipeline as an example (see Fig. 1.15).

38 CHAPTER 1

Fig. 1.15. Diagram of marine gas pipeline

Gas is fed from the trunk gas pipeline to the PGTU unit designed for removing of heavy hydrocarbons and water from natural gas by adsorption and for preventing formation of condensate and gas hydrates in the marine pipeline. After that, gas is fed to the MCS shop which has to provide gas feeding into the marine section of the gas pipeline with high initial pressure (25 MPa and over), without use of intermediary compressor stations. In case of large-scale projects, main compressor stations are most frequently unique, having no world analogues. For instance, Portovaya compressor station for the «Nord Stream» marine gas pipeline, which connects Russia and Germany on the Baltic Sea bottom. The unique character of this compressor station consists of its ability (which is actualized, in fact) to provide transferring of gas to the distance slightly over 1220 km via the «Nord Stream» gas pipeline with further gas feeding into land gas pipelines in the territory of Germany without erection of an additional compressor station in the point of the shore crossing. After the compressor station (CS), gas is fed to the gas metering station (GMS) for monitoring of its properties and commercial registration, and into the gas pipeline which runs on the sea bottom. Here the pipe repeats the sea bottom profile and bends under its own weight. Existing marine gas pipelines are running on various depths. For instance, «Blue Stream» pipeline which connects Russian and Turkey on the Black Sea bottom goes as deep as 2150 m in separate sections thereof. The features of submerged gas pipelines include: smoothing inner coating, corrosion- proof ballast concrete coating serving to protect the pipeline and stabilize it on the bottom. The submerged part of the pipeline is protected against corrosion for its entire life cycle by cathode protection. When designing a marine gas pipeline, many factors have to be considered, for example, it is necessary to optimize the pipeline location in order to minimize its

39 CHAPTER 1 crossing with other pipelines and cables, areas of navigation, obstacles occurring on the sea bottom (mountain ridges, reefs, carcasses of destroyed ships, etc.). A pipeline installation on the sea bottom to be performed ensuring its design position during the entire period of its operation. When necessary, the aquatory bottom is to be pre-treated. On the landfall wet sections the gas pipeline is laid in a trench and deepened beneath the predicted wash-out depth of the aquatory bottom or of the onshore section of the pipe preparation. Upon passing the pipeline marine section, gas is fed to a receiving terminal, from whichit is delivered into a network of trunk gas pipelines, and finally to the consumers. The receiving terminal includes at least the following equipment: • chamber for starting gas-cleaning units; • gas pretreatment equipment; • equipment for gas quality analysis; • gas heaters; • custody metering skid; • valves (for emergency shut-down / pressure regulation); • pressure protection equipment; • the structure ventilation system. Pipes are laid on the sea bottom from specialized pipe-lay ships. Other ships are also engaged in the process: those monitoring the sea bottom and barges, which provide for continuous delivery of pipes onto the pipe-lay ship. There are storage sites on the deck of the pipe-lay ship whereon delivered pipes are unloaded. Pipes are welded into an uninterrupted train directly on the pipe-lay ship.

Fig. 1.16. Gas pipeline installation on a sea bottom6

6 From materials of Nord Stream Company

40 CHAPTER 1

Upon welding, each welded seam is controlled for defects by ultrasound; thereafter anti- corrosion coating is applied on the seams. At present there are three basic methods of installation of marine trunk gas pipelines: stinger (S method), J method and Reel-lay. The first one allows conducting mounting, welding, diagnostic and insulation works on a working site which has horizontal location. A pipe is lowered onto the sea bottom over a special stinger boom which serves for supporting and formation of the curvature radius of the installed pipeline upper part. Inclination of the stinger can be changed, in dependence on the depth under water and on the place of pipeline installation. The pipe has got S-bend while being lowered. The rate of installing pipelines by the S method is relatively high (6 – 9 km a day). However, in process of lowering the pipeline is subjected to additional contact and bending loads on the stinger which may cause plastic strains in the pipe. It restricts the maximum depth of pipe laying to 2000 m. Shown in Fig. 1.17 is «Solitaire» world class pipe-lay ship owned by Swiss company «Allseas». The ship performs installation of a trunk gas pipeline by the S method. A number of problems encountered by pipe-lay ships in course of exploiting the S method can be solved by use of the J method of pipe-laying. This type of pipe- laying subjects the pipeline to a lesser load, as the line remains in vertical position during practically the whole process of installation. However, this method has its own technological complications: in particular, all works with the pipeline are performed on a mounting stinger which is in a nearly vertical position. When using the J method, the pipe is bent only once, forming a J-shaped bend under water, not a twin bend like in the

Fig. 1.17. “Solitaire” pipe-lay ship7

7 https://www.glassdoor.com.au

41 CHAPTER 1

S method. A lower load on the pipe allows using this method for installation of pipelines on deeper sections of the sea bottom, yet the rate of works are much lower for this type of pipe-laying. Fig. 1.18 shows « 7000», a floating load-hoisting crane owned by Saipem S.p.A. company. The vessel performs the deep-water J-shaped pipe-laying.

Fig. 1.18. «Saipem» pipe-lay ship8

Fig. 1.19. «Pieter Schelte» ship 9

8 http://www.gazprom.ru 9 https://yandex.ru/images

42 CHAPTER 1

The Reel-lay method implies that a pipe-lay ship is equipped with a removable drum whereon the pipe is reeled onshore. Such vessels are able to install pipes of lesser diameters and flexible pipes. Welding works in such a case are performed onshore where they are much cheaper. On the ship board, the pipeline is reeled off the drum, passed through a stretcher and laid on the sea bottom. When the entire pipe has been reeled off from the drum, the ship will go back for a new drum, or if appropriate cranes are available, will take new drums from supply barges and return empty ones. In 2014, the «Pieter Schelte» (see Fig. 1.19) was built on the wharf of Daewoo Shipbuilding & Marine Engineering, South Korea, by an order from Allseas Company (Switzerland). The ship is equipped with hi-tech tools for pipe-laying on a sea bottom to 3500 meters deep. As a rule, a marine gas pipeline is begun to be installed offshore. The gas pipeline can consist of multiple sections, which are to be connected with each other later on. For long offshore sections, pipes with various wall thicknesses are used, as the pipeline is able to withstand different pressures on different sections thereof. Upon construction of the offshore portion, pipes are drawn out onshore where they are connected to the land section of the pipeline. Initial commissioning test of the pipeline is a final stage. Scrutinized pipeline condition monitoring is continued to be conducted upon its commissioning as well, applying specialized electronic in-line inspection (ILI) tools for this purpose.

1.2.4. Marine transportation of liquefied natural gas

Asian countries (Japan, South Korea, China) are major LNG consumers. However, recently LNG has been becoming more and more popular in Europe, too. The world‘s main LNG supplier is Qatar. Enterprises of QatarGas and RasGas deliver LNG in every part of the Earth: Asia, Europe, North and South Americas, in amounts of 42 and 37 million tons per year, respectively. However, currently Qatar‘s influence in Asia is becoming to be inevitably reduced by introduction of Australian LNG. For instance, in March 2016 Chevron Company (USA) began to produce LNG at Gorgon deposit (the Island of Barrow) by the north-western shore of West Australia. The Gorgon project includes a LNG plant with capacity of 15.6 million tons/year. During next several years, Australia intends to outrun Qatar in terms of LNG export volume and become the world leader. Cheniere Energy, Inc. is the largest producer of liquefied gas in the USA. It owns Sabine Pass terminal (the Mexican Gulf), wherefrom since January 2016 shipment and delivery of LNG has been dispatched to such countries as Brazil, India and China. In 2019, the amount of LNG supply from this terminal has to reach 27 Mio tons/year. LNG supplies from the USA to Asian markets became cheaperfter broadening of the Panama Canal. It is expected that by 2020 the USA will grow to be the world‘s third country in

43 CHAPTER 1

Fig. 1.20. Organization pattern for LNG transportation terms of amounts of LNG exports, following Qatar and Australia. As a raw-material base for delivery of gas to an LNG-producing plant, various gas deposits (both on- and offshore), the gas transportation system and facilities thereon (compressor stations, underground gas storage facilities, etc.) can be used. Fig. 1.20 provides an organization pattern for the LBG transportation via a marine terminal for the option of gas delivery to a plant via a land trunk gas pipeline. Reprocessing of natural gas into LNG (regasification) can be performed on land or buoyant LNG plants or on gravity base structure plants. Fig. 1.21 illustrates Prigorodnoye land industrial complex of the Sakhalin-2 project. A liquefied natural gas plant consists of the following basic process units (in Fig. 1.22, a structural diagram of the LNG plant is presented): • gas reception and measuring unit, the basic function whereof is gas pre-cleaning from dripping liquid and solid impurities, and also measuring of gas;

Fig. 1.21. Prigorodnoye land industrial complex of Sakhalin-2 project10

10 http://www.sakhalinenergy.ru

44 CHAPTER 1

• unit for removal of acid gases which is designed for withdrawal of carbon dioxide and hydrogen sulfide from the feed gas. It is going to prevent freezing and clogging in the downstream equipment; • feed gas dehydration unit is designed for gas dehydration and decrease of water content, in order to prevent water freezing in further processes; • mercury removal unit should ensure decrease of the mercury content in the feed gas to a minimum level. It will allow to avoid a potential damage of the gas liquefaction unit equipment; • gas liquefaction unit is designed for gas liquefaction, so that it could be stored under pressure near to atmospheric; • fractionation unit the function whereof is extraction of propane, butane and condensate; • condensate stabilization unit the purpose whereof is removing of lighter components from the hydrocarbon condensate and feeding of the latter to a reservoir; • nitrogen removal unit is necessary if a large percentage of nitrogen is present in the feed gas; • storage reservoirs and LNG loading berth are designed for storage of produced LNG and loading thereof into gas-carrier vessels for transportation. LNG is loaded via standpipes. During storage and loading of LNG into gas-carrier vessels evaporation of methane vapors can be observed (tank return gas – TRG), which is caused by the effect of the ambient temperature and changes of atmospheric pressure. Tank return gas is fed to the compressor station and thereafter delivered for re-liquefaction or is used as fuel. There are various technologies of natural gas liquefaction: • Single Mixed Refrigerant (SMR) – for low capacity plants (to 1,0 million tons of LNG per year); • Single Mixed Refrigerant with pre-cooling by propane (C3MR) – most LNG producing plants engage this technological process of natural gas liquefaction which has been designed by APCI company. All components of the process were pilot-tested on process lines with capacities to 5.0 Mio tons of LNG per year; • Double Mixed Refrigerant (DMR) – at present there is a single LNG plant utilizing this process (the Sakhalin-2 project in the Island of Sakhalin, capacity 2*4.8 million tons per year); • Optimized Classic Cascade process (OC) – utilized at Sonatrach LNG plant in Algeria and at Kenai LNG plant of «Marathon» and «ConocoPhillips» companies in Alaska, etc. The cascade process is pilot-tested on LNG process lines with capacities to 4.8 Mio tons per year; • Mixed Fluid Cascade process (MFC) – at present only one project has been realized, specificallyHammerfest LNG plant in Norway, with capacity of

45 CHAPTER 1 Fig. 1.22. Structural diagram of an LNG plant (a single process line) process (a single plant LNG an of diagram 1.22. Structural Fig.

46 CHAPTER 1

4.3 million tons per year. LNG is transported in methane tankers, in special thermo-insulated reservoirs (tanks) under atmospheric pressure and temperature minus 162°C. Apart from gas reservoirs, such vessels can be equipped with refrigeration units for re-liquefaction of LNG which got evaporated in process of transportation thereof. All LNG contacting surfaces are made of materials enduring effects of extremely low temperatures. These materials usually are stainless steel, aluminum or invar (ferrous alloy with 36% Ni). For emergency cases, methane tankers possess two-body structure specially designed for prevention of leakages and tears. Today‘s methane tankers can carry 145-155 thou. m3 of liquefied gas, wherefrom about 89-95 Mio m3 of natural gas can be produced after regasification. Methane tankers are very capital intensive, so their down time is unacceptable. They are fast-running: the speed of a sea ship carrying liquefied natural gas can reach 18-20 knots. Besides, operations of LNG loading and unloading do not take much time (12-18 hours in average). Japanese and Korean wharfs are traditionally the largest builders of LNG carriers: Mitsui, Daewoo, Hyundai, Mitsubishi, Samsung, Kawasaki. More than two thirds of all gas carrying ships in the world were built on Korean wharfs. At present gas carrying ships are built in PRC as well. Modern tankers of Q-Flex and Q-Max series can carry up to 210-216 thou. m3 of liquefied gas. LNG can be transported for any distances. For example, the distance from the main LNG producers (Trinidad and Tobago, Algeria, Qatar) to the US market is from 3700 to 14800 km. At present, there are three basic types of cargo system in the scope of LNG transportation by gas carrying ships: • MOSS system (self-supporting inserted spherical tank); • SPB system (self-supporting inserted prismatic tank); • Membrane system. Due to a number of reasons, only two of the above methods became widely used in the world practice: MOSS system and membrane system (Fig. 1.23). Production of ships with SPB cargo system has not been arranged yet. At present LNG tankers of MOSS type occupy about 40% of the world fleet of methane tankers. Their distinctive feature is reservoirs of spherical form (Fig. 1.24). MOSS tankers were designed by Moss Maritime company (Norway). Reservoirs of such type were borrowed from ships carrying oil gases, and became popular for a short time. Spherical cargo tanks are usually made of aluminum and are self-supporting. These tanks are supported with annular metal cuffs over the equator line of the tank and allow free expansion and contraction of the sphere. Tanks are independent on the marine hull design, so they are built separately from the ship. A need to cool down the large mass of aluminum is a disadvantage of a spherical

47 CHAPTER 1

Fig. 1.23. Types of cargo system of gas carrying ships11

Fig. 1.24. Gas carrying tanker of MOSS type (spherical reservoirs)12 tank. The designer of these tanks suggested that insulation of the cryogenic reservoir could be replaced by polyurethane foam but it has not been realized by now. Shown in Fig. 1.25 is «Grand Aniva» gas carrying tanker of the spherical type. This ship was built in 2008 on Mitsubishi Heavy Industries, Ltd. wharfs in Nagasaki. «Grand Aniva» tanker is designed for operation under low temperatures with the purpose of the year-round navigation from the island of Sakhalin. It is used for LNG transportation to consumers in Asia-Pacific Region. This ice class tanker has the cargo capacity of appr. 145 thou. m3 of LNG. MOSS design was dominating in building of cargo tanks up to the end of 1990s. However, in recent years due to price changes, almost two thirds of the ordered gas carrying ships have membrane tanks (Fig. 1.26). Over 55% of gas carrying tankers have membrane reservoir systems supported by the marine hull. The design of tanks include flexible membranes possessing the primary and secondary layers. There are two insulation layers between membrane layers and the inner marine hull; these insulation layers are subjected to continuous blowing with

11 http://www.studfiles.ru 12 http://lngas.ru

48 CHAPTER 1

Fig. 1.25. «Grand Aniva» gas carrying tanker13

Fig. 1.26. Gas carrying tanker with membrane structures14 gaseous nitrogen and continuous monitoring of presence of gas or temperature changes. Membranes are divided into two types: planar and corrugated. GasTransport system includes the primary and secondary membranes in form of flat panels made of invar. The primary membrane in Technigaz system is made of corrugated stainless steel, while the secondary membrane is three-layer (a thin aluminum sheet between two layers of fiber- reinforced plastic). In SC1 system flat invar panels serve as the primary membrane, and Technigaz three-layer membrane is used as secondary. An advantage of gas carrying ships equipped with membrane tanks is their minimum weight characteristics in relation to cargo carrying capacity of the ship. Large-capacity gas carriers with membrane tanks possess preferable technical-economic indicators as compared to ships equipped with spherical cargo tanks. Membrane tanks are built only after the ship has been heaved off. It is quite an expensive and time-consuming (1.5 year) technology.

13 http://www.proinvel.ru 14 http://lngas.ru/transportation-lng/spg-tankery.html

49 CHAPTER 1

In Fig. 1.27 you can see «Mozah» gas carrying tanker of membrane type. This methane carrier was built on Samsung Heavy Industries wharfs for Qatar Gas Transport Company and heaved off in December 2008. It is the largest tanker of Q-Max series with the cargo capacity of 266 thou. m3 of LNG. At present there is possibility to build specialized LNG regasification ships which are known as LNGRV (Liquefied Natural Gas Regasification Vessel) according to customized designs. Such vessels, in addition to systems of LNG reception from LNG carrying ships, LNG regasification and re-gasified LNG (R-LNG) feeding onshore, can be also equipped with the system for reception of a reloading buoy of STL (Submerged Turret Loading) type via which high pressure R-LNG can be fed into a submerged pipeline. Regasification ships of LNGRV type are series built in Republic of Korea on DSME (Daewoo Shipbuilding & Marine Engineering Co., Ltd) wharf by the design of Exmar Marine, Belgium (see Fig. 1.28). Until recently, gas carrier tankers were powered exclusively with steam turbine plants able to utilize natural gas evaporating from reservoirs. New ships make it possible to use diesel and diesel-electric plants as main engines which are more compact and fuel- thrifty than steam turbines.

Fig. 1.27. «Mozah» gas carrying tanker15

15 http://top10i.ru

50 CHAPTER 1

The issue of LNG evaporation was solved on ships of certain types due to on-board location of an on-site cryogenic facility for gas liquefaction. The evaporated gas is liquefied again and returned into the reservoirs. However, such a facility for re-liquefaction of gas makes the price of the tanker significantly higher. A gas carrying tanker delivers the cargo to a reception terminal designed for reception of liquefied natural gas from gas carrying vessels and for LNG storage. After that LNG is fed to a regasification facility for its conversion from liquid state into gaseous, and then the gas is fed into a gas pipeline network. The world practice of failure-free operation of similar facilities shows that basic engineering solutions on terminals are properly elaborated and possess ready-to-apply technical solutions. At present there are several dozens of terminals for LNG reception, storage and regasification which are operated all over the world, and the trend towards growth of their number is observed. A «classic» example of an LNG onshore terminal is RABASKA LNG Terminal in Canada (see Fig. 1.29). A structural diagram of an onshore terminal for LNG reception, storage and regasification is presented in Fig. 1.30. The basic technological facilities of the terminal are: • LNG unloading system. To unload LNG, standpipes are installed on the offshore mooring which have to provide for LNG unloading, recycling of tank return gas into the ship reservoirs from the TRG treatment system and into the reserve reservoir; • LNG storage bank consists of reservoirs for LNG short-time storage. Each reservoir is equipped with pumps;

Fig. 1.28. “Excelsior” LNG regas ship16

16 http://excelerateenergy.com

51 CHAPTER 1

Fig. 1.29. LNG onshore terminal17

• Tank return gas (TRG) removal system. TRG is used after compressing for the terminal needs as fuel gas or for re-liquefaction; • High pressure LNG pump house is designed for increase of pressure of liquefied natural gas before the regasification system; • LNG regasification system where LNG evaporation takes place at the ambient temperature (water or air serve as a heat carrier) or at the temperature above ambient temperature (fume gas, water or propane-butane-freon mixture serve as a heat carrier); • Heat carrier heating system is designed for heating of water; • Gas measuring station (GMS) ensures registration of flow rate of the transported gas from the regasification unit to the system of trunk gas pipelines; • Torch system whose purpose is incineration of flammable gases and liquids and discharge of products of their burning into the atmosphere in a safe place in emergency situations (mostly in case of overpressure in reservoirs of LNG storage).

17 http://www.newsru.com

52 CHAPTER 1

Fig. 1.30. Structural diagram of an onshore terminal for LNG reception, storage and regasification

1.2.5. Marine transportation of compressed natural gas

The technology of LNG transportation is regarded as the method of natural gas transportation to domestic and foreign markets in large capacity high-pressure reservoirs on specially equipped ships. Gas loading and unloading can be performed onshore and offshore. Both the transported gas and heavy fuel can be used as fuel for the propulsion system. The structural diagram of the complex of support facilities for marine transportation of compressed natural gas is presented in Fig. 1.31. Natural gas is compressed at BCS (boosting compressor station) to pressure of 12.5 – 27.5 MPa and refrigerated. Then it is delivered to GMS for monitoring of its properties and commercial registration. On a loading terminal CNG is loaded to the ship under pressure of 12.5 – 27.5 MPa by means of a buoy loading facility. Upon connecting of the ship to the LNG unloading system, gas is fed on land where it passes through a pressure reduction unit. If the gas pressure is larger than the working pressure in the gas transportation system (GTS), gas is reduced in the gas pressure reduction unit (GRU) and then is fed into the land pipeline. If the gas pressure is lesser

53 CHAPTER 1

Fig. 1.31. Structural diagram of marine transportation of compressed natural gas than the working pressure in GTS, gas is fed first to the CS site for compressing to the working pressure and after that into the land pipeline. At present there are multiple concepts of CNG technology realization on gas carrier ships: • Installing coils of small diameter pipes on the ship (Coselle technology); • Vertical installing of packages of high pressure reservoirs on the ship (Knutsen technology); • Vertical installing of large diameter pipes into blocks on the ship (EnerSea Transport VOTRANS technology); • Horizontal installation of large diameter pipes (reinforced with composite materials) on the ship (Piton technology). Cargo systems for compressed gas transportation can be subdivide into metallic, non-metallic and combined (the latter integrating materials of the first two systems). Among metallic systems are cargo systems of companies Sea NG, Knutsen Shipping AS, EnerSea (VOTRANS), Compressed Energy Technology AS (CE TECH). To non-metallic belongs the cargo system of TransOcean company which, within its concept of transportation, proposed to produce cylinders from plastic materials with reinforcement by fiber plastic. To combined systems (metal + fiber plastic) belongs the cargo system of TransCanada company. Cran & Stenning Technology and Sea NG, Canada are designers of Coselle system. Compressed gas in pumped into a steel coil tube with diameter of 15.2 cm (6 inches) and 16 km long which is coiled onto a stackable revolving shelf. It is possible to install several such shelves on a CNG carrier ship (see Fig. 1.32). Gas can be transported at the ambient temperature, while compressed gas pressure can be as high as 27.5 MPa. Cargo capacities of such vessels vary from 1.8 to 15 million m3. Coselle system is the most cost-effective decision for transportation of small amounts

54 CHAPTER 1

Fig. 1.32. Design of the ship by Sea NG Corporation with Coselle system18

Fig. 1.33. Design of PNG tanker by Knutsen company19 of gas for relatively short distances. These ships can operate shuttle-wise in order to provide for continuous gas supply. The developed design of the ship obtained complete permission for construction from American Bureau of Shipping (ABS). Knutsen OAS Shipping (Norway), jointly with EUROPIPE GmbH and Det Norske Veritas, developed a new solution for transportation of compressed natural gas under the trade name of PNG. Knutsen proposes designs of compressed gas tankers wherein vertically positioned cylinders are offered as cargo reservoirs (see Fig. 1.33).

18 http://www.coselle.com 19 http://knutsenoas.com

55 CHAPTER 1

Cargo capacities of these vessels vary from 19.4 to 27.4 million m3. The cargo system design is such that all cylinders are connected to each other and can be regarded as one common reservoir; thus, all cylinders are loaded (unloaded) simultaneously. The cylinder offered by Knutsen is welded from two 42” pipes and two caps (plugs) in accordance with requirements of the standard for construction of marine pipelines OS-F101. The cylinders are installed into cassettes (8 pcs. in each). The end (bottom) plate of the cassette is its basic load-bearing element. A spot in the center of the cassette is used for surveying the state of cylinders. Cylinders are designed for 30.000 loading- unloading cycles which corresponds to the service life over 40 years. A block of cylinders is installed into a protective casing designed by FiReCo AS company. The protective casing is made of light fire-proof vibration impact-proof composite materials. The cargo system design shall envisage collection of condensate, precipitated in process of transportation, into separate tanks and shipping thereof to consumers as an individual product. Special measures for removal of free hydrogen (which is emitted from the transported gas) from the cylinders should be foreseen. In the cargo system surface piping valves (taps) for shutting-off of cylinder sections are foreseen. Gas is transported at the ambient temperature; pressure of the compressed gas can be as high as 25 MPa. PNG project is in the active development phase now, both in engineering and commercial terms. The concept project by EnerSea company (USA) contemplates optimization of the total structure of the system for gas transportation within the multiple-dimension project space: properties of gas, those of steel, gas technologies, normative and legal restrictions. The cargo system of the ship consists of blocks with upright standing cylinders made of pipes of diameters 42-48” which are at the same time elements of the marine hull (see Fig. 1.34). This technology is referred to by its authors as VOTRANS (Volume Optimized Transport Storage). Compressed gas pressure: 12.5 MPa; temperature: minus 30°C. The volume of gas transported by these ships can vary from 2 to 30 million m3. The systems developed by EnerSea are approved by ABS and are ready to be switched into construction stage. In May 2105, the state power generating company of Indonesia made an order to Enric Shijiazhuang (affiliate of CIMC Enric – China) – construction of the first CNG tanker in the world. In January 2015, the company began to build the tanker on record. Enric Shijiazhuang, in coordination with partners, owners of enterprises, wharfs, and classification society, provided construction, mounting and adjustment of a natural gas

56 CHAPTER 1

Fig. 1.34. Design of a ship with vertically positioned tanks20

Fig. 1.35. “Jayanti Baruna” CNG tanker21 terminal and successfully completed commissioning of the tanker. On January 25, 2016 «Jayanti Baruna», the world‘s first CNG tanker (see the figure above), was successfully heaved off in Jiangsu province. The tanker is designed for transportation of compressed gas from the plant at the deposit to an Indonesian island where the gas will be used as fuel for the electric power plant. The cargo capacity of the ship is equal to 0.7 million 3m of CNG. Vertical cylinders in amount of 832 units are used for CNG transportation on the tanker. The gas tanker engine is driven by two types of fuel; the ship speed is 13.9 knots.

20 http://enersea.com 21 http://www.cimc.com

57 CHAPTER 1

Fig. 1.36. Buoy-based loading of a tanker from a gas deposit22

A mooring terminal is a classic solution for organization of loading/unloading of gas on/off CNG tanker board. Loading/unloading can be performed through an overpass pipeline which is connected directly to one or multiple joint units on the tanker deck. All operations of jointing, loading, unloading and disjointing are made under the personnel‘s direct control. Loading of warm gas from the outlet of a compressor station located near the mooring can reduce requirements or exclude additional heating of gas. A drawback of this solution is complexity of choice of a place for construction of the mooring which would fit on a number of basic requirements: depth and proximity of the water-way, possibility of installing of a connecting pipeline to the trunk system or to onshore gas deposits, high expenses for construction of stationary berthing structures for ships with sizes and water draft peculiar for a CNG tanker. Offshore mooring terminals and sea-going buoy terminals can be used for gas loading and unloading. Offshore berths are located at a distance from one to several kilometers from the shore in the point which is most convenient for approaching and departure of ships. Such terminals can be stationary hydraulic structures or buoyant structures held by anchors. Offshore berths are non-serviceable structures, al all operations on jointing- disjointing with loading/unloading modules are performed by the crew of a CNG carrier ship. An offshore mooring terminal is a structure consisting of a submerged pipeline which is ended with a buoy whereon a jointing module is located. Such a buoy can be on the water surface (so-called BTL buoy), or in a semi-submerged state (STL and SAL buoys).

22 http://enersea.com

58 CHAPTER 1

To perform loading or unloading operations, a CNG carrier ship should reach the point of the buoy location, find it and perform jointing with it by means of special techniques. In process of loading/unloading, the tanker is held in this point by means of the dynamic positioning system. Upon completion of loading/unloading, the operation of disjointing is performed and the buoy returns into its initial position.

1.2.6. Qualitative comparison of technologies of natural gas marine transportation The basic comparative features of technologies of natural gas marine transportation are given in Table 1.9.

Table 1.9. Technologies of marine transportation Parameter Natural gas LNG CNG Method of LNG tanker Volume CNG tanker Volume Marine gal pipeline transportation up to 266 thou. m3 up to 30 mio. m3 Odourless and colour- Odorless and colorless Odorless and colorless less liquid. Non-flam- gaseous substance. Flam- gaseous substance. mable, non-toxic, non- mable, toxic, explosion- Physical properties Flammable, explosion- explosive. The volume is hazardous. The volume is hazardous 600-fold lesser that that 200-250-fold lesser that of natural gas that of natural gas

Chemical Basic component: methane CH4, other hydrocarbons (ethane C2H6, propane C3H8,

properties butane C4H10, and others), nitrogen N2, hydrogen sulfide 2H S, etc. Temperature and pressure - 30 or ambient Temperature, °C -162 at the beginning of the temperature gas pipeline shall ensure Pressure, MPa compressor-free gas feed- atmospheric from 12.5 to 27.5 ing in the sea • removal of heavy • removal of water, solid • compressing; hydrocarbons and water impurities, acid gases, • loading into tankers Preparation of gas • compressing mercury, nitrogen; for marine • liquefaction; transportation • extraction of propane, butane, condensate; • loading into tankers • pressure regulation • LNG unloading; • CNG unloading; Reception of gas • Regasification • Reducing/ compressing Gas losses in Fuel gas to compressor At evaporation, unless Fuel gas to compressor course of transpor- station repeatedly liquefied station tation

59 CHAPTER 1

As we can see from the table, the simplest method of feeding gas (in terms of technology) is a marine gas pipeline, as it does not require more intensive preparation of gas for transportation and delivery to consumers. However, when a pipeline is quite long (over 1500 km) availability of intermediary compressor stations will be essential which leads to significant investments and increase of fuel gas consumption. In recent years, gas extraction has been gradually decreasing at many existing deposits. Deficit volumes of gas extraction could be replenished by means of commissioning of new deposits, which might be located in hard-accessible regions far away from the existing gas transmissions networks, where large markets for hydrocarbon raw stocks are absent. Organization of gas transportation to areas of consumption requires huge investments for construction of trunk gas pipelines and compressor stations. Utilization of LNG and CNG technologies in areas remote from the gas extraction is economically more feasible than installation of new pipelines. The major advantages of LNG and CNG technologies in comparison to network natural gas is their mobility. In case of consumer‘s focusing at LNG/CNG, he will have to possess a terminal for reception of liquefied/compressed natural gas. LNG technology is well proofed and broadly spread. CNG technology can be more rapidly assimilated and economic, being utilized at small- and medium-scale remote natural gas deposits where huge amounts of associated gas are burned in torches. Compressed gas does not require too intensive purification, liquefaction, storage and regasification costs. Plus, reception thereof does not require high-tech and expensive onshore structures. Gas can be loaded directly from a gas transmissions network (GTN) or shelf wells, and unloaded into an underground gas storage or directly into GTN. An interim option is also possible: use of a LNGRV tanker for LNG, or of a CNG tanker and offshore mooring terminals (STL buoys) will allow reception of both liquefied and compressed gas. This solution will afford to use both the LNG and CNG technologies, with the only difference that LNG will be fed into GTN after having passed regasification stage on the ship, while CNG is fed into GTN directly. Such solving of the gas supply issue will allow more flexible use of fluctuation of prices at the gas spot market and accelerate diversification of supplies.

1.3. Realized projects and prospects of natural gas marine transportation

Marine transportation of natural gas is realized via submerged gas pipelines in form of liquefied natural gas by gas carrier ships or in form of compressed natural gas by gas carrier ships (gas tankers). This section presents characteristics of realized projects and prospects of marine transportation of natural gas with use of various technologies.

60 CHAPTER 1

Various projects are examined, both in the Russian Federation and abroad, with presentation of their technical and cost characteristics.

1.3.1. Transportation of natural gas via marine pipelines

The existing European marine gas pipelines are presented in Table 1.10. Speaking about perspectives of development of gas transportation via marine gas pipelines, one should note such pipelines as Polarled, Balticconnector, the Nord Stream-2, the Turkish Stream, the Trans-Adriatic pipeline. Each of these projects is described below.

Polarled Polarled, a perspective gas pipeline 500 km long, will be installed from Aasta Hansteen deposit to Nyhamna where a gas processing plant is located, with possible connection in areas of Linnorm and Zidane and with connection to Åsgard Transport pipeline (see Fig. 1.37). Six access points are installed for future connection of new deposits in the North Sea to the gas pipeline. The Polar Investment Group includes 12 enterprises. Expenditures for construction of the pipeline and installation of new systems are estimated in amount of 15 billion krones24.

Fig. 1.37. The route of Polarled gas pipeline23 23 http://norginfo.com 24 http://proekt-gaz.ru

61 CHAPTER 1 810 610 813 910 mm 1220 1000 1000 1100 1100 1000 610/1220 Diameter, Diameter, 510/660/1220 610/1200/1400 8 16 55 17 12 30 26 12 15 20 16 24 18 /year 3 m Capacity, billion Capacity, 540 757 360 814 840 440 670 670 1213 1224 1620 2475 1166 Length, km Italy Italy Final point Final Easington (UK) Easington Almeria (Spain) Cordoba (Spain) Cordoba Ankara (Turkey) Ankara Dunkirk (France) Emden (Germany) Emden Dornum (Germany) Dornum Dornum (Germany) Dornum Zeebrugge (Belgium) Greifswald (Germany) Greifswald Sant-Fergus (Scotland) Sant-Fergus Marine gas pipielines from Africa Europe from to pipielines gas Marine Marine gas pipielines from Russia to Europe to Russia from pipielines gas Marine Marine gas pipielines of the North Sea the (Norway)* North of pipielines gas Marine Table 1.10. Existing European marine gas pipelines marine European 1.10. Existing Table Initial point Initial Vyborg (Russia) Vyborg Mellitah (Libya) Mellitah Isobilny (Russia) Isobilny North Sea (Norway) North North Sea (Norway) North North Sea (Norway) North North Sea (Norway) North North Sea (Norway) North North Sea (Norway) North North Sea (Norway) North Hassi-Rmel (Algeria) Hassi-Rmel Hassi-Rmel (Algeria) Hassi-Rmel Hassi-Rmel (Algeria) Hassi-Rmel 2003 2015 2004 2010 1996 1983 2006 1978 1993 1998 1977 1999 1995 Year of commissioning pipeline Name of gas of Name Blue Stream Blue Nord Stream Greenstream MedGas MEG TransMed Langeled Vesterled Zeepipe Franpipe Europipe II Europipe Europipe * Major marine gas pipielines of the North Sea are indicated Sea the are North of pipielines gas marine * Major

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Polarled will also become the deepest pipeline on the Norwegian continental shelf: by the time a ship reaches the area of Aasta Hansteen, the depth will be equal to 1260 meters. Moreover, it will be the first 36-inch pipeline in the world installed on such depth. The pipeline is not laid in straightway in order to avoid corals and big rocks and perform installation on an optimal depth25. The «Solitaire» pipe-lay ship from Allseas company was used for the pipeline installing. Built in 1998, «Solitaire» is characterized with an excellent dynamic positioning system which allows operation of the ship at a narrow spot and on deep waters. Plus, it is a high- capacity vessel, the rate of pipe-laying is 9 km/day. 40 thousand pipes, each 12 m long, were used for construction. Pipe-laying works were started in March 2015. Commissioning of the pipeline is scheduled for 2017. The throughput capacity will be equal to 70 million m3/day of gas, which is quite sufficient for use of all the volume of gas from Aasta Hansteen deposit. Reserves of gas at Aasta Hansteen deposit, according to Statoil estimates, are equal to 47 billion m3 of gas. Since September 2014, Wintershall company has entered the project on the development of Aasta Hansteen deposit in the Norwegian Sea, while in mid- March of 2015 the resource base of the deposit was increased approximately by 15%. Investments in the project were equal to about 750 million euros. At the budget of 11.1 billion krones (1.316 billion US dollars), just about 7.5 billion Norwegian krones (0.98 billion US dollars) were spent. The cost of the marine gas pipeline in terms of 1 km was 2.85 million US dollars per 1 km (scheduled) and 1.9 million US dollars per 1 km (actual).

Balticconnector On October 21, 2016 the European Union, Estonia and Finland signed a contract on co-funding of the project on construction of Balticconnector trunk gas pipeline. It was announced by the press office of the government of Estonia. On the EU‘s part, the contract was signed by the International Networks Executive Agency (INEA), and by Elering AS and Baltic Connector OY state-owned companies on Finland‘s and Estonia‘s part. According to the document, co-funding of Balticconnector gas pipeline on the EU‘s part will be equal to 187 Mio euros. The decision about co-funding of the project was made by the European Commission in August 2016 when they agreed to allocate 75% of 250 million euros needed for construction of Balticconnector gas pipeline. The government of Finland announced in September 2016 that it would allocate 28 Mio euros for funding of construction of Balticconnector marine gas pipeline. In November 2014 Estonia and Finland agreed on uniting of gas transmission 25 http://neftegaz.ru

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Fig. 1.38. The route of Balticconnector gas pipeline26 networks and creation of the necessary infrastructure by 2019. Balticconnector MGP will be the first gas pipeline between Estonia and Finland which will unite the both countries‘ gas networks. The project was conceived as early as in 2013 but the decline in demand for energy commodities prevented its realization. That time it was planned that the capacity of Balticconnector would be equal to 2 billion m3/year, with the cost of the project being equal to 110 million euros. Now the project is planned as more powerful: Balticconnector will allow transmission of max. 7.2 million m3/day of gas between gas distributing networks of Estonia and Finland. The pipeline length will be equal to 150 km, 81 km of them will run on the sea bottom, 22 km on the land territory of Finland and 47 km on the land territory of Estonia (see Fig. 1.38). Also, compressor stations will be constructed on the both sides of the Gulf of Finland.

Turkish Stream The marine section of the Turkish Stream will run from the Russkaya compressor station near the city of Anapa, on the bottom of the Black Sea, to the coast of Turkey. The pipeline length is over 900 km (see Fig. 1.39).

26 http://neftegaz.ru

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Fig. 1.39. The route of the Turkish Stream gas pipeline 27

Nord Stream-2 The decision about construction of the Nord Stream-2 gas pipeline is based on the successful experience of construction and operation of the Nord Stream gas pipeline.

Fig. 1.40. The route of the Nord Stream-2 gas pipeline28

27 http://www.gazprom.ru 28 http://www.gazprom.ru

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«Nord Stream-2» is a project of a trunk gas pipeline from Russia to Germany via the Baltic Sea. In fact, it is an expansion of «Nord Stream» and corresponds to the existing gas pipeline in terms of the capacity and length. It differs from Nord Stream in terms of the structure of shareholders of the submerged section. The configuration of partners for construction of land branches from the new trunk pipeline is also being discussed with the control bodies29. To realize this project, New European Pipeline AG company was founded, with the following shareholders: Gazprom: 51%, E.ON, Shell, BASF/Wintershall, OMV: 10% each, ENGIE: 9%. The committee of the project‘s shareholders will also include representatives of minority shareholders (one from each entity)30. The project company Nord Stream 2 AG implements the Nord Stream 2 project. The company‘s shareholder is Gasprom. In October 2012, the shareholders of Nord Stream reviewed the preliminary results of the feasibility of the construction of the third and fourth strings of the gas pipeline and decided that their construction is economically and technically feasible. Later, the project for the construction of the third and fourth threads was called «Nord Stream-2». In April 2017, Nord Stream 2 AG signed an agreement with ENGIE, OMV, Royal Dutch Shell, Uniper and Wintershall on the financing of the Nord Stream-2 gas pipeline project. Five European companies will provide long-term financing in the amount of 50% of the total cost of the project. Initial cost of the project is 9,5 billion euros.

Trans-Adriatic gas pipeline Trans-Adriatic gas pipeline is a pipeline in the design phase for transportation of natural gas from Pre-Caspian region and from Middle East to West Europe. The route of the gas pipe (520 km long): Greece, Albania, the Adriatic Sea (the offshore part), and Italy (see Fig. 1.41). Designers of the projects are EGL (Switzerland), Statoil (Norway), and Uniper (Germany). SOCAR, BP (UK) and Snam (Italy) own 20% of the pipeline each, Fluxus (Belgium) owns 19%, Enagas (Spain) 16% and Axpo (Switzerland) 5%. It is supposed that is will become a part of Southern Gas Corridor project, thus continuing the chain from the South-Caucasian pipeline (Baku – Tbilisi – Erzurum) and Trans-Anatolian pipeline (Turkey). The supposed capacity of the gas pipeline: 10 billion m3 per year, with ability to increase the throughput capacity up to 20 billion m3 per year.

29 https://ru.wikipedia.org 30 https://ru.wikipedia.org

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Fig. 1.41. The route of the Trans-Adriatic gas pipeline

1.3.2. Marine transportation of liquefied natural gas

Within the infrastructure of LNG marine transportation, LNG is transported by a gas carrier ship from plants where natural gas is liquefied (LNG plants) to regasification terminals.

1.3.2.1. Plants for natural gas liquefaction

Tables 1.11 and 1.12 show LNG production world capacities (both existing and under construction):

Table 1.11. Existing LNG plants Capacity, Year of com- Country LNG plant Mio. tons/ Liquefaction technology missioning year Algeria Arzew - GL1Z (T1-6) 1978 7,9 APC C3MR Algeria Arzew - GL2Z (T1-6) 1981 8,2 APC C3MR Algeria Skikda - GL1K Rebuild 2013 4,5 APC C3MR Algeria Arzew - GL3Z (Gassi Touil) 2014 4,7 APC C3MR/Split MR™ ConocoPhillips Opti- Angola Angola LNG T1 2013 5,2 mized Cascade® Australia North West Shelf T1 1989 2,5 APC C3MR

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Australia North West Shelf T2 1989 2,5 APC C3MR Australia North West Shelf T3 1992 2,5 APC C3MR Australia North West Shelf T4 2004 4,4 APC C3MR ConocoPhillips Opti- Australia Darwin LNG T1 2006 3,6 mized Cascade® Australia North West Shelf T5 2008 4,4 APC C3MR Shell propane pre-cooled Australia Pluto LNG T1 2012 4,3 mixed refrigerant design ConocoPhillips Opti- Australia QCLNG T1 2014 4,3 mized Cascade® ConocoPhillips Opti- Australia QCLNG T2 2015 4,3 mized Cascade® Brunei Brunei LNG T1-5 1972 7,2 APC C3MR ConocoPhillips Opti- Egypt ELNG T1*** 2005 3,6 mized Cascade® ConocoPhillips Opti- Egypt ELNG T2*** 2005 3,6 mized Cascade® Egypt Damietta LNG T1*** 2005 5,0 APC C3MR Equatorial ConocoPhillips Opti- EG LNG T1 2007 3,7 Guinea mized Cascade® Indonesia Bontang LNG T3-4 1983 5,4 APC C3MR Indonesia Bontang LNG T5 1989 2,9 APC C3MR Indonesia Bontang LNG T6 1994 2,9 APC C3MR Indonesia Bontang LNG T7 1998 2,7 APC C3MR Indonesia Bontang LNG T8 1999 3,0 APC C3MR Indonesia Tangguh LNG T1 2009 3,8 APC C3MR/Split MRTM Indonesia Tangguh LNG T2 2009 3,8 APC C3MR/Split MRTM Indonesia Donggi-Senoro LNG 2015 2,0 APC C3MR Libya Marsa El Brega*** 1970 3,2 APC C3MR Malaysia MLNG Satu (T1-3) 1983 8,1 APC C3MR Malaysia MLNG Dua (T1-3) 1995 7,8 APC C3MR Malaysia MLNG Tiga (T1-2) 2003 6,8 APC C3MR Malaysia MLNG Dua Debottleneck 2010 1,2 APC C3MR Nigeria NLNG T1 1999 3,3 APC C3MR Nigeria NLNG T2 2000 3,3 APC C3MR Nigeria NLNG T3 2002 3,0 APC C3MR Nigeria NLNG T4 2006 4,1 APC C3MR

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Nigeria NLNG T5 2006 4,1 APC C3MR Nigeria NLNG T6 2008 4,1 APC C3MR Norway Snohvit LNG T1 2007 4,2 Linde MFC Oman Oman LNG T1 2000 3,6 APC C3MR Oman Oman LNG T2 2000 3,6 APC C3MR Oman Qalhat LNG 2006 3,7 APC C3MR Papua New PNG LNG T1 2014 3,5 APC C3MR Guinea Papua New PNG LNG T2 2014 3,5 APC C3MR Guinea Peru Peru LNG 2010 4,5 APC C3MR/Split MRTM Qatar Qatargas I (T1) 1997 3,2 APC C3MR Qatar Qatargas I (T2) 1997 3,2 APC C3MR Qatar Qatargas I (T3) 1998 3,1 APC C3MR Qatar RasGas I (T1) 1999 3,3 APC C3MR Qatar RasGas I (T2) 2000 3,3 APC C3MR Qatar RasGas II (T1) 2004 4,7 APC C3MR/Split MRTM Qatar RasGas II (T2) 2005 4,7 APC C3MR/ Qatar RasGas II (T3) 2007 4,7 APC C3MR/ Qatar Qatargas II (T1) 2009 7,8 APC AP-X Qatar Qatargas II (T2) 2009 7,8 APC AP-X Qatar Qatargas III 2010 7,8 APC AP-X Qatar RasGas III (T2) 2010 7,8 APC AP-X Qatar Qatargas IV 2011 7,8 APC AP-X Qatar Sakhalin 2 (T1) 2009 4,8 Shell DMR Russia Sakhalin 2 (T2) 2009 4,8 Shell DMR ConocoPhillips Opti- Russia ALNG T1 1999 3,3 mized Cascade® Trinidad& ConocoPhillips Opti- ALNG T2 2002 3,4 Tobago mized Cascade® Trinidad& ConocoPhillips Opti- ALNG T3 2003 3,4 Tobago mized Cascade® Trinidad& ConocoPhillips Opti- ALNG T4 2006 5,2 Tobago mized Cascade® Trinidad& ADGAS LNG T1-2 1977 2,6 APC C3MR Tobago UAE ADGAS LNG T3 1994 3,2 APC C3MR

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UAE Kenai LNG** 1969 1,5 ConocoPhillips Opti- mized Cascade® USA Yemen LNG T1 2009 3,6 APC C3MR/Split MRTM Yemen Yemen LNG T2 2010 3,6 APC C3MR/

Table 1.12. LNG plants under construction Capacity, Year of com- Liquefaction Country LNG plant Mio. tons/ missioning technology year ConocoPhillips Opti- Australia APLNG T1 2016 4,5 mized Cascade® ConocoPhillips Opti- Australia APLNG T2 2016 4,5 mized Cascade® ConocoPhillips Opti- Australia GLNG T1 2016 3,9 mized Cascade® Australia Gorgon LNG T1-2 2016 10,4 APC C3MR/Split MRTM ConocoPhillips Opti- Australia GLNG T2 2016 3,9 mized Cascade® ConocoPhillips Opti- Australia Wheatstone LNG T1 2016 4,5 mized Cascade® Australia Gorgon LNG T3 2017 5,2 APC C3MR/Split MRTM Australia Ichthys LNG T1 2017 4,5 APC Split MRTM Australia Prelude FLNG 2017 3,6 Shell Floating LNG ConocoPhillips Opti- Australia Wheatstone LNG T2 2017 4,5 mized Cascade® Australia Ichthys LNG T2 2018 4,5 APC Split MRTM Cameroon Cameroon FLNG 2017 2,4 GoFLNG Indonesia Senkang LNG T1 2016 0,5 Siemens Malaysia MLNG 9 2016 3,6 APC Split MRTM Malaysia PFLNG 1 2016 1,2 APC AP-NTM Malaysia PFLNG 2 2018 1,5 APC AP-NTM Russia Yamal LNG T1 2017 5,5 APC C3MRTM Russia Yamal LNG T2 2018 5,5 APC C3MRTM Russia Yamal LNG T3 2019 5,5 APC C3MRTM ConocoPhillips Opti- USA Sabine Pass T1-2 2016 9,0 mized Cascade® USA Cove Point LNG 2017 5,3 APC C3MR/Split MRTM

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ConocoPhillips Opti- USA Sabine Pass T3-4 2017 9,0 mized Cascade® USA Cameron LNG T1-3 2018 12,0 APC C3MRTM USA Freeport LNG T1 2018 4,4 APC C3MR/Split MRTM USA Freeport LNG T2 2019 4,4 APC C3MR/Split MRTM ConocoPhillips Opti- USA Sabine Pass T5 2019 4,5 mized Cascade® USA Freeport LNG T3 2019 4,4 APC C3MR/Split MRTM ConocoPhillips Opti- USA Corpus Christi LNG T1-2 2019 9,0 mized Cascade® TOTAL: 141,5

Fig. 1.42 provides information about the existing capacities and those under construction for LNG production per country. Qatar is the leader in world gas liquefaction capacities, followed by Australia and Algeria. By 2019 it is planned that Australia will have taken an upper hand in the liquefaction capacities upon completion of construction of six new LNG plants. A large amount of new liquefaction capacities (6 LNG plants) is going to appear in the USA by the end of 2019 due to discovering of large-scale shale gas deposits. For several latest years, the offer sharply grew on the world LNG production market.

Fig. 1.42. Existing capacities and capacities under construction for LNG production

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The aggregate capacity of offered projects is equal to 890 million tons/year, as by the data for January 2016. The location of the predominant amount of these projects is the USA and Canada (75%). Australia, East Africa and Russia also presented a number of new LNG projects. However, only a part of these will be realized, as the LNG market is over- saturated at present and the anticipated growth rate of LNG demand is much lower than the amount of the abovementioned offer. The key developing LNG production markets are the US Mexican Gulf Coast and Canada (where the offer growth is ensured by shale gas extraction), buoyant LNG installations all over the world (advantages to hard-extracted gas and lower specific costs of liquefaction). It is also planned to broaden existing productions in APR countries and to realize Arctic shelf projects in Russia and Alaska. 1.3.2.2. The world tanker fleet In 2015, twenty-nine new gas carrier ships were built and delivered to customers (including Golar Tundra gas pressure reduction station which was initially destined for LNG transportation) the total tonnage whereof exceeded the increment of liquefied gas production capacity by 4.7 million tons/year, which even more aggravates the over- saturation of the market of LNG marine transportation. As a whole, the world fleet of LNG marine transportation by the end of 2015 consists of 410 ships (excluding those with capacity under 60 thousand m3 of gas), with the total capacity of 63 million m3 of liquefied gas. The tide of demand for construction of new LNG carrier ships began on the eve of 2012-2013. Unlike the growth of demand for LNG, which led to emerging of new orders for gas carrier vessels during that period, today‘s orders for construction of new ships are conditioned by the rise of offer at the LNG market, first of all, in Australia and the USA. Conventional gas carrier ships are much different in terms of nominal size, however, the trend to increasing of cargo capacity is has being observed in recent time. Prior appearing of Q class ships (210 thousand m3 and over) in 2008-2010, the standard cargo capacity of ships was 125-150 thousand m3. By the end of 2015, 31% of tankers are in the range of 150-180 thousand m3 in terms of their cargo capacity. Q class ships (43 tankers) are representing 16% of the active tanker fleet. In 2015, the average capacity of gas carrier ships was equal to about 164 thousand m3, and this figure will grow up with accounting for new orders for construction of vessels. In accordance with the book of orders for construction of new tankers, the cargo capacity is expected to increase up to 175 thousand m3 by 2020. Opening of the broadened Panama Canal in the summer 2016 also contributes to the trend development towards the growth of gas carrier ships‘ cargo capacity with volumes of 170-180 thousand m3. Of 23 vessels ordered in 2015, 87% belong to New Panamax class. These tankers can pass through the broadened Panama Canal and will be more

72 CHAPTER 1 flexible, especially with Q class ships (210 thousand m3 and over), in terms of access to unloading ports, in particular, in Asia. As on January 2016, 143 new tankers are ordered with the supply date by 2022. In particular, delivery of 46 tankers from manufacture plants is expected in 2016, those with gas pressure reduction stations included, while the anticipated growth of liquefaction capacities will be equal to 10.5 million tons/year, according to preliminary estimates. Due to considerable delays of schedule commissioning of new capacities, the market of cargo LNG transportation will stay overheated. In terms of design, the cargo storage system in tankers can be of two types: MOSS and membrane type. By the end of 2015, 76% of the active tanker fleet belong to ships of membrane type. By the end of 2015, 55% of the tanker fleet was represented by ships over 10 years in age, which was the result of construction of newly-built ships in the mid-2000s and early 2010s after the growth of LNG production capacities. About 9% of tankers have been over 30 years old. To gain economic profit from old gas carrier ships, they have been used afterwards as gas pressure reduction stations or just as a storage for LNG. At the end of 2015, 19 ships (MOSS cargo storage system with a steam-turbine engine, cargo capacity to 150 thousand m3) were decommissioned. About 80% of them were over 30 years old, and every one of them was older than 10 years. In 2015, the number of orders for new ships reduced by 65%, as compared to 2014. Most of these orders are expected to be delivered in 2018-2019. All ships possess cargo capacity over 170 thousand m3. Table 1.13 represents the world tanker fleet by cargo capacity and age.

Table 1.13. Active world tanker fleet by cargo capacity and age Age of ships, years Cargo capacity of ships, thou. m3 < 10 10-19 20-29 30-39 > 39 30 – 124.9 2 2 5 2 4 125 – 149.9 56 114 25 20 1 150 – 180 134 1 0 0 0 > 180 44 0 0 0 0 TOTAL 236 117 30 22 5

In Figs. 1.43 and 1.44 the world tanker fleet is shown by cargo capacity and age, and by producers, respectively.

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Fig. 1.43. Active world tanker fleet by cargo capacity and age

Fig. 1.44. The world tanker fleet by producers

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1.3.2.3. Regasification terminals

Tables 1.14 and 1.15 represent the world‘s LNG regasification capacities, both existing and under construction.

Table 1.14. Existing LNG terminals Year of commis- Capacity, million Country Name of LNG terminal Conception sioning tons/year Argentina Bahia Blanca GasPort 2008 3.8 Buoyant Argentina Puerto Escobar 2011 3.8 Buoyant Belgium Zeebrugge 1987 6.6 Onshore Brazil Pecem 2009 1.9 Buoyant Brazil Guanabara LNG/Rio de Janeiro 2012 6.0 Buoyant Brazil Bahia/TRBA 2014 3.8 Buoyant Canada Canaport 2009 7.5 Onshore Chile Quintero LNG 2009 2.7 Onshore Chile Mejillones LNG 2010 1.5 Onshore China Guangdong Dapeng LNG I 2006 6.7 Onshore China Fujian (Putian) 2008 5.0 Onshore China Shanghai (Yangshan) 2009 3.0 Onshore China Dalian 2011 3.0 Onshore China Rudong Jiangsu LNG 2011 3.5 Onshore China Dongguan 2012 1.0 Onshore China Ningbo. Zhejiang 2013 3.0 Onshore China Zhuhai (CNOOC) 2013 3.5 Onshore China Tangshan Caofeidian LNG 2013 3.5 Onshore China Tianjin 2013 2.2 Buoyant China Hainan LNG 2014 2.0 Onshore China Shandong LNG 2014 3.0 Onshore Dominican AES Andres 2003 1.9 Onshore Republic Egypt Ain Sokhna Hoegh 2015 4.1 Buoyant Egypt Ain Sokhna BW 2015 5.7 Buoyant France Fos Tonkin 1972 4.0 Onshore France Montoir-de-Bretagne 1980 7.3 Onshore France FosMax LNG (Fos Cavaou) 2010 6.0 Onshore

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Greece Revithoussa 2000 3.3 Onshore India Dahej LNG 2004 10.0 Onshore India Hazira LNG 2005 5.0 Onshore India Dabhol 2013 2.0 Onshore India Kochi LNG 2013 5.0 Onshore Indonesia Nusantara 2012 3.8 Buoyant Indonesia Lampung LNG 2014 1.8 Buoyant Indonesia Arun LNG 2015 3.0 Onshore Israel Hadera Gateway 2013 3.0 Buoyant Italy Panigaglia (La Spezia) 1971 2.5 Onshore Italy Adriatic LNG/Rovigo 2009 5.8 Offshore Italy Livorno/LNG Toscana 2013 2.7 Buoyant Japan Negishi 1969 12.0 Onshore Japan Senboku 1972 15.3 Onshore Japan Sodegaura 1973 29.4 Onshore Japan Chita LNG Joint/ Chita Kyodo 1977 8.0 Onshore Japan Tobata 1977 6.8 Onshore Japan Himeji 1979 13.3 Onshore Japan Himeji 1979 13.3 Onshore Japan Chita 1983 12.0 Onshore Japan Higashi-Ohgishima 1984 14.7 Onshore Japan Nihonkai (Niigata) 1984 8.9 Onshore Japan Futtsu 1985 16.0 Onshore Japan Yokkaichi LNG Works 1987 7.1 Onshore Japan Oita 1990 5.1 Onshore Japan Yanai 1990 2.4 Onshore Japan Sodeshi/Shimizu LNG 1996 1.6 Onshore Japan Kawagoe 1997 7.7 Onshore Japan Ohgishima 1998 6.7 Onshore Japan Chita Midorihama Works 2001 8.3 Onshore Japan Sakai 2005 2.0 Onshore Japan Mizushima LNG 2006 1.7 Onshore Japan Ishikari LNG 2012 1.4 Onshore Japan Joetsu 2012 2.3 Onshore

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Japan Naoetsu (Joetsu) 2013 2.0 Onshore Japan Hibiki LNG 2014 3.5 Onshore Japan Hachinohe LNG 2015 1.5 Onshore Japan Shin-Sendai 2015 1.5 Onshore Jordan Aqaba LNG 2015 3.8 Buoyant Korea Pyeong-Taek 1986 34.5 Onshore Korea Incheon 1996 38.0 Onshore Korea Tong-Yeong 2002 17.0 Onshore Korea Gwangyang 2005 1.8 Onshore Korea Samcheok 2014 6.8 Onshore Kuwait Mina Al-Ahmadi 2009 5.8 Buoyant Lithuania Klaipeda LNG 2014 3.0 Buoyant Malaysia Lekas LNG (Malacca) 2013 3.8 Onshore Mexico Altamira LNG 2006 5.4 Onshore Mexico Costa Azul 2008 7.5 Onshore Mexico Manzanillo 2012 3.8 Onshore Netherlands GATE LNG 2011 8.8 Onshore Pakistan Engro LNG 2015 3.8 Buoyant Poland Swinoujscie 2016 3.6 Onshore Portugal Sines LNG 2004 5.8 Onshore Puerto Rico Penuelas (EcoElectrica) 2000 1.2 Onshore Singapore Singapore LNG 2013 6.0 Onshore Spain Barcelona 1969 12.8 Onshore Spain Huelva 1988 8.9 Onshore Spain Cartagena 1989 7.6 Onshore Spain Bilbao (BBG) 2003 5.3 Onshore Spain Saggas (Sagunto) 2006 6.7 Onshore Spain Mugardos LNG (El Ferrol) 2007 2.6 Onshore Spain El Musel 2013 5.4 Onshore Taiwan Yong an (Kaohsiung) 1990 10.0 Onshore Taiwan Taichung LNG 2009 3.0 Onshore Thailand Map Ta Phut LNG 2011 5.0 Onshore Turkey Marmara Ereglisi 1994 5.9 Onshore Turkey Aliaga LNG 2006 4.4 Onshore

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UAE Dubai 2010 3.0 Buoyant UK Grain LNG 2005 15.0 Onshore UK Teesside GasPort 2007 3.0 Buoyant UK Dragon LNG 2009 4.4 Onshore UK South Hook 2009 15.6 Onshore USA Everett 1971 5.4 Onshore USA Cove Point 1978 11.0 Onshore USA Elba Island 1978 12.4 Onshore USA Lake Charles 1982 17.3 Onshore USA Freeport LNG 2008 11.3 Onshore USA Northeast Gateway 2008 3.0 Buoyant USA Sabine Pass 2008 30.2 Onshore USA Cameron LNG 2009 11.3 Onshore USA Golden Pass 2011 15.6 Onshore USA Gulf LNG 2011 11.3 Onshore TOTAL 752.9

Table 1.15. LNG terminals under construction Year of commis- Capacity, million Country Name of LNG terminal Conception sioning tons/year China Rudong Jiangsu LNG Phase 2 2016 3.0 Береговой China Yuedong LNG (Jieyang) 2016 2.0 Береговой China Beihai. Guangxi LNG 2016 3.0 Береговой China Dalian Phase 2 2016 3.0 Береговой China Tianjin (onshore) 2016 3.5 Береговой China Yantai. Shandong Phase 1 2016 1.5 Береговой China Tianjin (Sinopec) Phase 1 2016 2.9 Береговой China Shenzhen (Diefu) 2017 4.0 Береговой China Fujian (Zhangzhou) 2018 3.0 Береговой China Zhoushan 2018 3.0 Береговой France Dunkirk LNG 2016 10.0 Береговой Greece Revithoussa (Expansion Phase 2) 2016 1.9 Береговой India Dahej LNG (Phase 3-A1) 2016 5.0 Береговой India Mundra 2017 5.0 Береговой India Ennore LNG 2019 5.0 Береговой

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Japan Soma LNG 2018 1.5 Береговой Korea Boryeong 2017 3.0 Береговой Philippines Pagbilao LNG Hub 2016 3.0 Береговой Thailand Map Ta Phut Phase 2 2017 5.0 Береговой TOTAL 68.3

In Fig. 1.45 existing LNG terminals and those under construction are presented. The world LNG regasification capacities are equal to 752.9 million tons/year. The leader in LNG regasification capacities is Japan, thereafter the USA and Korea follow. In recent years, buoyant liquefied gas terminals have been intensely developed, and gas pressure reduction stations have been becoming the most acceptable way of entering of new countries into the LNG market. 14 countries of 33 LNG importers possess buoyant capacities for LNG reception. According to the data for 2015, the total world capacities of buoyant terminals (20 gas pressure reduction stations) is equal to 77 million tons/year. In the beginning of 2016, construction of 15 new regasification terminals was announced, 8 of them being in China. By 2019, it is expected that the increase of the world LNG reception capacities is to be 68.3 million tons/year (10%), of them 51.6 million tons/year of capacities will emerge in the countries of the Asia Pacific Region, China‘s share in the total increase will be equal to 28.9 million tons/year, and that of India would hit 15 million tons/year.

1.3.3. Marine transportation of compressed natural gas

At present CNG carrier vessels are not in commercial use and there is not any information available about ships in active use, which have relatively big cargo capacity. In the open access in Internet there is nothing but just various projects of ships for carrying of compressed gas. Scope of Works (SOW) regarding creation of systems for marine transportation of compressed natural gas are most purposefully conducted by the following companies: • EnerSea Transport LLC, USA; • Knutsen OAS Shipping, Norway; • Compressed Energy Technology AS (CETech), Norway; • TransCanada Pipeline Ltd., Canada; • TransOcean Gas Inc. (TOG), Canada; • Sea NG Management Corporation, Canada.

79 CHAPTER 1 Fig. 1.45. LNG terminals – existing and under construction under and – existing terminals 1.45. LNG Fig.

80 CHAPTER 2. COMPARATIVE ECONOMIC ANALYSIS OF NATURAL GAS TRANSPORTATION TECHNOLOGIES

Currently, all major oil and gas companies are facing the problem of choosing the methods and routes of transporting their products to consumers. Improved technologies such as LNG production, offshore hydrocarbon production, extended usage of compressed natural gas have increased the number of hydrocarbons delivery and use options (Fig. 2.1). At the same time, different transportation modes have distinctive advantages and disadvantages, which ratio depends on many factors: geological, geographic, political, as well as on ways of hydrocarbon use by consumers on ways of hydrocarbon use by consumers. In particular, natural gas usage in recent years has undergone significant expansion, leading also to the increase of the ways to transport gas (Fig. 2.2). When optimizing their logistics systems, companies evaluate and compare the costs to deliver their products to consumers in different ways. To compare the methods of gas transportation, taking into account the forms of its transformation/replacement, it is necessary to bring all volumetric indicators to the common denominator that is the equivalent volume expressed in cubic meters of gas. When comparing efficiency of gas transportation methods, taking into account possible forms of its transformation, minimum of discounted costs per unit, as a rule, is used as a criterion.

Fig. 2.1 - Business model of modern large company of fuel and energy industry (based on BP example)31

31 BP Annual Report and Form 20-F 2015

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Fig. 2.2. Options for using natural gas

This section compares the technologies of natural gas transportation: • Onshore pipeline; • Offshore pipeline; • LNG; • CNG. 2.1. Methodology for Economic Analysis of Natural Gas Transportation Technologies This section discusses common approaches to compare the economic efficiency of various transportation technologies, regardless of the subject of transportation. When comparing different transport options, it is necessary to take into account the capital and operating costs incidental to each option. These costs determine the values of transportation tariffs. However, in general, the transportation tariff for each option is not constant, but depends on conditions of the transport project implementation. The main parameters that determine the cost transportation include freight traffic and distance (transportation volume and distance). That is, for different values of these parameters, different transportation options can be effective due to the lowest tariff. Therefore, the final conclusion on the economic efficiency of a particular transportation option can be made only in relation to specific conditions for the project implementation. The tariff corresponding to one of the transportation option under comparison may be the lowest in the entire range of freight traffics and distances considered. Or, under certain conditions, there may be a "change of leader", and the other transportation way

82 CHAPTER 2 may become the most cost-effective. The second option is possible when the transport technologies under comparison have different cost structure. The size of the project capital and operating costs has the largest impact on the tariff. Let us consider the value of the total unit costs for transportation σ (rubles/tons*km): S σ = (1) ML⋅ Here S is total costs (including both capital and operational costs) in rubles for the freight traffic using the kind of transport under consideration. These costs depend on both the freight flow and the distance. M (tons) is the annual freight flow. L (km) is the distance for transportation. The value of S in general form may be represented by the following formula: Sa=+bM⋅+сM⋅⋅Ld+⋅L (2) Here, a is the costs that depend neither on the freight flow M, nor on the distance L. For example, R & D costs, design work; b is a factor to characterize costs that depend on the freight flow M. It is determined by such costs as, for example, the costs to purchase and maintain vehicles used in the project; c is a factor characterizing costs that depend on both the freight flow M and the distance L. It is determined by such costs as, for example, the cost of fuel and energy resources; d is a factor characterizing costs that depend on the distance L. It is determined by such costs as, for example, the costs of road construction and of pipeline laying. We note that expression (equation) (2) does not take into account nonlinear effects. For example, the number of transport units of equipment involved in the project and the related costs increase in steps with increase of freight traffic. The fewer units of equipment are involved in the project and the greater the carrying capacity of one unit of equipment is, the more this effect is noticeable. According to (1, 2): 6 D E G V F  (3) 0/˜ 0/˜ / 0 You can see from this formula that the dependencies of the total unit costs, both on the freight traffic and on the distance, have hyperbolic form similar to that shown in Figures 2.3 and 2.4. It follows from (3) that the curvature of the dependence of σ= σ(L) for M=const is defined by the coefficients b and a. In turn, the coefficients d and c, on the graph σ = σ(L),

83 CHAPTER 2 determine the value of σ in the plateau when L →∞. Similarly, the curvature of the dependence σ=σ(M) for L=const is defined by the coefficients d and a, and the value of σ on the plateau when M →∞ is determined by the values of the parameters b and c. Figures 2.3 and 2.4 show the general form of the graphs σ=σ(L) when M=const for two modes of transport with similar and different cost structures, respectively. The graphs σ=σ(M) behave similarly for L=const. Dependency curves σ=σ(L) (or σ=σ(M)) constructed for two modes of transport with different cost structures have different curvatures that are characterized by the coefficients of formula (3). This entails the existence of points of intersection of these graphs. Thus, the relations between the parameters a, b, c, d define the cost structure for the transport modes being compared and the mutual arrangement of the graphs for the functions σ=σ(L) (or σ=σ(M)) plotted for these modes of transport. The different cost structure that characterizes transport projects being compared stipulates the existence of crossing points of the above-mentioned graphs. The total unit cost of freight traffic for the transport modes being compared is equal in the point of intersection, and if you move away from this point to one side, one of the compared transport mode turns out to be advantageous, but the movement to the other side makes advantageous the other transport mode. This allows us to substantiate limits of effectiveness of each mode of transport. The set of intersection points mapped on the plane (M, L) represents a line of critical

Fig. 2.3 - General view of dependency curves σ =σ(Ί) for two modes of transport with similar cost structure

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Fig. 2.4 - General view of dependency curves σ=σ(Σ) for two modes of transport with different cost structure equivalence that separates the areas of effective usage of the two transport modes being compared. To determine preference areas for different technologies, further analysis (theoretical calculations) is executed for ranges of transportation volumes and distances. The calculation results are illustrated graphically. The areas are defined where the only technology is definitely preferable as well as the areas where, depending on the particular project conditions, one or the other (or even the third) technology may be preferable – so called "gray" areas. The calculations are executed for the minimum and maximum estimates. The result is an area from the minimum value to the maximum one. In determining the minimum and maximum estimates, the variability is taken into account that is caused by the potential change in the project technical solutions that are not related to the gas supply volume and transport distances as well as the variability caused by uncertainty of the estimates. As examples of factors of the first kind, we may consider the dependence of capital investments in construction of an offshore gas pipeline on the pipe wall thickness that in turn depends on sea depths along the route, and the dependence of capital investments in construction of an LNG or CNG offshore transportation system on the costs of construction of loading and unloading terminals (volume of dredging, type of berthing facilities, etc.). As for uncertainty of the estimates, we suggest to guess the maximum estimate as the base one plus 30% and the minimum estimate as the base one minus 10%. The main criterion to compare technologies is transport tariff (in rubles and euros

85 CHAPTER 2 per thousand cubic meters per 100 km). The auxiliary criterion is the capital investments per unit (in rubles and euros per thousand cubic meters per 100 km). All values are calculated in real prices (without inflation). The estimated period is 25 years. The year of evaluation is 2016. The criterion to calculate the transport tariff is the IRR of commercial efficiency that is equal to 12%. The discount rate is 10%. The main result of the performed work is the determination of dependence (and its graphical representation) of the main and auxiliary criterion on the transport volume and on the transportation distance for all considered technologies.

2.2. Algorithm of Comparative Analysis of Economic Efficiency for Various Methods of Gas Transportation

The main criterion to compare these technologies is the transport tariff. The transportation tariffs are calculated based on the condition to ensure the specified rate of return of 12%. Each transportation option is considered as a separate investment project that is used to simulate cash flows including inflows and outflows from operating and investment activities. The transport technologies are compared according to the following algorithm: Step 1: Development of baseline data for calculations; Step 2: Simulation of cash flows for each option of natural gas transportation; Step 3: Calculation of the set of tariff values depending on distances and volumes of transportation; Step 4: Plotting the dependence of tariffs on freight traffics and distances and identifying their intersection points for various transport technologies; Step 5: Identification of areas of effective application for each transport technology (matrix of effectiveness). At the first step, the initial data of cash flow model building were obtained. They include: • Estimate of capital costs for each option for natural gas transportation; • Estimate of operating costs for each option for natural gas transportation; • Estimate of characteristics of investment projects that differ for transportation options; • Estimate of characteristics of investment projects that are the same for all transportation options.

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Estimates of capital and operating costs are based on data on the similar projects. The costs were adjusted to the price level of 2016 using deflator indices. Characteristics differing for transportation options include a special tax regime for export of liquefied natural gas (export duty of 0% for LNG). The characteristics that are the same for all options include, in particular: income tax (20%); accounting period (25 years); discount rate (10%); depreciation type (linear, 25 years); investment schedule by years (4 years, 5% - 15% -50% -30% respectively). At the second steps, the cash flows are simulated for each natural gas transportation option. Calculations are made in euros and Russian rubles at real prices (excluding inflation). Cash flows for each year include inflows and outflows. The inflows include cash inflows to the project from gas transportation that are calculated as the transportation volume times the transportation distance and the tariff. The outflows for operating activities include operating costs and taxes.. The investment outflows include investment costs. The cash flow analysis by discounting method allows us to obtain the following indicators of economic efficiency: • Net present value (NPV); • Internal rate of return (IRR); • Discounted profitability index (DPI). The net present value is calculated using the formula:

T NPVF= ∑αtt (4) t=0 where th Ft – cash flow in the t year of the accounting period; th αt – discount factor in the t year calculated by the formula: 1 α = (5) t ()1+ E t where t – serial number of the year (step) of the accounting period, t = 1,2,..., T; T – accounting period; Е – discount rate. The IRR is the discount rate that turns the NPV value for the accounting period to zero. In this case, the project NPV is positive for all values EIRR. The IRR value is determined from the numerical solution of the equation:

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T 1 ⋅ = (6) ∑ Ft t 0 t=0 ()1+ IRR The discounted profitability index of investments (DPI) is equal to the ratio of NPV to the accumulated discounted investment volume increased plus one. It is calculated by the formula: NPV DPI = T +1 (7) ∑αtt⋅ I t=1 where th It – project investment in the t year. At the third step, a set of values for transportation tariffs was obtained. For this purpose, the cash flow models obtained in the second step for each transport option were used. When calculating tariffs in cash flows, the requirement of commercial efficiency of projects was taken into account (IRR=12%). In the fourth step, the tariff dependencies on freight traffics and distances were plotted using the set of tariff values obtained in the previous step. For this purpose, some value of annual transportation volume was fixed and the tariff dependencies from the transportation distance were plotted for each of the transport technologies being compared. Then the intersection points (if any) for the specified curves were determined with the graph-analytic method. Then the procedure was repeated for another fixed value of annual transportation volume. Then some value of the transportation distance was fixed and the tariff dependencies from the annual transportation volume were plotted for each of the transport technologies being compared. Then the intersection points (if any) for the specified curves were determined with the graph-analytic method. Further, the procedure was repeated for another fixed value of transportation distance. As a result, a set of graph intersection points was obtained, and each of these points is characterized by values of transportation distance and annual transportation volume. At these points, there is a "change of leader": one transport technology becomes more efficient than the other one. At the fifth step, the set of points obtained in the previous step was displayed on the plane (matrix of effectiveness). Then these points were connected by lines that are the lines of critical equivalence that separate the areas of effective application of each transport technology depending on the gas transport annual volume of and the corresponding transportation distance.

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At the same time, variability due both to the potential change in the project technical solutions and to uncertainty of the estimates was taken into account. Therefore, the lines of critical equivalence that separate the effective application areas for each transport technology are characterized by their widths (uncertainty range). Within this range, none of the compared technologies is clearly preferable in view of uncertainty.

2.3. Design Premises and Assumptions to Simulate the Economic Feasibility of Offshore Transportation Technologies of Natural Gas

The design premises and assumptions used to simulate the economic feasibility of offshore transportation of natural gas are presented in Table 2.1.

Table 2.1 Quantitative characteristics and assumptions № Performance index Value Unit Basic criterion to compare the rubles & euro per thousand 1 Transport tariff technologies m3 per 100 km Auxiliary criterion to compare the Capital investments rubles & euro per thousand 2 technologies per unit m3 per 100 km IRR of commercial efficiency 3 12 % to calculate transport tariff 4 Discount rate 10 % 5 Customs duty for CNG natural gas 30 % 6 Customs duty for LNG 0 % 7 Income Tax 20 % 8 VAT 18 % 2016 – 1.3% 2017 – 1.6% 9 Property tax % 2018 – 1.9% 2019 and so forth – 2.2% 10 Investment period 4 years 1st year – 5% 2nd year – 15% 3rd year – 50% Investment schedule (investment 11 4th year – 30% % distribution by years) Commencement of commercial operation – from the 5th year

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The 1st year of commer- cial operation (the 5th Dynamics of gas transportation 12 year since the invest- volumes ment beginning) – 100% and so forth 13 Commercial operation period 25 years 14 Depreciation period 25 years 15 Depreciation type linear 16 Calculation currency ruble & euro 17 Currency rate 79.64 ruble/euro 18 Level of prices As of 01/01/2016 19 Recalculation to prices of 2016 using deflator indices 20 Inflation accounting not taken into account calculation in actual prices

Capital investments and operating costs are determined along the whole technological chain; the structure of costs per object is represented. The base cost estimates are set on the basis of the similar projects adjusted to a common price level of 2016 using the deflator indices. The list of the designed facilities for the technologies under consideration is presented in Table 2.2.

Таблица 2.2. List of the designed objects Gas pipeline Technology Technology Objects list Offshore Onshore of LNG of CNG Fuel Gas System + - - - Main gas pipeline + + - - Gas pipeline branch - - + + GCS/BCS + + - + Export terminal - - + + Import terminal + - + + LNG plant - - + - Harbour and harbour fleet - - + + LNG ships - - + - CNG ships - - - +

1. Gas preparation for LNG technology is accounted for as part of LNG plant facilities and is not considered separately;

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2. The import terminal for LNG technology includes regasification; 3. Bottom dredging and a breakwater may be provided in the structure of facilities of the export and import terminals. For the purposes of these calculations, costs for dredging and breakwaters are not taken into account; 4. Export/import of a buoy type or from a fixed berth may be provided. For the purposes of these calculations, a range is provided that includes both these types.

2.4. Systematization of Options for Multi-Choice Calculations to Analyze Effectiveness of Technologies for Offshore Transportation of Natural Gas

The distances and volumes of natural gas transportation analyzed in this paper research are presented in Table 2.3.

Table 2.3. Distances and volumes of transportation Volume of transportation, million tons/year 1 3 5 7,5 10 15 Distance, km Volume of transportation, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 + + + + + + 1000 + + + + + + 2000 + + + + + + 3000 + + + + + + 4000 + + + + + + 5000 + + + + + +

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2.5. Characteristics of Technical Solutions for Natural Gas Transportation

2.5.1. Characteristics of Usage of an Onshore Gas Pipeline

Tables 2.4-2.9 show technical solutions for the onshore gas pipeline

Table 2.4. Performance characteristics Path length is 300 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.448 4.326 7.209 10.814 14.411 21.602 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.008 0.016 0.029 0.034 0.041 0.052 billion m3/year Line pipe • Operating pressure, MPa 7.4 7.4 7.4 9.8 9.8 9.8 • Pipe diameter Dn, mm 500 800 1000 1000 1000 1200 Number of GCS, pcs 1 1 1 1 1 1 Number of gas compressor units (oper. + backup), pcs 1+1 1+1 2+1 2+1 2+1 2+1 Installed GCS capacity, total, MW 12.6 20 30 30 48 48 • GCU-6.3 12.6 - - - - - • GCU-10 - 20 30 30 - - • GCU-16 - - - - 48 48

Table 2.5. Performance characteristics Path length is 1000 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.457 4.344 7.240 10.850 14.445 21.647 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.017 0.034 0.060 0.070 0.075 0.097 billion m3/year Line pipe • Operating pressure, MPa 7.4 7.4 7.4 9.8 9.8 9.8 • Pipe diameter Dn, mm 500 800 1000 1000 1200 1400 Number of GCS, pcs 2 2 2 2 2 2

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Number of gas compressor units (oper. + backup), pcs 2+2 2+2 4+2 4+2 4+2 4+2 Installed GCS capacity, total, MW 25.2 40 60 60 96 96 • GCU-6.3 25.5 - - - - - • GCU-10 - 40 60 60 - - • GCU-16 - - - - 96 96

Table 2.6. Performance characteristics Path length is 2000 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.476 4.378 7.292 10.944 14.501 21.737 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.036 0.068 0.112 0.164 0.131 0.187 billion m3/year Line pipe • Operating pressure, MPa 7.4 7.4 7.4 9.8 9.8 9.8 • Pipe diameter Dn, mm 500 800 1000 1000 1200 1400 Number of GCS, pcs 4 4 4 4 3 3 Number of gas compressor units (oper. + backup) 4+4 4+4 8+4 8+4 6+3 6+3 Installed GCS capacity, total, MW 50.4 80 120 156 144 176 • GCU-6,3 50.4 - - - - - • GCU-10 - 80 120 60 - - • GCU-16 - - - 96 144 176

Table 2.7. Performance characteristics Path length is 3000 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.496 4.413 7.346 11.052 14.588 21.870 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.056 0.103 0.166 0.272 0.218 0.320 billion m3/year Line pipe • Operating pressure, MPa 7.4 7.4 7.4 9.8 9.8 9.8 • Pipe diameter Dn, mm 500 800 1000 1000 1200 1400 Number of GCS, pcs 6 6 6 6 5 5

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Number of gas compressor units (oper. + backup), pcs 6+6 6+6 12+6 12+6 10+5 14+5 Installed GCS capacity, total, MW 75.6 120 180 270 240 336 • GCU-6,3 75.6 - - - - - • GCU-10 - 120 180 30 - - • GCU-16 - - - 240 240 336

Table 2.8. Performance characteristics Path length is 4000 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.515 4.448 7.402 11.150 14.676 21.998 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.075 0.138 0.222 0.370 0.306 0.448 billion m3/year Line pipe • Operating pressure, MPa 7.4 7.4 7.4 9.8 9.8 9.8 • Pipe diameter Dn, mm 500 800 1000 1000 1200 1400 Number of GCS, pcs 8 8 8 8 7 7 Number of gas compressor units (oper. + backup), pcs 8+8 8+8 16+8 16+8 14+7 20+7 Installed GCS capacity, total, MW 100.8 160 240 366 336 432 • GCU-6,3 100.8 - - - - - • GCU-10 - 160 240 30 - - • GCU-16 - - - 336 336 432

Table 2.9. Performance characteristics Path length is 5000 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.534 4.483 7.461 11.256 14.757 22.129 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.094 0.173 0.281 0.476 0.387 0.579 billion m3/year Line pipe • Operating pressure, MPa 7.4 7.4 7.4 9.8 9.8 9.8 • Pipe diameter Dn, mm 500 800 1000 1000 1200 1400 Number of GCS, pcs 10 10 10 10 9 9

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Number of gas compressor units (oper. + backup), pcs 10+10 10+10 20+10 20+10 18+9 26+9 Installed GCS capacity, total, MW 126 200 300 462 432 560 • GCU-6,3 126 - - - - - • GCU-10 - 200 300 30 - - • GCU-16 - - - 432 432 560

2.5.2. Characteristics of Usage of an Offshore Gas Pipeline

Tables 2.10-2.12 show technical solutions for the offshore gas pipeline.

Table 2.10. Performance characteristics Path length is 300 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.459 4.339 7.235 10.852 14.465 21.687 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.019 0.029 0.055 0.072 0.095 0.137 billion m3/year Line pipe • Operating pressure, MPa 15.0 13.0 14.0 14.0 15.0 16.0 • Pipe diameter Dn, inches 14 22 26 30 33 38 • Pipe wall thickness, mm 11.0 11.0 13.0 15.0 17.0 21.0 • Concrete cover thickness, mm 40.0 40.0 40.0 40.0 40.0 40.0 Onshore GCS Number of GCS, pcs 1 1 1 1 1 1 Number of gas compressor units (oper. + backup), pcs 2+2 2+2 4+2 4+2 4+2 6+2 Installed GCS capacity, total, MW 25.2 40 60 60 96 128 • GCU-6,3 25.2 - - - - - • GCU-10 - 40 60 60 - - • GCU-16 - - - - 96 128

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Table 2.11. Performance characteristics Path length is 1000 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.460 4.365 7.260 10.868 14.462 21.685 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.020 0.055 0.080 0.088 0.092 0.135 billion m3/year Line pipe • Operating pressure, MPa 24.0 22.0 20.0 17.0 16.0 15.0 • Pipe diameter Dn, inches 14 22 28 35 40 48 • Pipe wall thickness, mm 18.0 17.0 19.0 20.0 22.0 24.0 • Concrete cover thickness, mm 50.0 50.0 50.0 50.0 50.0 50.0 Onshore GCS Number of GCS, pcs 1 1 1 1 1 1 Number of gas compressor units (oper. + backup), pcs 2+2 4+2 6+2 4+2 4+2 6+2 Installed GCS capacity, total, MW 25.2 60 80 96 96 128 • GCU-6,3 25.2 - - - - - • GCU-10 - 60 80 - - - • GCU-16 - - - 96 96 128

Table 2.12. Performance characteristics Path length is 2000 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Output, billion m3/year • Gross 1.481 4.421 7.342 10.957 14.557 21.824 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.041 0.111 0.162 0.177 0.187 0.274 billion m3/year Line pipe • Operating pressure, MPa 24.0 22.0 20.0 17.0 16.0 15.0 • Pipe diameter Dn, inches 14 22 28 35 40 48 • Pipe wall thickness, mm 18.0 17.0 19.0 20.0 22.0 24.0 • Concrete cover thickness, mm 50.0 50.0 50.0 50.0 50.0 50.0 Onshore GCS Number of GCS, pcs 1 1 1 1 1 1 Number of gas compressor units (oper. + backup), pcs 2+2 4+2 6+2 4+2 4+2 6+2

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Installed GCS capacity, total, MW 25.2 60 80 96 96 128 • GCU-6,3 25.2 - - - - - • GCU-10 - 60 80 - - - • GCU-16 - - - 96 96 128 In-house needs of the GCS, billion m3/year 0.021 0.056 0.082 0.089 0.095 0.139 GCS on the platform Number of GCS, pcs 1 1 1 1 1 1 Number of gas compressor units 2+2 4+2 6+2 4+2 4+2 6+2 (oper. + backup), pcs Installed GCS capacity, total, MW 25.2 60 80 96 96 128 • GCU-6,3 25.5 - - - - - • GCU-10 - 60 80 - - - • GCU-16 - - - 96 96 128 In-house needs of the GCS, billion m3/year 0.020 0.055 0.080 0.088 0.092 0.135

2.5.3. Characteristics of Marine Transportation of Liquefied Gas

Tables 2.13-2.14 show technical solutions for a gas pipeline branch to a LNG plant and from a regasification terminal.

Table 2.13. Performance characteristics of the gas pipeline branch to the LNG plant Operating pressure is 7,4 MPa. Length is 5 km Volume, million tons Characteristic name 1 3 5 7.5 10 15 Volume of gas, billion m3 per year 1.56 4.68 7.80 11.70 15.59 23.39 Pipe diameter Dn, mm 300 500 700 800 1000 1000 Pipe wall thickness, mm 4.0 6.6 8.9 10.1 12.6 12.6

Table 2.14. Performance characteristics of the gas pipeline branch from the import terminal. Operating pressure is 5,4 MPa Length of the offshore section is 8 km, length of the onshore section is 2 km Volume, million tons Characteristic name 1 3 5 7.5 10 15 Volume of gas, billion m3 per year 1.44 4.31 7.18 10.78 14.37 21.55 Pipe diameter Dn, mm 400 700 700 900 (36”) 1000 1200 Pipe wall thickness, mm 7.0 10.0 10.0 12.0 13.5 16.0

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The LNG export system includes the following main components: • Loading berths for LNG ships; • Loading arms to export LNG and to import stripping gas; • Cryogenic pipeline from the LNG storage system to the jetty head of the LNG loading berth with loading arms to export LNG and to import stripping gas; • Stripping gas pipe line from the LNG tank battery (storage) and from gas tankers during their loading to a stripping gas compressor station and to a low-pressure flare to discharge the stripping gas. A handling terminal of one loading berth consists of the following main components: • Two loading arms to export LNG; • One loading arm to return the stripping gas; • One loading arm of dual purpose; • General electrohydraulic control unit for the loading arms. The loading arm diameter should provide the required costs for injection of the LNG into a gas carrier ship. The loading arm diameter is determined depending on consumption of the LNG to be reloaded, which in turn depends on the cargo capacity of the LNG ship where the LNG is being shipped to. The loading arm dimensions and its operating area depend on the ship freight space, the ship board height, the berth height and the state of the sea. These characteristics are calculated by the loading arm manufacturer based on the transmitted initial data of the parameters of used ships and loading berths. Depending on the freight space and category of the LNG carrier ships, marine LNG transshipping loading arms of the appropriate size should be installed at the berthing facilities. To select the preferred technology, the following technologies to liquefy natural gas are considered: • Cooling by mixed refrigerant with preliminary propane cooling (C3MR); • Double circuit cooling by mixed refrigerant DMR; • Double circuit system with mixed refrigerant Liquefin™; • Optimized classical cascade operation (CO); • Cascade process using mixed refrigerant (MFC). As part of the previous work of JSC Giprospetsgaz "Pre-Investment Feasibility Study of the Project for Construction of a LNG Plant in the Leningrad Region (Baltic LNG)," the existing technologies to liquefy natural gas were analyzed thoroughly. Within the scope of this work, the criterial analysis of gas liquefaction technologies was executed for various parameters. Based on the analysis results, the C3MR liquefaction process was chosen as a basic option due to its ease of operation, extensive experience of application as well as lower technological and financial risks. In addition, this technology is flexible in terms of productivity and its usage is possible at all the LNG plant production facilities in

98 CHAPTER 2 question. For the considered options for offshore LNG transportation, the following number of loading berths will be required: • For LNG production from 1 to 7.5 million tons/year, 1 loading berth will be sufficient; • For LNG production of 10 million tons/year, 1 or 2 loading berths may be required, depending on the LNG transportation distance. More detailed calculations are needed; • For productivity of 15 million tons/year, 2 loading berths will be required. For the considered volumes and distances, LNG is transported by the gas carrier ships. In the calculations, current gas carrier ships with age of no more than 20 years and with cargo capacities of 19,100 m3, 31,000 m3, 65,000 m3, 130,400 m3, 149,700 m3, and 170,000 m3 were used. The estimated number of LNG carrier ships is calculated by the formula:

/1* VK (8) /1* \U

Nsh. – estimated number of ships;

QLNG – total annual volume of LNG produced;

qLNG – LNG density;

Vyr. – maximum LNG volume that one gas carrier ship can transport within a year. As a rule, the obtained number of ships is fractional. To get an integer value, the resulting number of the gas carrier ships should be rounded up. The volume that one gas carrier ship can transport within a year is defined as the ship volume multiplied by the possible number of the ship round trips during the year and is calculated by the formula:

\U VK (9) UW

Trt – time of a round trip of the gas carrier ship;

Vsh – capacity of the gas carrier ship. To determine the time of the round trip of the gas carrier ship, it is required to sum all the time components of the round trip. The time spent by the gas carrier ship for the round trip is calculated by the formula:

VDLO ORDG GLV PU XQO GLV PU (10)

Тload – time to load the gas carrier ship,

Тdis1 – time for disconnection from the LNG plant berth and for related operations, – ratio of the distance to the ship velocity, i.e., the time of the sea passage of the gas carrier ship,

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Tmr1 – time for mooring and related operations at a discharge port,

Тunl – time of unloading the gas carrier ship,

Тdis2 – time for disconnection and related operations at the discharge port,

Тmr2 – time for mooring to the LNG plant and for related operations. Equation (3) takes into account operations both at the loading port and at the destination port. Duration of loading (unloading) of the gas carrier ship is defined as the ratio of the useful volume of the gas carrier ship to the productivity of LNG pumps and is calculated by the formula:

JDVBFDUULHU ORDG (11) SXPS The estimated number of gas carrier ships required to transport the specified LNG volume to the specified distance is determined by calculating successively the values in accordance with formulas (11), (10), (9) and (8). The required number of the gas carrier ships will be obtained by rounding the value obtained by formula (1) up. This calculation technique is provided in simplified form and does not take into account possible delays in the ship route. Possible delays in the route due to severe climatic conditions or other reasons should be taken into account at more detailed stages of calculation by adding additional terms into equation (3). Probabilistic duration and frequency of delays are determined individually for each specific transportation route. Since this technique is designed to perform simplified calculations, it also does not take into account LNG losses during transportation due to evaporation in the ship cargo tanks. At the same time, it can be noted that the calculated value of the LNG evaporation during transportation is about 0.1% of the total transported LNG volume and cannot significantly affect the estimated quantity of the ships. The initial data used to calculate the required number of LNG carrier ships for all possible options under consideration is presented in Tables 2.15-2.16.

Table 2.15. Initial data of calculations for all options No. Parameter Value Designation

1 LNG plant efficiency, million tons/year 1 - 15 QLNG 3 2 LNG density, tons/m 0.43 qLNG 3 Ship velocity, km/h 32.41 υ Time for disconnection from the LNG plant and for related 4 4.5 T operations, h dis1 Time for mooring and related operation in the destination 5 10.5 T point, h mr1

3 6 Productivity of LNG pumps, м /ч * Qpump

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Time for disconnection and related operation in the destina- 7 6.5 T tion point, h dis2 Time for mooring to the LNG plant and for related 8 10.5 T operations, h mr2 9 Distance to LNG consumers, km 300 – 5 000 L

* he productivity of LNG pumps depends on the ship volume (Table 2.16).

Table 2.16. Productivity of LNG pumps depending on the ship volume Productivity of LNG pumps, Time to load (unload) No. Gas carrier ship volume, m3 m3/h the ship, h 1 19 100 2 300 8.3 2 31 000 4 400 7.0 3 65 000 5 500 11.8 4 130 400 10 100 12.9 5 149 700 11 400 13.1 6 170 000 12 800 13.3

The estimated quantity and cargo capacity of the LNG carrier ships are given in table 2.17. For some volumes and distances of LNG transportation, two alternative options to use the gas carrier ships with different cargo capacities are provided.

2.5.4. Characteristics of Marine Transportation of Compressed Gas

A CNG export system includes: • Loading arms to export high-pressure CNG; • Pipeline from the CNG production plant to the jetty head for export of CNG with the CNG loading arms. Handling terminal of one loading berth consists of the following main components: • High-pressure loading arms to export CNG; • General electrohydraulic control unit for the loading arms.

101 CHAPTER 2 3 3 3 3 3 3 3 or 5000 2 х 65 000 m 1 х 130 400 m 2 х 149 700 m 3 х 170 000 m 6 х 170 000 m 9 х 170 000 m 5 х 149 700 m 3 3 3 3 3 3 3 or 4000 2 х 65 000 m 1 х 130 400 m 2 х 130 400 m 3 х 149 700 m 4 х 170 000 m 5 х 170 000 m 8 х 170 000 m 3 3 3 3 3 3 3000 1 х 65 000 m 2 х 130 400 m 2 х 170 000 m 3 х 170 000 m 4 х 170 000 m 6 х 170 000 m 3 3 3 3 3 3 3 or 2000 1 х 65 000 m 2 х 31 000 m 1 х 149 700 m 2 х 130 400 m 3 х 130 400 m 3 х 170 000 m 5 х 149 700 m Distance to LNG consumer, km consumer, LNG to Distance 3 3 3 3 3 3 3 Estimated number and cargo and the ships capacity number Estimated or 1000 1 х 31 000 m 2 х 65 000 m 1 х 130 400 m 1 х 170 000 m 2 х 130 400 m 2 х 170 000 m 3 х 170 000 m 3 3 3 3 3 3 3 or 300 1 х 19 100 m 2 х 65 000 m 1 х 65 000 m 1 х 170 000 m 2 х 170 000 m 1 х 130 400 m 2 х 130 400 m Table 2.17. Estimated number and cargo capacity of the LNG carrier the LNG ships cargo and of capacity number 2.17. Estimated Table 1 3 5 15 10 7.5 Plan productivity, million tons/year productivity, Plan

102 CHAPTER 2

Table 2.18. Performance characteristics of the gas pipeline branch to export CNG Length of the section up to the GCS as well as after it is 5 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Production, billion m3/year • Gross 1.465 4.379 7.290 10.932 14.569 21.839 • Commodity 1.442 4.316 7.190 10.793 14.385 21.572 In-house needs of the gas pipeline, 0.023 0.063 0.100 0.139 0.184 0.267 billion m3/year Line pipe Section up to the GCS • operating pressure, MPa 9.8 9.8 9.8 9.8 9.8 9.8 • Pipe diameter Dn, inches 500 500 700 700 800 1000 • Pipe wall thickness, mm 8.7 8.7 11.8 11.8 13.4 16.7 Section after the GCS • operating pressure, MPa 26.0 26.0 26.0 26.0 26.0 26.0 • Pipe diameter Dn, mm 500 500 500 700 700 800 • Pipe wall thickness, mm 18.0 18.0 18.0 24.0 24.0 27.5 Number of GCS, pcs 1 1 1 1 1 1 Number of gas compressor units (oper. + backup), pcs 4+2 4+2 6+2 6+2 6+2 8+2 Installed GCS capacity, total, MW 60 60 80 128 200 250 • GCU-6,3 ------• GCU-10 60 60 80 - - - • GCU-16 - - - 128 - - • GCU-25 - - - - 200 250

Table 2.19. Performance characteristics of the gas pipeline branch to import CNG Length is 5 km Volume, billion m3 Characteristic name 1.44 4.31 7.18 10.78 14.37 21.55 Production, billion m3/year • Gross 1.442 4.316 7.190 10.793 14.385 21.572 • Commodity 1.440 4.310 7.180 10.780 14.370 21.550 In-house needs of the gas pipeline, 0.002 0.006 0.010 0.013 0.015 0.022 billion m3/year Line pipe • operating pressure, MPa 25.0 25.0 25.0 25.0 25.0 25.0 • Pipe diameter Dn, inches 700 700 800 1000 1200 1400 • Pipe wall thickness, mm 23.5 23.5 26.5 33.0 39.0 45.0 Number of GCS, pcs 1 1 1 1 1 1

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Number of gas compressor units (oper. + backup), pcs 2+1 2+1 3+1 3+1 3+1 3+1 Installed GCS capacity, total, MW 30 30 40 64 64 100 • GCU-6,3 ------• GCU-10 30 30 40 - - - • GCU-16 - - - 64 64 - • GCU-25 - - - - - 100

For the volumes and distances in question, CNG transportation by the ships with cargo capacity 22,5 million m3 was calculated. The cargo capacity and characteristics of the CNG gas carrier ships were used in accordance with the previous work of JSC Giprospetsgaz "Technical and economic analysis of options to create Gazprom own facilities for export of compressed natural gas and/or to liquefy gas in the Russian Far East. Volume 5. Marine freight of compressed and liquefied gas."

Methodology to calculate the number of the CNG carrier ships

The estimated number of the CNG carrier ships is calculated by the formula:

&1* VK (12) \U

QCNG – total annual volume of CNG produced;

VYR – maximum CNG volume that one gas carrier ship can transport within a year; «+1» – one additional ship required to ensure the condition of continuity of CNG loading and unloading that is specified in the task for calculations. Based on this requirement, at least one gas carrier ship must be continuously present both at the loading and unloading. At least one more gas carrier ship must be on the way at this time. So, the minimum number of the gas carrier ships is three. As a rule, the obtained number of ships is fractional. To get an integer value of the gas carrier ships, the resulting number should be rounded up. In the case of transportation of small volumes of gas (1.44 billion m3/year), intermittent loading of the system may be considered. For the intermittent loading of the CNG ship, it is assumed that the gas compressor station capacity is 4.31 billion m3/year (3 million tons/year) that reduces the ship loading time by three times. The ship number is calculated for the annual transportation volume of 1.44 billion m3/year (1 million tons/year). For this option, it doesn‘t need to add one ship to provide loading continuity. After the loading of the ship is finished, the shutdown valve on the offshore gas pipeline branch closes, the gas compressor station stops operating, and the operating gas compressor units are switched to the hot standby mode. Excess gas, which is generated during equipment downtime, is distributed over the

104 CHAPTER 2 existing gas transmission system (GTS). If there is a large underground gas storage facility (UGSF) near the CNG export system, the gas is injected into the UGSF. The volume that one gas carrier ship can transport within a year is defined as the ship volume multiplied by the possible number of the ship round trips during the year and is calculated by the formula:

\U JDVBFDUULHU UW (13)

Trt – time of a round trip of the gas carrier ship;

Vgas_carrier – capacity of the gas carrier ship. To determine the time of the round trip of the CNG carrier ship, it is required to sum all the time components of the round trip. The time spent by the gas carrier ship for the round trip is calculated by the formula:

UW ORDG GLV PU XQO GLV PU (14)

Тload – time to load the gas carrier ship,

Тdis1 – time for disconnection from the CNG plant berth and for related operations, – ratio of the distance to the ship velocity, i.e., the time of the sea passage of the gas carrier ship,

Tmr1 – time for mooring and related operations at a discharge port,

Тunl – time of unloading the gas carrier ship,

Тdis2 – time for disconnection and related operations at the discharge port,

Тmr2 – time for mooring to the CNG plant and for related operations. Equation (14) takes into account operations both at the loading port and at the destination port. According to the task conditions, the duration of loading is assumed to be equal to the unloading capacity of the CNG carrier ship and is calculated by the formula:

JDVBFDUULHUJDVBFDUULHU ORDG &1* &1* (15)

Vgas_carrier – ratio of useful volume of the gas carrier ship to the hourly rate of the gas compression facilities (CNG consumption volume). The estimated number of gas carrier ships required to transport the specified CNG volume to the specified distance is determined by calculating successively the values in accordance with formulas (15), (14), (13) and (12). The required number of the gas carrier ships will be obtained by rounding the value obtained by formula (12) up.

Note: The developed methodology allows us to calculate the number of the ships only with a relatively large mistake. For the calculations of the CNG transportation, the following

105 CHAPTER 2 assumptions were used, which changes may significantly affect the final calculation results due to uncertainty of many parameters: • Values of durations for loading and unloading the CNG carrier ship were assumed to be equal; • Duration of loading and unloading was determined based on the total capacity of gas compression facilities; • Assumption was used that the ship is unloaded evenly and completely. To determine the initial data that can significantly affect both the choice of an approach to calculations of the required number of the ships and the calculation results, it is necessary to know at least the following parameters of the CNG loading and unloading systems: • Diameter of the pipeline used to feed the CNG in the loading port; • Pressure and temperature in the export pipeline; • Availability and productivity of gas heaters on the export pipeline; • Number and diameter of the ship inlet and outlet flanges. Due to the fact that there are no such CNG carrier ships of this size, the exact number of the inlet and outlet flanges that can be installed on the CNG ship, is not known reliably. Without these values, it is not possible to determine accurately the loading and unloading duration for the CNG carrier ships, since loading/unloading operations can be performed both at one berth into one gas carrier ship using one or more loading arms and at several berths into several gas carrier ships gas using only one or more loading arms for each ship; • Pressure in the ship storage system: there are at least 3 projects of the CNG carrier ships with pressures in the range from 140 atm up to 275 atm; • Number of import and export loading arms and berths (related with the previous question); • Temperature restrictions in the ship and onshore gas loading/unloading systems; • Diameter of the import pipeline at the discharge port; • Presence of gas compressor facilities and heaters both in the ship and in the import terminal (for unloading); • Pressure and temperature in the import pipeline at the discharge port. Only if this information is available, it will be possible to simulate gas-dynamic processes of CNG loading and unloading and to determine accurately the duration of loading/unloading operations. The estimated number of the ships to transport CNG with cargo capacity of 22.5 million m3 is given in Table 2.20.

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Table 2.20. Estimated number of CNG ships with cargo capacity of 22.5 million m3 to ensure continuous gas supply to consumers Distance to LNG consumer, km Plant productivity, Minimum number of 300 1000 2000 3000 4000 5000 million tons/year berths to unload ships Estimated number of ships 1.44 2 2 2 3 3 4 4 4.31 2 5 6 7 8 10 11 7.18 2 5 7 9 11 14 16 10.78 2 6 9 12 15 19 22 14.37 3 7 10 15 19 24 28 21.55 3 9 14 20 27 34 41

Characteristics of the CNG ship with net cargo capacity of 22.5 million st.m3 (based on the Knutsen PNG project) are given in table 2.21.

Table 2.21/ Characteristics of the CNG ship with net cargo capacity of 22.5 million st.m3 (based on the Knutsen PNG project) Ship parameter Value Overall length ~ 309 m Width 52,6 m Theoretical board height ~ 23 m Extreme draft (approximate) 15,5 m Number of tanks (tank geometric volume is 3245 29.2 m3, its length is 37 m) Net cargo capacity for unloading 22,5 million st.m3 Category of ice reinforcement Ice 2 Main propulsion unit 2 × 17 500 kW Number of crew 20 people Rate of sailing for clear water 17,5 knots Fuel consumption at sea passage (heavy fuel) 160 tons/day Fuel consumption at berth 5 tons/day

CNG is transported at normal gas temperature in absolutely sealed tanks under high pressure. There are no losses of CNG during transportation. CNG losses can occur only in emergencies.

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2.6. Capital Investments into Implementation of Technical Solutions for Natural Gas Transportation

2.6.1. Capital Investments into the Onshore Pipeline

Tables 2.22-2.29 show the total capital investments and capital investments per unit for various options.

Table 2.22. Capital investments Distance is 300 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 409 496 619 619 669 782 Line pipe million euro 352 424 511 511 562 674 Gas compressor stations million euro 57 72 108 108 107 107 Capital investments billion rubles 33 40 49 49 53 62 Line pipe billion rubles 28 34 41 41 45 54 Gas compressor stations billion rubles 5 6 9 9 9 9

Table 2.23. Capital investments Distance is 1000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 1 288 1 558 1 920 2 088 2 462 2 837 Line pipe million euro 1 174 1 415 1 704 1 873 2 248 2 622 Gas compressor stations million euro 114 144 215 215 215 215 Capital investments billion rubles 103 124 153 166 196 226 Line pipe billion rubles 94 113 136 149 179 209 Gas compressor stations billion rubles 9 11 17 17 17 17

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Table 2.24. Capital investments Distance is 2000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 2 576 3 116 3 839 4 176 4 817 5 638 Line pipe million euro 2 348 2 829 3 408 3 746 4 495 5 245 Gas compressor stations million euro 228 287 431 430 322 394 Capital investments billion rubles 205 248 306 333 384 449 Line pipe billion rubles 187 225 271 298 358 418 Gas compressor stations billion rubles 18 23 34 34 26 31

Table 2.25. Capital investments Distance is 3000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 3 865 4 674 5 759 6 263 7 280 8 619 Line pipe million euro 3 522 4 244 5 113 5 618 6 743 7 867 Gas compressor stations million euro 343 431 646 644 537 751 Capital investments billion rubles 308 372 459 499 580 686 Line pipe billion rubles 281 338 407 447 537 627 Gas compressor stations billion rubles 27 34 51 51 43 60

Table 2.26. Capital investments Distance is 4000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 5 153 6 232 7 679 8 350 9 742 11 456 Line pipe million euro 4 696 5 658 6 817 7 491 8 990 10 490 Gas compressor stations million euro 457 574 862 859 751 966

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Capital investments billion rubles 410 496 612 665 776 912 Line pipe billion rubles 374 451 543 597 716 835 Gas compressor stations billion rubles 36 46 69 68 60 77

Table 2.27. Capital investments Distance is 5000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 6 441 7 791 9 598 10 438 12 204 14 364 Line pipe million euro 5 870 7 073 8 521 9 364 11 238 13 112 Gas compressor stations million euro 571 718 1 077 1 074 966 1 252 Capital investments billion rubles 513 620 764 831 972 1 144 Line pipe billion rubles 468 563 679 746 895 1 044 Gas compressor stations billion rubles 45 57 86 86 77 100

Table 2.28. Capital investments per unit, euro/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 0.95 0.38 0.29 0.21 0.16 0.12 1000-5000 0.89 0.36 0.27 0.19 0.17 0.13

Table 2.29. Capital investments per unit, euro/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 75.46 30.56 22.89 16.49 12.36 9.63 1000-5000 71.25 28.79 21.29 15.42 13.53 10.62

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2.6.2. Capital Investments into the Offshore Gas Pipeline

Tables 2.30-2.34 show the total capital investments and capital investments per unit for various options.

Table 2.30. Capital investments Distance is 300 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 1432 1554 1721 1837 1952 2259 Line pipe million euro 1276 1312 1351 1397 1442 1538 Gas compressor stations million euro 157 242 370 440 510 722 Capital investments billion rubles 114 124 137 146 155 180 Line pipe billion rubles 102 105 108 111 115 122 Gas compressor stations billion rubles 12 19 29 35 41 57

Table 2.31. Capital investments Distance is 1000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 2826 3155 3498 3727 4041 4624 Line pipe million euro 2670 2841 3056 3287 3531 3903 Gas compressor stations million euro 157 314 442 440 510 722 Capital investments billion rubles 225 251 279 297 322 368 Line pipe billion rubles 213 226 243 262 281 311 Gas compressor stations billion rubles 12 25 35 35 41 57

111 CHAPTER 2

Table 2.32. Capital investments Distance is 2000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Indicator name Unit Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Capital investments million euro 5105 5881 6610 7077 7636 8822 Line pipe million euro 4608 4951 5381 5843 6331 7074 Gas compressor stations million euro 497 929 1229 1234 1305 1748 Capital investments billion rubles 407 468 526 564 608 703 Line pipe billion rubles 367 394 429 465 504 563 Gas compressor stations billion rubles 40 74 98 98 104 139

Table 2.33. Capital investments per unit, euro/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 3.32 1.20 0.80 0.57 0.45 0.35 1000 1.96 0.73 0.49 0.35 0.28 0.21 2000 1.77 0.68 0.46 0.33 0.27 0.20

Table 2.34. Capital investments per unit, euro/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 264.03 95.75 63.65 45.25 36.06 27.83 1000 156.32 58.31 38.80 27.53 22.40 17.09 2000 141.17 54.33 36.66 26.14 21.16 16.30

112 CHAPTER 2

2.6.3. Capital Investments into Marine Transportation of Liquefied Natural Gas

Tables 2.35-2.38 show the total capital investments and capital investments per unit for various options.

Table 2.35. Capital investments in million euro Transportation volume, million tons/year 1.0 3.0 5.0 7.5 10.0 15.0 Supply pipeline (to the complex) 4 6 7 7 9 9 Complex for LNG production, storage and export 950 2 375 3 085 3 857 4 602 6 119 LNG ships Path length is 300 km 79 182 219 243 438 487 Path length is 1000 km 116 219 243 438 487 730 Path length is 2000 km 182 227 438 658 730 1137 Path length is 3000 km 182 438 487 730 974 1460 Path length is 4000 km 219 438 682 974 1217 1947 Path length is 5000 km 219 455 730 1217 1460 2190 Regasification terminal 224 673 1 122 1 683 2 244 3 365 Gas pipeline branch (from the terminal) 11 14 14 16 18 19

Table 2.36. Capital investments in billion rubles Transportation volume, million tons/year 1.0 3.0 5.0 7.5 10.0 15.0 Supply pipeline (to the complex) 0.3 0.5 0.5 0.6 0.7 0.7 Complex for LNG production, storage and export 75.6 189.1 245.7 307.2 366.5 487.3 LNG ships 0.0 0.0 0.0 0.0 0.0 0.0 Path length is 300 km 6.3 14.5 17.5 19.4 34.9 38.8 Path length is 1000 km 9.2 17.5 19.4 34.9 38.8 58.1 Path length is 2000 km 14.5 18.1 34.9 52.4 58.1 90.5 Path length is 3000 km 14.5 34.9 38.8 58.1 77.5 116.3 Path length is 4000 km 17.5 34.9 54.3 77.5 96.9 155.1 Path length is 5000 km 17.5 36.2 58.1 96.9 116.3 174.4 Regasification terminal 17.9 53.6 89.3 134.0 178.7 268.0 Gas pipeline branch (from the terminal) 0.9 1.1 1.1 1.3 1.4 1.5

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Table 2.37. Capital investments per unit, euro/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 2.93 2.51 2.06 1.80 1.70 1.55 1000 0.91 0.76 0.62 0.56 0.51 0.48 2000 0.48 0.38 0.32 0.29 0.26 0.25 3000 0.32 0.27 0.22 0.19 0.18 0.17 4000 0.24 0.20 0.17 0.15 0.14 0.13 5000 0.20 0.16 0.14 0.12 0.12 0.11

Table 2.38. Capital investments per unit, rubles/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 233.69 200.17 164.37 142.98 135.04 123.17 1000 72.16 60.73 49.58 44.34 40.78 37.85 2000 37.92 30.44 25.87 22.98 21.06 19.68 3000 25.28 21.59 17.43 15.50 14.49 13.52 4000 19.47 16.20 13.61 12.07 11.21 10.59 5000 15.57 13.02 11.00 9.90 9.24 8.65

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2.6.4. Capital Investments into Marine Transportation of Compressed Natural Gas

Tables 2.39-2.42 show the total capital investments and capital investments per unit for various options.

Table 2.39. Capital investments in million euro Productivity, million tons/year Indicator name 1.0 3.0 5.0 7.5 10.0 15.0 Supply pipeline 229 229 301 302 360 449 Line pipe 13 13 14 15 16 19 Gas compressor station 215 215 287 286 344 430 Export terminal 59 176 294 441 882 1322 CNG ships Path length is 300 km 586 1465 1465 1758 2051 2637 Path length is 1000 km 586 1758 2051 2637 2930 4103 Path length is 2000 km 879 2051 2637 3516 4396 5861 Path length is 3000 km 879 2344 3223 4396 5568 7912 Path length is 4000 km 1172 2930 4103 5568 7033 9963 Path length is 5000 km 1172 3223 4689 6447 8205 12015 Import terminal 59 176 294 441 882 1322 Outlet pipeline 116 116 152 154 157 188 Line pipe 8 8 9 11 13 16 Gas compressor station 108 108 144 143 143 172

Table 2.40. Capital investments in billion rubles Productivity, million tons/year Indicator name 1.0 3.0 5.0 7.5 10.0 15.0 Supply pipeline 18.2 18.2 24.0 24.0 28.7 35.7 Line pipe 1.1 1.1 1.1 1.2 1.3 1.5 Gas compressor station 17.2 17.2 22.9 22.8 27.4 34.3 Export terminal 4.7 14.0 23.4 35.1 70.2 105.3 CNG ships Path length is 300 km 46.7 116.7 116.7 140.0 163.4 210.0 Path length is 1000 km 46.7 140.0 163.4 210.0 233.4 326.7 Path length is 2000 km 70.0 163.4 210.0 280.1 350.1 466.8 Path length is 3000 km 70.0 186.7 256.7 350.1 443.4 630.1 Path length is 4000 km 93.4 233.4 326.7 443.4 560.1 793.5 Path length is 5000 km 93.4 256.7 373.4 513.4 653.5 956.8

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Import terminal 4.7 14.0 23.4 35.1 70.2 105.3 Outlet pipeline 9.2 9.2 12.1 12.3 12.5 15.0 Line pipe 0.6 0.6 0.7 0.9 1.1 1.3 Gas compressor station 8.6 8.6 11.4 11.4 11.4 13.7

Table 2.41. Capital investments per unit, euro/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 2.43 1.67 1.16 0.96 1.00 0.92 1000 0.73 0.57 0.43 0.37 0.36 0.37 2000 0.36 0.28 0.22 0.18 0.18 0.17 3000 0.31 0.24 0.20 0.18 0.18 0.17 4000 0.28 0.21 0.18 0.16 0.16 0.15 5000 0.23 0.18 0.16 0.14 0.15 0.14

Table 2.42. Capital investments per unit, rubles/thousand m3*km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 193.21 133.18 92.68 76.23 80.01 72.91 1000 57.96 45.37 34.30 29.36 28.87 27.29 2000 28.98 22.68 17.15 14.68 14.44 13.64 3000 24.72 18.73 15.77 14.12 14.50 13.79 4000 22.59 16.76 14.26 12.75 12.90 12.24 5000 18.08 14.49 12.71 11.50 11.62 11.31

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2.7. Tariffs for Gas Transportation

2.7.1. Tariffs for the Onshore Gas Pipeline

Tables 2.43-2.44 show tariffs for the gas transportation for various options.

Table 2.43. Transport tariff, euro/thousand m3 per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 25.1 10.2 7.7 5.6 4.2 3.3 1000 23.4 9.5 7.1 5.1 4.5 3.5 2000 23.4 9.5 7.1 5.1 4.4 3.4 3000 23.4 9.5 7.1 5.2 4.4 3.5 4000 23.4 9.5 7.1 5.2 4.5 3.5 5000 23.4 9.5 7.1 5.2 4.5 3.5

Fig. 2.5 Tariff for gas transportation

117 CHAPTER 2

Table 2.44. Transport tariff, rubles/m3 per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 2.0 0.8 0.6 0.4 0.3 0.3 1000 1.9 0.8 0.6 0.4 0.4 0.3 2000 1.9 0.8 0.6 0.4 0.4 0.3 3000 1.9 0.8 0.6 0.4 0.4 0.3 4000 1.9 0.8 0.6 0.4 0.4 0.3 5000 1.4 0.6 0.4 0.3 0.3 0.2

2.7.2. Tariffs for Offshore Gas Pipeline Tables 2.45-2.46 show tariffs for gas transportation.

Table 2.45. Transport tariff, euro/thousand 3m per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 85.9 31.5 21.3 15.2 12.2 9.6 1000 50.2 19.0 12.7 9.0 7.3 5.6 2000 45.7 17.9 12.1 8.6 7.0 5.4

Fig. 2.6. Tariff for gas transportation

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Table 2.46. Transport tariff, rubles/m3 per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 6.8 2.5 1.7 1.2 1.0 0.8 1000 4.0 1.5 1.0 0.7 0.6 0.4 2000 3.6 1.4 1.0 0.7 0.6 0.4

2.7.3. Characteristics of Marine Transportation of Liquefied Gas

Tables 2.47-2.48 show tariffs for gas transportation.

Table 2.47. Transport tariff, euro/thousand 3m per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 73.1 62.6 51.6 45.2 43.2 39.5 1000 22.8 19.1 15.6 14.2 13.1 12.2 2000 12.2 9.6 8.3 7.4 6.8 6.4 3000 8.1 6.9 5.6 5.0 4.8 4.5 4000 6.3 5.2 4.4 4.0 3.7 3.5 5000 5.1 4.2 3.6 3.3 3.1 2.9

Table 2.48. Transport tariff, rubles/m3 per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 5.8 5.0 4.1 3.6 3.4 3.1 1000 1.8 1.5 1.2 1.1 1.0 1.0 2000 1.0 0.8 0.7 0.6 0.5 0.5 3000 0.6 0.6 0.4 0.4 0.4 0.4 4000 0.5 0.4 0.4 0.3 0.3 0.3 5000 0.4 0.3 0.3 0.3 0.2 0.2

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Fig. 2.7. Tariff for gas transportation

2.7.4. Tariffs for Marine Transportation of Compressed Gas

Tables 2.49-2.50 show tariffs for the gas transportation for various options.

Table 2.49. Transport tariff, euro/thousand m3 per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 69.3 47.5 33.3 27.4 28.6 26.1 1000 20.8 16.1 12.2 10.5 10.3 9.7 2000 13.2 9.0 7.3 6.4 6.6 6.0 3000 8.8 6.6 5.6 5.0 5.1 4.9 4000 8.0 5.9 5.0 4.5 4.6 4.3 5000 6.4 5.1 4.5 4.1 4.1 4.0

Table 2.50. Transport tariff, rubles/m3 per 100 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Distance, km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 5.5 3.8 2.6 2.2 2.3 2.1 1000 1.7 1.3 1.0 0.8 0.8 0.8

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2000 1.1 0.7 0.6 0.5 0.5 0.5 3000 0.7 0.5 0.4 0.4 0.4 0.4 4000 0.6 0.5 0.4 0.4 0.4 0.3 5000 0.5 0.4 0.4 0.3 0.3 0.3

Fig. 2.8. Tariff for Gas Transportation

2.8. Matrix of Effectiveness: Comparison of Technologies by Economic Criteria

To determine preference areas for different technologies, the analysis (theoretical calculations) is executed for ranges of transportation volumes and distances. The calculation results are illustrated graphically. The areas are defined where the only technology is definitely preferable as well as the areas where, depending on the particular project conditions, one or the other (or even the third) technology may be preferable – so called "gray" areas. The main criterion to compare technologies is transport tariff (in rubles and euros per thousand cubic meters per 100 km). Tables 2.51-2.56 and Figures 2.9-2.14 show tariffs for gas transportation by the technologies.

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Table 2.51. Transport tariff, euro/thousand m3 per 100 km Path length is 300 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation technology Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Offshore pipeline gas transportation 85.9 31.5 21.3 15.2 12.2 9.6 Marine transportation of liquefied gas 73.1 62.6 51.6 45.2 43.2 39.5 Marine transportation of compressed gas 69.3 47.5 33.3 27.4 28.6 26.1

Fig. 2.9. Tariff for gas transportation by technology Path length is 300 km

Table 2.52. Transport tariff, euro/thousand 3m per 100 km Path length is 1000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation technology Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Offshore pipeline gas transportation 50.2 19.0 12.7 9.0 7.3 5.6 Marine transportation of liquefied gas 22.8 19.1 15.6 14.2 13.1 12.2 Marine transportation of compressed gas 20.8 16.1 12.2 10.5 10.3 9.7

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Fig. 2.10.Tariff for gas transportation by technology Path length is 1000 km

Table 2.53. Transport tariff, euro/thousand m3 per 100 km Path length is 2000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation technology Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Offshore pipeline gas transportation 45.7 17.9 12.1 8.6 7.0 5.4 Marine transportation of liquefied gas 12.2 9.6 8.3 7.4 6.8 6.4 Marine transportation of compressed gas 13.2 9.0 7.3 6.4 6.6 6.0

Fig. 2.11.Tariff for gas transportation by technology Path length is 2000 km

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Table 2.54. Transport tariff, euro/thousand m3 per 100 km Path length is 3000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation technology Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Offshore pipeline gas transportation ------Marine transportation of liquefied gas 8.1 6.9 5.6 5.0 4.8 4.5 Marine transportation of compressed gas 8.8 6.6 5.6 5.0 5.1 4.9

Fig. 2.12.Tariff for gas transportation by technology Path length is 3000 km

Table 2.55. Transport tariff, euro/thousand 3m per 100 km Path length is 4000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation technology Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Offshore pipeline gas transportation ------Marine transportation of liquefied gas 6.3 5.2 4.4 4.0 3.7 3.5 Marine transportation of compressed gas 8.0 5.9 5.0 4.5 4.6 4.3

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Fig. 2.13. Tariff for gas transportation by technology Path length is 4000 km

Table 2.56. Transport tariff, euro/thousand m3 per 100 km Path length is 5000 km Transportation volume, million tons/year 1 3 5 7.5 10 15 Transportation technology Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 Offshore pipeline gas transportation ------Marine transportation of liquefied gas 5.1 4.2 3.6 3.3 3.1 2.9 Marine transportation of compressed gas 6.4 5.1 4.5 4.1 4.1 4.0

When constructing the matrix of effectiveness, the preferential zones by technologies were determined using the graph-analytic method. As an example, Figure 2.15 shows the change of the gas transportation tariff depending on the gas volume transportation for the distance of 2000 km. In this case, the preferred technology changes at gas volumes of 3.2 billion m3/year (LNG/CNG) and of 16.6 billion m3/year (CNG/offshore gas pipeline). This data was used to determine the preference zones by technology. A similar analysis is made for other distances and gas volumes. The revenue structure that includes depreciation charges, operating costs, taxes and net profit is different for different technologies, leading to uneven decrease/increase of the tariffs for various transportation technologies with corresponding change in capital investments. Because of this unevenness, the preferential zones for the particular technology are shifted, causing appearance of an uncertainty zone. While reducing or increasing capital investments, the uncertainty zone between these

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Fig. 2.14. Tariff for gas transportation by technology Path length is 5000 km technologies is not emerged because the revenue structure for pipeline transportation technologies and CNG transportation technologies is similar. The LNG transportation technology has other revenue structure that is different from the previous two technologies, so the preferential zones shift when the capital investments are reduced or increased. The uncertainty zones are also determined using the graph-analytical method. Figure 2.16 shows, for example, the basic tariffs for gas transportation, depending on the

Fig. 2.15. Tariff for gas transportation by technology Path length is 2000 km

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Fig.2.16. Tariff for gas transportation by technology Path length is 2000 km gas transportation volume for distance of 2000 km as well as the corresponding tariffs for transportation for reducing capital investments by 10% and increasing by 30%. The volumes of gas that change the preferred technology changes for the given distance are 3.2, 2.9 and 3.7 billion m3/year, respectively, forming the uncertainty zone between the technologies of marine transportation of CNG and LNG. A similar analysis is made for other distances and gas volumes. Table 2.57 and Figure 2.17 show data for the preferred technology to transport gas, depending on the transportation volume and on the path distance (matrix of effectiveness).

Table 2.57. Matrix of Technology Effectiveness Transportation volume, million tons/year

Distance, 1 3 5 7.5 10 15 km Transportation volume, billion m3/year 1.44 4.31 7.18 10.78 14.37 21.55 300 CNG Pipeline Pipeline Pipeline Pipeline Pipeline 1000 CNG CNG CNG Pipeline Pipeline Pipeline 2000 LNG CNG CNG CNG CNG Pipeline

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3000 LNG CNG CNG CNG LNG LNG 4000 LNG LNG LNG LNG LNG LNG 5000 LNG LNG LNG LNG LNG LNG

Pipeline — offshore pipeline gas transportation CNG — marine transportation of compressed natural gas LNG — marine transportation of liquefied natural gas

Fig.2.17. Configuration of areas for effective usage of the gas transportation technologies

128 CHAPTER 3. SELECTING AN ALTERNATIVE METHOD FOR TRANSPORTING NATURAL GAS OVERSEAS IN TERMS OF THE POTENTIAL PROJECTS

Particular Black and Baltic Sea projects have been properly studied and valued in this paper. Various methods of transportation used to carry natural gas in the amount of 3 bn m3 and 5 bn m3 of the annual capacity have been discussed in details. The Russkaya compression station zone may be considered as a reference point for shipping gas through the Black Sea waters. Terminal points are to be at the areas of Bulgaria and Turkey. With natural gas transported through the Baltic Sea waters, the Portovaya or Slavyanskays CS zones may be used as reference points. It is assumed that natural gas may be delivered to Kaliningrad, to Germany, and to the UK. The diagram (Figure 2.11) that shows preferred gas transportation technologies specified depending on transport distance and volume to be used for plotting particular points referred to the projects discussed in this Section (Figure 3.1).

3.1. Analytical Review of Freight Traffic Flows in the Black and Baltic Sea Regions

Black Sea Though, the crisis has affected the Russian economy and there are some economic sanctions imposed on Russia by a number of countries, the Azov-Black Sea basin terminal operators successfully conduct their business in a regular manner and demonstrate quite a solid growth of transshipment cargo ratio. According the data reported by the Russian Maritime Ports Association32 at the end of 2015, the Azov-Black Sea basin freight turnover increased by 10.2%, as rated against 2014, and grew to 233.0 million tons. Among them, dry cargo vessels could carry 98.5 million tons (+21.5%) and tank vessels – 134.5 million tons (+3.2%). Principally, dry bulk vessel transshipment volume grew up at the expense of such products as grain – by 14.2%, ferrous metals – by 22.3%, freight ferries services – 3.0 times more, coal – by 19.2%, ore – by 37.8%, and non-ferrous metals – by 12.2%. At the same time, volume of cargo transferred in containers was reduced by 5.2%, mineral fertilizers – by 1.7%, sugar – by 21.5%, and scrap metal – by 12.2%. Liquid bulk cargo transshipment volume increased chiefly at the expense of such products as petrochemicals – by 5.5%, crude oil – by 1.5% and liquefied gas – 1.6 times more but food bulk cargo transshipment volume was reduced by 11.1%. The export share in the freight turnover is 66.1%, import share – 3.3%, transit share 32 http://transrussia.net

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– 18.9%, and cabotage – 11.7%. The freight turnover at Novorossiysk ports increased by 4.5% up to 127.1 million tons, at Caucasian ports – by 15.2% up to 30.5 million tons, at Tuapse ports – by 13.8% up to 25.2 million tons, at Taman ports – by 20.8% up to 12.3 million tons, at Rostov-on-Don ports – by 12.1% up to 11.6 million tons, at Azov ports – by 5.2% up to 7.1 million tons, at Temryuk ports – by 23.0% up to 2.5 million tons, and at Taganrog ports – by 7.9% up to 2.2 million tons. As for Yeysk ports, the fright carrying capacity was reduced by 2.8% down to 3.9 million tons. The tankers exporting oil and petrochemicals from the Russian ports (primarily, from Novorossiysk and Tuapse) and from the Georgian ports (Batumi) are substantially those Black Sea cargo carriers that demonstrate rather a significant transportation volume. However, the hydrocarbon export volumes are significantly restrained by the limited throughput of Bosporus and Dardanelles, while no similar restraining effect is caused within the Black Sea waters. Large freight terminals, particularly the Novorossiysk ones, have been constructed at the coastal zone for receiving oil supertankers. In addition to oil and petrochemicals, such cargo as metals, mineral fertilizers, vehicles and equipment, wood, timber, grain etc. are also carried over the Black Sea waters. Besides, container shipment turnover activities are also widely carried out within the Black Sea waters with freight delivered to the large container terminals. Lighter carrier and railroad ferry landing facilities are actively developed. The Blue Stream gas pipeline is laid along the bottom of the Black Sea for supplying Russian natural gas to Turkey passing a number of the third countries. This gas pipeline has been constructed for completing the Russia-Turkey gas transportation corridor running through the areas of Ukraine, Moldova, Romania, and Bulgaria. This project was implemented to improve reliability of gas supply to Turkey, thus developing the last gas transportation technologies. In 2015, Gazprom Public Company worked out the details of the offshore gas pipeline to be laid along the bottom of the Black Sea running towards Turkey (Turkish Stream) and to be completed with the Turkey overland natural gas pipeline running towards the Greece border. Turkish Stream is a new export gas line running from Russia to Turkey through the Black Sea. The first string of the gas pipeline is intended for supplying gas to Turkish consumers and the second string – to Southern and South-Eastern European countries. The offshore gas pipeline should have the length of about 900 km. Gazprom was firstly licensed by the Turkish authorities on September 2016 for implementing the Turkish Stream project. The contract for constructing the first string of the Turkish Stream offshore gas pipeline was executed between South Stream Transport B.V. (a subsidiary company 100% owned by Gazprom Public Company) and Allseas Group S.A. including the option for laying the second string. Availability of the well-developed gas transportation infrastructure, proximity to any potential markets and estimated cost-effective natural gas off-shore transportation are

130 CHAPTER 3 the very aspects to be estimated as the relevant ones and subject to specific gas delivery methods described in this paper.

Baltic Sea Ship traffic intensity has sufficiently increased in the Baltic Sea during the last decade. Simultaneously, about 2000 vessels are engaged in shipping including large oil tankers, ships that carry freight to be potentially dangerous to the environment, and passenger ships. Actually, the Baltic Sea is one of the high-loading transport arteries in the world. According the data reported by the Russian Maritime Ports Association RF14 at the end of 2015, the Baltic Sea basin freight turnover increased by 3.2% and grew to 230.7 million tons. ADry bulk vessel transshipment volume went down at the expense of containerized cargo by 17.0%, scrap metal – by 8.4%, and refrigerated cargo – by 18.5%. At the same time, some growth was demonstrated by the carriers engaged in transshipping coal – by 9.0%, mineral fertilizers – by 17.1%, ferrous metals – by 13.3%, and goods transported by ferries – by 14.2%. The primary export freight share is 88.8%, import share – 8.3%, cabotage and transit share – 2.5% and 0.4%, respectively. The Baltic Sea basin cargo handling activities held at Ust-Lug ports went up to 87.9 million tons (+16.1%) and at Primorsk ports – up to 59.6 million tons (+11.1%). The transshipment volume went down to 51.5 million tons (-15.8%) at St. Petersburg Bolshoy Port, down to 12.7 million tons (-8.6%) in Kaliningrad, and down to 1.6 million tons (-6.2%) at Vyborg. The Vysotsk Port freight turnover was actually similar to that at the last year – 17.5 million tons (+0.3%). The Nord Stream-2 project was launched for expanding the capacity of the existent Baltic Sea Nord Stream gas pipeline, thereby diversifying the pipeline routes to deliver Russian natural gas to the European markets traditionally operated by Gazprom Public Company. This new natural gas pipeline running from Russia to Germany along the bottom of the Baltic Sea will consist of two strings with the capacity of 27.5 bn m3 each. Western and Central European countries are the very target markets to the project. It is expected that the Gryazovets CS – Volkhov CS – Baltic Sea shore gas transporting facilities will be developed, as well as Nord Stream 2 exploratory and design works will be carried out for transporting natural gas to the above countries. The new gas pipeline like the current one shall couple Gazprom with European consumers and shall ensure that Russian gas will be efficiently and totally delivered to the European countries. Thus, it is especially important since gas production in Europe has declined but demand for imported gas is expected to continue going up. The Ust-Luga, Leningrad Region, will be the point from which the Nord Stream 2 pipeline is to run along the bottom of the Baltic Sea and to come out to the Greifswald area, Germany, nearby to the current Nord Stream discharge point.

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3.2. Analysis of Alternative Engineering Solutions for Transporting Gas in the Black Sea and the Baltic Sea Regions The alternative natural gas transportation technologies are listed in Tables 3.1 – 3.5.

Table 3.1. The Baltic Sea Russia-Turkey subsea gas pipeline technical data. Length – 389 km Volume, bn m3 Parameter 3.00 5.00 Production, bn m3/year • gross 3.038 5.055 • commercial 3.00 5.00 Auxiliary natural gas demands, bn m3/year 0.038 0.055 Line pipe characteristics • operating pressure, MPa 25.5 23.0 • pipe diameter (DN), in 15.0 19.0 • pipe wall thickness, mm 18.8 23.3 Onshore compressor station Number of CSs, ea 1 1 Number of GCU (operating + standby), ea 2+1 3+1 Rated CS power (GCU-10), MW 30.0 40.0

Table 3.2. The Baltic Sea Russia-Bulgaria subsea gas pipeline technical data. Length – 927.2 km Volume, bn m3 Parameter 3.00 5.00 Production, bn m3/year • gross 3.034 5.049 • commercial 3.00 5.00 Auxiliary natural gas demands, bn m3/year 0.034 0.049 Line pipe characteristics • operating pressure, MPa 28.3 28.3 • pipe diameter (DN), in 17.0 21.0 • pipe wall thickness, mm 21.5 26.0 Onshore compressor station Number of CSs, ea 1 1 Number of GCU (operating + standby), ea 2+1 3+1 Rated CS power (GCU-10), MW 30.0 40.0

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Table 3.3. The Baltic Sea Kaliningrad Region subsea gas pipeline technical data. Length – 1040.5 km Volume, bn m3 Parameter 3.00 5.00 Production, bn m3/year • gross 3.031 5.050 • commercial 3.00 5.00 Auxiliary natural gas demands, bn m3/year 0.031 0.050 Line pipe characteristics • operating pressure, MPa 22.0 22.0 • pipe diameter (DN), in 19.0 23.0 • pipe wall thickness, mm 13.5 16.0 Onshore compressor station Number of CSs, ea 1 1 Number of GCU (operating + standby), ea 2+1 3+1 Rated CS power (GCU-10), MW 30.0 40.0

Table 3.4. The Baltic Sea Germany subsea gas pipeline technical data. Length – 1225.5 km Volume, bn m3 Parameter 3.00 5.00 Production, bn m3/year • gross 3.030 5.050 • commercial 3.00 5.00 Auxiliary natural gas demands, bn m3/year 0.030 0.050 Line pipe characteristics • operating pressure, MPa 21.0 22.0 • pipe diameter (DN), in 21.0 25.0 • pipe wall thickness, mm 13.7 16.8 Onshore compressor station Number of CSs, ea 1 1 Number of GCU (operating + standby), ea 2+1 3+1 Rated CS power (GCU-10), MW 30.0 40.0

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Table 3.5. Baltic Sea and North Sea Great Britain subsea gas pipeline technical data. Length – 2500 km Volume, bn m3 Parameter 3.00 5.00 Production, bn m3/year • gross 3.030 5.048 • commercial 3.00 5.00 Auxiliary natural gas demands, bn m3/year 0.030 0.048 Line pipe characteristics • operating pressure, MPa 21.0 21.0 • pipe diameter (DN), in 24.0 29.0 • pipe wall thickness, mm 15.5 18.5 Onshore compressor station Number of CSs, ea 1 1 Number of GCU (operating + standby), ea 2+1 3+1 Rated CS power (GCU-10), MW 30.0 40.0

Estimated details of compressed and liquefied gas tanker quantity and capacity are listed in Tables 3.6 – 3.7.

Table 3.6. Estimated number of 22.5 MMSt.m3 CNG tankers for ensuring continuous gas supply to consumers Plant capacity, bn m3/year Gas supply terminal 3 5 Turkey 3 5 Bulgaria 3 6 Kaliningrad 3 6 Germany 4 6 Great Britain 5 8

Table 3.7. Estimated number and capacity of LNG tankers Plant capacity, bn m3/year Gas supply terminal 3 5 Turkey 1 x 65 000 m3 1 x 130 400 m3 Bulgaria 1 x 65 000 m3 1 x 130 400 m3 Kaliningrad 1 x 130 400 m3 1 x 130 400 m3 Germany 1 x 130 400 m3 1 x 130 400 m3 Great Britain 1 x 130 400 m3 2 x 130 400 m3

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3.3. Estimated Natural Gas Offshore Transportation Tariffs for Alternative Projects The Black Sea and the Baltic Sea 3 and 5 bn m3/year gas transportation tariffs are listed in Tables 3.8 – 3.11 respectively.

Table 3.8. Gas transportation tariffs Export volume – 3 bn m3/year, EUR/thousand m3 per 100 km Terminal Transportation Turkey Bulgaria Kaliningrad Germany Great Britain method Transportation distance, km 389 927.2 1040.5 1225.5 2500 Compressed gas 32.9 13.8 12.3 12.7 7.3 Liquefied gas 50.5 21.2 19.2 16.3 8.0 Subsea gas pipeline 45.0 31.2 28.7 27.6 24.6

Table 3.9. Gas transportation tariffs Export volume – 5 bn m3/year, EUR/thousand m3 per 100 km Terminal Transportation Turkey Bulgaria Kaliningrad Germany Great Britain method Transportation distance, km 389 927.2 1040.5 1225.5 2500 Compressed gas 31.8 15.1 13.5 11.4 6.9 Liquefied gas 45.0 18.9 16.8 14.3 7.4 Subsea gas pipeline 30.0 20.8 18.8 18.2 16.4

Table 3.10. Gas transportation tariffs Export volume – 3 bn m3/year, RUB/m3 per 100 km Terminal Transportation Turkey Bulgaria Kaliningrad Germany Great Britain method Transportation distance, km 389 927.2 1040.5 1225.5 2500 Compressed gas 2.6 1.1 1.0 1.0 0.6 Liquefied gas 4.0 1.7 1.5 1.3 0.6 Subsea gas pipeline 3.6 2.5 2.3 2.2 2.0

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Table 3.11. Gas transportation tariffs Export volume – 5 billion m3/year, RUB/m3 per 100 km Terminal Transportation Turkey Bulgaria Kaliningrad Germany Great Britain method Transportation distance, km 389 927.2 1040.5 1225.5 2500 Compressed gas 2.5 1.2 1.1 0.9 0.5 Liquefied gas 3.6 1.5 1.3 1.1 0.6 Subsea gas pipeline 2.4 1.7 1.5 1.5 1.3

Layout of alternative natural gas supplies with reference to transportation volume and distance details are illustrated in Figure 3.1. As shown in this Figure, the compressed gas transportation technology demonstrates its best efficiency when 3 billion m3/year of natural gas is carried over 300 km to approx. 1500 km distance (389 km, 927.2 km, 1040.5 km, 1225.5 km distances are taken into account). Both the compressed and liquefied gas technologies may be similarly efficient when 3 billion3 m /year of natural gas is carried over a 2500 km distance. The compressed gas transportation technology is the most effective when 5 billion m3/year of natural gas is carried over a 1000 km distance and more (927.2 km, 1040.5 km, 1225.5 km m, and 2500 km distances are taken into account). The subsea gas pipeline route is the most efficient when 5 billion3 m /year of natural gas is transported over a 389 km distance. Also, Figure 3.1 shows an effective CNG transportation region marked by a solid blue line that may be used when no special coast compressor stations are to be constructed. This method is suitable when there are some potentialities for using existent facilities. This CNG technology is rather effective for carrying relatively small volumes of natural gas (up to 3 billion m3) to relatively large distances (up to 3000 km and more).

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Gas volume, Point No. Route bn m3/year 1 5 Russkaya CS – Turkey (389 km) 2 3 3 5 Russkaya CS – Bulgaria (927.2 km) 4 3 5 5 Portovaya CS – Kaliningrad (1040.5 km) 6 3 7 5 Portovaya CS – Germany (1225.5 km) 8 3 9 5 Portovaya CS – Great Britain (2500 km) 10 3 Fig. 3.1. Configuration of the technologically effective gas transportation regions

137 CHAPTER 4. ENVIRONMENTAL IMPACT ASSESMENT IN THE PROCESS OF NATURAL GAS MARINE TRANSPORTATION 4.1. Methodological Approach to the Carbon Footprint Assessment Technique Currently, a number of environmental impact academic assessment in the process of natural gas marine transportation may be referred to a new field of studies. Nevertheless, multiple researchers have arrived to a consensus that this kind of an energy carrier is featured with high environmental capacity including an anthropological impact on global climate fluctuation processes. At large, being technologically new type of fuel, natural gas consumed emits minimum amount of greenhouse gases against other hydrocarbons.

When burnt, it produces small amount CO2, SOx, NOx and other particles. The carbon footprint assessment methodology commonly applied on a global scale may be specified suitable for appraisal of greenhouse gas emission volumes produced when utilizing any energy carrier throughout its entire technology life cycle. As referred to the LNG technology, the carbon footprint assessment procedure is to be performed with the greenhouse emission expertise made at the following phases: - gas field production; - gas pipeline transportation and delivery to a LNG plant; - LNG processing at a plant; - LNG offshore transportation; - LNG unloading; - regasification at a terminal; - gas pipeline transportation and delivery to a consumer; - gas consumption. Notwithstanding the above multi-stage expertise, such assessment fails to provide comprehensive data since for the total carbon footprint study it is necessary to cover, for example, specific amount of greenhouse gases emitted to atmosphere while producing metal for compressor stations, pipelines, LNG vessels including LNG plant reinforced concrete structures and other items but this approach is not frequently used and the assessment details subject to this paper limited by direct greenhouse gas emissions released throughout the entire LNG life cycle stages. If LNG is utilized for producing electric energy, it emits less natural gas throughout the entire technology cycle than coal but its specific emissions exceed those of pipeline gas33 (Figures 4.1, 4.2).

33 Source: Department of Energy and Climate Change “Potential Greenhouse Gas Emissions Associated with Shale Gas Extraction and Use”, Professor David J C MacKay FRS, Dr Timothy J Stone CBE, London 2013.

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As applied to emission level, LNG may be placed on the same footing as long transport distance pipeline gas (7000 km) as a result of its processing at compressor stations and, moreover, fuel gas is burnt at gas-compressor units and methane is emitted to atmosphere during service and maintenance works. The following significant LNG plant environmental impact aspects are to be referred to a particular process flow: - need for proper gas treatment process with the effect exceeding that of a LNG processing plant (LNGPP) for preventing refrigeration equipment failures during transportation; - compulsory availability of a flare to be in a service condition; - liquid to gas (stripping gas) conversion process induced by interaction between LNG and vessel walls throughout the entire life cycle (including tanker transportation period) and, moreover, such stripping gas may be utilized as fuel and supplied for re- liquefaction or may be burnt. In the process of gas drying, cleaning and liquefying, air is contaminated with hydrocarbons, carbon monoxide, nitric and sulfur oxides. Flairs, gas turbines, acid gas burners, boilers and standby diesel generators are the main sources of atmospheric emissions.

Fig. 4.1. Appraisal of greenhouse gas emissions in Great Britain to be released as a result of electricity generation by various energy sources throughput the entire life cycle

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Fig. 4.2. Appraisal of greenhouse gas emissions in Great Britain to be released as a result of electricity generation by various gases

Individually, it should be noted that a particular negative environmental impact is caused by pollutants generated as a result of construction of an LNG plant, an LNG jetty, and a regasification terminal (Table 4.1). All the above-mentioned factors demonstrate that the LNG technology, in comparison with the CNG gas transportation technology, negatively affects the environment due to processing energy carrier-specific characteristics and scope of the production facilities.

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Table 4.1. Environmental impacts caused by LNG production, transportation and regasification activities Global Local surface targets Local sea targets targets

LNG production and transportation life cycle phase Fish Seabed Benthos Habitats Sea birds Sea water landscapes Biodiversity Sea mammals Global climate Flora and fauna and Flora Atmospheric air Atmospheric Atmospheric air Atmospheric Local population Ground and soils and Ground Surface and ground waters ground and Surface

LNG plant construction LNG plant operation LNG jetty construction LNG jetty operation Dredging LNG tanker transportation LNG terminal construction LNG terminal operation

The comparative analysis of a negative environmental impact caused by LNG production and transportation activities demonstrates that low- and medium-power compressor plants are involved as opposed to the LNG plant processing facilities. Actually, methane combustion products, as well as methane gas, to be emitted during maintenance, are discharged to the atmosphere (Table 4.2). In this case, rate of target exposure significantly declines thanks to using the CNG technology with a list of environmental impact targets cut down.

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Table 4.2. Environmental impacts caused by CNG production, transportation and delivery activities Global Local surface targets Local sea targets targets

LNG production and transportation life cycle phase Fish Seabed Benthos Habitats Sea birds Sea water landscapes Biodiversity Sea mammals Global climate Flora and fauna and Flora Atmospheric air Atmospheric Atmospheric air Atmospheric Local population Ground and soils and Ground Surface and ground waters ground and Surface

CNG export terminal construction CNG export terminal operation CNG jetty construction CNG jetty operation

CNG transportation by ships

CNG import terminal construction CNG import terminal operation

4.2. Environmental Aspects of Natural Gas Offshore Transportation With natural gas transported overseas, both the offshore environment and its components can be inevitably affected. This Section describes particular environmental aspects of natural gas offshore transportation: - by subsea pipeline system; - by CNG marine vessels; - by LNG marine vessels. Each of the above methods has its advantages and disadvantages that can have an effect on the decision to be made with reference to alternative ways of natural gas delivery to a consumer.

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Environmental aspects of subsea natural gas pipeline transportation

A key environmental aspect of natural gas subsea pipeline transportation is pollutant emissions released from gas-compressor units (GCU) of a compressor station while compressing natural gas supplied to subsea gas pipelines. The preference will be given to new-generation GCUs equipped with low-emission combustion chambers for reducing any atmospheric emissions. Seabed gas pipelines will never impact the marine environment. Therefore, gas pipelines are to be surveyed in proper time and checked for any deformations, bed movements, welding defects, dents, pipeline protection flaws, and possible natural gas leaks for preventing pipeline failures and emergency situations. Operating parameters, pressure and temperature will be continuously monitored for any fluctuations. Those gas pipelines that are to be operated in corrosive hydrogen-sulfide applications (Black Sea projects) will meet extended industrial and environmental safety requirements.

Environmental aspects of LNG vessel transportation

Nitrogen oxide (NOX) and carbon monoxide (CO) are those components to be referred to the environmental aspects of LNG vessel transportation. A great portion of atmospheric emissions is released by electricity and heat production facilities that support LNG plant processes, by regasification units, and by LNG import terminals. Pollutants are emitted as a result of operating such equipment as compressors, pumps, piston engines, and flares. Alternative process equipment (e.g. regasification terminal evaporators to be substantially used since they have specific performance and environmental impact characteristics) and electric/heat energy sources (e.g. generated by third-party companies) are to be involved in every LNG transportation project for minimizing pollutant emissions. Stripping gas (methane fumes) generated in the LNG handling products process (storage, transportation, and regasification) is trapped or returned to a reservoir (tank, vessel, regasification unit) or it is utilized as fuel (LNG plant, gas carrier vessel). LNG facilities can irregularly emit pollutants to the atmosphere as a result LNG of loading/unloading operations, tank handling, as well as due to natural gas escape events occurred when operating safety valves, flanges, glands, pump and compressor seals. Therefore, LNG facilities are to be periodically maintained and inspected for any leaks for preventing and cutting down irregular pollutant emissions. Soil erosion is equally significant factor since bottom deposit and benthos structure is changed under the effects caused by LNG facilities. Hydrocole living conditions may be affected since the required right-of-way is to be established and restricted for fishing or other activities.

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Environmental aspects of CNG vessel transportation

One of the most significant environmental aspects of LNG vessel transportation is pollutant emissions released to atmospheric air when: - natural gas is compressed at onshore boosting compressor stations (BCS) situated as natural gas loading and unloading points; - natural gas is carried by vessels and operated by auxiliary vessels. The BCS pollutant emissions are primarily released after burning fuel gas in GCU. When pumping gas into CNG carrier vessels out of offshore field boreholes, it is necessary to take into account a negative environmental impact that may be likely caused by subsea production systems (e.g. production trees, operating pipelines, and gas/water injection tools). When operating gas carrier vessels, apart from engine fuel combustion products, there may be some emissions released by vent stacks (single or multiple units) equipped with a flame burning system. Such stacks are required for monitoring high-pressure (freight containers) and low-pressure (bilge space) gas discharge flow and for venting gas and its combustion products. With natural gas stored at buffer reservoirs/tanks, pollutant emissions may be released in the atmosphere as a result of natural gas escape through any loose joints. Pollutant emissions may be reduced under those projects that do not assume implementing a natural gas compression phase but provide for pumping gas into carrier vessels (with gravity flow gas pumped out of offshore field boreholes). Wastes and effluents produced by gas carrier vessels can be also referred to rather important environmental aspects. Waste water treatment plants may be used for reducing wastes and effluents discharged to sea waters from gas carrier vessels with combined treatment methods applied including mechanical, chemical, physiochemical (electrolysis) and biological treatment techniques. Waste water treatment plants meet the requirements set out in MARPOL 73/78 Convention, Annex IV. Discharged water quality is confirmed by the type approval certificate. Carrier vessels are equipped with sewage tanks to be subsequently delivered to waterside waste disposal facilities for minimizing an effluent impact within the 12-mile coastal zone and seaport waters. A CNG loading/unloading remote offshore terminal can likely affect both the offshore and onshore environment since sea current, natural ground movement and other process changes may occur. Also, it should be noted that any gas carrier vessels moving in waters produces an acoustic effect influencing flora and fauna habitation. When selecting an alternative natural gas transportation method, particular attention shall be paid to the environmental aspects of processing facilities to be constricted for supplying natural gas to a consumer

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(LNG plants, gas carrier loading/unloading terminals, pipelines etc.). Undoubtedly, it is a transient factor that can negatively affect the environment throughout a construction phase. But such impact must be minimized, thus preventing any irreversible effects, primarily caused to a unique and vulnerable offshore environment. With the alternative natural gas transportation methods being brought to comparison, a number of advantages may be identified as those that can both directly and indirectly reduce a negative environmental impact. For example, when using CNG carrier vessels, delivered gas may be discharged through a buoy system platform directly to a gas distribution circuit or to a consumer gas reservoir. Actually, no import terminal construction is required. As compared to the LNG vessel transportation method, an amount of gas that could be lost is significantly reduced when transporting CNG (down to 2-3%). The CNG vessel transportation method can be featured with the following other benefits: - no need to pump in/out ballast water as it has to be done when using LNG carrier vessels; - low power consumption (to be consumed three times less than when using LNG carriers); - using existent platforms and pipeline systems instead of any new gas discharge terminals. Natural gas carrier vessels are mainly differed from subsea pipelines by their functional flexibility (e.g. possibility to change routes and supply volumes). Besides, the subsea pipeline technique ensures reliable and safe delivery of natural gas to a consumer. It should be noted that gas carrier vessel capacity depends on respective environment and climatic conditions (wind speed, rain and snow fall, ice conditions etc.). Therefore, marine vessels must be routed with due reference to actual climatic (environment and physiographic) conditions within the area concerned. In addition to, it is necessary to take into account a number of restrictions to be followed when entering any port (gas carrier vessel draft, width, length).

4.3. Natural Gas Offshore Transportation Effect on the Atmosphere High energy capacity natural gas to be suitable for storing and delivering to any spot in the world, as well as for transporting over subsea pipelines have been selected from alternative variants. Liquefied natural gas (LNG) intended for energy facilities is currently widely shipped by tankers. As for compressed natural gas (CNG), it may be shipped by special gas carrier vessels as stored at high-pressure reservoirs.

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In terms of comparative analysis of the atmospheric effect to be caused by various gas offshore transportation methods, there may be alternately implemented the following gas transportation and processing chains: - transporting natural gas overseas through pipelines (along the bottom of sea) with the support of onshore infrastructure – compressor station gas suppliers; - transporting LNG along a shipping routes by tankers from LNG plants/facilities and supplying gas to import terminals after processing at regasification plants; - transporting CNG along a shipping route by gas carrier vessels from gas treatment infrastructure facilities including BCS and loading terminals (including anchor buoys, mooring and offshore loading platforms) and unloading terminals (including buffer gas reservoirs). Such parameters as quantity and dimensions are to be specified with reference to vessel capacity, delivery distance, crossing period, length of full loading-unloading cycle. Comparative analysis of atmospheric air pollutants (by the example of nitrogen oxides (NOX) and carbon monoxides (CO)) and their environmental effect details are set forth below regarding three sea gas transportation methods mentioned above: I. The Black Sea transportation route – 400 km from Beregovaya CS; to be considered as prototype of the Turkish Stream running 900 km from the Russkaya CS; II. The Baltic Sea transportation route – from the Portovaya CS, three alternative unloading terminals – Kaliningrad Region, Germany and Great Britain; transport distance – 900 km, 1200 km, and 2500 km, respectively. Gas volumes to be delivered along these sea routes – 3.0 and 5.0 billion m3/year.

Variant I. The Black Sea transportation route The Black Sea transportation route is to be used for carrying 16 billion m3/year of gas to a 400 km distance. There are other options to be taken into account for increasing volumes with gas carried to a 900 km distance over the following transportation and processing chains: 1.1. Subsea (along the bottom of sea) natural gas pipeline transportation with the support of the onshore infrastructure – from the Beregovaya or Russkaya compressor stations; 1.2. Transporting CNG by gas carrier vessels along the Black Sea route from gas treatment infrastructure facilities including the BCS and loading terminals (including anchor buoys and offshore loading platforms).

1.1. Environmental Black Sea natural gas pipeline transportation analysis

It is assumed that natural gas will be transported overseas (along the bottom of sea) to a 400 km (900 km) distance with the support of the onshore infrastructure –

146 CHAPTER 4 from the Beregovaya or Russkaya compressor station to be a pilot plant responsible for transporting gas along the Black Sea bottom and for maintaining the route covered by the Blue Stream or the Turkish Stream pipelines. For example, the Beregovaya CS is equipped with six GPA-25I(S) units (operating duty: 4+2), total installed capacity – 150 MW, which characteristics are listed in Table 4.3; this capacity is sufficient enough for maintaining the Turkish Stream gas subsea pipeline running 900 km off the Russkaya compressor station. These GPA-25I(S) units fail to have the best environmental gas-compressor parameters – i.e. actual concentrations of NOX 3 3 emissions – 235 mg/m and CO emissions – 135 mg/m (as reduced to 15% of O2) [1]. For transporting 16 billion m3/year of gas by subsea pipelines, four compressor units are involved.

Table 4.3. Russkaya CS gas-compressor unit performance characteristics (by the example of Beregovaya compressor station) Gas-compressor unit type GPA-25I(S) PLC 84 Nuovo Compressor Pignone Drive М 5322 R (С) Compressor Q rated MM m3/24 hours 50.3 Number of GCUs piece 6 (4+2) GCU power, N rated kW 25000 N total kW 150000 Fuel gas flow rate m3/hour (kg/s) 7483.0 (1.4)

3 Pollutant concentration NOХ mg/m 235 3 (by 15% of O2) СО mg/m 135 NO g/s 14.5 Intensity of pollutant emission Х СО g/s 7.5

3 Specific pollutant emission per NOХ g/m FG 7.0 fuel gas unit 3 СО g/m FG 4.0 3 Specific pollutant emission per gas NOХ g/thou m (pumping) 25.0 supply unit СО g/thou m3 (pumping) 13.0

Total pollutant emission released when NOХ tons (per 1 / 4 units) 100 / 400 pumping 16 bn m3 of gas / 4.0 bn m3 per 1 unit each СО tons (per 1 / 4 units) 52 / 208 NO tons 400 Great total CS pollutant emissions Х СО tons 208

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For specific pollutant emission perpipeline length unit to be specified with reference to natural gas transported along the Black Sea bottom, refer to Table 4.4.

Table 4.4. Specific pollutant emission per length unit as referred to the Turkish Stream gas subsea pipeline – 900 km Specific emission per gas pipeline length Pollutant unit, tons/km Nitrogen oxides 0.45 Carbon monoxides 0.23

1.2. Environmental Black Sea CNG carrier vessel transportation analysis

Compressed natural gas is to be shipped by gas carrier vessels to a 400 km or 900 km distance along the Black Sea route with the support of the gas treatment infrastructure via BCS and loading terminals (including anchor buoys and offshore loading platforms). The CNG volume to be equivalent to that of 16 billion m3/year pumped over by the subsea pipeline is 64 MM m3. A CNG gas carrier equivalent vessel is «Elba» to have the following characteristics: - load-carrying capacity – 40 thousand m3; - propulsion plant power (x2 gas reciprocating engines) – 12.2 MW; - speed – 8 knots (15 km/h) to 15 knots (25 km/h). Such gas carrier vessel can run a 400 km distance within 24 hours (900 km – within 36 hours), i.e. with 2 tankers simultaneously charged at the loading jetty and with 4 vessels loaded a day, 8 vessels in total are to be used for regular turnover. This group of vessels shouldmake about 200 trips (total gas-carrying period is about 1 year) for carrying 64 MM m3 of CNG; and all the vessels should make 1600 trips. Gas carrier vessels are equipped with low-speed gas reciprocating engines (x2) 12.2 MW and 3000 m3/hour fuel gas flow each (total fuel gas flow rate – 60003 m /hour). Gas reciprocating engines produced after 2016 should have exhaust emission parameters satisfying the requirements set out in GOST 31967-2012. For gross and specific gas reciprocating exhaust emission values, refer Table 4.5. The gross emissions are calculated for shipping 64 MM m3 of CNG provided that totally 1600 trips are made in 36 hours each.

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Table 4.5. CNG carrier vessel gas reciprocating engine exhaust emission values Specific emission per Specific emissions, g/ Gross emissions, Pollutants gas pipeline length (kW·h tons unit, tons/km

Nitrogen oxides (NO2) 6.0 8432.6 9.37 Carbon monoxides 1.5 2108.1 2.34 Hydrocarbons* 0.4 *- as rated to a greenhouse gas group

Variant II. Baltic Sea transportation route The Baltic Sea transportation routed covers the distance of 900 km.. It is assumed that natural gas would be supplied by the following over the following transportation and processing chains: 2.1. Natural gas subsea (along the bottom of sea) pipeline transportation with the support of the onshore infrastructure – from the Portoaya compressor station; 2.2. Transporting LNG by tankers from LNG treatment plants / facilities to consumers along the Baltic Sea route with gas being properly treated at regasification terminals; 2.3. Transporting CNG by gas carrier vessels along the Baltic Sea route from gas treatment infrastructure facilities including BCS and loading terminals (including anchor buoys and offshore loading platforms).

2.1. Environmental analysis of the Baltic Sea subsea natural gas pipeline transportation

It is assumed that natural gas would be transported overseas (along the bottom of sea) to a 900 km (or 1200 km / 2500 km) distance with the support of the onshore infrastructure – from the Portovaya compressor station involving Gazprom Transgas St. Petersburg LLC, a gas carrier that operates the Northern Gas line (1 and 2 strings). The Portovaya CS is equipped with eight gas-compressor units used at 2 shops (operation scheme: 3+1), total installed capacity – 366 MW, which characteristics are listed in Table 4.6 (as of 01.01.2016). The subsea pipeline is capable to carry the volume of 2.94 billion m3/year of gas (equivalent to 2 bn m3 of LNG) that is pumped over in 27 days and nights by 6 (6+2) 52 MW units – this capacity is sufficient enough for maintaining the 1200 km gas subsea pipeline and, if transported to a 2500 km distance, it is necessary to take into account the capacity of 3 equivalent gas-compressor units. These gas-compressing units fail to have the best environmental parameters – i.e. 3 3 actual concentrations of NOX emissions – 65 mg/m and CO emissions – 130 mg/m (as reduced to 15% of O2) [1].

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Table 4.6. The Beregovaya CS gas-compressor unit performance characteristics RB211- TRENT Gas-compressor unit type GPA-27 GPA-52 6562DLE 60DLE Compressors D10R6B D14R6B Drives RB211-6562 DLE TRENT 60 DLE Changeable air gas channel type D10R6B-220/2.83 D14R6B-220/2.83 Engine manufacturer Rolls-Royce (USA) Rolls-Royce (USA) Compressor Q rated, MM m3/24 hours 13 27.9 Number of GCUs, pcs 1 3 GCU power, N rated 27000 52000 N total, kW 27000 156000 Fuel gas flow rate, kg/hour 5566 9000 NO 50.0 65.0 Pollutant concentration (by 15% of O ) Х 2 СО 100.0 130.0 NO 3.1 6.0 Intensity of pollutant emission, g/s Х СО 6 12.9

Specific pollutant emission per fuel NOХ 1.4 1.7 3 gas unit, g/m СО 2.7 3.6

Specific pollutant emission per gas supply NOХ 21.3 18.6 3 (pumping) unit, g/thousand m СО 40.0 39.0

Total pollutant emission released when pumping NOХ Standby 9.1 / 27.3 2.94 bn m3 of gas / 0.49 bn m3 per 1 unit each, tons (per 1/3 units) СО Standby 18.0 / 54.0

Great total CS pollutant emissions, NOХ 54.6 / 81.9 tons (2 / 3 shops) СО 108.0 / 162.0

For specific pollutant emission perpipeline length unit to be specified with reference to natural gas transported along the Baltic Sea bottom, refer to Table 4.7.

Table 4.7. Specific pollutant emission per gas pipeline length unit Specific emission per gas pipeline length unit – Pollutant 900 (1200) / 2500 km, tons/km Nitrogen oxides 0.06 / 0.167 Carbon monoxides 0.12 / 0.33

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2.2. Baltic Sea transportation by LNG tankers

Natural gas is transported by LNG tankers along the sea route from the LNG plants/ facilities to suppliers with gas being properly treated at regasification terminals. For details of pollutant emissions released by the LNG plants/ facilities to have the capacity of 5 billion m3/year of LNG and by the regasification terminal, refer to Table 4.8.

Table 4.8. Gross pollutant emissions released by the NLG facilities and by the regasification terminal Gross pollutant emissions, tons Pollutant LNG facility regasification terminal Nitrogen oxides 900 62.5 Carbon monoxides 350 37.5

Liquefied natural gas is to be shipped by gas carrier vessels to a 900 km distance along the Baltic Sea route from the LNG plants/ facilities to have the capacity of 5 billion m3/ year of LNG and to be supplied to a consumer via the regasification terminal. A LNG gas carrier equivalent vessel is «Veliky Novgorod» to have the following characteristics: - гload-carrying capacity – 172 thousand m3; - gross tonnage – 72.5 thousand tons; - propulsion plant power (x2 gas reciprocating engines) – 17.1 MW; - speed – 13.5 knots/25 km/h. Such gas carrier vessel can run a 900 km distance within 36 hours (1200 km – within 48 hours and 2500 km in 100 hours). Two vessels should make 28 trips; one tanker gas carrying turnover is 4 days and total LNG may be carried in 4 months, respectively. Gas carrier vessels are equipped with low-speed gas reciprocating engines (x2) 17.1 MW and 5000 m3/hour fuel gas flow each [2]. Gas reciprocating engines released after 2016 shall have exhaust emission parameters satisfying the requirements set out in GOST 31967-2012. For gross and specific gas reciprocating exhaust emission values, refer Table 4.9. The gross emissions are calculated for shipping 5 billion m3/year of LNG provided that totally 28 trips are made within 36 hours by each tanker.

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Table 4.9. LNG tanker gas reciprocating engine exhaust emission values Specific emission per Specific emissions, g/ Gross emissions, Pollutants gas pipeline length unit (kW·h) tons – 900 km, tons/km

Nitrogen oxides (NO2) 6.0 517.1 0.57 Carbon monoxides 1.5 129.25 0.14 Hydrocarbons* 0.4 *as rated to a greenhouse gas group

For details of pollutant emissions released by LNG tankers carrying gas along the Baltic Sea route and environmental impact caused by the LNG facilities and regasification terminal, refer to Table 4.10.

Table 4.10. LNG facilities and regasification terminal emissions released when carrying gas by LNG tankers along the Baltic Sea transportation route Gross emissions, Specific emission per gas pipeline Pollutant tons length unit – 900 km, tons/km Nitrogen oxides 1479.6 1.644 Carbon monoxides 516.75 0.574

2.3. Baltic Sea transportation by CNG carrier vessels

Compressed natural gas is to be shipped by gas carrier vessels to a 900 km distance along the Baltic Sea route with the support of gas treatment infrastructure via BCS and loading terminals (including anchor buoys and offshore loading platforms). The CNG volume to be equivalent to that of 2 million tons per year (5 billion m3/year) pumped over by the subsea pipeline is 11.76 MM m3. A CNG gas carrier equivalent vessel is the «Veliky Novgorod» ice-breaker to have the following characteristics: - load-carrying capacity – 172 thousand m3; - propulsion plant power (x2 gas reciprocating engines) – 17.1 MW; - speed – 13.5 knots / 25 km/h. Such gas carrier vessel can run a 900 km distance within 36 hours. Two vessels should make 69 trips for carrying 11/76 MM m3 of CNG wihthin 4 days; as concerns LNG, it may be carried over within 9.5 months, respectively. Gas carrier vessels are equipped with low-speed gas reciprocating engines (x2) 17.1 MW and 5000 m3/hour fuel gas flow each [2]. Gas reciprocating engines manufactured after 2016 should have exhaust emission

152 CHAPTER 4 parameters satisfying the requirements set out in GOST 31967-2012. For gross and specific gas reciprocating exhaust emission values, refer Table 4.11. The gross emissions are calculated for shipping 11.76 MM m3 of CNG provided that totally 69 trips are made by two vessels in 36 hours each.

Table 4.11. CNG carrier vessel gas reciprocating engine exhaust emission values Specific emission per Specific emissions, g/ Gross emissions, Pollutants gas pipeline length unit (kW·h) tons – 900 km, tons/km

Nitrogen oxides (NO2) 6.0 1274.0 1.42 Carbon monoxides 1.5 318.75 0.35 Hydrocarbons* 0.4 *as rated to a greenhouse gas group

4.4. Environment Analysis of Natural Gas Offshore Transportation Effect on the Atmosphere

Environmental factors and their effects on the atmosphere have been studied within the scope of alternative transportation technologies with various options duly compared and analyzed. As it is comparatively specified regarding the environmental impact, gas volume and transportation distance are the very components that should be considered as the key effectiveness parameters. Consequently, to make a conclusion about environmental effectiveness of any transportation method, particular a subsea pipeline, LNG, CNG project implementation conditions should be approximately estimated. Environmental factors that have an effect on the atmosphere when transporting gas to a 900 km distance have been taken as a criterion for comparison of the said technologies. The transportation technologies have been compared under the algorithm as follows: Step 1: receiving environmental impact data and specific nitrogen oxide and carbon monoxide emission values subject to use of various gas transportation variants; Step 2: calculating gross pollutant emissions by a matrix form depending on transportation distances and values; Step 3: plotting graphs (diagrams) of emissions to freight traffic flows and distances; Step 4: assessing every transportation technology for its efficiency. Step 1. For the environmental impact data and specific nitrogen oxide and carbon monoxide emission values subject to use of various gas transportation variants, refer to Table 4.12, Figure 4.3.

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Table 4.12. Environmental factors affecting the atmosphere when transporting gas to a 900 km distance Gross emissions Specific emissions Pollutant emissions t/year t/bn m3 t/(bn m3*km) CNG + gas carrier vessel

NOX 1274 43.333 0.048 CO 318.75 10.842 0.012 LNG plant + gas carrier vessel + regasification

NOX 1479.6 295.92 0.329 CO 516.75 103.35 0.115 Subsea pipeline

NOX 81.9 11.143 0.012 CO 162 22.041 0.024

Fig. 4.3. Specific pollutant emissions to transportation distances

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Step 2. For a gross pollutant emission matrix form calculated depending on the transportation distances and values, refer to Table 4.13.

Table 4.13. Gross pollutant emissions depending on the transportation distances and volumes Subsea gas pipeline transportation

Gross pollutant emissions, tons Nitrogen oxides (total) - NO Gas transportation X volume Transportation distance, km bn m3/year 300 1000 2000 3000 4000 5000 21.55 80.042 266.809 533.619 800.428 1067.238 1334.048 14.37 53.374 177.914 355.828 533.742 711.657 889.571 10.78 40.04 133.466 266.933 400.4 533.866 667.333 7.18 26.668 88.895 177.791 266.685 355.581 444.476 4.31 16.008 53.362 106.723 160.085 213.447 266.809 1.44 5.348 17.828 35.657 53.485 71.314 89.142 Gross CO emissions, tons Gas transportation volume Transportation distance, km bn m3/year 300 1000 2000 3000 4000 5000 21.55 158.326 527.755 1055.51 1583.265 2111.02 2638.776 14.37 105.575 351.918 703.836 1055.755 1407.673 1759.592 10.78 79.2 264.0 528.0 792.0 1056.0 1320.0 7.18 52.751 175.836 351.673 527.510 703.346 879.183 4.31 31.665 105.551 211.102 316.653 422.204 527.755 1.44 10.579 35.265 70.530 105.795 141.061 176.326 Compressed natural gas and carrier vessel transportation

Gross pollutant emissions, tons Nitrogen oxides (total) - NO Gas transportation X volume Transportation distance, km bn m3/year 300 1000 2000 3000 4000 5000 21.55 311.277 1037.592 2075.185 3112.778 4150.37 5187.963 14.37 207.566 691.888 1383.778 2075.667 2767.556 3459.444 10.78 155.711 519.037 1038.074 1557.111 2076.148 2595.185 7.18 103.711 345.703 691.407 1037.111 1382.815 1728.519 4.31 62.255 207.518 415.037 622.555 830.074 1037.593 1.44 20.8 69.333 138.666 208.0 277.333 346.666

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Gross CO emissions, tons Gas transportation volume Transportation distance, km bn m3/year 300 1000 2000 3000 4000 5000 21.55 77.880 259.601 519.203 778.805 1038.407 1298.009 14.37 51.932 173.108 346.216 519.324 692.432 865.54 10.78 38.958 129.861 259.722 389.583 519.444 649.305 7.18 25.948 86.493 172.987 259.481 345.975 432.468 4.31 15.576 51.920 103.840 155.761 207.681 259.601 1.44 5.204 17.346 34.693 52.040 69.387 86.734 LNG plant + gas carrier vessel + regasification

Gross pollutant emissions, tons Nitrogen oxides (total) - NO Gas transportation X volume Transportation distance, km bn m3/year 300 1000 2000 3000 4000 5000 21.55 2125.692 7085.640 14171.280 21256.920 28342.560 35428.200 14.37 1417.457 4724.856 9449.712 14174.568 18899.424 23624.280 10.78 1063.339 3544.464 7088.928 10633.392 14177.856 17722.320 7.18 708.235 2360.784 4721.568 7082.352 9443.136 11803.920 4.31 425.138 1417.128 2834.256 4251.384 5668.512 7085.640 1.44 142.042 473.472 946.944 1420.416 1893.888 2367.360 Gross CO emissions, tons Gas transportation volume Transportation distance, km bn m3/year 300 1000 2000 3000 4000 5000 21.55 742.398 2474.658 4949.317 7423.975 9898.633 12373.292 14.37 495.047 1650.155 3300.310 4950.465 6600.620 8250.775 10.78 371.371 1237.903 2475.807 3713.710 4951.613 6189.517 7.18 247.351 824.503 1649.007 2473.510 3298.013 4122.517 4.31 148.480 494.932 989.863 1484.795 1979.727 2474.658 1.44 49.608 165.360 330.720 496.080 661.440 826.800

Step 3. For graphs (diagrams) of emissions to freight traffic flows and distances, refer to Figure 4.4. Step 4. Crossover points of an annual transportation volume and distance fixed values have been found for comparable alternative transportation technologies with reference to the gross pollutant emissions specified by a matrix form depending on the transportation distances and values, as well as by using the graphic analysis method. Sets of points that show the most efficient gas transportation technology have been

156 CHAPTER 4 obtained. These points can conventionally characterize the lines of critical equivalence separating the environmentally suitable zones to be efficiently used for involving every transportation technology depending on annual gas transportation volume and distance. The points are spread so as induced by variability of methods with every transportation technology to be conditionally assessed for accuracy and with the areas of ambiguity (white areas) to be duly characterized (Fig. 4.5).

Gross NOX emissions, tons/year Gross СО emissions, tons/year Natural gas subsea pipeline transportation

Compressed natural gas and carrier vessel transportation

LNG plant + gas carroer vessel + regasification

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Fig. 4.4. Diagrams of gross pollutant emissions to fright traffic flows and distances

Fig. 4.5. Efficient regions for using particular gas transportation technologies that minimize any abnormal effect to the atmosphere

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4.5. Calculating a Carbon Footprint of Natural Gas Offshore Transportation A natural gas carbon footprint is an indicator of efficiency of environment-friendly production processes and energy resource utilization activities held throughout all the phases of blue flame gas life cycle (from gas production to delivery to a consumer) and this indicator is of great interest for both the society and investors. A number of various natural gas carbon footprint studies has been carried out for estimating natural gas supplies and deliveries from Russia or other countries to the EU member countries including the appraisal of gas as motor fuel [4]. The review of the environmental Yamal LNG project aspects was published in 2016 [5]. The natural gas offshore transportation carbon footprint effect has been described in details in this paper. A carbon footprint of the natural gas offshore transportation is an amount of greenhouse gas emissions released to atmosphere with any of the variants used for transporting natural gas to an end customer. A carbon footprint of the natural gas offshore transportation is a specific value of greenhouse emissions to be specified as tCO2-eq by J of gas delivered to a customer. Such carbon footprint has been rated with reference to three alternative natural gas offshore transportation variants. «The offshore pipeline system» consists of the following major natural gas life cycle facilities: - an onshore compressor station (gas treatment (scrubbing and drying), compressing); - a subsea gas pipeline (gas transportation). «The CNG carrier vessel transportation system» consists of the following facilities: - CNG loading/unloading terminals (including the facilities for supplying gas to a vessel less previous compression); - CNG reservoirs and tanks; - CNG carrier vessels (gas transportation). «The LNG carrier vessel transportation system» consists of the following facilities: - an LNG production plant (gas treatment and liquefying, reservoir storage); - an LNG loading terminal (loading carrier vessels with gas); - LNG carrier vessels (gas transportation); - an LNG import terminal (LNG reservoir storage, regasification). The carbon footprint has been estimated and analyzed for the conditions as follows: - the natural gas offshore transportation routes are approximated to the particular large project scenarios (the Black Sea projects, the Baltic Sea projects) described in details in open sources (www.gazprom.ru);

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- some new subsea gas pipelines, modern marine vessels, power efficient machines and process equipment are used for transporting gas overseas; - all the processing facilities exhibit satisfactory performance. Natural gas, diesel fuel and electrical power flow rates have been duly studied for estimating interrelated natural gas offshore transportation life cycle components starting with the gas treatment process (scrubbing and drying) and ending in the gas consuming process. As referred to each live cycle phase the following factors have been taken into account: - specific methane and carbon dioxide emissions; - specific energy consumed parameters as calculated per a product unit.

Other greenhouse gasses (N2O, SF6) have not been included in the studies since their share is maximum 1% of all greenhouse effect gas emissions released when transporting natural gas.

For reducing greenhouse gases to a common factor, the following tCO2-eq coefficients have been used: - 25 as methane conversion factor (IPCC, 2014); - 1 as carbon dioxide conversion factor. The following conditions have been kept out of carbon footprint assessment: - emergency variants; - natural gas offshore transportation processing facilities construction period. For the source data of the offshore pipeline system carbon footprint assessment, refer to Tables 4.14 and 4.15.

Table 4.14. Source data for estimating a carbon footprint of the offshore pipeline system (the Black Sea projects) Ser. Parameter Characteristic No. 1 Route name (life cycle phases) Beregovaya CS – subsea pipeline to come ashore on the Turkish coast (Samsun)1) 2 The Blue Stream subsea pipeline length 400 km2) 3 Estimated gas supply volume to be delivered 16 bn m3/year2) under the Blue Stream project 4 Estimated Beregovaya CS power 150 MW (x6 GCUs)3) 5 Gas-compressor unit fuel gas flow rate 7483 m3/h (25MW GCU with Nuovo Pignone compressors)4) 6 CCU operating duty 4+2 (standby)5) 7 CS natural gas flow required under 1.5-2% of auxiliary CS natural gas demands5) a maintenance plan 8 Product transportation, bn m3*km 64006)

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7) 9 Emission of CO2, t CO2/year 433908 7) 10 Emission of CH4, t CO2-eq/year 71700 1) The Blue Stream project; 2) www.gazprom.ru; 3) www.regnum.ru; 4) Gazprom Regulation 2-1.19-540-2011; 5) expert appraisal; 6) item 2*item 3; 7) as rated according to the IPCC methodology [6] and methodological guidelines [7]

The carbon footprint has been estimated using the GHGenius design model [8]. Particular natural gas transportation technologies to be rather unique for global market are implemented for ensuring industrial and environmental safety of production facilities. For example, a cascade ultrahigh pressure process is used for transporting gas along the Black Sea route (the Blue Stream project) and dehydration and single-phase processes are used for processing gas prior to transporting along the subsea pipeline. This technology has been acknowledged as the most effective and reliable in the world. Gas-compressor unit emissions are to be taken into account for estimating correct carbon footprint parameters since such compressor units are the main natural gas consumers and greenhouse gas emission points. Actually, more than 80% of gas consumed for own technological needs during transportation is used for feeding such compressors.

Table 4.15. Source data for estimating a carbon footprint of the offshore pipeline system (the Baltic Sea projects) Ser. Parameter Characteristic No. 1 Route name (life cycle phases) Portovaya CS – subsea pipeline to come ashore on the Germany coast (Greifswald)1) 2 The Nord Stream subsea pipeline length 1224 km2) 3 Estimated gas supply volume to be delivered 55 bn m3/year2) under the Nord Stream project 4 Estimated Portovaya CS power 366 MW (x8 GCUs)1) 5 Gas-compressor unit fuel gas flow rate 8800 m3/h (52MW GCU, TRENT60DLE)3) 6 CCU operating duty 66+2 (standby)4) 7 CS natural gas flow required under 1.5-2% of auxiliary CS natural gas demands4) a maintenance plan 8 Product transportation, bn m3*km 673205)

6) 9 Emission of CO2, t CO2/year 765414 6) 10 Emission of CH4, t CO2-eq/year 89625 1) The Nord Stream project;2) www.gazprom.ru; 3) Gas Turbines – Saturn data; 4) expert appraisal; 5) item 2* item 3; 6) as rated according to the IPCC methodology [6] and methodological guidelines [7]

161 CHAPTER 4

Commonly, an essential share of the total natural gas consumed by the linear part of the gas main pipeline falls on a maintenance period when unavoidable loss of natural gas occurs with gas being discharged to atmosphere. A carbon footprint specified for new subsea gas pipelines only is discussed in this paper. Therefore, no greenhouse gas emissions released during the maintenance works can be considered typical for any offshore gas pipeline areas. As referred to the source data (Tables 4.14 and 4.15), we shall determine specific parameters that characterize a carbon footprint of natural gas transported by the subsea gas pipelines (Table 4.16). This carbon footprint is substantially different since the Black Sea natural gas transportation system requires a large amount of process and energy resources to be consumed for supplying natural gas over 25 MPa pipelines along the sea bottom at the depth of more than 2000 meters.

Table 4.16. Specific parameters representative of a carbon footprint of subsea natural gas pipelines Parameter Unit Value Black Sea projects Specific gas piping energy consumption J/J*km 37.0*10-6

Specific greenhouse gas emissions* gCO2-eq/GJ 962 Baltic Sea projects Specific gas piping energy consumption (Baltic sea projects) J/J*km 5.0*10-6

Specific greenhouse gas emissions* gCO2-eq/GJ 344 * as rated per product (natural gas delivered to a consumer)

The source data for estimating a carbon footprint of natural gas shipped by LNG carrier vessels are listed in Tables 4.17 and 4.18. Using state-of-the-art gas liquefaction processes to be supported by average annual atmospheric temperatures it is possible to gain high LNG output performance, to reduce energy cost, and to minimize greenhouse gas emissions. New-generation vessels operating in ‘slow steaming‘ mode (speed of 7 to 9 knots with the main engine operating at the load below 40%) can be used to reduce the fuel flow and to increase energy performance. Besides, this subsea natural gas transportation technology is featured with its environment-friendly characteristics with greenhouse gas emissions reduced.

162 CHAPTER 4

Table 4.17. Source data for estimating a carbon footprint of natural gas shipped by LNG carrier vessels (the Baltic Sea projects) Ser. Parameter Characteristic No. 1 Route name (life cycle phases) LNG plant – LNG tanker (shipment to Kaliningrad) – LNG receiving terminal (regasification)1) 2 LNG transportation route LNG plant (Portovaya CS area) – Kaliningrad2)

3 Sea route length 900 km2) 4 Estimated LNG output volume 2 MM t/year1)1) 5 LNG plant fuel gas consumption 10% of LNG raw product2)2) 6 LNG carrier vessel Veliky Novgorod, SKF1) 7 Load-carrying capacity 170 thousand m3 (72 thou tons of LNG1) 8 Fuel Gas (stripping gas), diesel2) 9 Stripping gas 0,10.15% per 24 hours of LNG volume2)

3) 10 Marine vessel CO2 emissions 430 g CO2/kW*h 11 Mean operating speed with an allowance for 25 km/h (600 km/day)2) climatic and environmental conditions 12 Mean marine vessel engine power 20 MW2) 13 Regasification plant Submerged-type evaporator4)4) 14 Regasification gas flow 1.5% of regasified LNG2) 1) LNG Plant at the Portovaya CS area; 2) expert appraisal; 3) Magalog, GL and HELCOM studies; 4) www.cnoocltd.com

Natural gas utilized as motor fuel for feeding on-board power units is a product that meets the requirements set out in the MARPOL Convention, Annex IV, applicable to special monitoring areas the Baltic Sea belongs to.

Table 4.18. Source data for estimating a carbon footprint of natural gas shipped by LNG carrier vessels (the Asia-Pacific projects) № Наименование показателя Характеристика показателя п/п 1 Route name (life cycle phases) LNG plant (liquefaction) – LNG tanker (shipment to Shanghai (China)) – LNG receiving terminal (regasification)1) 2 LNG transportation route Yamal Peninsula – Northern Sea Route – Bering Strait – Pacific Ocean – Shanghai1)

163 CHAPTER 4

3 Sea route length 6000 miles2) 4 Estimated LNG output volume 16.5 MM t/year1) 5 LNG plant fuel gas consumption 10% of LNG raw product3) 6 LNG carrier vessel Arc7 ice-breaking tanker4) 7 Load-carrying capacity 172 thousand m3 (73 thou tons of LNG)4) 8 Fuel Gas (stripping gas), diesel3) 9 Stripping gas 0.15% per 24 hours of LNG volume5)

6) 10 Marine vessel CO2 emissions 430 g CO2/kW*h 11 Mean operating speed with an allowance for 25 km/h (600 km/day)3) climatic and environmental conditions 12 Mean marine vessel engine power 35 MW3) 13 Regasification plant Submerged-type evaporator7) 14 Regasification gas flow 1.5% of regasified LNG3) 1) Yamal LNG project; 2) www.arctic-info.ru; 3) expert appraisal; 4) www.sever-press.ru; 5) API Gudelines, 2015; 6) Magalog, GL and HELCOM studies; 7) www.cnoocltd.com

A carbon footprint of the abovementioned gas delivery projects has the values of the same order (Table 4.19). As the main environmental impact is caused by the LNG plant, the rest life cycle phases have less effect and actually do not influence the total value of a carbon footprint of LNG shipped by gas carrier vessels.

Table 4.19. Specific parameters representative of a carbon footprint of natural gas shipped by LNG carrier vessels Parameter Unit Unit LNG shipment to Asia-Pacific countries Specific LNG piping energy consumption J/J*km 10.0*10-6

Specific greenhouse gas emissions* gCO2-eq/GJ 11053 Baltic Sea projects Specific LNG piping energy consumption J/J*km 6.0*10-6

Specific greenhouse gas emissions* gCO2-eq/GJ 10457 * as rated per product (natural gas delivered to a consumer)

The new natural gas transportation technology is to be introduced for transporting compressed bottled gas on CNG carrier vessels (CNG technology). CNG carrier vessels of approximately 30 MM m3 load-carrying capacity are equivalent to a pipeline which has 1.5-1.6 bn m3/year capacity. Such CNG technology is featured with the process of

164 CHAPTER 4 charging gas carrier vessels directly from a deposit using gas formation pressure (loading by gravity). The most significant advantage of the CNG technology is applicability of CNG carrier vessels for servicing unfurnished fields and terminal points which are difficult for access. Two alternative variants have been studied for estimating a carbon footprint of CNG: charging a carrier vessel with natural gas out of offshore holes by gravity and using a booster compressor station for building gas pressure up to 25 MPa before gas carrier vessels are loaded. The source data for estimating a carbon footprint of natural gas shipped by CNG carrier vessels are listed in Tables 4.20, 4.21, and 4.22.

Table 4.20. Source data for estimating a carbon footprint of natural gas shipped by CNG carrier vessels (the Baltic Sea projects) Ser. Parameter Characteristic No. 1 Route name (life cycle phases) Portovaya CS (tanker loading) – CNG tanker (shipment to Kaliningrad) – CNG receiving terminal (supplying gas to a consumer)1) 2 CNG transportation route Portovaya CS – Kaliningrad1) 3 Sea route length 900 km1) 4 Estimated CNG output volume 3 bn m3/year2) 5 CNG plant fuel gas consumption 22.0 MM m3 1) 6 CNG carrier vessel Veliky Novgorod, SKF1) 7 Load-carrying capacity 170 thousand m3 1) 8 Fuel Gas (primary, +1% of diesel)1) 9 Mean operating speed with an allowance for 25 km/h 1) climatic and environmental conditions 1) expert appraisal; 2) equivalent to the Baltic LNG output volume

165 CHAPTER 4

Table 4.21. Source data for estimating a carbon footprint of natural gas shipped by CNG carrier vessels (The Black Sea projects) Ser. Parameter Characteristic No. 1 Route name (life cycle phases) Beregovaya CS (tanker loading) – CNG tanker (shipment to Samsun) – CNG receiving terminal (supplying gas to a consumer)1) 2 CNG transportation route Portovaya CS – Samsun1) 3 Sea route length 400 km1) 4 Estimated CNG output volume 16 bn m3/year2) 5 CNG plant fuel gas consumption 259 MM m3 1) 6 CNG carrier vessel Elba1) 7 Load-carrying capacity 40 thousand m3 1) 8 Fuel Gas (primary, +1% of diesel)1) 9 Mean operating speed with an allowance for 14 km/h 1) climatic and environmental conditions 1) expert appraisal; 2) equivalent to the Blue Stream natural gas transportation parameter

Table 4.22. Source data for estimating a carbon footprint of natural gas shipped by CNG carrier vessels (Asia-Pacific projects) Ser. Parameter Characteristic No. 1 Route name (life cycle phases) Sabetta (tanker loading) – CNG tanker (shipment to China (Shanghai)) – CNG receiving terminal (supplying gas to a consumer)1) 2 CNG transportation route Sabetta – Samsun1) 3 Sea route length 12000 km1) 4 Estimated CNG output volume 24.2 bn m3/year2) 5 CNG plant fuel gas consumption 2206 MM m3 1) 6 CNG carrier vessel Arc7 ice-breaking tanker1) 7 Load-carrying capacity 172 thousand m3 1) 8 Fuel Gas (primary, +1% of diesel)1) 9 Mean operating speed with an allowance for 25 km/h 1) climatic and environmental conditions 1) expert appraisal; 2) equivalent to the LNG Yamal project natural gas transportation parameter

166 CHAPTER 4

With the Asia-Pacific gas supply projects implemented, the largest carbon footprint of natural gas shipped by CNG carrier vessels may be steadily forecasted since gas carrier vessels energy cost grows up while passing long distances due to influence of particular environment and climatic factors (Table 4.23).

Table 4.23. Carbon footprint of natural gas shipped by CNG carrier vessels,

gCO2-eq/GJ of natural gas delivered to a consumer Parameter Value Asia-Pacific CNG supply projects 5542 (5147*) The Baltic Sea projects 1180 The Black Sea Projects 1037 * charging carrier vessels with gas by gravity out of offshore fields

Thereafter, the environmental appraisal was made for particular project implementation conditions (transportation volume and distance, number of gas carrier vessels) set out in Section 2. The carbon footprint diagrams as related to transportation distance and annual volume specified for every alternative technology were plotted on the basis of the carbon footprint data array. Then, the above graphical crossover points (where available) were found by using the grapho-analytical method. For details of such relations, refer to Figures 4.6 and 4.7. Figure 4.6 shows the intersect point of the curves that characterize the CNG and LNG transportation carbon footprint. This point at plane coordinates (V; L): (V≈21.55; L=4200) demonstrates that the LNG vessel carrier transportation method is more favorable for the environment than that of the CNG vessel carrier transportation (with a distance extended). Figure 4.7 shows the intersect point of the curves at plane coordinates (V; L): (V≈12; L=1000) that characterize carbon footprint of gas supplied by subsea pipelines (The Baltic Sea projects) and by CNG carrier vessels. Those point demonstrates that the subsea pipeline gas transportation method is more favorable than the CNG transportation method (with the freight flow grown up). The point array obtained was graphically illustrated in plane (V, L). The methodology specified in Section 1 was applied. The points were linked to produce lines of critical equivalence separating the environmentally suitable zones to be efficiently used for involving every transportation technology regarding the least possible environmental affect depending on annual gas transportation volume and distance. Figure 4.7 shows the zones to be efficiently used for involving various natural gas transportation technologies, thereby minimizing any environmental impact and climate abnormal conditions. With the Baltic Sea and the Black Sea offshore projects implemented for transporting

167 CHAPTER 4

Fig. 4.6. Natural gas offshore transportation carbon footprints as rated against distances with various technologies applied for transporting annually the volume of 21.55 billion m3

Fig.4.7. Natural gas offshore transportation carbon footprints as rated against freight flows with various technologies applied for transporting to a 1000 km distance

168 CHAPTER 4

3 and 5 bn m3/year of gas to the distance of 400 to 2500 km, the environmental carbon footprint impact can be totally minimized by using the CNG transportation technology (see the shaded area in Figure 3.7). If natural gas is supplied by LNG carrier vessels under the abovementioned projects, the offshore transportation carbon footprint will be expanded.

Point No. Gas volume, bn m3/year Route 1 5 Russkaya CS – Turkey (389 km) 2 3 3 5 Russkaya CS – Bulgaria (927.2 km) 4 3 5 5 Portovaya CS – Kaliningrad (1040.5 km) 6 3 7 5 Portovaya CS – Germany (1225.5 km) 8 3 9 5 Portovaya CS – Great Britain (2500 km) 10 3 Fig. 4.8. Technologically effective gas transportation regions with minimum environmental and climate impact

169 CONCLUSIONS AND RECOMMENDATIONS The comparative analysis of economic efficiency of various offshore gas transportation methods shows that the compressed gas transportation technology is suitable enough as it can, on the one hand, contribute to growth of the product and service diversification level and, on the other hand, allowing to reduce gas transportation expenditures. Particularly, the logistics costs related to the charges for delivery of maximum 3 bn m3/ year of gas using the infrastructure of compressed gas transportation facilities in the Black Sea and in the Baltic Sea regions can be significantly reduced. Should the volume of gas transported along the Black Sea route come out beyond the range of 3 to 5 bn m3, the transportation method should be properly validated for its economic efficiency. Efficiency of the compressed natural gas delivery method is attained owing to systematic use of the gas transportation benefits, particularly: – lower cost of shore facilities in comparison with the LNG technology when it is necessary to construct complex liquefaction, storage and regasification systems; – Environmental safety ensured by the low gas transportation rate of loss. As it has been proved by the offshore gas transportation studies, gas alternately delivered by subsea pipelines, CNG carrier vessels, and LNG carrier vessels can induce different carbon footprint factors. The comparative assessment of the Black and the Baltic Sea transportation projects currently using natural gas makes it possible to arrive at the conclusion that the new compressed natural gas transportation technology is suitable for reducing a carbon footprint of gas supplied overseas in particular conditions. With the CNG technology applied in the currently used the Baltic Sea projects, a carbon footprint occurs to be less than that of gas supplied along subsea pipelines with the volumes as follows: – up to 10-12 bn m3, if supplied maximum to a 1000 km distance; – 12 to 20 bn m3, if supplied to a 2000 to 2500 km distance; – 20 to 25 bn m3, if supplied to a 2000 to 2500 km distance. When natural gas volumes exceeding 12-15 bn m3 transported to a 1000 km distance, exceeding 15-20 bn m3 transported to a 1000 to 2000 km distance and exceeding 20-25 bn m3 transported to a 1000 to 2000 km distance over subsea pipelines, a carbon footprint is less than that specified when using the CNG technology. As compared to the CNG technology applied for transporting natural gas to long distances (extended gas flow output), the value of the carbon footprint of the subsea gas pipelines is less. And it should be noted that the subsea pipelines have limited length and depth parameters. With natural gas transported to the distance exceeding 4000 km, the CNG technology cannot be as preferable as that of LNG carrier vessels since a carbon footprint grows up with the distance expanded (due to increased gas flow output). But it should be noted that the LNG transportation systems require large amounts of gas delivered and significant shore infrastructure charges.

170 CONCLUSIONS AND RECOMMENDATIONS

Thus, the CNG technology applied under the promising Baltic and the Black Sea projects with 3 and 5 bn m3/year of gas supplied to a 400 to 2500 km is the most favorable for the environmental and climatic conditions against that of the LNG subsea pipelines and gas carrier vessels.

171 BIBLIOGRAPHY 1. Ametistova L.E., Knizhnikov A.Yu. Environmental Aspects of LNG Projects in Arctic Conditions – World Wildlife Fund (WWF), Moscow, 2016, 48 p. 2. Analytical survey, WWF 2016. Ametistova L.E., Knizhnikov A.Yu., «Environmental Aspects of LNG Projects in Arctic Conditions» 3. Atlas ☺Environmental Impact Caused by Motor Vehicles Converted from Gasoline to Natural Gas Fuel in the Russian Federation», Gazprom Public Company, M. 2015. 4. Battalkhanov A.A. Step-by-Step Development of the Compressed Natural Gas Market // World Science Journal, - 2015, No. 6, pp. 4-11. 5. Blinkov A.N., Vlasov A.A., Offshore Compressed Gas Transportation. URL: http://www.slb.com/~/media/Files/resources/oilfield_review/russia08/sum08/04_ movingnaturalgas.pdf. 6. Blinkov A.N., Vlasov A.A., Litsis A.V., Shurpyak V.K., CNG – New Gas offshore Transportation Technology, Problems // Scientific and Technical Digest of the Russian Marine Registry of Shipping, 2007, No. 30, pp. 127-162. 7. Vasserman A.A., Lavrechenko G.K., Analysis of Gas Carriage by Sea // Technical Gas Products – 2014, No. 2, pp. 57-65. 8. Vlasyev M.V., Feasibility Study of the Vessel Making Technology for Transporting Compressed Natural Gas; Abstract of the Thesis, St. Petersburg, 2015, 27 p. 9. Votintsev A.V., Compressed Natural Gas Transportation // Gas Industry, 2007, No. 2, pp. 62-63. 10. Vympel. Vessel Design Engineering Department, Nizhny Novgorod, URL: http://www.vympel.ru. GasServiceComposite. URL: http: //gassc.com/avtonomnaya- gazifikatsiya.html. 11. Glenn Perry F. (SA) RF Patent No. 2296266. Cooled Natural Gas Transportation Method, Hibino Kouetsu, Honma Nobutaka, Terasima Yukio, Sinozava Tamio, Okui Tosiharu, Inomata Kyioto, PR Patent No. 2224171, Cooled Methane-Based Natural Gas Storage Method; Patent Prioritet 14.12.1999. 12. GOST 31967-2012 Internal Combustion Reciprocating Engines – Emissions of Harmful Substances with the Exhaust Gases – Limit Values and Test Methods. 13. Power Equipment Catalog. Turbines and Diesel Engines – 2016, Rybinsk, 2017. 14. IPCC, 2006. Guiding Principles of National Greenhouse Gas Inventories. 15. Methodological Guidance for Monitoring Greenhouse Gas Emissions produced by Economic Entities in the Russian Federation. Order No. 300 of Ministry of Natural Resources of the Russian Federation dated 30.06.2015. 16. Minnegulova F.S., Krapivsky E.I., Analysis of Mixture Phase State Characteristics of the Liquefied Yanal Hydrocarbons at Low Temperatures // Gas Industry, 2014, No. 1, pp. 86-90.

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174 APPENDIX A COST-EFFECTIVE VALUES The cost-effective values as rated for alternative gas transportation options are listed in Tables A.1-A.42. Such cost-effective values are shown exclusive custom duties.

175 APPENDIX A 15 2.5 7.5 922 782 141 406 276 130 782 533 122 1.30 11.0 19.6 1.37 -824 4 066 2 663 2 130 2 130 21.55 540.05 538.75 12.00% 10 3.2 9.7 790 669 120 350 248 103 669 456 104 1.03 11.0 19.6 1.37 -705 3 483 2 280 1 824 1 824 14.37 360.28 359.25 12.00% /year 3 85 4.3 7.5 790 670 121 333 248 670 456 104 0.85 11.0 19.6 1.37 12.9 -706 3 468 2 281 1 825 1 825 10.78 270.35 269.50 12.00% 5 73 97 6.0 730 619 111 308 236 619 422 0.73 11.0 19.6 1.37 7.18 17.9 -652 3 206 2 109 1 687 1 687 180.23 179.50 12.00% Gas transportation volume, bn m bn volume, Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 89 40 77 7.9 585 496 218 178 496 338 0.40 11.0 19.6 1.37 4.31 23.6 -523 2 541 1 690 1 352 1 352 108.15 107.75 12.00% 1 74 20 64 483 409 165 145 409 279 0.20 11.0 19.6 1.37 19.3 1.44 57.8 -431 2 082 36.20 36.00 1 395 1 116 1 116 12.00% 3 3 3 3 per 100 km 3 % Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou Table А.1. Cost-effective values. Gas transportation by overland pipeline. Distance – 300 km Distance pipeline. overland А.1. Cost-effectiveby values. transportation Gas Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Commercial gas gas Commercial gas Auxiliary cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

176 APPENDIX A 15 2.7 511 870 243 443 2.43 11.0 19.6 1.37 26.7 3 348 2 837 1 113 2 837 9 666 1 933 7 733 7 733 21.55 -2990 14 396 541.18 538.75 12.00% 10 3.5 443 964 777 188 384 1.88 11.0 19.6 1.37 34.8 2 905 2 462 2 462 8 389 1 678 6 711 6 711 14.37 -2595 12 493 361.13 359.25 12.00% /year 3 3.9 7.5 376 859 684 175 326 1.75 11.0 19.6 1.37 39.5 2 464 2 088 2 088 7 115 1 423 5 692 5 692 10.78 -2201 10 636 271.25 269.50 12.00% 5 5.4 346 791 641 150 300 1.50 11.0 19.6 1.37 7.18 54.5 9 779 2 265 1 920 1 920 6 540 1 308 5 232 5 232 -2023 181.00 179.50 12.00% Gas transportation volume, bn m bn volume, Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 85 7.3 280 582 497 243 0.85 11.0 19.6 1.37 4.31 73.1 7 877 1 839 1 558 1 558 5 309 1 062 4 247 4 247 -1642 108.60 107.75 12.00% 1 43 232 450 408 878 201 0.43 11.0 19.6 1.37 18.0 1.44 6 482 36.43 36.00 1 520 1 288 1 288 4 389 3 511 3 511 180.1 -1358 12.00% 3 3 3 3 per 100 km 3 % Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou Table А.2. Cost-effective values. Gas transportation by overland pipeline. Distance – 1000 km Distance pipeline. overland А.2. Cost-effectiveby values. transportation Gas Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Commercial gas gas Commercial gas Auxiliary cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

177 APPENDIX A 15 2.7 468 880 4.68 11.0 19.6 1.37 53.0 6 653 5 638 1 015 2 172 1 705 5 638 3 842 21.55 -5943 28 572 543.43 538.75 19 211 15 369 15 369 12.00% 10 3.4 867 328 752 3.28 11.0 19.6 1.37 67.7 5 684 4 817 1 773 1 446 4 817 3 283 14.37 -5077 24 328 362.53 359.25 16 413 13 130 13 130 12.00% /year 3 4.0 7.5 752 410 652 4.10 11.0 19.6 1.37 79.1 4 927 4 176 1 776 1 366 4 176 2 845 10.78 -4401 21 327 273.60 269.50 14 227 11 382 11 382 12.00% 5 5.4 691 280 599 2.80 11.0 19.6 1.37 7.18 4 530 3 839 1 563 1 283 3 839 2 616 108.9 -4047 19 539 182.30 179.50 13 081 10 465 10 465 12.00% Gas transportation volume, bn m bn volume, Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 7.3 561 994 170 486 1.70 11.0 19.6 1.37 4.31 3 677 3 116 1 164 3 116 2 123 8 494 8 494 146.2 -3284 15 755 109.45 107.75 10 617 12.00% 1 90 464 905 815 402 0.90 11.0 19.6 1.37 18.0 1.44 36.90 36.00 3 040 2 576 2 576 8 778 1 756 7 023 7 023 360.2 -2716 12 969 12.00% 3 3 3 3 per 100 km 3 % Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou Table А.3. Cost-effective values. Gas transportation by overland pipeline. Distance – 2000 km Distance pipeline. overland А.3. Cost-effectiveby values. transportation Gas Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Commercial gas gas Commercial gas Auxiliary cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

178 APPENDIX A 15 2.7 800 8.00 11.0 19.6 1.37 81.4 8 619 1 551 3 518 2 718 8 619 5 873 1 345 21.55 -9084 43 872 546.75 538.75 10 170 29 365 23 492 23 492 12.00% 10 3.4 545 5.45 11.0 19.6 1.37 8 590 7 280 1 310 2 767 2 222 7 280 4 960 1 136 14.37 102.6 -7673 36 851 364.70 359.25 24 802 19 842 19 842 12.00% /year 3 4.0 7.5 680 977 6.80 11.0 19.6 1.37 7 390 6 263 1 127 2 729 2 049 6 263 4 268 10.78 118.9 -6601 32 052 276.30 269.50 21 338 17 070 17 070 12.00% 5 5.4 415 899 4.15 11.0 19.6 1.37 7.18 6 795 5 759 1 037 2 339 1 924 5 759 3 924 163.2 -6070 29 303 183.65 179.50 19 621 15 697 15 697 12.00% Gas transportation volume, bn m bn volume, Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 7.3 841 258 729 2.58 11.0 19.6 1.37 4.31 5 516 4 674 1 749 1 492 4 674 3 185 219.4 -4927 23 635 110.33 107.75 15 926 12 741 12 741 12.00% 1 696 140 603 1.40 11.0 19.6 1.37 18.0 1.44 37.40 36.00 4 560 3 865 1 363 1 223 3 865 2 634 540.5 -4073 19 458 13 168 10 534 10 534 12.00% 3 3 3 3 per 100 km 3 % Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou Table А.4. Cost-effective values. Gas transportation by overland pipeline. Distance – 3000 km Distance pipeline. overland А.4. Cost-effectiveby values. transportation Gas Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Commercial gas gas Commercial gas Auxiliary cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

179 APPENDIX A 15 2.7 11.0 19.6 1.37 11.20 2 062 4 708 3 588 1 120 7 806 1 788 21.55 108.3 58 346 549.95 538.75 13 518 11 456 11 456 39 031 31 225 31 225 -12074 12.00% 10 3.4 765 7.65 11.0 19.6 1.37 9 742 1 754 3 764 2 999 9 742 6 638 1 520 14.37 137.4 49 376 366.90 359.25 11 495 33 192 26 553 26 553 -10268 12.00% /year 3 4.0 7.5 925 9.25 11.0 19.6 1.37 9 853 8 350 1 503 3 657 2 732 8 350 5 690 1 303 10.78 158.6 -8801 42 754 278.75 269.50 28 450 22 760 22 760 12.00% 5 5.4 555 5.55 11.0 19.6 1.37 7.18 9 061 7 679 1 382 3 121 2 566 7 679 5 232 1 198 217.7 -8093 39 073 185.05 179.50 26 162 20 929 20 929 12.00% Gas transportation volume, bn m bn volume, Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 7.3 345 973 3.45 11.0 19.6 1.37 4.31 7 354 6 232 1 122 2 334 1 989 6 232 4 247 292.5 -6569 31 515 111.20 107.75 21 235 16 988 16 988 12.00% 1 928 188 804 1.88 11.0 19.6 1.37 18.0 1.44 37.88 36.00 6 080 5 153 1 818 1 631 5 153 3 511 720.7 -5431 25 945 17 557 14 045 14 045 12.00% 3 3 3 3 per 100 km 3 % Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou Table А.5. Cost-effective values. Gas transportation by overland pipeline. Distance – 4000 km Distance pipeline. overland А.5. Cost-effectiveby values. transportation Gas Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Commercial gas gas Commercial gas Auxiliary Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

180 APPENDIX A 15 2.7 11.0 19.6 1.37 135.9 14.48 2 586 5 978 4 530 1 448 9 788 2 241 21.55 73 234 553.23 538.75 16 950 14 364 14 364 48 941 39 153 39 153 -15140 12.00% 10 3.4 968 9.68 11.0 19.6 1.37 172.3 2 197 4 743 3 776 8 316 1 904 14.37 61 884 368.93 359.25 14 401 12 204 12 204 41 581 33 265 33 265 -12863 12.00% /year 3 4.0 7.5 11.0 19.6 1.37 198.4 11.90 1 879 4 605 3 415 1 190 7 113 1 629 10.78 53 476 281.40 269.50 12 317 10 438 10 438 35 563 28 450 28 450 -11001 12.00% 5 5.4 703 7.03 11.0 19.6 1.37 7.18 272.1 9 598 1 728 3 910 3 207 9 598 6 540 1 498 48 849 186.53 179.50 11 326 32 702 26 162 26 162 -10116 12.00% Gas transportation volume, bn m bn volume, Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 7.3 433 4.33 11.0 19.6 1.37 4.31 365.6 9 193 7 791 1 402 2 919 2 486 7 791 5 309 1 216 -8211 39 395 112.08 107.75 26 543 21 235 21 235 12.00% 1 235 18.0 2.35 11.0 19.6 1.37 1.44 38.35 36.00 900.9 7 601 6 441 1 159 2 273 2 038 6 441 4 389 1 005 -6789 32 432 21 946 17 557 17 557 12.00% 3 3 3 3 per 100 km 3 % Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou Table А.6. Cost-effective values. Gas transportation by overland pipeline. Distance – 5000 km Distance pipeline. overland А.6. Cost-effectiveby values. transportation Gas Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Commercial gas gas Commercial gas Auxiliary tariff transportation Gas Gas transportation cost transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

181 APPENDIX A 73 62 11 32 22 10 62 42 10 15 0.6 0.2 -66 324 212 170 170 1.30 11.0 19.6 1.37 21.55 540.05 538.75 12.00% 8 8 63 53 10 28 20 53 36 10 0.8 0.3 -56 277 182 145 145 1.03 11.0 19.6 1.37 14.37 360.28 359.25 12.00% /year 3 7 8 63 53 10 27 20 53 36 1.0 0.3 7.5 -56 276 182 145 145 0.85 11.0 19.6 1.37 10.78 270.35 269.50 12.00% 9 6 5 8 58 49 25 19 49 34 1.4 0.5 -52 255 168 134 134 0.73 11.0 19.6 1.37 7.18 180.23 179.50 12.00% Gas transportation volume, bn m bn volume, Gas transportation Gas transportation volume, million t/year volume, Gas transportation 7 3 3 6 47 40 17 14 40 27 1.9 0.6 -42 202 135 108 108 0.40 11.0 19.6 1.37 4.31 108.15 107.75 12.00% 6 2 1 5 38 33 13 12 33 22 89 89 4.6 1.5 -34 166 111 0.20 11.0 19.6 1.37 1.44 36.20 36.00 12.00% 3 3 3 3 % per 100 km 3 Unit years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m Table А.7. Cost-effective values. Gas transportation by overland pipeline. Distance – 300 km Distance pipeline. overland А.7. Cost-effectiveby values. transportation Gas Table Parameters Gross gas Gross Commercial gas gas Commercial gas Auxiliary cost transportation Gas Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

182 APPENDIX A 41 89 69 19 35 15 2.1 0.2 267 226 226 770 154 616 616 2.43 11.0 19.6 1.37 -238 1 147 21.55 538.75 541.18 12.00% 35 77 62 15 31 10 2.8 0.3 995 231 196 196 668 134 535 535 1.88 11.0 19.6 1.37 -207 14.37 359.25 361.13 12.00% /year 3 30 68 54 14 26 3.1 0.3 7.5 847 196 166 166 567 113 453 453 1.75 11.0 19.6 1.37 -175 10.78 269.50 271.25 12.00% 5 28 63 51 12 24 4.3 0.4 779 180 153 153 521 104 417 417 1.50 11.0 19.6 1.37 7.18 -161 179.50 181.00 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 7 22 46 40 85 19 5.8 0.6 627 146 124 124 423 338 338 0.85 11.0 19.6 1.37 4.31 -131 107.75 108.60 12.00% 1 3 18 36 32 70 16 1.4 516 121 103 103 350 280 280 0.43 14.3 11.0 19.6 1.37 1.44 -108 36.00 36.43 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m Table А.8. Cost-effective values. Gas transportation by overland pipeline. Distance – 1000 km Distance pipeline. overland А.8. Cost-effectiveby values. transportation Gas Table Parameters Gross gas Gross Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas tariff transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

183 APPENDIX A 81 37 70 15 4.2 0.2 530 449 173 136 449 306 4.68 11.0 19.6 1.37 -473 2 275 1 530 1 224 1 224 21.55 538.75 543.43 12.00% 69 26 60 10 5.4 0.3 453 384 141 115 384 261 3.28 11.0 19.6 1.37 -404 1 937 1 307 1 046 1 046 14.37 359.25 362.53 12.00% /year 3 60 33 52 6.3 7.5 0.3 392 333 141 109 333 227 906 906 4.10 11.0 19.6 1.37 -351 1 699 1 133 10.78 269.50 273.60 12.00% 5 55 22 48 8.7 0.4 361 306 124 102 306 208 833 833 2.80 11.0 19.6 1.37 7.18 -322 1 556 1 042 179.50 182.30 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 45 93 79 14 39 0.6 293 248 248 846 169 676 676 1.70 11.0 19.6 1.37 4.31 11.6 -262 1 255 107.75 109.45 12.00% 7 1 37 72 65 32 1.4 242 205 205 699 140 559 559 0.90 11.0 19.6 1.37 1.44 28.7 -216 36.00 36.90 1 033 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m Table А.9. Cost-effective values. Gas transportation by overland pipeline. Distance – 2000 km Distance pipeline. overland А.9. Cost-effectiveby values. transportation Gas Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

184 APPENDIX A 64 15 6.5 0.2 810 686 124 280 216 686 468 107 8.00 11.0 19.6 1.37 -723 3 494 2 339 1 871 1 871 21.55 538.75 546.75 12.00% 43 90 10 8.2 0.3 684 580 104 220 177 580 395 5.45 11.0 19.6 1.37 -611 2 935 1 975 1 580 1 580 14.37 359.25 364.70 12.00% /year 3 90 54 78 9.5 7.5 0.3 589 499 217 163 499 340 6.80 11.0 19.6 1.37 -526 2 553 1 699 1 359 1 359 10.78 269.50 276.30 12.00% 5 83 33 72 0.4 541 459 186 153 459 313 4.15 11.0 19.6 1.37 7.18 13.0 -483 2 334 1 563 1 250 1 250 179.50 183.65 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 67 21 58 0.6 439 372 139 119 372 254 2.58 11.0 19.6 1.37 4.31 17.5 -392 1 882 1 268 1 015 1 015 107.75 110.33 12.00% 1 55 97 11 48 1.4 363 308 109 308 210 839 839 1.40 11.0 19.6 1.37 1.44 43.0 -324 36.00 37.40 1 550 1 049 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m Table А.10. Cost-effective values. Gas transportation by overland pipeline. Distance – 3000 km Distance pipeline. overland А.10. Cost-effectiveby values. transportation Gas Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

185 APPENDIX A 89 15 8.6 0.2 912 164 375 286 912 622 142 11.0 19.6 1.37 -962 11.20 4 647 1 077 3 108 2 487 2 487 21.55 538.75 549.95 12.00% 61 10 0.3 915 776 140 300 239 776 529 121 7.65 10.9 11.0 19.6 1.37 -818 3 932 2 643 2 115 2 115 14.37 359.25 366.90 12.00% /year 3 74 0.3 7.5 785 665 120 291 218 665 453 104 9.25 12.6 11.0 19.6 1.37 -701 3 405 2 266 1 813 1 813 10.78 269.50 278.75 12.00% 5 44 95 0.4 722 612 110 249 204 612 417 5.55 17.3 11.0 19.6 1.37 7.18 -645 3 112 2 084 1 667 1 667 179.50 185.05 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 89 27 77 0.6 586 496 186 158 496 338 3.45 23.3 11.0 19.6 1.37 4.31 -523 2 510 1 691 1 353 1 353 107.75 111.20 12.00% 1 74 15 64 1.4 484 410 145 130 410 280 1.88 57.4 11.0 19.6 1.37 1.44 -433 36.00 37.88 2 066 1 398 1 119 1 119 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m Table А.11. Cost-effective values. Gas transportation by overland pipeline. Distance – 4000 km Distance pipeline. overland А.11. Cost-effectiveby values. transportation Gas Table Parameters Gross gas Gross Gas transportation cost transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary tariff transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

186 APPENDIX A 15 0.2 206 476 361 115 780 179 10.8 11.0 19.6 1.37 14.48 5 832 1 350 1 144 1 144 3 898 3 118 3 118 21.55 -1206 538.75 553.23 12.00% 77 10 0.3 972 175 378 301 972 662 152 13.7 9.68 11.0 19.6 1.37 4 928 1 147 3 311 2 649 2 649 14.37 -1024 359.25 368.93 12.00% /year 3 95 0.3 7.5 981 831 150 367 272 831 566 130 15.8 11.0 19.6 1.37 -876 11.90 4 259 2 832 2 266 2 266 10.78 269.50 281.40 12.00% 5 56 0.4 902 764 138 311 255 764 521 119 7.03 21.7 11.0 19.6 1.37 7.18 -806 3 890 2 604 2 084 2 084 179.50 186.53 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 34 97 0.6 732 620 112 232 198 620 423 4.33 29.1 11.0 19.6 1.37 4.31 -654 3 137 2 114 1 691 1 691 107.75 112.08 12.00% 1 92 19 80 1.4 605 513 181 162 513 350 2.35 71.7 11.0 19.6 1.37 1.44 -541 36.00 38.35 2 583 1 748 1 398 1 398 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m Table А.12. Cost-effective values. Gas transportation by overland pipeline. Distance – 5000 km Distance pipeline. overland А.12. Cost-effectiveby values. transportation Gas Table Parameters Gross gas Gross Gas transportation cost transportation Gas Auxiliary gas Auxiliary tariff transportation Gas Commercial gas gas Commercial Gas transportation proceeds transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

187 APPENDIX A 15 7.4 407 991 343 353 3.43 22.1 11.0 19.6 1.37 2 666 2 259 1 333 2 259 7 698 1 540 6 159 6 159 21.55 -2381 538.75 542.18 11 912 12.00% 10 9.4 351 762 238 305 2.38 28.2 11.0 19.6 1.37 2 303 1 952 1 000 1 952 6 650 1 330 5 320 5 320 14.37 -2057 359.25 361.63 10 139 12.00% /year 3 7.5 331 865 685 180 287 11.7 1.80 35.1 11.0 19.6 1.37 9 468 2 168 1 837 1 837 6 260 1 252 5 008 5 008 10.78 -1937 269.50 271.30 12.00% 5 310 744 607 138 269 16.3 1.38 49.0 11.0 19.6 1.37 7.18 8 804 2 031 1 721 1 721 5 865 1 173 4 692 4 692 -1814 179.50 180.88 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 73 280 544 472 243 24.2 0.73 72.6 11.0 19.6 1.37 4.31 7 823 1 834 1 554 1 554 5 296 1 059 4 237 4 237 -1638 107.75 108.48 12.00% 1 48 258 427 380 976 223 66.0 0.48 11.0 19.6 1.37 1.44 36.00 198.1 36.48 7 133 1 690 1 432 1 432 4 880 3 904 3 904 -1510 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou gas pipeline transportation. Distance – 300 km Distance А.13. Cost-effective values. Subseatransportation. gas pipeline Table Parameters Gross gas Gross Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas tariff transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

188 APPENDIX A 15 4.3 832 338 722 3.38 43.4 11.0 19.6 1.37 5 457 4 624 1 742 1 405 4 624 3 151 21.55 -4874 538.75 542.13 23 395 15 756 12 605 12 605 12.00% 10 5.6 727 230 631 2.30 56.5 11.0 19.6 1.37 4 769 4 041 1 358 1 128 4 041 2 754 14.37 -4260 359.25 361.55 20 280 13 769 11 015 11 015 12.00% /year 3 6.9 7.5 671 220 582 2.20 69.3 11.0 19.6 1.37 4 398 3 727 1 235 1 015 3 727 2 540 10.78 -3928 269.50 271.70 18 684 12 698 10 158 10 158 12.00% 5 9.8 630 977 200 546 2.00 97.8 11.0 19.6 1.37 7.18 4 128 3 498 1 177 3 498 2 384 9 535 9 535 -3687 179.50 181.50 17 556 11 919 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 568 949 811 138 492 14.6 1.38 11.0 19.6 1.37 4.31 145.9 3 723 3 155 3 155 2 150 8 601 8 601 -3326 107.75 109.13 15 723 10 751 12.00% 1 50 509 674 624 441 38.6 0.50 11.0 19.6 1.37 1.44 36.00 386.3 36.50 3 335 2 826 2 826 9 630 1 926 7 704 7 704 -2979 13 908 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou gas pipeline transportation. Distance – 1000 km Distance А.14. Cost-effective values. Subseatransportation. gas pipeline Table Parameters Gross gas Gross Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas tariff transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

189 APPENDIX A 15 4.2 685 6.85 83.5 11.0 19.6 1.37 8 822 1 588 3 671 2 986 8 822 6 011 1 377 21.55 -9298 538.75 545.60 44 976 10 410 30 057 24 046 24 046 12.00% 10 5.4 468 4.68 11.0 19.6 1.37 107.5 9 010 7 636 1 374 2 880 2 413 7 636 5 203 1 192 14.37 -8048 359.25 363.93 38 633 26 017 20 813 20 813 12.00% /year 3 6.6 7.5 443 4.43 11.0 19.6 1.37 133.0 8 351 7 077 1 274 2 699 2 257 7 077 4 823 1 104 10.78 -7459 269.50 273.93 35 835 24 113 19 290 19 290 12.00% 5 9.3 405 4.05 11.0 19.6 1.37 7.18 186.8 7 800 6 610 1 190 2 576 2 171 6 610 4 504 1 031 -6967 179.50 183.55 33 526 22 522 18 018 18 018 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 278 918 13.7 2.78 11.0 19.6 1.37 4.31 274.8 6 939 5 881 1 059 2 073 1 796 5 881 4 007 -6198 107.75 110.53 29 608 20 037 16 029 16 029 12.00% 1 919 103 797 35.2 1.03 11.0 19.6 1.37 1.44 36.00 703.0 37.03 6 024 5 105 1 406 1 303 5 105 3 479 -5381 25 308 17 394 13 915 13 915 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou gas pipeline transportation. Distance – 2000 km Distance А.15. Cost-effective values. Subseatransportation. gas pipeline Table Parameters Gross gas Gross Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas tariff transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

190 APPENDIX A 32 79 27 28 15 1.8 0.6 949 212 180 106 180 613 123 490 490 3.43 11.0 19.6 1.37 -190 21.55 538.75 542.18 12.00% 28 80 61 19 24 10 2.2 0.7 807 183 155 155 530 106 424 424 2.38 11.0 19.6 1.37 -164 14.37 359.25 361.63 12.00% /year 3 26 69 55 14 23 2.8 7.5 0.9 754 173 146 146 499 100 399 399 1.80 11.0 19.6 1.37 -154 10.78 269.50 271.30 12.00% 5 25 59 48 11 93 21 3.9 1.3 701 162 137 137 467 374 374 1.38 11.0 19.6 1.37 7.18 -145 179.50 180.88 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 6 3 22 43 38 84 19 5.8 1.9 623 146 124 124 422 337 337 0.73 11.0 19.6 1.37 4.31 -130 107.75 108.48 12.00% 4 1 21 34 30 78 18 5.3 568 135 114 114 389 311 311 0.48 11.0 19.6 1.37 1.44 15.8 -120 36.00 36.48 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m gas pipeline transportation. Distance – 300 km Distance А.16. Cost-effective values. Subseatransportation. gas pipeline Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

191 APPENDIX A 66 27 57 15 3.5 0.3 435 368 139 112 368 251 3.38 11.0 19.6 1.37 -388 1 863 1 255 1 004 1 004 21.55 538.75 542.13 12.00% 58 90 18 50 10 4.5 0.4 380 322 108 322 219 877 877 2.30 11.0 19.6 1.37 -339 1 615 1 097 14.37 359.25 361.55 12.00% /year 3 53 98 81 18 46 5.5 7.5 0.6 350 297 297 202 809 809 2.20 11.0 19.6 1.37 -313 1 488 1 011 10.78 269.50 271.70 12.00% 5 50 94 78 16 43 7.8 0.8 329 279 279 949 190 759 759 2.00 11.0 19.6 1.37 7.18 -294 1 398 179.50 181.50 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 45 76 65 11 39 1.2 297 251 251 856 171 685 685 1.38 11.0 19.6 1.37 4.31 11.6 -265 1 252 107.75 109.13 12.00% 4 1 41 54 50 35 3.1 266 225 225 767 153 614 614 0.50 11.0 19.6 1.37 1.44 30.8 -237 36.00 36.50 1 108 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m gas pipeline transportation. Distance – 1000 km Distance А.17. Cost-effective values. Subseatransportation. gas pipeline Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

192 APPENDIX A 55 15 6.6 0.3 829 703 126 292 238 703 479 110 6.85 11.0 19.6 1.37 -741 3 582 2 394 1 915 1 915 21.55 538.75 545.60 12.00% 37 95 10 8.6 0.4 718 608 109 229 192 608 414 4.68 11.0 19.6 1.37 -641 3 077 2 072 1 658 1 658 14.37 359.25 363.93 12.00% /year 3 35 88 0.5 7.5 665 564 101 215 180 564 384 4.43 10.6 11.0 19.6 1.37 -594 2 854 1 920 1 536 1 536 10.78 269.50 273.93 12.00% 5 95 32 82 0.7 621 526 205 173 526 359 4.05 14.9 11.0 19.6 1.37 7.18 -555 2 670 1 794 1 435 1 435 179.50 183.55 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 84 22 73 1.1 553 468 165 143 468 319 2.78 21.9 11.0 19.6 1.37 4.31 -494 2 358 1 596 1 277 1 277 107.75 110.53 12.00% 8 1 73 63 2.8 480 407 112 104 407 277 1.03 56.0 11.0 19.6 1.37 1.44 -429 36.00 37.03 2 016 1 385 1 108 1 108 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m gas pipeline transportation. Distance – 2000 km Distance А.18. Cost-effective values. Subseatransportation. gas pipeline Table Parameters Gross gas Gross Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas tariff transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

193 APPENDIX A 15 11.0 19.6 1.37 39.5 65.19 9 999 1 800 6 519 9 999 6 813 1 560 21.55 118.4 63 800 538.75 603.94 11 799 16 984 10 465 34 067 27 254 27 254 -10539 12.00% 10 11.0 19.6 1.37 43.2 43.36 8 626 7 310 1 316 7 960 4 336 7 310 4 981 1 141 14.37 129.5 -7705 46 522 359.25 402.61 12 296 24 906 19 925 19 925 12.00% /year 3 7.5 906 11.0 19.6 1.37 45.2 32.60 6 851 5 806 1 045 9 339 6 079 3 260 5 806 3 956 10.78 135.5 -6120 36 524 269.50 302.10 19 782 15 826 15 826 12.00% 5 800 694 11.0 19.6 1.37 51.6 7.18 21.83 5 246 4 446 6 993 4 810 2 183 4 446 3 029 154.9 -4686 27 809 179.50 201.33 15 147 12 118 12 118 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 585 507 11.0 19.6 1.37 62.6 4.31 13.71 3 835 3 250 5 005 3 635 1 371 3 250 2 215 8 858 8 858 187.7 -3425 20 221 107.75 121.46 11 073 12.00% 1 228 505 864 198 5.05 11.0 19.6 1.37 73.1 1.44 7 893 36.00 41.05 1 496 1 268 1 958 1 453 1 268 4 319 3 455 3 455 219.3 -1336 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 300 km Distance transportation. gas А.19. Cost-effective offshore values. Liquefied Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

194 APPENDIX A 15 11.0 19.6 1.37 12.2 65.82 1 844 6 582 6 979 1 598 21.55 122.3 65 915 538.75 604.57 12 086 10 242 17 960 11 378 10 242 34 897 27 917 27 917 -10795 12.00% 10 11.0 19.6 1.37 13.1 43.78 8 683 7 358 1 324 8 142 4 378 7 358 5 014 1 148 14.37 130.7 -7756 46 972 359.25 403.03 12 520 25 070 20 056 20 056 12.00% /year 3 7.5 936 11.0 19.6 1.37 14.2 32.91 7 081 6 001 1 080 6 811 3 291 6 001 4 089 10.78 141.7 -6325 38 200 269.50 302.41 10 102 20 447 16 358 16 358 12.00% 5 805 697 11.0 19.6 1.37 15.6 7.18 22.04 5 275 4 470 7 105 4 901 2 204 4 470 3 046 156.2 -4711 28 034 179.50 201.54 15 230 12 184 12 184 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 592 513 11.0 19.6 1.37 19.1 4.31 13.83 3 878 3 287 5 156 3 773 1 383 3 287 2 240 8 958 8 958 190.7 -3464 20 544 107.75 121.58 11 198 12.00% 1 235 509 889 204 5.09 11.0 19.6 1.37 22.8 1.44 8 211 36.00 41.09 1 540 1 305 2 102 1 593 1 305 4 446 3 557 3 557 228.1 -1375 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 1000 km Distance transportation. gas А.20. Cost-effective offshore values. Liquefied Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

195 APPENDIX A 15 6.4 11.0 19.6 1.37 66.72 1 917 6 672 7 256 1 662 21.55 128.9 69 435 538.75 605.47 12 566 10 649 19 575 12 903 10 649 36 282 29 026 29 026 -11224 12.00% 10 6.8 11.0 19.6 1.37 44.38 8 970 7 602 1 368 9 054 4 438 7 602 5 180 1 186 14.37 136.6 -8012 49 084 359.25 403.63 13 492 25 899 20 720 20 720 12.00% /year 3 7.4 7.5 971 11.0 19.6 1.37 33.36 7 340 6 220 1 120 7 633 3 336 6 220 4 239 10.78 148.8 -6556 40 094 269.50 302.86 10 969 21 194 16 955 16 955 12.00% 5 8.3 840 728 11.0 19.6 1.37 7.18 22.34 5 505 4 665 7 866 5 632 2 234 4 665 3 179 165.5 -4917 29 708 179.50 201.84 15 894 12 715 12 715 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 9.6 593 514 11.0 19.6 1.37 4.31 14.01 3 888 3 295 5 204 3 803 1 401 3 295 2 245 8 981 8 981 191.5 -3473 20 631 107.75 121.76 11 226 12.00% 1 247 515 934 214 5.15 11.0 19.6 1.37 12.2 1.44 8 777 36.00 41.15 1 618 1 371 2 357 1 842 1 371 4 672 3 738 3 738 243.8 -1445 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 2000 km Distance transportation. gas А.21. Cost-effective offshore values. Liquefied Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

196 APPENDIX A 15 4.5 11.0 19.6 1.37 67.62 1 975 6 762 7 477 1 712 21.55 134.1 72 252 538.75 606.37 12 947 10 972 20 878 14 116 10 972 37 384 29 907 29 907 -11565 12.00% 10 4.8 11.0 19.6 1.37 44.98 9 257 7 845 1 412 9 967 4 498 7 845 5 346 1 224 14.37 142.5 -8269 51 196 359.25 404.23 14 465 26 729 21 383 21 383 12.00% /year 3 5.0 7.5 982 11.0 19.6 1.37 33.81 7 426 6 293 1 133 7 905 3 381 6 293 4 288 10.78 151.2 -6633 40 750 269.50 303.31 11 286 21 441 17 153 17 153 12.00% 5 5.6 848 735 11.0 19.6 1.37 7.18 22.64 5 562 4 713 8 077 5 813 2 264 4 713 3 212 167.9 -4968 30 146 179.50 202.14 16 059 12 847 12 847 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 6.9 631 547 11.0 19.6 1.37 4.31 14.19 4 137 3 506 6 014 4 595 1 419 3 506 2 389 9 556 9 556 208.2 -3695 22 429 107.75 121.94 11 945 12.00% 1 8.1 247 521 934 214 5.21 11.0 19.6 1.37 1.44 8 783 36.00 41.21 1 618 1 371 2 363 1 842 1 371 4 672 3 738 3 738 244.0 -1445 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 3000 km Distance transportation. gas А.22. Cost-effective offshore values. Liquefied Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

197 APPENDIX A 15 3.5 11.0 19.6 1.37 68.52 2 063 6 852 7 809 1 788 21.55 141.9 76 447 538.75 607.27 13 522 11 459 22 794 15 941 11 459 39 043 31 234 31 234 -12078 12.00% 10 3.7 11.0 19.6 1.37 45.58 9 544 8 088 1 456 4 558 8 088 5 512 1 262 14.37 148.4 -8525 53 308 359.25 404.83 15 438 10 880 27 558 22 046 22 046 12.00% /year 3 4.0 7.5 11.0 19.6 1.37 34.26 7 713 6 536 1 177 8 817 3 426 6 536 4 454 1 020 10.78 159.0 -6889 42 847 269.50 303.76 12 244 22 270 17 816 17 816 12.00% 5 4.4 884 766 11.0 19.6 1.37 7.18 22.94 5 792 4 909 8 840 6 546 2 294 4 909 3 345 177.3 -5174 31 823 179.50 202.44 16 724 13 380 13 380 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 5.2 631 547 11.0 19.6 1.37 4.31 14.37 4 137 3 506 6 032 4 595 1 437 3 506 2 389 9 556 9 556 208.3 -3695 22 447 107.75 122.12 11 945 12.00% 1 6.3 253 527 959 220 5.27 11.0 19.6 1.37 1.44 9 100 36.00 41.27 1 661 1 408 2 507 1 980 1 408 4 797 3 838 3 838 252.8 -1484 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 4000 km Distance transportation. gas А.23. Cost-effective offshore values. Liquefied Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

198 APPENDIX A 15 2.9 11.0 19.6 1.37 69.42 2 106 6 942 7 974 1 826 21.55 145.9 78 589 538.75 608.17 13 809 11 702 23 796 16 854 11 702 39 872 31 897 31 897 -12334 12.00% 10 3.1 11.0 19.6 1.37 46.18 9 831 8 332 1 500 4 618 8 332 5 677 1 300 14.37 154.3 -8782 55 420 359.25 405.43 16 410 11 792 28 387 22 710 22 710 12.00% /year 3 3.3 7.5 11.0 19.6 1.37 34.71 7 906 6 700 1 206 9 430 3 471 6 700 4 565 1 045 10.78 164.3 -7061 44 270 269.50 304.21 12 901 22 826 18 261 18 261 12.00% 5 3.6 892 773 11.0 19.6 1.37 7.18 23.24 5 849 4 957 9 050 6 726 2 324 4 957 3 378 179.7 -5224 32 258 179.50 202.74 16 888 13 510 13 510 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 4.2 634 550 11.0 19.6 1.37 4.31 14.55 4 156 3 522 6 111 4 656 1 455 3 522 2 400 9 600 9 600 209.8 -3712 22 602 107.75 122.30 12 001 12.00% 1 5.1 253 533 959 220 5.33 11.0 19.6 1.37 1.44 9 106 36.00 41.33 1 661 1 408 2 513 1 980 1 408 4 797 3 838 3 838 252.9 -1484 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 5000 km Distance transportation. gas А.24. Cost-effective offshore values. Liquefied Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

199 APPENDIX A 15 9.4 3.1 940 796 143 833 519 796 543 124 11.0 19.6 1.37 -839 65.19 5 081 1 353 2 713 2 171 2 171 21.55 538.75 603.94 12.00% 91 10 3.4 687 582 105 979 634 345 582 397 11.0 19.6 1.37 10.3 -614 43.36 3 705 1 983 1 587 1 587 14.37 359.25 402.61 12.00% /year 3 83 72 7.5 3.6 546 462 744 484 260 462 315 11.0 19.6 1.37 10.8 -487 32.60 2 909 1 575 1 260 1 260 10.78 269.50 302.10 12.00% 5 64 55 4.1 418 354 557 383 174 354 241 965 965 11.0 19.6 1.37 7.18 12.3 -373 21.83 2 215 1 206 179.50 201.33 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 47 40 5.0 305 259 399 289 109 259 882 176 705 705 11.0 19.6 1.37 4.31 14.9 -273 13.71 1 610 107.75 121.46 12.00% 1 18 40 69 16 5.8 629 119 101 156 116 101 344 275 275 5.05 11.0 19.6 1.37 1.44 17.5 -106 36.00 41.05 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 300 km Distance transportation. gas А.25. Cost-effective offshore values. Liquefied Table Parameters Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

200 APPENDIX A 15 9.7 1.0 963 816 147 906 524 816 556 127 11.0 19.6 1.37 -860 65.82 5 250 1 430 2 779 2 223 2 223 21.55 538.75 604.57 12.00% 91 10 1.0 691 586 105 997 648 349 586 399 11.0 19.6 1.37 10.4 -618 43.78 3 741 1 997 1 597 1 597 14.37 359.25 403.03 12.00% /year 3 86 75 7.5 1.1 564 478 805 542 262 478 326 11.0 19.6 1.37 11.3 -504 32.91 3 042 1 628 1 303 1 303 10.78 269.50 302.41 12.00% 5 64 56 1.2 420 356 566 390 176 356 243 970 970 11.0 19.6 1.37 7.18 12.4 -375 22.04 2 233 1 213 179.50 201.54 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 47 41 1.5 309 262 411 300 110 262 892 178 713 713 11.0 19.6 1.37 4.31 15.2 -276 13.83 1 636 107.75 121.58 12.00% 1 19 41 71 16 1.8 654 123 104 167 127 104 354 283 283 5.09 11.0 19.6 1.37 1.44 18.2 -110 36.00 41.09 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 1000 km Distance transportation. gas А.26. Cost-effective offshore values. Liquefied Table Parameters Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

201 APPENDIX A 15 0.5 848 153 531 848 578 132 11.0 19.6 1.37 10.3 -894 66.72 5 530 1 001 1 559 1 028 2 890 2 312 2 312 21.55 538.75 605.47 12.00% 94 10 0.5 714 605 109 721 353 605 413 11.0 19.6 1.37 10.9 -638 44.38 3 909 1 075 2 063 1 650 1 650 14.37 359.25 403.63 12.00% /year 3 89 77 7.5 0.6 585 495 874 608 266 495 338 11.0 19.6 1.37 11.8 -522 33.36 3 193 1 688 1 350 1 350 10.78 269.50 302.86 12.00% 5 67 58 0.7 438 372 626 449 178 372 253 11.0 19.6 1.37 7.18 13.2 -392 22.34 2 366 1 266 1 013 1 013 179.50 201.84 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 47 41 0.8 310 262 414 303 112 262 894 179 715 715 11.0 19.6 1.37 4.31 15.2 -277 14.01 1 643 107.75 121.76 12.00% 1 20 41 74 17 1.0 699 129 109 188 147 109 372 298 298 5.15 11.0 19.6 1.37 1.44 19.4 -115 36.00 41.15 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 2000 km Distance transportation. gas А.27. Cost-effective offshore values. Liquefied Table Parameters Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

202 APPENDIX A 15 0.4 874 157 539 874 595 136 11.0 19.6 1.37 10.7 -921 67.62 5 754 1 031 1 663 1 124 2 977 2 382 2 382 21.55 538.75 606.37 12.00% 97 10 0.4 737 625 112 794 358 625 426 11.0 19.6 1.37 11.3 -659 44.98 4 077 1 152 2 129 1 703 1 703 14.37 359.25 404.23 12.00% /year 3 90 78 7.5 0.4 591 501 899 630 269 501 342 11.0 19.6 1.37 12.0 -528 33.81 3 245 1 708 1 366 1 366 10.78 269.50 303.31 12.00% 5 68 59 0.4 443 375 643 463 180 375 256 11.0 19.6 1.37 7.18 13.4 -396 22.64 2 401 1 279 1 023 1 023 179.50 202.14 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 50 44 0.6 329 279 479 366 113 279 951 190 761 761 11.0 19.6 1.37 4.31 16.6 -294 14.19 1 786 107.75 121.94 12.00% 1 20 42 74 17 0.6 699 129 109 188 147 109 372 298 298 5.21 11.0 19.6 1.37 1.44 19.4 -115 36.00 41.21 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 3000 km Distance transportation. gas А.28. Cost-effective offshore values. Liquefied Table Parameters Gross gas Gross Gas transportation cost transportation Gas Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

203 APPENDIX A 15 0.3 913 164 546 913 622 142 11.3 11.0 19.6 1.37 -962 68.52 6 088 1 077 1 815 1 270 3 109 2 487 2 487 21.55 538.75 607.27 12.00% 10 0.3 760 644 116 866 363 644 439 101 11.8 11.0 19.6 1.37 -679 45.58 4 245 1 229 2 195 1 756 1 756 14.37 359.25 404.83 12.00% /year 3 94 81 0.3 7.5 614 521 975 702 273 521 355 12.7 11.0 19.6 1.37 -549 34.26 3 412 1 774 1 419 1 419 10.78 269.50 303.76 12.00% 5 70 61 0.4 461 391 704 521 183 391 266 14.1 11.0 19.6 1.37 7.18 -412 22.94 2 534 1 332 1 066 1 066 179.50 202.44 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 50 44 0.4 329 279 480 366 114 279 951 190 761 761 16.6 11.0 19.6 1.37 4.31 -294 14.37 1 788 107.75 122.12 12.00% 1 20 42 76 17 0.5 725 132 112 200 158 112 382 306 306 5.27 20.1 11.0 19.6 1.37 1.44 -118 36.00 41.27 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 4000 km Distance transportation. gas А.29. Cost-effective offshore values. Liquefied Table Parameters Gross gas Gross Gas transportation cost transportation Gas Auxiliary gas Auxiliary tariff transportation Gas Commercial gas gas Commercial Gas transportation proceeds transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

204 APPENDIX A 15 0.2 932 168 553 932 635 145 11.6 11.0 19.6 1.37 -982 69.42 6 259 1 100 1 895 1 342 3 175 2 540 2 540 21.55 538.75 608.17 12.00% 10 0.2 783 664 119 939 368 664 452 104 12.3 11.0 19.6 1.37 -699 46.18 4 414 1 307 2 261 1 809 1 809 14.37 359.25 405.43 12.00% /year 3 96 83 0.3 7.5 630 534 751 276 534 364 13.1 11.0 19.6 1.37 -562 34.71 3 526 1 027 1 818 1 454 1 454 10.78 269.50 304.21 12.00% 5 71 62 0.3 466 395 721 536 185 395 269 14.3 11.0 19.6 1.37 7.18 -416 23.24 2 569 1 345 1 076 1 076 179.50 202.74 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 50 44 0.3 331 281 487 371 116 281 956 191 765 765 16.7 11.0 19.6 1.37 4.31 -296 14.55 1 800 107.75 122.30 12.00% 1 20 42 76 17 0.4 725 132 112 200 158 112 382 306 306 5.33 20.1 11.0 19.6 1.37 1.44 -118 36.00 41.33 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 5000 km Distance transportation. gas А.30. Cost-effective offshore values. Liquefied Table Parameters Gross gas Gross Gas transportation cost transportation Gas Auxiliary gas Auxiliary tariff transportation Gas Commercial gas gas Commercial Gas transportation proceeds transportation Gas Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

205 APPENDIX A 15 723 924 7.23 11.0 19.6 1.37 20.1 60.3 6 984 5 919 1 065 4 767 4 044 5 919 4 033 21.55 -6238 32 479 538.75 545.98 20 166 16 133 16 133 12.00% 10 780 498 676 4.98 11.0 19.6 1.37 22.0 66.1 5 111 4 331 3 471 2 974 4 331 2 951 14.37 -4565 23 750 359.25 364.23 14 756 11 805 11 805 12.00% /year 3 7.5 557 380 483 3.80 11.0 19.6 1.37 21.1 63.2 3 653 3 096 2 532 2 152 3 096 2 109 8 438 8 438 10.78 -3263 17 026 269.50 273.30 10 547 12.00% 5 451 275 391 2.75 11.0 19.6 1.37 25.6 7.18 76.8 2 958 2 507 2 046 1 771 2 507 8 541 1 708 6 832 6 832 -2642 13 783 179.50 182.25 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 389 173 337 1.73 11.0 19.6 1.37 36.5 4.31 2 551 2 162 1 682 1 510 2 162 7 367 1 473 5 894 5 894 109.6 -2279 11 806 107.75 109.48 12.00% 1 63 189 848 786 714 164 0.63 11.0 19.6 1.37 53.3 1.44 5 755 36.00 36.63 1 237 1 048 1 048 3 571 2 857 2 857 159.9 -1105 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m million Euros million EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 300 km Distance transportation. А.31. Cost-effective values. Compressed gas offshore Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

206 APPENDIX A 15 7.5 723 7.23 11.0 19.6 1.37 74.8 8 713 7 384 1 329 5 719 4 996 7 384 5 032 1 152 21.55 -7783 40 292 538.75 545.98 25 158 20 127 20 127 12.00% 10 7.9 938 498 813 4.98 11.0 19.6 1.37 79.2 6 148 5 210 4 043 3 545 5 210 3 550 14.37 -5491 28 437 359.25 364.23 17 751 14 201 14 201 12.00% /year 3 8.1 7.5 715 380 620 3.80 11.0 19.6 1.37 80.6 4 690 3 975 3 103 2 723 3 975 2 708 10.78 -4189 21 713 269.50 273.30 13 542 10 834 10 834 12.00% 5 9.4 557 275 483 2.75 11.0 19.6 1.37 7.18 94.2 3 649 3 093 2 427 2 152 3 093 2 107 8 430 8 430 -3260 16 908 179.50 182.25 10 537 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 442 173 383 1.73 11.0 19.6 1.37 12.4 4.31 2 897 2 455 1 873 1 700 2 455 8 365 1 673 6 692 6 692 124.1 -2588 13 369 107.75 109.48 12.00% 1 63 189 848 786 714 164 0.63 11.0 19.6 1.37 16.0 1.44 5 755 36.00 36.63 1 237 1 048 1 048 3 571 2 857 2 857 159.9 -1105 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m million Euros million EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 1000 km Distance transportation. А.32. Cost-effective values. Compressed gas offshore Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

207 APPENDIX A 15 4.6 723 7.23 11.0 19.6 1.37 92.2 9 142 1 646 6 862 6 139 9 142 6 230 1 427 21.55 -9636 49 667 538.75 545.98 10 788 31 149 24 919 24 919 12.00% 10 5.0 498 4.98 11.0 19.6 1.37 7 877 6 675 1 202 4 995 4 498 6 675 4 549 1 042 14.37 100.9 -7036 36 250 359.25 364.23 22 744 18 195 18 195 12.00% /year 3 4.9 7.5 874 380 757 3.80 11.0 19.6 1.37 98.0 5 727 4 854 3 675 3 295 4 854 3 308 10.78 -5116 26 401 269.50 273.30 16 538 13 230 13 230 12.00% 5 5.6 662 275 574 2.75 11.0 19.6 1.37 7.18 4 341 3 679 2 808 2 533 3 679 2 507 111.6 -3877 20 033 179.50 182.25 12 534 10 027 10 027 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 6.9 495 173 429 1.73 11.0 19.6 1.37 4.31 3 243 2 748 2 063 1 891 2 748 9 364 1 873 7 491 7 491 138.6 -2897 14 931 107.75 109.48 12.00% 1 63 241 976 914 209 0.63 11.0 19.6 1.37 10.2 1.44 7 318 36.00 36.63 1 582 1 341 1 039 1 341 4 569 3 655 3 655 203.3 -1414 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m million Euros million EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 2000 km Distance transportation. А.33. Cost-effective values. Compressed gas offshore Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

208 APPENDIX A 15 3.7 723 7.23 11.0 19.6 1.37 2 015 8 195 7 473 7 628 1 747 21.55 112.5 60 605 538.75 545.98 13 208 11 193 11 193 38 138 30 510 30 510 -11798 12.00% 10 3.9 498 4.98 11.0 19.6 1.37 9 260 7 847 1 413 5 757 5 260 7 847 5 347 1 225 14.37 118.3 -8271 42 500 359.25 364.23 26 737 21 390 21 390 12.00% /year 3 3.8 7.5 380 895 3.80 11.0 19.6 1.37 6 765 5 733 1 032 4 246 3 866 5 733 3 907 10.78 115.4 -6042 31 088 269.50 273.30 19 533 15 626 15 626 12.00% 5 4.3 768 275 666 2.75 11.0 19.6 1.37 7.18 5 033 4 265 3 189 2 914 4 265 2 906 129.0 -4495 23 158 179.50 182.25 14 531 11 625 11 625 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 5.1 547 173 475 1.73 11.0 19.6 1.37 4.31 3 589 3 041 2 254 2 081 3 041 2 072 8 290 8 290 153.1 -3206 16 494 107.75 109.48 10 362 12.00% 1 63 6.8 241 976 914 209 0.63 11.0 19.6 1.37 1.44 7 318 36.00 36.63 1 582 1 341 1 039 1 341 4 569 3 655 3 655 203.3 -1414 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m million Euros million EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 3000 km Distance transportation. А.34. Cost-effective values. Compressed gas offshore Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

209 APPENDIX A 15 3.3 723 7.23 11.0 19.6 1.37 2 384 9 528 8 806 9 025 2 067 21.55 132.8 71 542 538.75 545.98 15 629 13 245 13 245 45 127 36 101 36 101 -13960 12.00% 10 3.5 498 4.98 11.0 19.6 1.37 9 313 1 676 6 709 6 212 9 313 6 346 1 453 14.37 140.0 -9816 50 312 359.25 364.23 10 989 31 729 25 383 25 383 12.00% /year 3 3.5 7.5 380 3.80 11.0 19.6 1.37 8 148 6 905 1 243 5 008 4 628 6 905 4 705 1 077 10.78 138.5 -7278 37 338 269.50 273.30 23 526 18 821 18 821 12.00% 5 3.9 926 275 803 2.75 11.0 19.6 1.37 7.18 6 070 5 144 3 760 3 485 5 144 3 505 155.1 -5422 27 845 179.50 182.25 17 526 14 021 14 021 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 4.6 653 173 566 1.73 11.0 19.6 1.37 4.31 4 280 3 627 2 635 2 462 3 627 2 472 9 887 9 887 182.1 -3823 19 619 107.75 109.48 12 359 12.00% 1 63 6.2 294 255 0.63 11.0 19.6 1.37 1.44 8 880 36.00 36.63 1 928 1 634 1 229 1 167 1 634 5 568 1 114 4 454 4 454 246.7 -1722 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m million Euros million EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 4000 km Distance transportation. А.35. Cost-effective values. Compressed gas offshore Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

210 APPENDIX A 15 3.1 723 7.23 11.0 19.6 1.37 2 753 2 387 21.55 153.1 82 480 538.75 545.98 18 049 15 296 10 862 10 139 15 296 52 116 10 423 41 692 41 692 -16122 12.00% 10 3.1 498 4.98 11.0 19.6 1.37 1 887 7 471 6 974 7 145 1 636 14.37 157.4 56 562 359.25 364.23 12 372 10 485 10 485 35 723 28 578 28 578 -11051 12.00% /year 3 3.1 7.5 380 3.80 11.0 19.6 1.37 9 185 7 784 1 401 5 579 5 199 7 784 5 304 1 215 10.78 155.9 -8205 42 026 269.50 273.30 26 522 21 217 21 217 12.00% 5 3.5 275 894 2.75 11.0 19.6 1.37 7.18 6 762 5 730 1 031 4 141 3 866 5 730 3 905 172.5 -6040 30 970 179.50 182.25 19 523 15 619 15 619 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 3.9 706 173 612 1.73 11.0 19.6 1.37 4.31 4 626 3 920 2 825 2 653 3 920 2 672 196.6 -4132 21 181 107.75 109.48 13 358 10 686 10 686 12.00% 1 63 4.9 294 255 0.63 11.0 19.6 1.37 1.44 8 880 36.00 36.63 1 928 1 634 1 229 1 167 1 634 5 568 1 114 4 454 4 454 246.7 -1722 12.00% 3 3 3 3 per 100 km 3

% Unit years years bn m bn m bn m million Euros million EUR/thou m EUR/thou million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million million Euros million EUR/thou m EUR/thou – 5000 km Distance transportation. А.36. Cost-effective values. Compressed gas offshore Table Parameters Gas transportation proceeds transportation Gas Gross gas Gross Gas transportation tariff transportation Gas Capital investment Capital Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

211 APPENDIX A 85 58 74 15 4.8 1.6 556 471 380 322 471 321 7.23 11.0 19.6 1.37 -497 2 587 1 606 1 285 1 285 21.55 538.75 545.98 12.00% 62 40 54 10 5.3 1.8 407 345 276 237 345 235 940 940 4.98 11.0 19.6 1.37 -364 1 891 1 175 14.37 359.25 364.23 12.00% /year 3 44 30 38 5.0 7.5 1.7 291 247 202 171 247 840 168 672 672 3.80 11.0 19.6 1.37 -260 1 356 10.78 269.50 273.30 12.00% 5 36 22 31 6.1 2.0 236 200 163 141 200 680 136 544 544 2.75 11.0 19.6 1.37 7.18 -210 1 098 179.50 182.25 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 31 14 27 8.7 2.9 940 203 172 134 120 172 587 117 469 469 1.73 11.0 19.6 1.37 4.31 -181 107.75 109.48 12.00% 5 1 98 83 15 68 63 83 57 13 4.2 -88 458 284 228 228 0.63 11.0 19.6 1.37 1.44 12.7 36.00 36.63 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 300 km Distance transportation. А.37. Cost-effective values. Compressed gas offshore Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

212 APPENDIX A 58 92 15 6.0 0.6 694 588 106 455 398 588 401 7.23 11.0 19.6 1.37 -620 3 209 2 004 1 603 1 603 21.55 538.75 545.98 12.00% 75 40 65 10 6.3 0.6 490 415 322 282 415 283 4.98 11.0 19.6 1.37 -437 2 265 1 414 1 131 1 131 14.37 359.25 364.23 12.00% /year 3 57 30 49 6.4 7.5 0.6 374 317 247 217 317 216 863 863 3.80 11.0 19.6 1.37 -334 1 729 1 079 10.78 269.50 273.30 12.00% 5 44 22 38 7.5 0.8 291 246 193 171 246 839 168 671 671 2.75 11.0 19.6 1.37 7.18 -260 1 347 179.50 182.25 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 35 14 31 9.9 1.0 231 196 149 135 196 666 133 533 533 1.73 11.0 19.6 1.37 4.31 -206 1 065 107.75 109.48 12.00% 5 1 98 83 15 68 63 83 57 13 1.3 -88 458 284 228 228 0.63 11.0 19.6 1.37 1.44 12.7 36.00 36.63 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 1000 km Distance transportation. А.38. Cost-effective values. Compressed gas offshore Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

213 APPENDIX A 58 15 7.3 0.4 859 728 131 546 489 728 496 114 7.23 11.0 19.6 1.37 -767 3 955 2 481 1 985 1 985 21.55 538.75 545.98 12.00% 96 40 83 10 8.0 0.4 627 532 398 358 532 362 4.98 11.0 19.6 1.37 -560 2 887 1 811 1 449 1 449 14.37 359.25 364.23 12.00% /year 3 70 30 60 7.8 7.5 0.4 456 387 293 262 387 263 3.80 11.0 19.6 1.37 -407 2 103 1 317 1 054 1 054 10.78 269.50 273.30 12.00% 5 53 22 46 8.9 0.4 346 293 224 202 293 998 200 799 799 2.75 11.0 19.6 1.37 7.18 -309 1 595 179.50 182.25 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 39 14 34 0.6 258 219 164 151 219 746 149 597 597 1.73 11.0 19.6 1.37 4.31 11.0 -231 1 189 107.75 109.48 12.00% 5 1 19 83 78 73 17 0.8 583 126 107 107 364 291 291 0.63 11.0 19.6 1.37 1.44 16.2 -113 36.00 36.63 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 2000 km Distance transportation. А.39. Cost-effective values. Compressed gas offshore Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

214 APPENDIX A 58 15 9.0 0.3 891 160 653 595 891 607 139 7.23 11.0 19.6 1.37 -940 4 827 1 052 3 037 2 430 2 430 21.55 538.75 545.98 12.00% 40 98 10 9.4 0.3 737 625 112 458 419 625 426 4.98 11.0 19.6 1.37 -659 3 385 2 129 1 703 1 703 14.37 359.25 364.23 12.00% /year 3 82 30 71 9.2 7.5 0.3 539 457 338 308 457 311 3.80 11.0 19.6 1.37 -481 2 476 1 556 1 244 1 244 10.78 269.50 273.30 12.00% 5 61 22 53 0.3 401 340 254 232 340 231 926 926 2.75 11.0 19.6 1.37 7.18 10.3 -358 1 844 1 157 179.50 182.25 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 44 14 38 0.4 286 242 180 166 242 825 165 660 660 1.73 11.0 19.6 1.37 4.31 12.2 -255 1 314 107.75 109.48 12.00% 5 1 19 83 78 73 17 0.5 583 126 107 107 364 291 291 0.63 11.0 19.6 1.37 1.44 16.2 -113 36.00 36.63 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 3000 km Distance transportation. А.40. Cost-effective values. Compressed gas offshore Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

215 APPENDIX A 58 15 0.3 190 759 701 719 165 7.23 11.0 19.6 1.37 10.6 5 698 1 245 1 055 1 055 3 594 2 875 2 875 21.55 -1112 538.75 545.98 12.00% 40 10 0.3 875 742 133 534 495 742 505 116 4.98 11.0 19.6 1.37 11.2 -782 4 007 2 527 2 022 2 022 14.37 359.25 364.23 12.00% /year 3 99 30 86 7.5 0.3 649 550 399 369 550 375 3.80 11.0 19.6 1.37 11.0 -580 2 974 1 874 1 499 1 499 10.78 269.50 273.30 12.00% 5 74 22 64 0.3 483 410 299 278 410 279 2.75 11.0 19.6 1.37 7.18 12.4 -432 2 218 1 396 1 117 1 117 179.50 182.25 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 52 14 45 0.4 341 289 210 196 289 984 197 787 787 1.73 11.0 19.6 1.37 4.31 14.5 -304 1 562 107.75 109.48 12.00% 5 1 23 98 93 89 20 0.5 707 154 130 130 443 355 355 0.63 11.0 19.6 1.37 1.44 19.6 -137 36.00 36.63 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 4000 km Distance transportation. А.41. Cost-effective values. Compressed gas offshore Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

216 APPENDIX A 58 15 0.2 219 865 807 830 190 7.23 11.0 19.6 1.37 12.2 6 569 1 437 1 218 1 218 4 150 3 320 3 320 21.55 -1284 538.75 545.98 12.00% 40 10 0.3 985 835 150 595 555 835 569 130 4.98 11.0 19.6 1.37 12.5 -880 4 505 2 845 2 276 2 276 14.37 359.25 364.23 12.00% /year 3 30 97 7.5 0.2 732 620 112 444 414 620 422 3.80 11.0 19.6 1.37 12.4 -653 3 347 2 112 1 690 1 690 10.78 269.50 273.30 12.00% 5 82 22 71 0.3 538 456 330 308 456 311 2.75 11.0 19.6 1.37 7.18 13.7 -481 2 466 1 555 1 244 1 244 179.50 182.25 12.00% Gas transportation volume. bn m bn volume. Gas transportation Gas transportation volume, million t/year volume, Gas transportation 3 56 14 49 0.3 368 312 225 211 312 213 851 851 1.73 11.0 19.6 1.37 4.31 15.7 -329 1 687 1 064 107.75 109.48 12.00% 5 1 23 98 93 89 20 0.4 707 154 130 130 443 355 355 0.63 11.0 19.6 1.37 1.44 19.6 -137 36.00 36.63 12.00% 3 3 3 3 % per 100 km 3 Unit years years years bn m bn m bn m bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn bn rubles bn rubles/m rubles/m – 5000 km Distance transportation. А.42. Cost-effective values. Compressed gas offshore Table Parameters Gross gas Gross Gas transportation tariff transportation Gas Gas transportation proceeds transportation Gas Auxiliary gas Auxiliary cost transportation Gas Commercial gas gas Commercial Capital investment Capital Capital investment (exclusive of VAT) of (exclusive investment Capital VAT Maintenance charges Maintenance Gas pipeline Gas Auxiliary gas Auxiliary Depreciation charges Depreciation Sales income Income tax Income Net income Net Cash income (net effective income) effective (net Cash income Cash discounted income (net discounted income) discounted (net income Cash discounted Internal rate of return of rate Internal Simple payback period payback Simple Discounted payback period payback Discounted Profitability index (PI) index Profitability Maximum negative cash flow cash negative Maximum

217 APPENDIX B COST-EFFECTIVE VALUES OF BLACK AND BALTIC SEA GAS TRANSPORTATION The cost-effective values as rated for 3 and 5 bin m3/year of Black and Baltic Sea gas transportation variants are listed in Tables B.1-A.20. Such cost-effective values are shown exclusive custom duties.

Table B.1. Cost-effective values. Gas supply to Turkey along the Black Sea route. Route length – 389 km. Output volume – 3 bn m3/year Transportation technology

Parameters Unit Subsea Liquefied Compressed pipeline gas gas Gross gas bn m3 76.30 85.52 75.95 Commercial gas bn m3 75.00 75.00 75.00 Auxiliary gas bn m3 1.30 10.52 0.95 Gas transportation cost EUR/thou m3 98.5 196.6 134.6 Gas transportation tariff EUR/thou m3 per 100 km 25.3 50.5 34.6 Gas transportation proceeds million Euros 7 386 14 747 10 094 Capital investment million Euros 1 582 2 954 1 984 Capital investment (exclusive of VAT) million Euros 1 341 2 503 1 682 VAT million Euros 241 451 303 Maintenance charges million Euros 1 106 3 027 2 220 Gas pipeline million Euros 976 1 975 2 125 Auxiliary gas million Euros 130 1 052 95 Depreciation charges million Euros 1 341 2 503 1 682 Sales income million Euros 4 569 8 529 5 730 Income tax million Euros 914 1 706 1 146 Net income million Euros 3 655 6 823 4 584 Cash income million Euros 3 655 6 823 4 584 Cash discounted income million Euros 209 391 262 Internal rate of return % 12.00% 12.00% 12.00% Simple payback period years 11.0 11.0 11.0 Discounted payback period years 19.6 19.6 19.6 Profitability index (PI) 1.37 1.37 1.37 Maximum negative cash flow million Euros -1414 -2638 -1772

218 APPENDIX B

Table B.2. Cost-effective values Gas supply to Bulgaria along the Black Sea route Route length – 927.2 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.56 75.85

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.56 0.85

Gas transportation cost EUR/thou m3 98.5 196.7 222.3

Gas transportation tariff EUR/thou m3 per 100 km 10.6 21.2 24.0

Gas transportation proceeds million Euros 7 386 14 751 16 669

Capital investment million Euros 1 582 2 954 3 361

Capital investment (exclusive of VAT) million Euros 1 341 2 503 2 848

VAT million Euros 241 451 513

Maintenance charges million Euros 1 106 3 031 3 334

Gas pipeline million Euros 976 1 975 3 249

Auxiliary gas million Euros 130 1 056 85

Depreciation charges million Euros 1 341 2 503 2 848

Sales income million Euros 4 569 8 529 9 703

Income tax million Euros 914 1 706 1 941

Net income million Euros 3 655 6 823 7 763

Cash income million Euros 3 655 6 823 7 763

Cash discounted income million Euros 209 391 444

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -1414 -2638 -3002

219 APPENDIX B

Table B.3. Cost-effective values Gas supply to Kaliningrad along the Baltic Sea route Route length – 1040.5 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.56 75.78

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.56 0.78

Gas transportation cost EUR/thou m3 98.5 199.3 229.4

Gas transportation tariff EUR/thou m3 per 100 km 9.5 19.2 22.0

Gas transportation proceeds million Euros 7 386 14 948 17 207

Capital investment million Euros 1 582 2 997 3 475

Capital investment (exclusive of VAT) million Euros 1 341 2 540 2 945

VAT million Euros 241 457 530

Maintenance charges million Euros 1 106 3 055 3 420

Gas pipeline million Euros 976 1 999 3 343

Auxiliary gas million Euros 130 1 056 78

Depreciation charges million Euros 1 341 2 540 2 945

Sales income million Euros 4 569 8 654 10 033

Income tax million Euros 914 1 731 2 007

Net income million Euros 3 655 6 923 8 026

Cash income million Euros 3 655 6 923 8 026

Cash discounted income million Euros 209 396 459

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -1414 -2677 -3104

220 APPENDIX B

Table B.4. Cost-effective values Gas supply to Germany along the Baltic Sea route Route length – 1225.5 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.56 75.75

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.56 0.75

Gas transportation cost EUR/thou m3 119.3 199.3 260.6

Gas transportation tariff EUR/thou m3 per 100 km 9.7 16.3 21.3

Gas transportation proceeds million Euros 8 948 14 948 19 543

Capital investment million Euros 1 928 2 997 3 963

Capital investment (exclusive of VAT) million Euros 1 634 2 540 3 359

VAT million Euros 294 457 605

Maintenance charges million Euros 1 297 3 055 3 817

Gas pipeline million Euros 1 167 1 999 3 742

Auxiliary gas million Euros 130 1 056 75

Depreciation charges million Euros 1 634 2 540 3 359

Sales income million Euros 5 568 8 654 11 444

Income tax million Euros 1 114 1 731 2 289

Net income million Euros 4 454 6 923 9 155

Cash income million Euros 4 454 6 923 9 155

Cash discounted income million Euros 255 396 524

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -1722 -2677 -3540

221 APPENDIX B

Table B.5. Cost-effective values Gas supply to Great Britain along the Baltic Sea route Route length – 2500 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.62 75.75

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.62 0.75

Gas transportation cost EUR/thou m3 140.1 199.4 473.6

Gas transportation tariff EUR/thou m3 per 100 km 5.6 8.0 18.9

Gas transportation proceeds million Euros 10 511 14 954 35 518

Capital investment million Euros 2 274 2 997 7 302

Capital investment (exclusive of VAT) million Euros 1 927 2 540 6 188

VAT million Euros 347 457 1 114

Maintenance charges million Euros 1 487 3 061 6 545

Gas pipeline million Euros 1 357 1 999 6 470

Auxiliary gas million Euros 130 1 062 75

Depreciation charges million Euros 1 927 2 540 6 188

Sales income million Euros 6 566 8 654 21 083

Income tax million Euros 1 313 1 731 4 217

Net income million Euros 5 253 6 923 16 866

Cash income million Euros 5 253 6 923 16 866

Cash discounted income million Euros 301 396 966

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -2031 -2677 -6522

222 APPENDIX B

Table B.6. Cost-effective values Gas supply to Turkey along the Baltic Sea route Route length – 389 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.30 126.38

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.30 1.38

Gas transportation cost EUR/thou m3 95.2 175.2 89.9

Gas transportation tariff EUR/thou m3 per 100 km 24.5 45.0 23.1

Gas transportation proceeds million Euros 11 904 21 896 11 234

Capital investment million Euros 2 551 4 348 2 170

Capital investment (exclusive of VAT) million Euros 2 162 3 685 1 839

VAT million Euros 389 663 331

Maintenance charges million Euros 1 780 4 644 2 623

Gas pipeline million Euros 1 563 2 915 2 486

Auxiliary gas million Euros 217 1 730 138

Depreciation charges million Euros 2 162 3 685 1 839

Sales income million Euros 7 367 12 554 6 266

Income tax million Euros 1 473 2 511 1 253

Net income million Euros 5 894 10 043 5 013

Cash income million Euros 5 894 10 043 5 013

Cash discounted income million Euros 337 575 287

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -2279 -3884 -1938

223 APPENDIX B

Table B.7. Cost-effective values Gas supply to Bulgaria along the Black Sea route Route length – 927.2 km Output volume – 5 bn m3/yearд

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.42 126.23

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.42 1.23

Gas transportation cost EUR/thou m3 107.7 175.3 148.7

Gas transportation tariff EUR/thou m3 per 100 km 11.6 18.9 16.0

Gas transportation proceeds million Euros 13 467 21 909 18 584

Capital investment million Euros 2 897 4 348 3 709

Capital investment (exclusive of VAT) million Euros 2 455 3 685 3 143

VAT million Euros 442 663 566

Maintenance charges million Euros 1 971 4 657 3 866

Gas pipeline million Euros 1 754 2 915 3 743

Auxiliary gas million Euros 217 1 742 123

Depreciation charges million Euros 2 455 3 685 3 143

Sales income million Euros 8 365 12 554 10 710

Income tax million Euros 1 673 2 511 2 142

Net income million Euros 6 692 10 043 8 568

Cash income million Euros 6 692 10 043 8 568

Cash discounted income million Euros 383 575 491

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -2588 -3884 -3313

224 APPENDIX B

Table B.8. Cost-effective values Gas supply to Kaliningrad along the Baltic Sea route Route length – 1040.5 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.42 126.25

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.42 1.25

Gas transportation cost EUR/thou m3 107.7 175.3 150.2

Gas transportation tariff EUR/thou m3 per 100 km 10.4 16.8 14.4

Gas transportation proceeds million Euros 13 467 21 909 18 770

Capital investment million Euros 2 897 4 348 3 748

Capital investment (exclusive of VAT) million Euros 2 455 3 685 3 176

VAT million Euros 442 663 572

Maintenance charges million Euros 1 971 4 657 3 900

Gas pipeline million Euros 1 754 2 915 3 775

Auxiliary gas million Euros 217 1 742 125

Depreciation charges million Euros 2 455 3 685 3 176

Sales income million Euros 8 365 12 554 10 821

Income tax million Euros 1 673 2 511 2 164

Net income million Euros 6 692 10 043 8 657

Cash income million Euros 6 692 10 043 8 657

Cash discounted income million Euros 383 575 496

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -2588 -3884 -3348

225 APPENDIX B

Table B.9. Cost-effective values Gas supply to Germany along the Baltic Sea route Route length – 1225.5 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.42 126.25

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.42 1.25

Gas transportation cost EUR/thou m3 107.7 175.3 171.7

Gas transportation tariff EUR/thou m3 per 100 km 8.8 14.3 14.0

Gas transportation proceeds million Euros 13 467 21 909 21 456

Capital investment million Euros 2 897 4 348 4 309

Capital investment (exclusive of VAT) million Euros 2 455 3 685 3 652

VAT million Euros 442 663 657

Maintenance charges million Euros 1 971 4 657 4 358

Gas pipeline million Euros 1 754 2 915 4 233

Auxiliary gas million Euros 217 1 742 125

Depreciation charges million Euros 2 455 3 685 3 652

Sales income million Euros 8 365 12 554 12 442

Income tax million Euros 1 673 2 511 2 488

Net income million Euros 6 692 10 043 9 954

Cash income million Euros 6 692 10 043 9 954

Cash discounted income million Euros 383 575 570

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -2588 -3884 -3849

226 APPENDIX B

Table B.10. Cost-effective values Gas supply to Great Britain along the Baltic Sea route Route length – 2500 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.60 126.20

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.60 1.20

Gas transportation cost EUR/thou m3 132.7 184.8 314.6

Gas transportation tariff EUR/thou m3 per 100 km 5.3 7.4 12.6

Gas transportation proceeds million Euros 16 592 23 096 39 329

Capital investment million Euros 3 589 4 607 8 045

Capital investment (exclusive of VAT) million Euros 3 041 3 904 6 818

VAT million Euros 547 703 1 227

Maintenance charges million Euros 2 352 4 817 7 406

Gas pipeline million Euros 2 135 3 057 7 286

Auxiliary gas million Euros 217 1 760 120

Depreciation charges million Euros 3 041 3 904 6 818

Sales income million Euros 10 362 13 301 23 230

Income tax million Euros 2 072 2 660 4 646

Net income million Euros 8 290 10 641 18 584

Cash income million Euros 8 290 10 641 18 584

Cash discounted income million Euros 475 609 1 064

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow million Euros -3206 -4115 -7186

227 APPENDIX B

Table B.11. Cost-effective values Gas supply to Turkey along the Baltic Sea route Route length – 389 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.52 75.95

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.52 0.95

Gas transportation cost rubles/m3 7.8 15.7 10.7

Gas transportation tariff rubles/m3 per 100 km 2.0 4.0 2.8

Gas transportation proceeds bn rubles 588 1 174 804

Capital investment bn rubles 126 235 158

Capital investment (exclusive of VAT) bn rubles 107 199 134

VAT bn rubles 19 36 24

Maintenance charges bn rubles 88 241 177

Gas pipeline bn rubles 78 157 169

Auxiliary gas bn rubles 10 84 8

Depreciation charges bn rubles 107 199 134

Sales income bn rubles 364 679 456

Income tax bn rubles 73 136 91

Net income bn rubles 291 543 365

Cash income bn rubles 291 543 365

Cash discounted income bn rubles 17 31 21

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -113 -210 -141

228 APPENDIX B

Table B.12. Cost-effective values Gas supply to Bulgaria along the Black Sea route Route length – 927.2 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.56 75.85

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.56 0.85

Gas transportation cost rubles/m3 7.8 15.7 17.7

Gas transportation tariff rubles/m3 per 100 km 0.8 1.7 1.9

Gas transportation proceeds bn rubles 588 1 175 1 328

Capital investment bn rubles 126 235 268

Capital investment (exclusive of VAT) bn rubles 107 199 227

VAT bn rubles 19 36 41

Maintenance charges bn rubles 88 241 266

Gas pipeline bn rubles 78 157 259

Auxiliary gas bn rubles 10 84 7

Depreciation charges bn rubles 107 199 227

Sales income bn rubles 364 679 773

Income tax bn rubles 73 136 155

Net income bn rubles 291 543 618

Cash income bn rubles 291 543 618

Cash discounted income bn rubles 17 31 35

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -113 -210 -239

229 APPENDIX B

Table B.13. Cost-effective values Gas supply to Kaliningrad along the Baltic Sea route Route length – 1040.5 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.56 75.85

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.56 0.85

Gas transportation cost rubles/m3 7.8 15.7 17.7

Gas transportation tariff rubles/m3 per 100 km 0.8 1.7 1.9

Gas transportation proceeds bn rubles 588 1 175 1 328

Capital investment bn rubles 126 235 268

Capital investment (exclusive of VAT) bn rubles 107 199 227

VAT bn rubles 19 36 41

Maintenance charges bn rubles 88 241 266

Gas pipeline bn rubles 78 157 259

Auxiliary gas bn rubles 10 84 7

Depreciation charges bn rubles 107 199 227

Sales income bn rubles 364 679 773

Income tax bn rubles 73 136 155

Net income bn rubles 291 543 618

Cash income bn rubles 291 543 618

Cash discounted income bn rubles 17 31 35

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -113 -210 -239

230 APPENDIX B

Table B.14. Cost-effective values Gas supply to Germany along the Baltic Sea route Route length – 1225.5 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.56 75.75

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.56 0.75

Gas transportation cost rubles/m3 9.5 15.9 20.8

Gas transportation tariff rubles/m3 per 100 km 0.8 1.3 1.7

Gas transportation proceeds bn rubles 713 1 190 1 556

Capital investment bn rubles 154 239 316

Capital investment (exclusive of VAT) bn rubles 130 202 267

VAT bn rubles 23 36 48

Maintenance charges bn rubles 103 243 304

Gas pipeline bn rubles 93 159 298

Auxiliary gas bn rubles 10 84 6

Depreciation charges bn rubles 130 202 267

Sales income bn rubles 443 689 911

Income tax bn rubles 89 138 182

Net income bn rubles 355 551 729

Cash income bn rubles 355 551 729

Cash discounted income bn rubles 20 32 42

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -137 -213 -282

231 APPENDIX B

Table B.15. Cost-effective values Gas supply to Great Britain along the Baltic Sea route Route length – 2500 km Output volume – 3 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 76.30 85.62 75.75

Commercial gas bn m3 75.00 75.00 75.00

Auxiliary gas bn m3 1.30 10.62 0.75

Gas transportation cost rubles/m3 11.2 15.9 37.7

Gas transportation tariff rubles/m3 per 100 km 0.4 0.6 1.5

Gas transportation proceeds bn rubles 837 1 191 2 829

Capital investment bn rubles 181 239 582

Capital investment (exclusive of VAT) bn rubles 153 202 493

VAT bn rubles 28 36 89

Maintenance charges bn rubles 118 244 521

Gas pipeline bn rubles 108 159 515

Auxiliary gas bn rubles 10 85 6

Depreciation charges bn rubles 153 202 493

Sales income bn rubles 523 689 1 679

Income tax bn rubles 105 138 336

Net income bn rubles 418 551 1 343

Cash income bn rubles 418 551 1 343

Cash discounted income bn rubles 24 32 77

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -162 -213 -519

232 APPENDIX B

Table B.16. Cost-effective values Gas supply to Turkey along the Baltic Sea route Route length – 389 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.30 126.38

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.30 1.38

Gas transportation cost rubles/m3 7.6 14.0 7.2

Gas transportation tariff rubles/m3 per 100 km 1.9 3.6 1.8

Gas transportation proceeds bn rubles 948 1 744 895

Capital investment bn rubles 203 346 173

Capital investment (exclusive of VAT) bn rubles 172 293 146

VAT bn rubles 31 53 26

Maintenance charges bn rubles 142 370 209

Gas pipeline bn rubles 124 232 198

Auxiliary gas bn rubles 17 138 11

Depreciation charges bn rubles 172 293 146

Sales income bn rubles 587 1 000 499

Income tax bn rubles 117 200 100

Net income bn rubles 469 800 399

Cash income bn rubles 469 800 399

Cash discounted income bn rubles 27 46 23

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -181 -309 -154

233 APPENDIX B

Table B.17. Cost-effective values Gas supply to Bulgaria along the Black Sea route Route length – 927.2 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.42 126.23

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.42 1.23

Gas transportation cost rubles/m3 8.6 14.0 11.8

Gas transportation tariff rubles/m3 per 100 km 0.9 1.5 1.3

Gas transportation proceeds bn rubles 1 072 1 745 1 480

Capital investment bn rubles 231 346 295

Capital investment (exclusive of VAT) bn rubles 196 293 250

VAT bn rubles 35 53 45

Maintenance charges bn rubles 157 371 308

Gas pipeline bn rubles 140 232 298

Auxiliary gas bn rubles 17 139 10

Depreciation charges bn rubles 196 293 250

Sales income bn rubles 666 1 000 853

Income tax bn rubles 133 200 171

Net income bn rubles 533 800 682

Cash income bn rubles 533 800 682

Cash discounted income bn rubles 31 46 39

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -206 -309 -264

234 APPENDIX B

Table B.18. Cost-effective values Gas supply to Kaliningrad along the Baltic Sea route Route length – 1040.5 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127.17 142.42 126.25

Commercial gas bn m3 125.00 125.00 125.00

Auxiliary gas bn m3 2.17 17.42 1.25

Gas transportation cost rubles/m3 8.6 14.0 12.0

Gas transportation tariff rubles/m3 per 100 km 0.8 1.3 1.1

Gas transportation proceeds bn rubles 1 072 1 745 1 495

Capital investment bn rubles 231 346 298

Capital investment (exclusive of VAT) bn rubles 196 293 253

VAT bn rubles 35 53 46

Maintenance charges bn rubles 157 371 311

Gas pipeline bn rubles 140 232 301

Auxiliary gas bn rubles 17 139 10

Depreciation charges bn rubles 196 293 253

Sales income bn rubles 666 1 000 862

Income tax bn rubles 133 200 172

Net income bn rubles 533 800 689

Cash income bn rubles 533 800 689

Cash discounted income bn rubles 31 46 39

Internal rate of return % 12.00% 12.00% 12.00%

Simple payback period years 11.0 11.0 11.0

Discounted payback period years 19.6 19.6 19.6

Profitability index (PI) 1.37 1.37 1.37

Maximum negative cash flow bn rubles -206 -309 -267

235 APPENDIX B

Table B.19. Cost-effective values Gas supply to Germany along the Baltic Sea route Route length – 1225.5 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127,17 142,42 126,25

Commercial gas bn m3 125,00 125,00 125,00

Auxiliary gas bn m3 2,17 17,42 1,25

Gas transportation cost rubles/m3 8,6 14,0 13,7

Gas transportation tariff rubles/m3 per 100 km 0,7 1,1 1,1

Gas transportation proceeds bn rubles 1 072 1 745 1 709

Capital investment bn rubles 231 346 343

Capital investment (exclusive of VAT) bn rubles 196 293 291

VAT bn rubles 35 53 52

Maintenance charges bn rubles 157 371 347

Gas pipeline bn rubles 140 232 337

Auxiliary gas bn rubles 17 139 10

Depreciation charges bn rubles 196 293 291

Sales income bn rubles 666 1 000 991

Income tax bn rubles 133 200 198

Net income bn rubles 533 800 793

Cash income bn rubles 533 800 793

Cash discounted income bn rubles 31 46 45

Internal rate of return % 12,00% 12,00% 12,00%

Simple payback period years 11,0 11,0 11,0

Discounted payback period years 19,6 19,6 19,6

Profitability index (PI) 1,37 1,37 1,37

Maximum negative cash flow bn rubles -206 -309 -307

236 APPENDIX B

Table B.20. Cost-effective values Gas supply to Great Britain along the Baltic Sea route Route length – 2500 km Output volume – 5 bn m3/year

Transportation technology Parameters Unit Subsea Liquefied Compressed pipeline gas gas

Gross gas bn m3 127,17 142,60 126,20

Commercial gas bn m3 125,00 125,00 125,00

Auxiliary gas bn m3 2,17 17,60 1,20

Gas transportation cost rubles/m3 10,6 14,7 25,1

Gas transportation tariff rubles/m3 per 100 km 0,4 0,6 1,0

Gas transportation proceeds bn rubles 1 321 1 839 3 132

Capital investment bn rubles 286 367 641

Capital investment (exclusive of VAT) bn rubles 242 311 543

VAT bn rubles 44 56 98

Maintenance charges bn rubles 187 384 590

Gas pipeline bn rubles 170 243 580

Auxiliary gas bn rubles 17 140 10

Depreciation charges bn rubles 242 311 543

Sales income bn rubles 825 1 059 1 850

Income tax bn rubles 165 212 370

Net income bn rubles 660 847 1 480

Cash income bn rubles 660 847 1 480

Cash discounted income bn rubles 38 49 85

Internal rate of return % 12,00% 12,00% 12,00%

Simple payback period years 11,0 11,0 11,0

Discounted payback period years 19,6 19,6 19,6

Profitability index (PI) 1,37 1,37 1,37

Maximum negative cash flow bn rubles -255 -328 -572

237 ABBREVIATIONS

GMS – gas-measuring station GCU – gas-compressor unit GDS – gas-distribution station GTS – gas transportation system BCS – base compressor station EEZ – exclusive economic zone CS – compressor station LP – linear part GMP – gas-main pipeline PGTU – pre-transport gas treatment unit FRU – floating regasification unit LNG – liquefied natural gas CNG – compressed natural gas

238 NOTES

239 UDC 656.6.073.41:661.91 LBC 39.486.4+33.362.087 I‘78

ENVIRONMENTAL AND ECONOMIC COMPRESSED GAS TRANSPORTATION ASSESSMENT

Signed to print on 15.05.2017 Form 60х84 1/16. Print sheet 14,41.

ISBN 978-5-9907508-8-3

© NIIPE, 2017 © the V.I. Vernadsky Nongovernmental Ecological Foundation, 2017