Liq(.0 8 Natural Gas Trade in Asia and the Middle East Shigeru Kubota AzO b. v Natural Gas Trade in Asia and the Middle East Shigeru Kubota September 1996 Industry and Energy Department The World Bank Cover: LNG terminal, Kalimantan, Indonesia. Photo courtesy of INPEX Company, Ltd., Japan. Contents Preface .................................................................. vii Abbreviations and Acronyms ......................... ......................................... viii Definitions .................................................................. ix Energy Measurements ................................................................ x Natural Gas ................................................................ x Energy and Power ................................................................ x Executive Summary .................................................................. 1 Natural Gas Demand ................................................................ 1 Natural Gas Resource Base ................................................................ 2 Gas Trade in Asia and the Middle East ................................................................ 2 Market Value of Natural Gas ................................................................ 4 Gas Transport Cost ................................................................ 5 Possible Gas Trade Schemes ................................................................ 6 Challenges in Formulating Gas Trade Projects ........................................................ 12 Gas Tariffs ................................................................ 12 Contractual Arrangements ................................................................ 12 Legal Framework ................................................................ 12 Structuring Project Company ................................................................ 12 Financing ................................................................ 12 1. Natural Gas Demand .................................................................. 15 Primary Energy Growth ................................................................ 15 Sphere of Influence of Export Markets for Asian and Middle Eastern Gas Producers ............................................................. 17 Sectoral Demands ............................................................. 18 Regional Gas Balance ............................................................. 21 OECD Europe ............................................................. 21 Middle East (Turkey and Israel) ........................................ ..................... 22 iii South Asia (India and Pakistan) ....................................................... 22 Southeast Asia (Thailand and Singapore) ....................................................... 23 East Asia (China, South Korea, Japan, and Taiwan) ........................ ................. 23 2. Natural Gas Resource Base ............................................................... 25 Gas Reserves, Production, and Exportable Gas ....................................................... 25 Production Costs ............................................................. 27 3. Gas Trade Schemes for the Developing Countries ............................................. 29 Growth of International Gas Trade ............................................................. 29 New Trends in Gas Trade ............................................................. 30 Potential Gas Export Markets for Asian and Middle Eastern Gas Producers .......... 30 W estern European Market ...................... ....................................... 30 Turkish Market ............................................................. 31 South Asian Market ............................................................. 32 Southeast Asian Market ............................................................. 32 East Asian Market ............................................................. 32 Basic Gas Trade Development Model ............................................................ . 34 Market Value of Natural Gas ............................................................. 36 World Gas Transport ............................................................. 37 Engineering Yardsticks ............................................................. 37 Cost Comparison for Piped Gas versus LNG ........................................ ............ 39 Possible Gas Trade Schemes ............................................................. 42 Challenges in Formulating Gas Trade ............................................................. 43 4. Conclusion ............................................................... 51 Annex 1 Country Profiles ............................................................... 53 Annex 2 Gas Balance in Selected Countries .......................................................... 75 Annex 3 Main Gas Reserves in Selected Gas Producers ...................................... 77 Annex 4 Basic Gas Trade Planning Model-Brief Discussion on Each Task ..... 81 iv Annex 5 Principles of Gas Trade Contracts: Sample LNG Sales Contract ......... 85 Annex 6 Publicly Announced Potential Gas Trade Projects in Asia and the Middle East .................................................................. 89 Annex 7 Netback Values for Gas in Power Generation ............... .......................... 91 Annex 8 Sample Calculation of Gas Transport Costs ................. .......................... 95 References ................................................................. 105 Tables 1 Benchmark Gas Netback Values in Power Generation for Four Regions ........... ................. 5 2 Indicative Costs for Long-Distance Transportation of Natural Gas by Quantity and Distance ...................................................................... 6 3 Possible Trade Schemes for Selected Gas-Importing Countries ............... ........................... 7 4 Potentially Feasible Gas Trade Schemes, Middle East and Asia .......................................... 13 1.1 Economic Growth Forecast for Selected Countries or Groups of Countries in Asia and the Middle East, 1995-2000 ...................................................................... 16 1.2 Annual Energy and Natural Gas Demand Growth in Five Regions, 1990-2000 ............. 17 1.3 World Natural Gas Demand by Region and Selected Country, 1995-2010 ...................... 19 1.4 Natural Gas Consumption by Region and Sector ................................................... ............ 20 1.5 Projected Gas Balance for OECD Europe, 200(-2010 ...................................................... 21 1.6 Projected Gas Balance for Turkey and Israel, 2000-2010 ................................................. 22 1.7 Projected Gas Balance for India and Pakistan 2000-2010 ................................................. 22 1.8 Projected Gas Balance for Singapore and Thailand 2000-2010 ........................................ 23 1.9 Projected Gas Balance for China, South Korea, Japan, and Taiwan ............. .................... 24 2.1 Gas Reserves, Production, and Exportable Gas in Asia and the Middle East ......... .......... 26 3.1 World Gas Trade, 1970-1994 ...................................................................... 29 3.2 Volumes and Sources of Western European Gas Imports, 1995 ....................................... 31 3.3 Volumes and Sources of East Asian Gas Imports, 1995 .................................................... 33 3.4 Expandable Capacities of the Existing LNG Projects ........................................................ 33 3.5 Benchmark Gas Netback Values in Power Generation ...................................................... 36 3.6 Benchmark Gas Netback Values in Various Sectors other than Power ............................. 37 3.7 Engineering Yardsticks for Gas Transport ...................................................................... 38 v 3.8 Gas Transport Costs for Onshore Pipelines over Three Volumes and Three Distances.... 40 3.9 Gas Transport Costs for Offshore Pipelines over Three Volumes and Three Distances... 40 3.10 Gas Transport Costs for LNG Transport over Three Volumes and Three Distances ...... 41 3.11 Transport Costs for LNG on CIF Basis for Three Volumes over Three Distances (Excluding Regasification) ...................................................................... 41 3.12 Conceivable Gas Trade Schemes ...................................................................... 42 3.13 Internal Gas Prices for Three Sectors in Selected Countries ................ ........................... 44 3.14 Gas Contract Fundamentals ...................................................................... 45 3.15 Gas Transit Tariff Calculation Methodologies ................................................................ 46 3.16 Typical Project Risks and Risk Mitigation Measures ...................................................... 49 4.1 Conceivable Gas Trade Schemes in Asia and the Middle East ............... .......................... 52 Figures 1 Predicted Growth of Demand for Gas in Five Major Markets ................ ............................. 2 2 Proven Natural Gas Reserves, Middle East and Asia ........................................................... 3 3 Predicted Gas Supply Gap in Five Major Markets, 2000-2010 ................ ........................... 4 4 Natural Gas Trade, Pakistan .......................................................................8 5 Natural Gas Trade, India ...................................................................... 9 6 Natural Gas Trade, Thailand ...................................................................... 10 7 Natural Gas Trade, China ...................................................................... 11 3.1 Model for Developing Gas Trade ...................................................................... 35 vi Preface This report was prepared using data and information in World Bank reports and in the public domain to illustrate potential gas trade schemes that may benefit the developing countries of Asia and the Middle East-whether they are gas exporters or future importers. The World Bank has already carried out several comprehensive surveys for other regions including Russia, Africa, and Latin America. This report is thus intended to remedy, at least in part, the information gap for Asia and the Middle East. vii Abbreviations and Acronyms ADB Asian Development Bank BCF billion cubic feet (109 CF) BCM billion cubic meter (109 CM) BOD barrels of oil equivalent per day BOE barrels of oil equivalent BOO Build-Operate-Own BOT Build-Operate-Transfer Btu British thermal units CA Central Asia Capex capital expenditure CIF cost, insurance, and freight (included) CIS Commonwealth of Independent States CO2 carbon dioxide EBRD European Bank for Reconstruction and Development EPC engineering, procurement, and construction ESMAP Energy Sector Management Assistance Programme ESR Energy Sector Report EU European Union FE Far East FGD flue-gas desulfurization FO fuel oil FSU Former Soviet Union G-7 United States, Japan, Germany, United Kingdom, France, Italy, Canada GDP gross domestic product GWh Gigawatt hours (109 Wh) IEA International Energy Agency IENOG World Bank Industry and Energy Department, Oil and Gas Division lOC international oil company KWh kilowatt hours (103 Wh) LNG liquefied natural gas LPG liquefied petroleum gas LSTK lump-sum turn-key viii MCF thousand cubic feet ME Middle East MMBtu million British thermal units MMSCFD million standard cubic feet per day MMTCE million tonnes of coal equivalent MMTOE million tonnes of oil equivalent mtoe thousand tonnes of oil equivalent MW megawatt NG natural gas OECD Organization for Economic Cooperation and Development Opex operating expenditure p.a. per annum SA South Asia SAR Staff Appraisal Report SCF standard cubic feet measured at 60°F and 30 inch Hg SEA Southeast Asia TCM trillion cubic meter (1012 CM) TOC ton of coal equivalent TOE ton of oil equivalent TWh terawatt hour (1012 watts) UAE United Arab Emirates WB World Bank Definitions OECD Europe: Austria, Belgium, Denmark, Finland, France, Germany, Greece, Iceland, Ireland, Italy, Luxembourg, The Netherlands, Norway, Portugal, Spain, Sweden, Switzerland, United Kingdom. Middle East: Turkey, Israel, Bahrain, Iran, Iraq, Kuwait, Qatar, Saudi Arabia, Syria, UAE, Yemen. South Asia: India, Pakistan, Bangladesh, Sri Lanka, Nepal. Southeast Asia: Singapore, Thailand, Malaysia, Myanmar, Vietnam, Brunei, Indonesia, Papua New Guinea, Cambodia, Laos, Philippines. East Asia: China, South Korea, Taiwan, Japan, Mongolia, the Russian Far East. (For details on particular countries, see Annex 1.) ix Energy Measurements Natural Gas 1 MCF (1,000 CF) = 28.32 cubic meter = about 1 MMBtu = 252,000 Kcal 1 CM = about 9,000 Kcal 1 BCM = 35.3 BCF = about 0.9 MMTOE = about 1.35 MMTCE = (about 2.7 million tonnes of lignite) LNG 1 ton = LNG 2.35 m3 = about 1,400 m3 of natural gas Energy and Power lkWh = 3,412 Btu = 860 Kcal 1,000 kWh = 3.412 MMBtu 1 MW = 1,000 kW 1 GWh of electricity consumes approximately: 250 tons of oil in an oil-fired conventional steam power plant. 390 tons of coal in a coal-fired power plant. 8,000,OOOCF of natural gas in a combined-cycle power plant. x Executive Summary 1 This report explores the potential for expanded gas trade to benefit developing countries in Asia and the Middle East. The comparative environmental and economic benefits of using natural gas are such that many countries are seeking to mobilize resources to produce, trade, and use it (particularly as a substitute for coal and fuel oil for power generation). Gas trade projects are complex and often difficult to finance and undertake, however, and not all proposed projects are economically feasible. The report thus seeks to clarify the economic and technical potential for gas trade in Asia and the Middle East by reviewing the resource bases and gas markets in the region. It then discusses the viable gas trade schemes and elaborates some key issues and principles for formulating gas trade projects. 2 Toward the end of encouraging further development of gas trade, this report also seeks to stimulate discussion at the World Bank that will help guide the Bank's work in developing sound gas trade projects for its client countries all over the world. Natural Gas Demand 3 Natural gas is expected to continue to expand its share of primary energy markets throughout the world, as demand for this efficient, plentiful, and clean-burning fuel increases (see Figure 1 for projected gas consumption). In Asia, total primary energy demand is expected to expand from 650 million tons of oil equivalent (mtoe) in 1994 to 1,380 mtoe by 2010, an annual growth rate of 4.9 percent. This near-doubling of total energy demand over the next 15 years is certain to be accompanied by a shift toward natural gas, which is expected to grow by about 250 percent, from 73 mtoe (81 BCM) to 186 mtoe (207 BCM) by 2010, increasing from 11 percent of the total primary energy market in 1994 to 13.5 percent in 2010. A large portion of the incremental gas consumption will be gas-fired power generation. 4 A similar expansion of gas demand is expected in the Middle East, where total gas consumption is expected to climb from 40 mtoe (45 BCM) in 1994 to about 91 mtoe (101 BCM) in 2010. This would make the Middle East the fastest-growing gas- consuming region, with an annual growth rate of about 6 percent. 1 2 Natural Gas Trade in Asia and the Middle East Figure 1 Predicted Growth of Demand for Gas in Five Major Markets BCM/year 500 450 _ OECD Europe 400_ El Middle East 350 M South Asia 300 250 _ Southeast Asia 200 _ East Asia 150 __ 100- 50 1995 2000 2005 2010 Year Source: Cedigaz (1994a), Althius and others (1995). British Petroleum Company (1994). Natural Gas Resource Base 5 Distribution of the world's total estimated proven gas reserves of 141,000 BCM is highly uneven. More than two-thirds of global reserves are in two regions alone: the Middle East, with 32 percent (45,000 BCM); and the former Soviet Union (FSU), with 40 percent (57,000 BCM). In contrast, the Asia Pacific region and Africa each possess only about 7 percent of the world's reserves (9,900 BCM and 9,600 BCM, respectively), and North and South America each have about 5 percent (6,800 BCM and 7,100 BCM, respectively). Europe has the remaining 4 percent. The uneven global distribution of gas resources has important implications for trade, because major gas- consuming countries in East Asia and most of Europe lack sufficient indigenous gas reserves to supply their projected growth of consumption. Gas Trade in Asia and the Middle East 6 In Asia and the Middle East, substantial volumes of exploitable gas reserves could form the basis for greatly expanded intra- and interregional trade. Potentially large gas-consuming markets will grow in China, India, Pakistan, and Thailand, in addition to the existing large markets in East Asia and Europe. Far Eastern gas-consuming countries such as Japan, for example, are keen to secure alternative gas supply sources, as some of their major sources (Arun in Indonesia, for example) are becoming depleted. Moreover, despite the often long distances of gas supplies from markets, the high economic netback values (or market values)' of natural gas in various markets make transporting the gas over far greater distances feasible. 1. The gas netback value in a market can be found by calculating the price at which the cost of running on gas is the same as running on the cheapest alternative. This is equivalent to the market value and a measure of the maximum prices that a customer is prepared to pay for the gas. Executive Summary 3 20,999 Figure 2 Proven Natural Gas Reserves, Middle East and Asia (in billions of cubic meters) 2,500 2,500 1,840 2,000 Irk _ East Siberia _ W I d 'H k` sK->. 5 Irlutak Sak lin region G-p-y lejriloy h.1rar I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~rarrrr) f rrach loourrr 2,8591,868 PI- ~~~~~~~~~~r ... b N-J,-~irof I | X W 7 0 6 a~~~~~~~~~167 ra Republic of~~~~~~~~~ ~~77 1 I., Chiiia ~ ~ ~ Rp o India 2~~~~~~~~~~~~~oea io I N S 2 > Ban Iadesh yn a Ko-g (LIO K) t1 1 497 | 0 ~~~~~~~~~ ~ ~~Sri Lanka 1>g , Brtni9 Z rnittd ^ \ > Au5,793 alav Austrla a Saudi 630 Arabia 424 man R,p of Yeme e C Source: Data from British Petroleum Company (1994). 4 Natural Gas Trade in Asia and the Middle East 7 The projected increase in gas demand would create a supply gap in each region that is shown in Figure 3. Figure 3 Predicted Gas Supply Gap in Five Major Markets, 2000-2010 BCM/year 160 140 El OECD Europe E Middle East 120 - _ E South Asia 100 - Southeast Asia E East Asia 80 40 20 0-- 2000 2005 2010 Year Source: International Energy Agency (1994b), Cedigaz (1994a). Althius and others (1995), British Petroleum Company (1994). Market Value of Natural Gas 8 The feasibility of gas trade in specific cases would largely be determined by the market conditions in the consuming countries. If natural gas is largely available, the largest consumer in each gas market would be the power sector. A sample calculation (Table 1) indicates the benchmark netback values of gas used for power generation in selected countries. 9 Power generation based on combined-cycle gas turbines has at least the following economic advantages in addition to environmental benefits: * Least capital cost per unit power generation capacity (typically, $650/kW versus $1,300/kW for a coal-fired plant with flue-gas desulfurization [FGD] and $ 1,000/kW for a fuel-oil-fired plant with FGD) * Higher thermal efficiency (typically, 45 to 50 percent versus 30 to 35 percent for a coal-fired plant and 30 to 35 percent for a fuel-oil-fired plant) * Shorter construction period (typically, 2 to 3 years versus 5 years for a coal-fired plant and 4 years for a fuel-oil-fired plant). 10 Furthermore, a combined-cycle power generation plant can easily respond to load variation, whereas a coal- or fuel-oil-fired plant is more suitable for base load power Executive Summary 5 generation (in particular, coal-fired plants). Switching from high-carbon coal to low- carbon natural gas reduces output of carbon dioxide, which is a major source of global warming. 11 At present, gas markets in Japan, Korea, and Taiwan largely consist of imported liquefied natural gas (LNG). Since the current cost, insurance, and freight (CIF) price of LNG is about $3.0 to 3.3 per million British thermal units (MMBtu), the market value or reference value of imported gas would be about $3.7 per MMBtu considering the typical regasification cost for LNG of about $0.4 per MMBtu. Thus, if the cost of gas supply to these East Asian markets exceeds this reference value, the supply scheme would not be competitive. Table 1 Benchmark Gas Netback Values in Power Generation for Four Regions Total electricity Major fuel for Benchmark netback value for generated power generation gas in power generation Region and country (GWh) (percent) ($ per MMBtu) Middle East Turkey 73,808 Coal 32.2 3.6 Israel 30,116 Coal 53.1 3.6 South Asia Pakistan 56,639 Fuel oil 21.9 5.7 India 356,263 Coal 70.3 3.4 Southeast Asia Thailand 63,409 Coal 21.3 3.4 Singapore 18,962 Fuel oil 100 5.5 East Asia China 839,453 Coal 72.7 3.4 South Korea 144,437 Coal 21.4 3.4 Taiwan 107,118 Coal 34.8 3.4 Japan 906,705 Coal 12.6 3.4 Source: Electricity and major fuel data: for Turkey and Japan. International Energy Agency (1992): for others. International Energy Agency (1993b). Gas data: Althius and others (1995). Gas Transport Cost 12 The preliminary cost of transporting gas can be determined with the help of a model developed for this paper from several sources.2 The model assumes transport over ordinary terrain using engineering rules of thumb and information on typical operating cost and indicates costs for transporting gas volumes of 5, 10, and 20 MMTY (e.g. 6.9, 2. The pipeline model used information from MHI. JGC (Japan), and Gasunie (The Netherlands). The LNG model is similar to that given in a World Bank paper (Althius and others 1995). 6 Natural Gas Trade in Asia and the Middle East 13.8, and 27.6 BCMY)3 over distances of 1,200 km to 7,600 km. The model has been based on preliminary design of a potential Central Asia-Far East gas pipeline project. Although a detailed survey is required for any specific gas trade scheme, the model suggests that costs of long-distance onshore pipeline transport from Central Asia to the Far East could be competitive with those of LNG if the transport volume were large enough. (This is particularly true when, as is often the case, the sea route from exporter to importer is not the most direct, which would make the cost of LNG transport even higher.) This implies that even some landlocked Central Asian producers could export gas to remote markets provided that proper commercial arrangements were made. An engineering yardstick suggests that economies of scale for single pipelines would permit a maximum of 52- to 56-inch diameter pipe, which would transport about 20 MMTY (or about 28 BCMY) of natural gas. Above that volume, the equivalent of two or more pipelines would be needed, and general economies of scale may not work. Table 2 Indicative Costs for Long-Distance Transportation of Natural Gas by Quantity and Distance (US$ per MMBtu of natural gas) Distance (km) Transport volume Transport method 1,200 3,800 7,600 5 MMTY (6.9 BCMY) Onshore pipeline 0.99 3.41 7.80 Offshore pipeline 2.10 7.20 16.52 LNG 3.05 3.62 4.26 10 MMTY (13.8 BCMY) Onshore pipeline 0.74 2.52 5.65 Offshore pipeline 1.58 5.37 11.43 LNG 2.58 3.16 4.01 20 MMTY (27.6 BCMY) Onshore pipeline 0.54 1.75 3.89 Offshore pipeline 1.18 3.82 8.12 LNG 2.21 2.78 3.55 Note: LNG figures include costs for liquefaction and regasification. Calculations by this model roughly meet the actual cost of Japan's LNG imports from Indonesia (over 6,000 km), considering an LNG price of $3.81/MMBtu CIF and regasification cost of about $0.4/MMBtu. For any specific case, of course, data need to be input based on the actual costs. Possible Gas Trade Schemes 13 Assuming that each major gas market in Asia and the Middle East adopts an opportunity-cost approach toward its gas pricing policy and that the major consumer of gas in each of the markets is the power generation industry, gas import parameters for selected countries are as presented in Table 3 and Figures 4 through 7. 3. These volumes are at the supply point. For a long-distance pipeline, fuel gas consumption for gas compressor stations should be taken into account. The model has taken account of it. Executive Summary 7 Table 3 Possible Trade Schemes for Selected Gas-importing Countries Gas market Scheme parameters Pakista.' India Thailand China Benchmark gas netback value 5.7 (FO) 3.4 (C) 3.4 (C) 3.4 (C) for power ($/MMBtu) 5.5 (FO) Potential supply gap (BCMY) 2000 0.5 8.4 5.9 9.0 2005 7.5 20.8 10.6 16.1 2010 19.3 35.5 17.9 23.7 Potential gas suppliers Middle Eastern producers Distance 1,500 km 2,500 km 7,000 km 9,000 km Transport cost ($/MMBtu) Off-pipe: 2.0 Off-pipe: 2.5 LNG: 3.8 LNG: 3.8 LNG: 2.6 LNG: 2.5 @ 10 MMTY @Cb 20 MMTY @C 10 MMTY @u)20 MMTY Netback C supply country ($/MMBtu) Off-pipe: 3.7 Off-pipe: 0.9 1.7 (FO) LNG: 3.1 LNG: 0.9 South Asian producers n.a. (Bangladesh) n.a. n.a. Distance 500-1.000 km Transport cost ($/MMBtu) On-pipe: 0.5-0.9 Ca, 5 MMTY Netback (a) supply country ($/MMBtu) 2.5-2.9 Southeast Asian producers n.a. n.a. Distance 2,000-3,000 km 3000 km Transport cost ($/MMBtu) Off-pipe: 2.7-4.2 LNG: 3 LNG: 2.8-3.0 Ca 10 MMTY Ca 10 MMTY Netback (C supply country ($/MMBtu) Off-pipe: 1.3-2.8 0.4 LNG: 2.5-2.7 (FO) Central Asian producers n.a. Distance 2,500 km 3,500 km 6.000 km Transport cost ($/MMBtu) 2.2 C@,5 MMTY 3.1 (C 5 MMTY 3.0 @, 20 MMTY 1.7 C@10 MMTY 2.3 C@ 10 MMTY Netback (a) supply country ($/MMBtu) 3.5 Ca' 5 MMTY 0.3 (a 5 MMTY 0.4 Ca 20 MMTY 4.0 @ 10 MMTY 1.1 @ 10 MMTY Far Eastern producers n.a. n.a. n.a. Distance 3,500 km Transport cost ($/MMBtu) 2.3a @) 10 MMTY 1.6 @20 MMTY Netback Co, supply country ($/MMBtu) 1.1 @ 10 MMTY 1.8 @ 20 MMTY Note: The Middle Eastern producers are the Gulf countries (Egypt. Yemen, and so on); the South Asian producer is Bangladesh; the Southeast Asian producers are Indonesia, Malaysia, Brunei, and Papua New Guinea; the Central Asian producers are Turkmenistan, Kazakstan, and Uzbekistan; and the Far Eastern producers are the regions of the Russian Far East (Yakutsk. Baikal, and Sakhalin). (C) = coal; (FO) = fuel oil. 8 Natural Gas Trade in Asia and the Middle East Figure 4 Natural Gas Trade, Pakistan CU I R ussian Federation ~~~ASIA\ _' tN7,000 BCea Bua India > Mongolia 9 C () ~~Kzakstan~ , Turkmed Ara China th_ ato heWrdBn Grup sanyjdmen nh efghal stuso any Sri Lank territr oraceptnce of s . / 4 ~~~~Uzbeldstan Y~Myama < gturkmenistan SistavChina Islamic ~ ~ ~ ~ ~ 4Bngads g Irat '-.,\ Iran tR ,Jv \ I / * <>\~~~~~~~Kuwait Pa P istan Nea BhutaA EAS MIDE -'+,tQatar 8t * ,> l4,600 BCM aA INDIA , \w ~~ArdNa& /t ; -t~/ t(ynar y~~~United Arab % XBagdeh_, \ Emirates frl 9 BANG LADESH -. / 9 h g ~~~~~700 BCM > Rep. of Yemen | ~~~~~~Pipeline| … ___-__ LNG The boundaries and any other information shown on this map do not imply, Sri Lanka on the part of the World Bank Group, any judgment on the legal status of any territory or any endorsement or acceptance of such boundaries. INDICATIVE TRANSPORT COSTS (CASES): 1. Central Asia to India: 3,500 km by pipeline; $3.1/MMBtu @a 5 MMTY; $2.3 MMBtu (a 10 MMTY. 2. Middle East to India: 2,500 km by offshore pipeline; 3.5/MMBtu C@ 10 MMTY; $2.5 MMBtu C 20 MMTY. 3. Middle East to India by LNG: $2.9/MMBtu C,10 MMTY; $2.5 MMBtu (C 20 MMTY. 4. Bangladesh to India: 500- 1,000 km by pipeline; $0.5 - 0.9 MMBtu Ca, 5 MMTY. GAS SUPPLY GAP: 2000,9 BCMY; 2005,20 BCMY; 2010,36 BCMY. INDIA BENCHMARK NETBACK COAL REPLACEMENT: $3.4/MMBtu. Source: Geographic data from McAllister (1993). 10 Natural Gas Trade in Asia and the Middle East Figure 6 Natural Gas Trade, Thailand Turkmenistan aolikistas B s Myanma anistanL Hn K / > it ttl >f\ Iran CanJhodi / MIDD LEfKuwait \ BPauistan Nej BChina 9 <, gnitedArab + < Ba la~~~~B Ides g (U.K.) / Emiratesfil s \ /Ug S ( 1 \Ss g ~~~~~~~~~Macato > s \ Y LTHAILAND X Sh~~~~~~~~~~~~~~~~~~~~~~~~~ilippine, riXS Lanka # S J " a?,\s 2 ~~~~Brunei P - 3 Malaysia - -- -- -LNGa The boundaries and any other inforniation shown on this map do not imply, on the SOUTHEASd part of the World Bank Group, any judgment on the legal status of any territory or ASIA any endorsement or acceptance of such boundaries. 7,500 BCM Indonesia INDICATIVE TRANSPORT COSTS (CASES): 1. Southeast Asia to Thailand: 2,000 - 2,5000 km by offshore pipeline; $2.7 - $4.2/MMBtu (+ 10 MMTY. 2. Southeast Asia to Thailand by LNG: 2.8 - $3.0/MMBtu C@ 10 MMTY. 3. Middle East to Thailand 7,000 km by LNG: $3.8/MMBtu @10 MMTY. GAS SUPPLY GAP: 2000,6 BCMY; 2005, 11 BCMY; 2010, 18 BCMY. THAILAND BENCHMARK NETBACK COAL REPLACEMENT: $3.4/MMBtu. THAILAND BENCHMARK NETBACK FUEL OIL REPLACEMENT: $5.5MMBtu. Source: Geographic data from McAllister (1993). Executive Summary 11 Figure 7 Natural Gas Trade, China EAST Russian FedQratiOn 2ade0h HC M 1< ~~7,000 sCM \ < () I; a X ~~~~~~Mongolia Replip [c ofLa- MIDDI E .K-val iPakistal I Npl Bua CHINJ p ':Iudi S1Ma" )' \ r5> r i--p l o D A tbi. /4 \ \ X Ba ladesh g~~anma Ktng (U.K.) RCmv \ hailan X J.I Wp n d 1~~~~~~~~~~~~~~~~~~~ Pipeline | \)Sri Lanka 9 Brunei SOUTHEAST ASIA Indonesia d 7,500 BCM Iddone&'a The boundaries and any olSr antormanaon l l-w-n n ,his map do not impl). .0n tho part of tho World Bnnc Group, anN judgmcnr on the legal status of ans terrhtony or any ondorsonnen- or ac.cptance ot ,uch b-oundarie. INDICATIVE TRANSPORT COSTS (CASES): 1. Middle East to China: 9,000 km by LNG; $3.8/MMBtu Ca) 20 MMTY. 2. Southeast Asia to China: 3,000 km by LNG; 3.0/MMBtu @ 10 MMTY. 3. East Siberia to China: 3,500 km by pipeline; $2.3/MMBtu @10 MMTY; $1.6 MMBtu Ca 20 MMTY. 4. Central Asia to China: 6,000 km by pipeline; $4.3 MMBtu @C 10 MMTY; $3.0 MMBtu Ca, 20 MMTY GAS SUPPLY GAP: 2000,9 BCMY; 2005,16 BCMY; 2010,24 BCMY. CHINA BENCHMARK NETBACK COAL REPLACEMENT: $3.4/MMBtu. Source: Geographic data from McAllister (1993). 12 Natural Gas Trade in Asia and the Middle East Challenges in Formulating Gas Trade Projects Gas Tariffs 14 In most developing countries in Asia and the Middle East, current gas prices are extremely low by international standards and often lower than the marginal cost of supply. In the case of natural gas imports to countries such as China, India, and Pakistan, pricing reform will be an essential element for formulating financially viable gas import projects. Contractual Arrangements 15 Large gas export projects with modest profit margins depend on a reliable long-term (15 to 25 year) take-or-pay commitment by the gas importer. Hence, sound contractual models for gas sales and transit arrangements must be established. Legal Framework 16 To put in place the minimum requirements for private sector participation, an internationally accepted legal framework is essential for gas producers and exporting and consuming countries that clarifies governing laws/regulations, the regulatory framework for licenses/permits, accounting standards, and resolution of commercial disputes. This should also cover private sector corporate laws, foreign investment protection, and bankruptcy law. Structuring Project Company 17 Private sector participation in a project in a developing country could be a tool for promoting business efficiency and enhancing the viability of the project. In developing countries where rapid privatization is not feasible, a joint venture between the government and international private sector firms could be a realistic way to formulate a project. Financing 18 Successful financial arrangements are always critical in formulating any project. In particular, projects must offer potential investors and financiers clear and feasible plans for resolving numerous financing and operating issues and for mitigating risk. Some of these financing issues are as follows: a. The method of payment. Is it cash or barter? In-country or external? Does it require foreign exchange? b. Contractual options. Do contracts take into account the need of the supplier to enforce take-or-pay contracts? What is the necessary duration of the supply contract? c. The supply profile. Can the producer meet it? d. Present and future institutional issues. e. Supply reliability and risk. f. Policy issues. These include open access and whether policy objectives can be achieved with each option. Executive Summary 13 19 The financing options for any particular project would differ according to the status of the implementing institution, its financial strength, its access to hard currency, and whether the financing is included "on balance sheet" or "off balance sheet." 20 According to the economic and technical model of gas trade analysis presented here, several specific gas trade schemes in Asia and the Middle East appear fundamentally feasible and would justify further evaluation (see Table 4). The main challenges would be resolving the political and commercial issues that are involved. Table 4 Potentially Feasible Gas Trade Schemes, Middle East and Asia Gas import demand Gas importing (BCMY) Possible gas Economical gas trade region! countries 2000 2005 2010 suppliers volume (order of magnitude) Middle East 6.6 9.2 13.3 Turkey 1. ME producers 1. Min. 2-3 BCMY (by pipe) Israel 2. CA producers 2. Min. 4-5 BCMY (by pipe) (to Turkey) South Asia 8.8 28.3 54.9 Pakistan 1. ME producers 1. Min. 5 BCMY (by pipe) 1. Min. 5 BCMY (by LNG) 2. CA producers 2. Min. 5 BCMY (by pipe) India 1. ME producers 1. Min. 10 BCMY (by LNG) 2. CA producers 2. Min. 10 BCMY (by pipe) 3. Bangladesh 3. Min. 5 BCMY (by pipe) Southeast Asia 7.3 11.6 18.4 Thailand 1. ME producers 1. Min. 10 BCMY (by LNG) Singapore 2. SEA producers 2. Min. 5 BCMY (by pipe) 2. Min. 5 BCMY (by LNG) East Asia 7.3 22.2 67 China 1. ME producers 1. Min. 20 BCMY (by LNG) South Korea 2. SEA producers 2. Min. 5 BCMY (by LNG) Taiwan 3. CA producers 3. Min. 20 BCMY (by pipe) Japan 4. FE producers 4. Min. 10 BCMY (by pipe) Note: CA = Central Asia; FE = Far East: ME = Middle East: SEA = Southeast Asia. 21 Given the increasing demand for gas, the World Bank could be in a position to support sound, proactive gas trade projects in World Bank member countries. Such schemes may involve trade and transmission of gas in varying volumes and over a range of distances. If the member countries or project entities want the Bank to become involved, the Bank can play a catalytic role in developing countries and among private sector investors in a variety of ways-through technical advice and assistance and through innovative guarantee instruments that can help mobilize critical financing, conventional loans, or both. 1 Natural Gas Demand Primary Energy Growth 1.1 Total primary energy demand in the world is expected to increase from 8,290 mtoe in 1995 to 11,700 mtoe (more than 40 percent) by the year 2010. In volume of growth, the greatest expansion in primary energy demand is anticipated in Asia, with a projected increase from 2,138 mtoe in 1995 to 3,673 mtoe, by year 2010. As early as the year 2000, Asia will overtake North America as the largest regional market for energy. The Middle East will also experience a significant increase in primary energy demand, from 377 mtoe in 1995 to 689 mtoe (more than 80 percent growth) by 2010. 1.2 In rate of growth, the Middle East is the fastest-expanding energy consumer in the world, with an annual growth in energy use of 3.88 percent (cumulating to more than 80 percent) expected between 1995 and 2010. Energy demand in Asia is projected to grow at an annual average of 3.67 percent (cumulating to more than 70 percent over the period) compared with annual growth in world energy demand of 2.32 percent from 1995 to 2010. The escalation of energy consumption is driven by an increase in economic activity and the changing structure of the economy. As developing countries in Asia and the Middle East industrialize their economies, demand for energy will increase proportionally and with much greater intensity. 1.3 Forecasts for economic growth for selected countries or groups of countries in Asia and the Middle East are presented in Table 1.1. 15 16 Natural Gas Trade in Asia and the Middle East Table 1.1 Economic Growth Forecast for Selected Countries or Groups of Countries in Asia and the Middle East, 1995-2000 Country/group 1995 1996 1997 1998 1999 2000 China 9.9 8.2 7.9 7.7 7.6 7.5 Egypt 4.3 4.7 4.9 5.9 5.9 5.0 Europe 3.1 3.0 2.7 2.7 2.8 2.7 India 5.0 4.9 5.0 4.9 4.9 4.8 Indonesia 6.2 5.3 5.2 5.3 5.4 4.6 Iran 3.2 3.4 4.1 4.4 4.5 4.6 Israel 4.8 6.3 6.4 5.9 5.6 5.3 Korea 7.4 6.3 6.2 6.0 5.8 5.8 Malaysia 8.5 7.2 6.9 7.0 6.3 5.5 Pakistan 3.9 4.1 4.3 4.2 4.2 4.2 Philippines 6.2 5.5 6.0 5.7 5.9 5.8 Saudi Arabia -2.5 3.3 2.8 2.9 2.7 2.4 Singapore 8.6 6.8 5.4 4.7 4.7 4.8 Taiwan 6.7 6.2 5.8 5.8 5.8 5.7 Thailand 8.5 6.2 6.3 6.1 5.8 6.2 Turkey 0.9 4.8 4.8 4.7 4.7 4.6 EU 3.2 2.9 2.6 2.7 2.7 2.7 G-7 2.8 2.6 2.6 2.4 2.7 2.9 Source: For China, India, Indonesia, Korea. and Thailand: Ishiguro and Akiyama (1995). For Malaysia, Pakistan, Philippines, Singapore, and Taiwan: Asian Development Bank (1994). For Europe, EU, and G-7: DRI/McGraw-Hill (1996). 1.4 Most countries in Asia and the Middle East are expected to have annual energy growth rates in excess of 4 percent. This compares favorably with G-7 and EU countries, which have annual growth rates of less than 3 percent. Although the relative size of some of the Asian and Middle Eastern economies is small compared with Europe, the incremental demand for energy is huge, as shown in Table 1.2. Natural Gas Demand 17 Table 1.2 Annual Energy and Natural Gas Demand Growth in Five Regions, 1990-2000 (percent) Primary energy Natural gas Region 1990-2000 2000-2010 1990-2000 2000-2010 Western Europe 1.10 1.20 2.60 2.60 Middle East 3.43 3.64 9.02 7.24 South Asia 4.22 4.76 7.98 7.91 Southeast Asia 7.03 5.53 12.29 6.94 East Asia 3.25 2.95 2.28 4.51 Source: For Western Europe and Southeast Asia: International Energy Agency (1994c). For Middle East, South Asia. and East Asia: International Energy Agency (1995d). 1.5 Among the various primary energy sources, natural gas is preferable for environmental reasons. In particular, gas-turbine combined-cycle technology provides a clean, least-cost option for generating electric power, the largest demand source for primary energy. The benefits of gas make it a valuable resource; thus, despite the cost of transport, gas can be expected to increase its overall share in primary energy. Sphere of Influence of Export Markets for Asian and Middle Eastern Gas Producers 1.6 Given the geography of Asia and the Middle East, the market spheres for gas producers/exporters would likely be as follows: a. Middle Eastern producers/exporters would find markets among the following areas: Middle Eastern gas-consuming countries-in particular, Israel, Jordan, and Turkey * Western Europe * South Asia (India, Pakistan) * Southeast Asia (Thailand, Singapore) * East Asia (Japan, Korea, Taiwan, China). b. Asian gas producers/exporters would find markets in the following regions: * South Asia * Southeast Asia * East Asia. 18 Natural Gas Trade in Asia and the Middle East c. Central Asian producing/exporting countries are landlocked and would have markets as follows: * Similar to those of Middle East (see item a) * Azerbaijan's markets more limited-principally Europe and Turkey. 1.7 A number of studies have been carried out to forecast gas demand in each of these regions and in each large consuming country therein. A typical example, synthesized from various projections, indicates the gas demand growth as presented in Table 1.3. 1.8 This forecast of natural gas demand is considered conservative because it assumes no large increases in oil prices, gas prices remaining competitive relative to oil prices, and only small increases in industrial and power sector efficiency. 1.9 The relative underdevelopment of Asian gas markets is expected to lead to rapid increases in natural gas demand. Previously, a single consumption point was linked to a single supply center, with these centers potentially supplemented by new consumers. Now, an extensive transmission and distribution network is being developed, with countries expected to diversify their energy sources by importing via LNG or pipeline. Multiple sources of natural gas will safeguard against possible disruptions and will enhance gas supply security. Sectoral Demands 1.10 One possible limitation on the growth of energy demand in many newly industrialized countries is that they have little spare capacity in their port, rail, and road infrastructures. (For example, China has plentiful supplies of coal, which is considered the country's cheapest primary energy resource. However, the difficulties in transporting coal to the point of consumption constrain its use.) In this context, broad-scale renovations and investments in instrastructures, when properly taken into account, may make gas import schemes more viable. 1.11 Where infrastructure is capable, or potentially capable, of supporting an import program, the power sector is expected to remain the largest consumer of natural gas. Given the current suppressed level of electricity consumption in many developing countries, the power sector is expected to grow approximately threefold over a 20-year period ending in 2010 in many regions of the world, such as the Middle East (where production is expected to rise from 228 TWh to 652 TWh) and China (where production is expected to jump from 677 TWh to 2094 TWh). In many countries, often the need for additional power generation is for peak sharing loads. Power generation via gas firing is by far most suitable for load variation. 1.12 Technical advances have made natural gas the fuel of choice among power producers. A gas-fired combined-cycle power plant has a typical capital cost of $690/kW compared with $1,000/kW for fuel-oil-based generation and $1,300/kW for a coal plant with a flue-gas desulfurization (FGD) unit. For a country seeking to add 1,000 to 2,000 Natural Gas Demand 1 9 MW of electric generation capacity over a short period, the savings in total capital investment costs using gas combined-cycle would be close to a billion dollars. Table 1.3 World Natural Gas Demand by Region and Selected Country, 1995-2010 (BCM per year) Regioni/country 1995 2000 2005 2010 OECD Europe France 37.7 42.0 44.4 46.3 Germany 84.6 109.3 119.3 125.3 Italy 53.4 67.0 72.4 77.9 Spain 7.6 14.3 16.3 18.1 United Kingdom 81.1 98.3 103.1 107.8 Other countries 23.6 13.6 71.8 119.0 Subtotal 288.0 344.4 427.2 494.4 Middle East Egypt 11.4 16.4 20.8 25.4 Iran 27.2 33.6 41.6 55.1 Israel 0.2 1.3 2.3 3.5 Turkey 6.5 8.6 11.6 16.6 Subtotal 45.4 60.0 76.3 100.6 South Asia India 17.5 28.2 47.5 71.3 Pakistan 19.6 27.1 35.8 47.2 Subtotal 37.1 55.3 83.3 118.4 Southeast Asia Singapore 1.4 1.4 1.4 1.4 Thailand 10.1 15.0 21.6 30.7 Subtotal 11.5 16.4 23.0 32.2 East Asia China 21.8 27.1 35.0 44.9 Japan 50.4 50.9 60.4 72.0 Korea 6.5 8.6 11.3 13.4 Taiwan 4.3 6.0 8.8 13.3 Subtotal 83.0 92.6 115.4 143.6 North America 594.7 639.5 711.8 784.0 Latin America 100.8 110.9 134.4 157.9 Eastern and Central Europe 68.3 72.8 91.3 109.8 CIS 631.7 622.7 663.6 704.5 Africa 43.7 50.4 66.1 81.8 Oceania 27.8 38.7 52.3 70.2 WORLD TOTAL 1,932.0 2,103.7 2,444.7 2,797.4 Source: International Energy Agency (1994c, 1995d). 20 Natural Gas Trade in Asia and the Middle East 1.13 Another key source of demand for natural gas would be the cement, fertilizer, petrochemical, and steel industries of newly industrialized countries. Such large industrial consumers are integral to the growth of these countries and most likely will provide the basis for developing a domestic natural gas network. The governments of the developing countries should also consider the economic benefits of using natural gas in the residential and commercial sectors. 1.14 For all potential market areas for gas produced in the Middle East, Asia, and Central Asia, the breakdown of consumption by sector is shown in Table 1.4. Table 1.4 Natural Gas Consumption by Region and Sector (BCM per year) Region/sector 1995 2000 2005 2010 OECD Europe (excluding Turkey) Industry 158.6 156.5 185.9 210.0 Commercial/residential 38.7 40.7 50.3 58.0 Power 90.8 147.2 191.0 226.4 Total 288.0 344.4 427.2 494.4 Middle East Industry 31.0 36.1 46.7 58.2 Commercial/residential 16.5 17.5 20.5 24.1 Power 35.5 39.0 48.2 61.4 Total 83.0 92.6 115.4 143.6 South Asia Industry 20.6 26.2 34.4 44.6 Commercial/residential 3.5 5.5 7.8 10.2 Power 13.0 23.6 41.1 63.6 Total 37.1 55.3 83.3 118.4 Southeast Asia Industry 0.8 (.9 1.1 1.4 Commercial/residential 0.0 0.0 0.0 0.0 Power 10.8 15.5 21.9 30.8 Total 11.5 16.4 23.0 32.2 East Asia Industry 21.7 28.2 36.2 46.4 Commercial/residential 8.3 10.5 14.2 18.4 Power 53.0 53.9 65.0 78.9 Total 83.0 92.6 115.4 143.6 Source: International Energy Agency (1994c, 1995d). Natural Gas Demand 21 Regional Gas Balance 1.15 Many countries in Asia and Europe lack sufficient domestic hydrocarbon resources to satisfy their growing energy demand-particularly the demand for natural gas. In fact, most industrialized countries must import natural gas. Note, however, that not all this demand could be satisfied immediately even if gas were available, because for some countries, the existing infrastructure cannot handle the increases in demand. Tables 1.5 through 1.9 show the natural gas balances in the major gas markets for gas producers in Asia and the Middle East. OECD Europe 1.16 In Europe, where most countries are active consumers of natural gas, France, Germany, Belgium, Switzerland, Austria, and others with little domestic gas production rely on imports, giving rise to significant cross-border trade. Traditionally, gas supplies to European consumers have come from producers in the Netherlands, Denmark, Russia, and Norway. Algeria also supplies gas via pipeline to Italy. Other European countries import a substantial amount of LNG from Algeria and, to a lesser degree, from Libya. However, gas production in Denmark and the Netherlands is declining, with the latter planning to phase out most of its gas exports before 2015. The United Kingdom is not expected to have any surplus gas available for export. In Western Europe, only Norway has substantial gas reserves, is keen to continue exporting, and is planning new gas export pipelines. Gas exports to Europe from Russia (and, to a lesser degree, from Turkmenistan) are expected to continue. However, this will require major rehabilitation of existing pipelines (in particular at gas compressor stations on the Soyuz, Progress, Urengoi-Ujugorod, and other export pipelines in Ukraine). Alternatively, they require a new trunk pipeline (e.g., the Yamal-Germany pipeline). Another limiting factor on the potential of Russia to supply Western Europe is that Russian and Eastern and Central Europe's domestic gas demand is expected to grow. Hence, even after extending current contracts and utilizing all the spare capacity of the existing pipelines, a potential supply gap exists. Table 1.5 Projected Gas Balance for OECD Europe, 2000-2010 (BCM) Balance item 2000 2005 2010 Demand 344.4 427.2 494.4 Production and import contracts 248.5 246.2 189.8 Extensions 36.0 59.0 152.0 Potential supply gap 59.9 122.0 152.6 Note: Extensions are based on contracts being extended, utilizing current infrastructure. Source: Cedigaz (1994a, 1994b) and International Energy Agency (1994b). 22 Natural Gas Trade in Asia and the Middle East Middle East (Turkey and Israel) 1.17 Table 1.6 shows the gas balances for Turkey and Israel. The Middle East is expected to be the fastest growing gas-consuming region. This growth will be based on development of large gas fields, collection of associated gas, development of the petrochemical and other gas-based industries, and substitution of gas for oil in other domestic industries and power generation. Table 1.6 Projected Gas Balance for Turkey and Israel, 2000-2010 (BCM) Balance item 2000 2005 2010 Demand 6.7 9.3 13.4 Production 0.1 0.1 0.1 Potential supply gap 6.6 9.2 13.3 Source: Shilo, Bar Mashiah, and Er-El (1993) and DRI/McGraw-Hill (1995). South Asia (India and Pakistan) 1.18 Table 1.7 shows the gas balances for India and Pakistan. India is the world's second-largest economy outside the OECD; consequently, its energy requirements are enormous. India has gas deposits in many different parts of the country. Although some of these deposits are being exploited commercially, reserves are insufficient to meet the growing demand. Bottlenecks in transport infrastructure and environmental concerns in densely populated areas do not allow for increased use of coal, which is abundant but of poor quality. India also suffers from power shortages. Promoters of new power projects in general prefer the use of natural gas, given the low project costs and short lead times. Table 1.7 Projected Gas Balance for India and Pakistan 2000-2010 (BCM) Balance item 2000 2005 2010 Demand 55.3 83.3 118.4 Production 46.5 55.0 63.5 Potential supply gap 8.8 28.3 54.9 Source: World Bank (1996). India: Althius and others (1995). 1.19 Pakistan is a rapidly developing economy that is also industrializing at a rapid rate. Pakistan has a successful exploration program that has led to increased exploitation of domestic reserves. Much of the demand for gas is not being met because the government is forced to prioritize customers. In addition, current domestic production is Natural Gas Demand 23 expected to plateau by 2008. Imports of gas from nearby producers could be a viable option for Pakistan. Southeast Asia (Thailand and Singapore) 1.20 Table 1.8 shows the gas balance for Southeast Asia, a region with one of the highest economic growth rates in the world. The GDPs of Singapore and Thailand are growing at between 4 and 5 percent a year, and rapid industrialization has increased demand for energy. Concomitantly, rising incomes and demand for cleaner fuels have increased the demand for natural gas. Singapore has no natural gas deposits; Thailand has small amounts of gas in the Gulf of Thailand (estimated proved reserves as of January 1995 were 0.2 TCM). Given the very modest local supplies, the only option is to make up shortfalls with imports via pipeline or LNG. Myanmar, west of Thailand, possesses exportable quantities of gas (estimated proved reserves as of January 1995 were 0.3 TCM). A piped-gas export scheme is in the planning stages. Thailand is also considering an LNG import option from the Middle East, whereas Singapore may increase natural gas imports from gas-rich Malaysia. Table 1.8 Projected Gas Balance for Singapore and Thailand 2000-2010 (BCM) Balance item 2000 2005 2010 Demand 16.4 23.0 32.2 Production 9.1 11.4 13.8 Potential supply gap 7.3 11.6 18.4 Source: World Bank (1994d) and DRI/McGraw-Uill (1993). East Asia (China, South Korea, Japan, and Taiwan) 1.21 Table 1.9 shows the gas balance for four major East Asian economies. Existing natural gas markets in this region are expected to grow steadily. The annual growth of the Japanese market alone is estimated at about 3 percent. China became a net oil importer in 1994. East Asia is one of the most energy-scarce regions in the world, given the level of demand. Japan, Korea, and Taiwan have only marginal hydrocarbon resources and continue to import a majority of their energy supply. All these countries use LPG imports, since no regional pipeline network exists at present. Japan in fact is the world's largest importer of gas, accounting for 84 percent of the Asian market (and consuming 65 percent of the world's LNG). In the near future, China could be a gas importer, as well. 24 Natural Gas Trade in Asia and the Middle East Table 1.9 Projected Gas Balance for China, South Korea, Japan, and Taiwan (BCM) Balance item 2000 2005 2010 Demand 92.6 115.4 143.6 Production and import contracts 78.9 72.3 63.3 Extension 6.4 20.9 13.3 Potential supply gap 7.3 22.2 67.0 Note: The LNG import contract is extended to the maximum handling capacity of the regasification terminals. Source: Cedigaz (1994a, 1994b), British Petroleum Company (1994). 2 Natural Gas Resource Base Gas Reserves, Production, and Exportable Gas 2.1 Although demand for natural gas has increased over time, natural gas reserves have also shown a remarkable growth. In 1994, worldwide proven gas reserves were estimated at 141,000 BCM, an increase of 360 percent from 1970 (Oil and Gas Journal 1995). This trend is expected to continue, especially considering the investments allocated for exploration and production of gas reserves around the world. 2.2 Natural gas is no longer merely a wasted by-product of crude oil production. In addition to exploring more vigorously for exploitable reservoirs of gas (nonassociated), many countries are also capturing formerly flared or vented gas that is produced in conjunction with oil (associated gas). Countries are also improving energy efficiency and arresting gas leakage as ways of protecting the environment and strengthening their gas supplies. 2.3 The distribution of natural gas throughout the world is very uneven, with more than two-thirds of the reserves located in the Middle East and the FSU. Of the world's total estimated proven gas reserves of 141,000 BCM, the Middle East has 45,000 BCM (32 percent) and the FSU 57,000 BCM (40 percent). The Asia Pacific region and Africa possess 9,900 BCM and 9,600 BCM (about 7 percent each of the world's reserves). North America and South America have 6,800 BCM and 7,100 BCM, respectively (about 5 percent of the world's reserves). Europe has only 4 percent of the world share. Reserves, production, and potential exportable gas are shown for Asia and the Middle East in Table 2.1. 2.4 For most natural gas producers in Asia and the Middle East, exploiting and exporting natural gas could become an important means of generating foreign exchange. 2.5 In the Middle East, natural gas deposits are concentrated in a few countries. Iran alone possesses estimated recoverable reserves of 21,000 BCM. Other nations with significant export potential include Qatar, Abu Dhabi, and Saudi Arabia, with recoverable gas reserves of 7,080 BCM, 5,335 BCM and 5,250 BCM, respectively. Yemen, Syria, and Oman also possess large gas deposits that are available for export, given the small 25 26 Natural Gas Trade in Asia and the Middle East size of their domestic markets. If its Western Desert and Mediterranean gas fields are developed, Egypt, too, could also become a gas exporter. Table 2.1 Gas Reserves, Production, and Exportable Gas in Asia and the Middle East 1993 Reserves (proven recoverable Gross production Net importsl Domestic reserves) imports (exports) consumption (B(CM) (BCMp.a.) (BCMp.a.) (BCM p.a.) Egypt 436 9.80 0.00 9.80 Iran 20,700 25.00 0.00 25.00 Iraq 3,100 2.86 0.00 2.86 Kuwait 1,485 2.62 0.00 2.62 Saudi Arabia 5,250 34.00 0.00 34.00 Oman 550 3.31 0.00 3.31 Qatar 7,079 11.35 0.00 1.35 UAE 5,765 Syria 200 3.60 0.00 3.60 Yemen 429 0.00 0.00 0.00 Bangladesh 714 5.84 0.00 5.84 Brunei 400 8.10 (7.13) 0.97 Indonesia 3,180 54.05 (31.63) 22.42 Malaysia 1,926 22.55 (10.86) 11.69 Myanmar 280 1.43 0.00 1.43 Thailand 163 9.68 0.00 9.68 Russian Far East 4,500-5,070 8.60 0.00 8.60 Papua New Guinea 436 0.05 0.00 0.05 Vietnam 106 0.21 0.00 0.21 Azerbaijan 900 9.30 5.30 (0.95) 9.54 Kazakstan 2,400 8.30 13.06 (4.67) 14.43 Turkmenistan 2,900 55.00 (47.56) 5.80 Uzbekistan 1,900 39.10 2.12 (3.67) 37.60 Source: Except as noted, Oil and Gas Journal (1995). Petroleum Economist Ltd. (1994), and Petroleum Economist and Ernst & Young (1994). For Egypt, Cedigaz (1994a). For Azerbaijan, Petroleum Economist Ltd. (1994: 80-81). Natural Gas Resource Base 27 2.6 In Southeast Asia, Indonesia could continue to be a major gas exporter. However, its main gas reserve, the Arun gas field, is severely depleted, limiting the potential for gas exports. Brunei and Malaysia are also important gas suppliers. New gas exporters could include Myanmar, Papua New Guinea, and Bangladesh. If the gas deposits in the Nam Con Son Basin are developed, Vietnam would consider gas exports to Thailand. 2.7 Gas from the Russian Far East could be a substantial source of supply to East Asian markets. The remoteness and harsh climate of Russia's Far Eastern gas-producing regions (i.e., Lena-Tunguska, Lena-Vilyui, and Okhotsk) have so far impeded the full exploitation of most of the gas resources. China's Tarim basin could be a large gas supplier, but all the gas from this field would be consumed in China's ever-growing markets. 2.8 In Central Asia, Kazakstan, Turkmenistan, and Uzbekistan (in particular, Turkmenistan and, in the future, Kazakstan) have surplus gas to export. A major challenge for these landlocked countries is to secure access to international markets, which may require new gas pipelines. An economically viable scheme in the near future is, however, to use existing Russian gas export pipelines. Although Kazakstan possesses a relatively large gas deposit, at present the country imports about 5 to 7 BCMY of gas from Turkmenistan because the main gas consumption center in Kazakstan is located in the southeastern region, whereas the gas-producing zone is in the northwestern region, more than 2,000 km distant. A better arrangement would be to swap gas; for example, while Kazakstan would continue to import Turkmen gas, Kazakstan would export Karachaganak gas under a swap arrangement. Production Costs 2.9 Gas production costs vary significantly from field to field. Major factors include the reservoir size, reserve depth, geological and geophysical characteristics of the field, and quality of the gas. The efficiency of production is also influential. Natural gas, when produced from associated gas fields, has a cost advantage because some infrastructure costs can be shared with oil production. For example, if ethane, LPG, or hydrocarbon condensates were present in appreciable amounts, the economics of gas production projects generally would improve. Natural gas must be treated before it is transported to remove impurities such as sulfur, water, and carbon dioxide. The gas treatment plants required for this purpose will depend to a large degree on the amount of impurities present in the gas. Most gas producers in the CIS require considerable investments for gas conditioning. 2.10 Although it is difficult to predict production costs, the industry consensus for the Middle East is $0.40 to $0.60 per MMBtu. Production costs are estimated at $0.50 per MMBtu in Siberia and Turkmenistan, $1.50 per MMBtu in the Barents Sea, and $1.50 per MMBtu in the British sector of the North Sea. 3 Gas Trade Schemes for the Developing Countries Growth of International Gas Trade 3.1 World gas trade will continue to grow. Since 1970, gas trade volume expanded almost tenfold, as shown in Table 3.1. Table 3.1 World Gas Trade, 1970-1994 World World World Percent total World pipeline World LNG of LNG in World total (% of pipeline (% of LNG (% of total gas Year (billion m3) prod'ni) (billion m-3) prod'n) (billion m3) prod'n) trade 1970 45.68 4.4 42.93 4.1 2.69 0.3 5.9 1975 125.37 9.9 112.32 8.9 13.05 1.0 10.4 1980 200.98 13.2 169.64 11.1 31.34 2.1 15.6 1985 228.85 13.1 177.97 10.2 50.88 2.9 22.2 1986 226.70 12.6 175.50 9.8 51.20 2.8 22.6 1987 252.26 13.4 196.17 10.4 56.09 3.0 22.2 1988 265.40 13.5 204.94 10.4 60.46 3.1 22.8 1989 292.84 14.4 228.35 11.2 64.49 3.2 22.0 1990 307.43 14.8 235.29 11.3 72.14 3.5 23.5 1991 322.56 15.3 245.59 11.6 76.97 3.7 23.9 1992 337.46 16.0 257.52 12.2 80.94 3.8 24.0 1993 347.13 16.1 264.09 12.2 83.04 3.8 24.0 1994 362.75 16.7 275.00 12.7 87.80 4.0 24.2 1995 388.40 18.3 295.90 14.0 92.50 4.4 23.8 Source: Cedigaz (1995a) and British Petroleum Company (1996). 29 30 Natural Gas Trade in Asia and the Middle East 3.2 World LNG exports began expanding in earnest during the 1980s on the heels of almost negligible shipments in the 1970s. Throughout the world, the volume of piped gas far exceeds the volume of gas transported as LNG (275 BCM versus 87.8 BCM in 1994). New Trends in Gas Trade 3.3 Large reserves of exploitable gas exist in Asia and the Middle East. Potentially large markets for gas will grow in China, India, Pakistan, and Thailand in addition to the existing large- and medium-sized markets in the Middle East, South Asia, East Asia, and Europe. The Far Eastern countries in particular are keen on securing alternative gas supply sources to replace some major gas sources that are being depleted (such as the Arun field in Indonesia). Hence, a trend toward transporting gas over greater distances is emerging, encouraged by the high netback values of natural gas in various markets. 3.4 Another trend is to exploit the increasing opportunities for localized gas transport with relatively small volumes of gas between countries within the same region. A good example is a proposed scheme that would transport a few BCM of gas per year from Egypt to Israel. Again, the high netback values of natural gas would enhance the localized small-volume gas transactions. 3.5 A third trend is reflected in the increase in gas pipeline projects that are multinational efforts. Except for the gas trade between western Siberia and Europe and between Algeria and Italy, gas has traditionally been traded on a bilateral basis. LNG transactions, for example, are always based on bilateral contracts. Longer-distance gas transportation, however, with its greater capital requirements and greater number of transit countries, increases the need for multinational participation, particularly for gas exports from landlocked Central Asian producers. Potential Gas Export Markets for Asian and Middle Eastern Gas Producers 3.6 Based on the information on gas demand and gas supply in the two previous chapters, potential gas trade scenarios may be synthesized as follows for several key markets. Western European Market 3.7 Current Gas Trade. Currently, gas markets in OECD European countries are being supplied from European gas producers (mainly the Netherlands and Norway); the Commonwealth of Independent States (CIS; about 90 percent from Russia and 10 percent from Turkmenistan); Algeria; and, to a lesser extent, Libya. Western Europe is the third- largest gas consumer in the world (about 292 BCM in 1994) after North America (690 BCM) and Eastern Europe (including the former Soviet Union, 605 BCM). Table 3.2 presents the current pattern and sources of gas imports of Western Europe's gas imports. Gas Trade Schemes for the Developing Countries 31 Table 3.2 Volumes and Sources of Western European Gas Imports, 1995 (BCMY) Source of natural gas Gas imports cIS Algeria Libya UAE Alustralia By pipeline 135.2 117.4 17.8 0 0 0 By LNG 21.0 - 17.7 1.5 1.5 0.3 TOTAL 156.2 117.4 35.5 1.5 1.5 0.3 Source: British Petroleum Company (1996). Note: The source of natural gas data excludes gas exporters within the region. CIS = Commonwealth of Independent States. The gas trade to Western European markets is largely based on piped gas, and LNG trade is limited. 3.8 Future Gas Markets and Potential Gas Trade. By the year 2010, gas demand in Western Europe is expected to require an additional volume of about 110 to 150 BCMY. Since the gas reserves in the Netherlands are being depleted, and the country will terminate gas exports before 2010, Western Europe needs to consider new gas trade schemes to import more than 150 BCMY. Possible sources would include the current North African and FSU gas suppliers plus Middle Eastern gas producers. With the planned development of gas reserves in the Yamal peninsula and the Barents Sea, Russia should remain a large gas supplier to Western Europe. Central Asian gas producers, however, may be hard pressed to compete in the Western European market given their long distance from Western Europe (more than 6,000 km) and the relatively cheap market prices for gas in Western Europe, (compared, say, with Japanese markets). Hence, Turkmenistan and, in the future, potentially Kazakstan and Azerbaijan, may not become substantial players in the Western European gas market unless their gas can be exported through the existing Russian gas pipeline network. Opportunities for Middle Eastern producers to export gas to Western Europe would be similarly limited in the near future. Turkish Market 3.9 Current Gas Imports. Currently Turkey imports about 5 BCMY from the CIS via Ukraine, Romania, and Bulgaria, and about 0.4 BCMY of LNG from Algeria. Since the Russian and East European gas pipelines have deteriorated and uncertainties are arising about transit agreements, a steady gas supply may not be maintained. 3.10 Future Gas Market and Potential Gas Trade. Because the Turkish gas market is expected to triple by the year 2010, the country may need to consider additional gas imports of about 10 BCMY. In addition to the current CIS gas supplier (mainly Russia), Central Asian producers (Turkmenistan and, to a lesser degree, Azerbaijan), Iran, and Iraq may be well positioned to develop gas exports to this market. For now, however, political tensions in the Gulf and Caucasus regions have caused a major bottleneck. 32 Natural Gas Trade in Asia and the Middle East Although importing gas from Central Asia and from Gulf producers could be economically attractive, this would serve as only a medium-term option. South Asian Market 3.11 Current Gas Supply. Pakistan and India are large gas consumers. At present, the countries utilize indigenous gas resources from the Sui and other gas fields in Pakistan, and the Bombay-high and others in India, respectively. 3.12 Future Gas Markets and Potential Gas Trade. In Pakistan, gas will continue to play an important role in supplying primary energy. The country's gas demand is expected to grow from 20 BCMY in 1995 to 47 BCMY by 2010. The main gas reserve, the Sui field, is being depleted rapidly. Therefore, formulating a gas import strategy deserves top priority. To meet future demand, Pakistan may need to import about 15 BCMY of gas. Gas consumption in India is also expected to grow substantially, from 17.5 BCMY in 1995 to about 70 BCMY by 2010. India might have to import about 40 BCMY of gas, equivalent to 70 percent of current Japanese gas market. Several import options are under study, with potential gas import sources including the following: X Gulf producers (Qatar, Iran, UAE, Oman, and Yemen) * Central Asia (Turkmenistan) * Bangladesh (to eastern Indian markets). Private international investors are closely investigating gas trade options. Possible channels are Oman to Pakistan, Qatar to Pakistan, and Bangladesh to East India. Southeast Asian Market 3.13 Current Gas Supply. The major gas consumers in this region are Thailand (about 10 BCMY) and, to a lesser degree, Singapore (1.5 BCMY). At present, Thailand uses domestically produced gas exclusively. In April 1992, Singapore started importing piped gas from Malaysia. The import volume in 1994 was 1.5 BCM-Singapore's entire supply. 3.14 Future Gas Market and Potential Gas Trade. Gas demand in Thailand is expected to increase substantially, from 10 BCMY in 1995 to about 30 BCMY in 2010. As domestic gas production reaches its peak, incremental gas consumption will have to be met by imports. Potential suppliers to Thailand include Myanmar, Malaysia, and Middle Eastern producers. Vietnam is also examining the possibility of exporting piped gas. However, Vietnam's current proven gas reserves are too small to support this export option. Thailand itself is carrying out investment studies for importing piped gas from Myanmar and LNG from Gulf state producers. East Asian Market 3.15 Current Gas Trade. The largest gas consumer in the region is Japan (60.3 BCMY in 1994), followed by Korea (8.4 BCMY) and Taiwan (4 BCMY). All gas trade is currently based on LNG, as summarized in Table 3.3. Gas Trade Schemes for the Developing Countries 33 Table 3.3 Volumes and Sources of East Asian Gas Imports, 1995 Source of natural gas United States Abu Gas imports (BCMY) (Alaska) Dhabi Australia Brunei Indonesia Malaysia Japan 57.9 1.6 5.4 9.2 7.5 23.4 10.8 Korea 9.5 0)0 0.1 1.0 7.0 1.4 Taiwan 3.5 0 0 0 0 2.8 0.7 Total 70.9 1.6 5.4 9.3 8.5 33.2 12.9 Source: British Petroleum Company (1996). 3.16 Future Gas Markets and Potential Gas Trade. Gas consumption in East Asia is expected to grow strongly beyond the year 2000. China became a net oil importer in 1994. For environmental reasons, the country wishes in the near future to increase the share of natural gas in its primary energy supply from the present 2 percent to about 6 percent. China could thus become a large gas consumer. By the year 2010, an additional gas supply of about 60 BCMY will be needed in the region. 3.17 By 2010, LNG demand in Japan, Korea, and Taiwan will reach approximately 90 to 96 million tons (about 126 to 134 BCM). By that time, China and Thailand are destined to become LNG importers. The expandable capacities under the present LNG contracts (Table 3.4) cannot meet such increased future demand. Unless other resources are exploited, a significant gap in the gas supply may arise. Table 3.4 Expandable Capacities of the Existing LNG Projects (thousand tons) Plant location Base outputs Expandable capacity Total capacity Malaysia 14,760 6,240 21,000 Indonesia 23,950 3,750 27,700 Australia 6,820 4,680 11,500 Alaska 1,230 0 1,230 Brunei 5,540 1,660 7,200 Abu Dhabi 4,300 200 4,500 Qatar 6,000 0 6,000 TOTAL 62,000 16,530 79,130 Source: Personal communication, Mr. Hasegawa of KMH International, Scarsdale, N.Y., 1995. 34 Natural Gas Trade in Asia and the Middle East 3.18 LNG trade in East Asia could be expanded to meet the anticipated supply gap by exploiting such new gas suppliers as the Russian Far East (Sakhalin), Papua New Guinea, Myanmar, Oman, and Yemen. Qatar possesses the world's largest gas field and can easily expand its LNG exports. Iran and Saudi Arabia also could be future gas suppliers. 3.19 Piped gas is another possible source of additional supply for East Asian consumers. Possible suppliers include Central Asia (Turkmenistan and Kazakstan) and the Russian Far East (Yakutsk and Sakhalin). The Chinese markets are looking at other options that include importing gas from Central Asia or from the Yakutsk and Baikal regions in East Siberia. Basic Gas Trade Development Model 3.20 In the planning of international gas trade schemes, the steps outlined in Figure 3.1 should be taken if the project is primarily based on economic criteria and is not hindered by political considerations. As target gas markets are often not supply- constrained, market analysis is extremely important. In fact, market-oriented planning is more practical than supply-source-oriented planning in formulating gas trade projects. 3.21 Annex 4 presents a brief discussion of each of the tasks diagrammed in the figure. In addition, gas-importing countries should carry out more extensive market surveys and preinvestment studies based on the above steps or similar steps before they finalize any specific gas trade project. The key for both exporters and importers is that planning and development of an international gas trade requires special expertise. Coordination between upstream (gas production) and downstream (gas utilization) is extremely important. Thus, producers in developing countries may wish to consider international experts as core partners when formulating their projects. Perhaps the World Bank's major role in future gas trade schemes will then be to encourage dialogue between developing countries and international private sector firms during the project identification stage and to extend its support at each of the project development stages in formulating economically, financially, technically, and environmentally sound projects. Gas Trade Schemes for the Developing Countries 35 Figure 3.1 Model for Developing Gas Trade INFRASTRUCTURE SUPPLY MODULE MARKET MODULE DIAGNOSIS TASK1 TASK2 TASK3 * Reserves * Gas demand * Transmission * Supply potential * Gas tariff/tax * Storage (per each supply * Institutional and source) regulatory framework TASK 4 TASK5 Gas supply costs * Gas market values (e.g., production costs and transport costs) TASK6 Gas balance (by market) TASK 7 Evaluation of additional infrastructure (by market) TASKP8 TASK 9 *Gas development * Investment plan ----- strategy -Eauto | ~~TASK10 TASK11 l . . . < { * ~~~Financial options *Priority InvestmentsII 36 Natural Gas Trade in Asia and the Middle East Market Value of Natural Gas 3.22 Because the power sector is the largest consumer in each market where natural gas is readily available, the netback values of gas to the sector are crucial. Two sample calculations have been made to estimate benchmark gas netback values-one is for replacing coal-fired power plants with gas; the other is for replacing fuel-oil-fired power plants (see Annex 7). In the calculations for both, a natural-gas-fired combined-cycle power generation plant is the replacement option. The sample calculation indicates benchmark netback values of gas in generating power in selected countries, as described in Table 3.5. Table 3.5 Benchmark Gas Netback Values in Power Generation Major fuel for Total electricity power Benchmark netback value for Subregion and generated generation gas in power generation country (GWh) (percent) ($ per MMBtu) Middle East Turkey 73,808 Coal 32.2 3.6 Israel 30,116 Coal 53.1 3.6 Fuel oil 30.7 5.6 South Asia Pakistan 56,639 Fuel oil 21.9 5.7 India 356,263 Coal 70.3 3.4 Southeast Asia Thailand 63,409 Coal 21.3 3.4 Fuel oil 28.8 5.5 Singapore 18,962 Fuel oil 100 5.5 East Asia China 839,453 Coal 72.7 3.4 South Korea 144,437 Coal 21.4 3.4 Fuel oil 24.2 5.9 Taiwan 107,118 Coal 34.8 3.4 Fuel oil 24.7 5.9 Japan 906,705 Coal 12.6 3.4 Fuel oil 19.8 5.9 Source: Electricity and major fuel data: for Turkey and Japan, International Energy Agency (1992); for others, International Energy Agency (1993b). Gas data: Althius and others (1995). 3.23 For consumers other than the power sector, benchmark gas netback values are shown in Table 3.6. Gas Trade Schemes for the Developing Countries 37 Table 3.6 Benchmark Gas Netback Values in Various Sectors other than Power Netback value End use (US$/MMBtu)a Residential/commercial New commercial consumers 6. 7b New residential consumers 3.5-7.Oc Combined cycle power generation Diesel replacement 6.4 Industrial heat and steam raising 3.0 Fertilizerd Future greenfield 2.2 Existing plants 5.0 a The netback values do not include any environmental premium. b The high valuations are due to the high replacement costs of hydrocarbon liquids. c The higher value represents the marginal customer in a well-developed distribution system. The netback value for new residential consumers is often very low if the area is underpopulated and/or high investment costs are required for transmission and distribution. d Based on urea production and a low international price level in 1994 (about $125 to 150 per ton). The capital investments of existing plants are considered to be sunk costs. Source: Althius and others (1995). World Gas Transport 3.24 Gas transport is of course the crucial link in the gas trade chain, and the engineering and economic considerations must be well understood. There are two basic methods for transporting natural gas: pipeline and as LNG. Engineering Yardsticks 3.25 In estimating gas transport costs, the engineering yardsticks shown in Table 3.7 could be used for a preliminary study. 38 Natural Gas Trade in Asia and the Middle East Table 3.7 Engineering Yardsticks for Gas Transport Item Yardsticks Onshore pipeline Pressure level 75 to 100 Bar for transmission pipelines Gas flow velocity 5 to 15 m/sec. Economically maximum pipe diameter 56 inches Pipeline installed cost (materials and Average $20 per-inch-diameter more than one installation) meter installation Gas compressor stations Require one station every 150 to 300 kilometers Installation cost of compressor station About $1.3 to 1.5 million per MWa Gas turbine driven compressor installed About $1,000 per each kW (In the case of new gas cost compressor stations, about 40 to 50 percent of the total cost of the gas turbines/compressors.) Gas energy consumption for gas About 33,000 to 42,000 CM of gas per 1 BCM of transmission gas transport over 1 km (33,000 to 42,000 m3/BCM/km)b at 25 percent thermal eff. Annual operating cost Pipeline: about 0.5 to 1.5 percent of the initial investment cost Compressor station (fixed cost): about 4 to 5 percent of the initial investment cost Offshore pipeline Pressure level About 100 to 130 Bar Pipeline installation cost Average $40c per inch-diameter over 1 m installation Water depth Max. 1,000 m Gas compressor station About $3.5 to 4.5 milliond per MW Gas velocity up to 30 m/sec. LNG Standard LNG liquefaction process plant 2 to 2.2 million tons per year LNG liquefaction plant cost About $1,600 millione for 4 million ton/year LNG plant annual operating cost About 4 to 5 percent of the initial investment Standard LNG cargo vessel 125,000 m3 (Gross 53,000 ton LNG) The speed of LNG cargo vessel About 18 to 19 knots (or 33.3 to 35.2 km/h) Cost of LNG cargo vessel About $250 to 300 million Boil-off rate of LNG during voyage About 0.2 percent per day (continues on next page) Gas Trade Schemes for the Developing Countries 39 (Table 3.7 continued) Item Yardsticks Annual operating cost of LNG cargo About $10 to 20 million per vessel (or about 6 to 8 percent of the initial investment cost) LNG regasification plant cost About $450 millionf for 4 million ton/year LNG Annual operating cost of LNG About 3 to 4 percent of the initial investment cost regasification plant a Inclusive of stand-by capacities. b 42,000 CM/BCM/km is for 5 MMTY gas transport over 1,200 km. 33,000 CM/BCM/km is for 20 MMTY gas transport over 3,800 km. c Largely dependent on water depth and other oceanographic conditions. d See note c. e Largely depend on site conditions and offsite requirement. As a '"ballpark" cost estimate of a new plant. the following equation could be used: C2/C1=(S2/S1)R. Here. Cl and C2 are the costs, and SI and S2 are the corresponding capacities. R is about 0.7. f See note e. Cost Comparison for Piped Gas versus LNG 3.26 Base Case. Using the engineering yardsticks shown in Table 3.7, a preliminary computation presents the following gas pipeline transportation costs versus LNG, inclusive of gasification (see Annex 9). Although a more detailed survey is required for any specific gas trade scheme, costs of long-distance onshore pipeline transport could be competitive with those of LNG if the transport volume were large enough. This implies that even some landlocked Central Asian producers could export gas to remote markets, with proper commercial arrangements. An engineering yardstick suggests that economies of scale for pipelines work up to a maximum of 56-inch- diameter pipe, which would transport about 20 MMTY of natural gas. 3.27 Sensitivity Tests. Gas transport costs vary widely depending on the capital investment costs, which in turn vary with conditions, routes, and other project specifications. Sensitivity tests have been applied for various capital expenditures (capex), plus and minus 20 percent of the base case. Tables 3.8, 3.9, and 3.10 present the computation results for gas transport costs via onshore pipelines, offshore pipelines, and LNG transport, respectively. 40 Natural Gas Trade in Asia and the Middle East Table 3.8 Gas Transport Costs for Onshore Pipelines over Three Volumes and Three Distances (US$ per MMBtu of natural gas) Capex variation Distance (km) Transport volume (percent) 1,200 3,800 7,600 5 MMTY (6.9 BCMY) -20 0.80 2.75 6.30 Base 0.99 3.41 7.80 +20 1.18 4.06 9.30 10 MMTY (13.8 BCMY) -20 0.60 2.03 4.57 Base 0.74 2.52 5.65 + 20 0.87 2.99 6.73 20 MMTY (27.6 BCMY) -20 0.44 1.42 3.15 Base 0.54 1.75 3.89 + 20 0.64 2.09 4.62 Note: Capex = capital expenditure. Table 3.9 Gas Transport Costs for Offshore Pipelines over Three Volumes and Three Distances (US$ per MMBtu of natural gas) Capex variation Distance (kn) Transport volume (percent) 1,200 3,800 7,600 5 MMTY (6.9 BCMY) -20 1.69 5.79 13.26 Base 2.10 7.20 16.50 +20 2.51 8.62 19.73 10 MMTY (13.8 BCMY) -20 1.27 4.33 9.18 Base 1.58 5.37 11.43 + 20 1.89 6.43 13.65 20 MMTY (27.6 BCMY) -20 0.95 3.07 6.53 Base 1.18 3.82 8.12 + 20 1.41 4.56 9.69 Note: Capex = capital expenditure. Gas Trade Schemes for the Developing Countries 41 Table 3.10 Gas Transport Costs for LNG Transport over Three Volumes and Three Distances (US$ per MMBtu of natural gas) Capex variation Distance (km) Transport volume (percent) 1,200 3,800 7,600 5 MMTY (6.9 BCMY) -20 2.44 2.90 3.41 Base 3.05 3.62 4.26 +20 3.66 4.35 5.11 10 MMTY (13.8 BCMY) -20 2.07 2.52 3.21 Base 2.58 3.16 4.01 + 20 3.10 3.78 4.82 20 MMTY (27.6 BCMY) -20 1.76 2.22 2.84 Base 2.21 2.78 3.55 + 20 2.65 3.34 4.26 Note: Capex = capital expenditure. 3.28 LNG Transport Cost on CIF Basis (Before Regasification). Most international market LNG prices are based on CIF delivery. For reference, Table 3.11 indicates preliminary transport costs on this basis. Table 3.11 Transport Costs for LNG on CIF Basis for Three Volumes over Three Distances (Excluding Regasification) (US$ per MMBtu of natural gas) Distance (km) Transport volume 1,200 3,800 7,600 5 MMTY (6.9 BCMY) 2.52 3.09 3.77 10 MMTY (13.8 BCMY) 2.15 2.72 3.58 20 MMTY (27.6 BCMY) 1.86 2.43 3.22 42 Natural Gas Trade in Asia and the Middle East Possible Gas Trade Schemes 3.29 Assuming that each major gas market in Asia and the Middle East adopts an opportunity-cost approach toward gas pricing and that the major consumer in each of the markets is power generation, several gas trade schemes would be conceivable, as shown in Table 3.12. Table 3.12 Conceivable Gas Trade Schemes Gas market Scheme parameter Middle East South Asia Southeast Asia East Asia TOTAL Major consumers - All Power * Turkey (C) Pakistan (F) Thai (F&C) China (C) Israel (F) India (C) Singapore (F) S. Korea (F&C) Taiwan (C&F) Japan (F&C) Benchmark gas netback 3.6 for coal 3.4 for coal 3.4 for coal 3.4 for coal value ($/MMBtu) 5.6 for fuel oil 5.7 for fuel oil 5.5 for fuel oil 5.9 for fuel oil Market reference value (3.0) n.a n.a (3.6) (BCMY) 2000 6.6 8.8 7.3 7.3 30.0 NG potential 2005 9.2 28.3 11.6 22.2 71.3 Supply gap 2010 13.3 54.9 18.4 67.0 153.6 Selected potential gas suppliers Middle Eastern Distance (km) 100 to 500 1,500 to 2,500 6,000-7,000 (to 9,000 (to Hong Largest (to Karachi, Singapore) Kong) gas Bombay) supply Transport cost ($/MMBtu) a) 0.2-0.5 b) 2.0-3.7 c) 3.8 c) 3.8 source in @. 5 MMTY @ 1(0 MMTY @ 10 MMTY @20 MMTY Asia and c) 2.6-2.9 Eastl @10 MMTY East Netback C supply country 5.4-5.1 Pakistan Thailand ($/MMBtu) for fuel oil b) = 3.7 c) = 1.7 3.1 for coal c) = 3.1 for fuel oil for fuel oil India b) = 0.2 c) = 0.5 for coal South Asian n.a. n.a. n.a. Distance (km) 500 to 1,000 Transport cost a) 0.5-0.9 Netback @ suppty country @5 MMTY India a) = 2.5-2.9 for coal (continues on next page) Gas Trade Schemes for the Developing Countries 43 (Table 3.12 continued) Gas market Scheme parameter Middle East South Asia SoutheastAsia East Asia TOTAL Southeast Asian n.a. n.a. Distance (km) 2.000 to 3.000 3,000 (to Hong Kong area) Transport cost b) 2.7-4.2 c) 3.0 @10 MMTY @4510 MMTY c) 2.8-3.0 @10 MMTY Netback @ supply country Thai China b) = 1.3-2.8 c) = 0.4 for coal c) = 2.5-2.7 for fuel oil Central Asian n.a. Distance (km) 2,(00 2,500-3,500 6,000 (to China) Transport cost a) 1.7 a) 2.2-3.1 a) 3.0 Ca 5 MMTY @&5 MMTY @20 MMTY and 1.7-2.3 @a10 MMTY Netback Ca supply country Turkey Pakistan China a) = 1.9 for coal a) = 3.5- 4.0 a) = 0.4 for coal for fuel oil India a) = 0.3-1.1 for coal Far Eastern n.a. n.a. n.a. Distance (km) 3.500 Transport cost a) 2.3 Ca@10 MMTY a) 1.6 @; 20 MMTY Netback C) supply country China a) = 1.1-1.8 for coal Symbols: "a)": Onshore pipeline; "b)': Offshore pipeline: and "c)": LNG I (Fuel to be replaced: C = Coal; and F = Fuel Oil) Note: Middle Eastern producers: the Gulf states, Egypt, Yemen. etc. South Asian Producers: Bangladesh Southeast Asian Producers: Indonesia, Ma]aysia. Brunei, Papua New Guinea Central Asian Producers: Turkmenistan, Kazakstan, Uzbekistan Far Eastern Producers: the Russian Far East (Yakutsk, Baikal, Sakhalin) Challenges in Formulating Gas Trade 3.30 Gas Prices. In most developing countries in Asia and the Middle East that may require gas imports in the future, current gas prices are extremely low by international standards. The low prices often provide returns on investment that are 44 Natural Gas Trade in Asia and the Middle East insufficient to allow the replacement of the gas infrastructure when it reaches the end of its economic life. Thus, pricing reform is an essential element for formulating a financially viable gas import project. 3.31 Natural gas trade on the international market closely follows trends in oil and petroleum products, including price drops in these markets. In early 1994, for example, CIF prices settled at $2.25 to 2.60 per MMBtu on the European markets, $3.40 to 3.70 per MMBtu on the Japanese market, and $2.08 per MMBtu on the U.S. market for imports of Canadian gas (Cedigaz 1995). Gas prices (with years in parentheses) for selected developed country markets are shown in Table 3.13. Table 3.13 Internal Gas Prices for Three Sectors in Selected Countries (US$ per MMBtu) Country Power Industry Households United Kingdom 2.99 (1994) 3.18 (1994) 7.27 (1994) France n.a. 3.57 (1994) 12.70 (Q2, 1995) Germany 3.68 (1994) 4.66 (1994) 10.99 (1994) The Netherlands 3.88 (Q3, 1995) 4.72 (Q3, 1995) 9.18 (Q3, 1995) Italy 2.98 (1994) 4.21 (Q2, 1995) 16.03 (1993) United States 1.88 (Q2, 1995) 2.61 (Q2, 1995) 6.42 (Q2, 1995) Canada 1.42 (1992) 1.98 (1994) 4.42 (1994) Japan 3.67 (1994) 11.75 (1994) 32.95 (1994) Turkey 4.26 (02, 1995) 4.22 (1994) 5.41 (Q2, 1995) Note: Q = quarter. Source: International Energy Agency (1994a, 1995a, 1995b. 1995c). 3.32 Pricing Options. Governments or government agencies may consider two fundamental options in formulating a gas pricing policy: (a) the "cost plus" approach and (b) the "opportunity cost" approach. 3.33 Under the cost-plus approach, costs for gas exploration, production, processing, storage, and transportation are summed and averaged over the volume of gas sold. Capital and operating costs are thus recovered, and prices paid by consumers normally include a profit margin commensurate with the typical rate of return on capital employed in the gas industry. Taxes on profits, or royalty payments on gas production, would be recovered from consumers. 3.34 Under the opportunity cost approach, gas is priced at a level equal to its value in other markets, or equal to the cost of replacing it with other fuels. This is the basis of pricing in almost every gas export project. Actual price setting for gas trade projects requires long and complicated negotiations. Gas Trade Schemes for the Developing Countries 45 3.35 One of the main objectives of a pricing policy is to ensure that each segment of the industry attracts capital investment to fund exploration, production, and transportation. International experience suggests that foreign investors seek minimum after-tax returns of approximately 7 to 15 percent on relatively risk-free investments and 20 to 25 percent or more on relatively risky investments. 3.36 Gas Sales Contracts. Large gas export projects with modest profit margins depend on a 20- to 25-year take-or-pay commitment by the importer of gas. Details of gas trade contracts may vary by country and by case. However, long-term gas trade sales agreements are based on certain standard concepts. Table 3.14 presents basic principles that should be stipulated in international gas sales contracts (Annex 3 provides several examples of these principles). Table 3.14 Gas Contract Fundamentals A. Definitions of Business Terms B. Description of the Service i Type of Service * Quantity of Service • Quality of Service C. Force Majeure Provisions D. Payment for the Service • Rate and Tariff Provisions * Method of Payment E. Penalties, Billing Adjustments, and Make-up Provisions F. Measurement G. Duration of the Contract H. Standard Contract Provisions 1. Dispute Resolution 3.37 The type of contracts now likely to be sought by suppliers would ideally include the following terms: * 15- to 25-year supply agreements * High levels of "take or pay" * High load factor offtake (7,000 to 8,000 hours annually) * Payment in hard currencies * Three-year price reviews * Adjustment of gas price on a quarterly basis referenced either to petroleum products or coal, and sometimes to inflation and commodity indices, or combination of these. 46 Natural Gas Trade in Asia and the Middle East 3.38 Gas Transit Contracts. Several methodologies may be used to calculate transit rates for gas. These include the formulas shown in Table 3.15. Table 3.15 Gas Transit Tariff Calculation Methodologies Calculation methodology Rate components 1. "Unbundled" three-part a. Rate for order of transportation ($/month) rate design capacities ($/1,000 m3/100 km) b. Tariff rate for gas transportation ($/1,000 m3 of active gas) c. Tariff rate for gas storage 2. Proportional "bundled" a. Rate for order of transport capacities ($/month) two-part rate design b. Tariff rate for gas transportation ($/1,000 m3/100 km) 3. Single-element a. Tariff rate for gas transportation and ($/1,000 m3/100 km) "bundled" rate storage 3.39 Transit rates in Europe and the United States range from US$1.3 to 1.5/1,000 M3/100 km. In 1992, the estimated transit tariff in the then Czech and Slovak Republic was $1.41/100 m3/100 km for transit of Russian gas to Western Europe (World Bank 1993b). 3.40 Legal Framework. To promote private international investment, modern laws would need to be put in place in each of the countries for any designated gas trade project, covering the following areas: a. A civil code governing rights, contractual obligations (including leases), and secured transactions b. Private sector corporate laws c. A regulatory framework to simplify licenses, permits, and approvals d. Accounting standards, with particular attention to state enterprises e. Protective legislation for foreign investment f. Bankruptcy law g. Resolution of commercial disputes. 3.41 Structuring a Project Company. The fundamental elements for a successful project company are as follows: a. A combination of sponsors that includes governments of host and transit countries and expertise in finance, planning, marketing, and operations b. Private sector financiers with a strong financial base c. Firm commitment by governments and transit countries. Gas Trade Schemes for the Developing Countries 47 If a Build-Operate-Own (BOO) or Build-Operate-Transfer (BOT) scheme is appropriate, internationally competent construction contractors should also be invited to participate. 3.42 Private sector participation in a developing-country project could become a tool for promoting business efficiency and enhancing project viability. In developing countries where rapid privatization is not feasible, joint ventures between governments and international private sector firms could be a realistic way to formulate a project. Such firms should make at least 50 percent of project shares available to private investors. 3.43 For any gas trade projects, ownership structure is of primary importance. This structure establishes the organizational relations between owners, shippers, and lenders, determining the risks for each party. To make ownership structure effective, it should take account of the following factors: a. Possible exploitation of third-party financing b. Benefits to participating countries c. Private sector participation and business efficiency d. Return on investment and risk sharing among the participants. Basic ownership structures conceivable for international gas trade projects include the functions of a joint stock company (JSC) and an unincorporated joint venture (UJV). A JSC perhaps would be more suitable for transnational gas trade projects with a high capital cost, external funding requirements, and the participation of transit countries. 3.44 Financing. A large-scale pipeline or LNG project requires a combination of equity provided by the sponsors and loans by commercial banks, international financial institutions, and bilateral government agencies. The cost and availability of financing would only be determined after drafting all critical agreements. Potential lenders must first determine the robustness of the project economics and the financial strength of the project company. The financial structure of a project will vary according to capital requirements and the availability of financing. However, reducing up-front cash exposure and increasing the return on equity would enhance financial leverage, bringing equity generally into the range of 25 to 30 percent and debt of about 70 to 75 percent. 3.45 Potential sources of equity for gas trade projects include the following: a. International oil companies b. Construction contractors c. Product off-takers d. Governments of host, transit, and consuming countries e. Multilateral agencies such as the International Finance Corporation (IFC), Asian Development Bank (ADB), or the European Bank for Reconstruction and Development (EBRD) 48 Natural Gas Trade in Asia and the Middle East f. Independent third-party investors (equity funds, etc.). 3.46 Possible sources of debt finance could be loans from the following: a. Multilateral agencies, for example, the World Bank,4 IFC, ADB, or EBRD b. Bilateral agencies c. Export credit agencies d. Commercial banks e. Equipment suppliers (General Electric, Asia Brown Boveri, etc.). If the governments of the host and transit countries need back financing,5 loans from multilateral agencies could be important resources. Apart from several countries with a good credit rating (minimum BBB at S&P's rating or BAA at Moody's) are likely to secure bond financing in international financial markets. 3.47 Successful financing largely relates to risk perception and availability of mitigation measures for the proposed project. In general, two broad categories of risks (commercial and noncommercial) would be perceived by investors and lenders. Table 3.16 illustrates such risks and possible risk mitigation measures. 3.48 The ability to secure the required debt and equity depends on the economics of project viability. The ultimate importance for funding would be the development of project cash flow projections that demonstrate an attractive rate of return. 4. If the project is formed on a purely commercial basis, the World Bank could not be a lender. 5. Assume, for example, that the World Bank provides a loan to a government and the government uses the loan as equity required for a project. The Bank may disburse the loan to cover called-in capital. Gas Trade Schemes for the Developing Countries 49 Table 3.16 Typical Project Risks and Risk Mitigation Measures Risk item Examples of risk mitigation measures Noncommercial Risks War and civil disturbance Guarantees by international insurance agencies including World Bank guarantees. Change of the regulatory Same as above framework Failure of the government to Same as above meet agreed contractual obligations Payment/repayment transfer risk Same as above Commercial Risks Project completion risk Use of a LSTK contract for construction Project cost over-run risk Same as above Pipeline or LNG plant design Use of a LSTK contract and involvement of performance risk international design/construction firm(s) Operation risk Involvement of IOCs as investors and/or operational service contract with IOCs Geological risk Either [by] a "depletion contract" (the buyer agrees to buy all of the gas in a particular field) or a "supply contract" (the seller agrees to deliver a specified volume of gas over a given number of years) Gas supply price risk A long-term agreement between the gas supplier and the consumers (use of a "floor price," a minimum price for the gas) Market risk (volume risk) A high level (80 or 90 percent) of "take-or-pay" (to guarantee payment for a substantial proportion of the gas, regardless of whether there is a market for it on delivery) Note: LSTK = lump-sum turnkevy IOC = international oil company. 4 Conclusion 4.1 Given its environmental benefits and high market value, natural gas is expected to expand its role as a fuel in developing as well as developed countries. As a result, transnational gas trade projects will increase, especially in Asia and the Middle East, where high rates of economic growth are expected to prevail. Developing countries could serve as gas exporters, and sometimes importers or transmitters. The path toward increased gas trade will not be wholly straightforward, however. Unlike the spot oil trade, gas trade requires special expertise in various technical and contractual arrangements in addition to substantial capital investments. Financial viability as well as economic benefits to developing countries must be assessed through appropriate technical and economic studies. 4.2 According to our model (chapter 3), several gas trade schemes justify further evaluation (Table 4.1). Upon request by the nations and private investors, the World Bank could play a catalytic role in resolving critical obstacles to these schemes and in creating a sound business framework for formulating these and other regional gas trade projects. 4.3 Gas trade projects in the coming decades will often be accomplished through joint-venture arrangements between the governments of the developing countries and financially strong private international investors. Interaction between governments and private investors will be the first step in this process. It will also be useful to encourage interaction between representatives from the countries, international agencies, and private sector investors, through discussions on commercial activities such as contractual arrangements for sales and transit, gas pricing, taxes/duties, and gas trade operations. 4.4 The World Bank's role can be expected to expand in particular with respect to technical assistance in fostering strategic planning of gas sector development in member countries. The Bank's new guarantees are also expected to be useful to support its borrowing countries in securing debt finance from international private sector capital markets. Such Bank guarantees could play an important role in securing financing for gas trade project because of their capital intensity. It may be advisable in fact for the Bank to develop guarantee applications specifically geared toward gas trade projects based on some concrete examples of such projects. 51 52 Natural Gas Trade in Asia and the Middle East Table 4.1 Conceivable Gas Trade Schemes in Asia and the Middle East Gas import demand Economical gas trade Gas importing (B CMY) Possible gas volume (order of region! countries 2000 2005 2010 suppliers magnitude) Middle East Turkey 6.6 9.2 13.3 1. ME producers 1. Min. 2-3 BCMY (by pipe) Israel 2. CA producers 2. Min. 4-5 BCMY (by pipe) (to Turkey) South Asia Pakistan 8.8 28.3 54.9 1. ME producers 1. Min. 5 BCMY (by pipe) 1. Min. 5 BCMY (by LNG) 2. CA producers 2. Min. 5 BCMY (by pipe) India 1. ME producers 1. Min. 10 BCMY (by LNG) 2. CA producers 2. Min. 10 BCMY (by pipe) 3. Bangladesh 3. Min. 5 BCMY (by pipe) Southeast Asia Thailand 7.3 11.6 18.4 1. ME producers 1. Min. 10 BCMY (by LNG) Singapore 2. SEA producers 2. Min. 5 BCMY (by pipe) 2. Min. 5 BCMY (by LNG) East Asia China 7.3 22.2 67 1. ME producers 1. Min. 20 BCMY (by LNG) Republic of Korea 2. SEA producers 2. Min. 5 BCMY (by LNG) Taiwan 3. CA producers 3. Min. 20 BCMY (by pipe) Japan 4. FE producers 4. Min. 10 BCMY (by pipe) Annex 1 Country Profiles A1.1 This annex presents basic data on 21 Asian and Middle Eastern countries, along with recent statistics on energy and foreign trade, energy reserves, gas balances and consumption, and fuel prices. A1.2 Sources for Tables A1.1 through A1.21 were as follows: Coal Statistics International (1994); World Bank (1993a, 1993c, 1993d, 1994a, 1994c, 1995); International Energy Agency (1993a, 1994a); Oil and Gas Journal (1995); Cedigaz (1995); British Petroleum Company (1995); Platt's Oil Price Handbook and Oilmanac (1994); Platt's Oilgram (1995); World Resources Institute (1994). 53 54 Natural Gas Trade in Asia and the Middle East Table A1.1 Azerbaijan Area: 86.6 '000 km2 Population: 7.4 m Per Capita Income: 740 US$ Gross Domestic Investment: 8.1 % of GDP (1993) Current Account balance: 19.6 % of GDP (1993) GDP (1995) (million US$) 3,600 Agriculture 900 (25%) Industry 1,692 (47%) [Manufacturing 1,332 (37%)] Services 1,008 (28%) Foreign Trade and Energy (1995) (million US$) Imports 955 Exports 612 Fuels 162 (17%) Fuels 330 (54%) Nonfuel Primary Products 344 (36%) Nonfuel Primary Products 141 (23%) Manufactures 449 (47%) Manufactures 141 (23%) Primary Energy (1995) (million toe) Production Imports Exports Consumption Petroleum 9.20 - - 6.71 Gas 4.71 4.74 0.55 11.60 Coal - 0.01 0.01 Electricity - 0.01 0.01 0.00 Hydro 0.20 - - 0.21 Nuclear - _ Reserves (31 Dec 1995) (million toe) Petroleum 1,916 13,689 m bbl Gas 403 16,127 bcf (452 bcm) Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 0.35 4,070 GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 9.07 0.88 Reinjected - - Flared, Vented 1.43 0.14 Transit/production losses 2.41 0.23 Net production 5.23 0.51 Imports 5.26 0.51 Exports 0.95 0.09 Consumption 9.54 0.92 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat generation Energy Sector - - Industry 3.70 0.36 Commercial - - Residential 0.17 0.02 Nonspecified - - Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 0.04 0.14 ¢/m3 (as of January 1996) Natural Gas - Commercial 0.64 2.36 ¢/m3 (as of January 1996) Natural Gas - Industrial 1.51 5.33 0/m3 (as of January 1996) Electricity - Residential 0.32 0.11 0/kWh Electricity - Commercial 2.58 0.88 0/kWh Electricity - Industry 2.58 0.88 0/kWh Fuel Oil 0.71 2.65 0/liter Gasoline 6.03 18.60 0/liter Diesel 4.64 16.28 0/liter Annex 1 Country Profiles 55 Table A1.2 United Arab Emirates Area: 0.6 '000 km2 Population: 0.5 m Per Capita Income (bank method): 8,030 US$ Gross Domestic Investment: - % of GDP (1993) Current Account balance: - % of GDP (1993) GDP (1993) (Million US$) 4,529 Agriculture 45 (1 %) Industry 1,902 (42%) [Manufacturing 770 (17%)] Services 2,582 (57%) Foreign Trade and Energy (1993) (Million US$) Imports 3.825 Exports 3,689 Fuels 1,721 (45%) Fuels 3,246 (88%) Nonfuel Primary Products 421 (11%) Nonfuel Primary Products 184 (5%) Manufactures 1.683 (44%) Manufactures 258 (7%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 2.44 10.51 10.05 2.90 Gas 5.85 - - 5.85 Coal Electricity - _ _ _ Hydro Nuclear - _ _ _ Reserves (31 Dec 1994) (million toe) Petroleum 28.77 210 m bbl Gas 133.5 5,295 bcf (150 bcm) Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) - - GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 9.61 0.93 Reinjected 2.88 0.28 Flared, Vented - - Transit/Production losses 0.24 0.02 Net production 6.49 0.63 Imports Exports Consumption 6.49 0.63 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat Generation - Energy Sector Chemical/Petrochemical 1.51 0.15 Iron and Steel Industry Residential Nonspecified Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - ¢/m3 Natural Gas - Industry - - ¢/m3 Natural Gas - Power - - ¢/m3 Electricity - Residential - - ¢/KWh Electricity - Commercial - - ¢/kWh Electricity - Industry - - o/kWh Fuel Oil - - ¢/liter Gasoline - - ¢/liter Diesel - - ¢/liter Kerosene - - 0/liter 56 Natural Gas Trade in Asia and the Middle East Table A1.3 Bangladesh Area: 144 '000 km2 Population: 114.4 m Per Capita Income (bank method): 240 US$ Gross Domestic Investment: 16.6 % of GDP (1993) Current Account balance: -3.5 % of GDP (1993) GDP (1995) (Million US$) 29,100 Agriculture 9,021 (31%) Industry 5,238 (18%) [Manufacturing 2,910 (10%)] Services 15,132 (52%) Foreign Trade and Energy (1993) (Million US$) Imports 3,986 Exports 2,383 Fuels 304 (8%) Fuels 74 (3%) Nonfuel Primary Products 2,436 (61%) Nonfuel Primary Products 786 (33%) Manufactures 1,246 (31%) Manufactures 1,533 (64%) Primary Energy (1995) (million toe) Production Imports Exports Consumption Petroleum 0.13 1.98 0.06 2.05 Gas 5.94 - - 5.94 Coal - 0.19 0.19 Electricity - - - Hydro 0.07 0.07 Nuclear - - Reserves (31 Dec 1994) (million toe) Petroleum 0.55 4 m bbl Gas 635.35 25,200 bcf (714 bcm) Coal 496.69 1,054 m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 0.10 1,140 GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1995) (bcm/y) (bcf/d) Gross production 7.35 0.71 Reinjected Flared, Vented - - Transit/production losses - - Net production 7.35 0.71 Imports - - Exports Consumption 7.35 7.35 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat Generation Energy Sector - - Chemical/Petrochemical 1.93 0.19 Other Industry 0.45 0.04 Residential 0.37 0.04 Nonspecified - - Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - ¢/m3 Natural Gas - Industry 2.27 8.40 ¢/m3 Natural Gas - Power 1.08 4.00 ¢/m3 Electricity - Residential 19.24 5.64 0/kWh Electricity - Commercial 26.92 7.89 0/kWh Electricity - Industry 21.73 6.37 ¢/kWh Fuel Oil 4.88 18.23 0/liter Gasoline 10.45 32.21 o/liter Diesel 9.79 34.38 0/liter Kerosene 10.37 34.38 o/liter LPG 21.00 48.93 ¢/liter Annex 1 Country Profiles 57 Table A1.4 China Area: 9,597 '000 km2 Population: 1,165 m Per Capita Income: 620 US$ Gross Domestic Investment: 40.5 % of GDP (1993) Current Account balance: 2.2 % of GDP (1993) GDP (1995) (Million US$) 663,300 Agriculture 139,293 (21%) Industry 318,384 (48%) [Manufacturing 252,054 (38%)] Services 212,256 (32%) Foreign Trade and Energy (1993) (Million US$) Imports 80,585 Exports 84,940 Fuels 3,604 (4%) Fuels 4,652 (5%) Nonfuel Primary Products 11,569 (14%) Nonfuel Primary Products 12,973 (15%) Manufactures 65,413 (81%) Manufactures 67,315 (79%) Primary Energy (million toe) Production Imports Exports Consumption Petroleum 146.08 29.25 24.92 146.13 Gas 14.72 - - 14.72 Coal 619.95 0.61 15.52 612.26 Electricity - 0.16 0.33 -0.18 Hydro 14.47 - - 14.47 Nuclear 3.62 - 3.62 Reserves (31 Dec 1994) (million toe) Petroleum 3,287.67 24.000 m bbl Gas 1,487.54 59,000 bcf (1,671 bcm) Coal 63,375.83 126,215 m tons Nuclear (Capacity) 0.67 7,750 GWh/yr Hydro (Capacity) 10.72 125,100 GWh/yr Hydro (Exploitable) 509.12 5,921.066 GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 17.03 1.65 Reinjected - - Flared, Vented Transit/production losses - - Net production 17.03 1.65 Imports - - Exports - - Consumption 17.03 17.03 Gas Consumption (1993) (bcm/y) (bcf/d) Power/Heat Generation 0.79 0.08 Energy Sector 3.60 0.35 Chemical/Petrochemical - - Iron and Steel Industry - - Residential 1.99 0.19 Nonspecified 10.32 1.00 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 0.94 3.49 ¢/m3 Natural Gas - Commerical - - 0/i3 Natural Gas - Industry 1.34 4.98 ¢/m3 Electricity - Residential 11.09 3.25 0/kWh Electricity - Commercial 9.72 2.85 0/kWh Electricity - Industry 8.73 2.56 0/kWh Fuel Oil - - 0/liter Gasoline 3.39 10.46 0/liter Diesel 2.72 9.56 0/liter 58 Natural Gas Trade in Asia and the Middle East Table A1.5 Egypt, Arab Republic of Area: 1,001.0 '000 km2 Population: 54.7 m Per Capita Income (bank method): 790 US$ Gross Domestic Investment: 17 % of GDP (1995) Current Account balance: -2.1 % of GDP (1995) GDP (1995) (Million US$) 46,440 Agriculture 7,523 (16%) Industry 15,697 (34%) [Manufacturing 7,988 (17%)] Services 22,848 (49%) Foreign Trade and Energy (1993) (Million US$) Imports 8,293 Exports 3,050 Fuels 114 (1 %) Fuels 1,334 (44%) Nonfuel Primary Products 3,228 (39%) Nonfuel Primary Products 637 (21%) Manufactures 4,951 (60%) Manufactures 1,080 (35%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 49.58 0.37 26.82 21.75 Gas 10.49 - - 10.49 Coal - 0.98 0.01 0.97 Electricity - Hydro 0.86 0.86 Nuclear - -- Reserves (31 Dec 1994) (million toe) Petroleum 446.58 3,260 m bbl Gas 486.35 19,290 bcf (546 bcm) Coal 40.80 64 m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 1.16 13,510 GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 15.54 1.50 Reinjected 1.00 0.10 Flared, Vented 1.20 0.12 Transit/production losses 1.35 0.13 Net production 12.00 1.16 Imports - - Exports - - Consumption 12.00 1.16 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat Generation Energy Sector - - Chemical/Petrochemical 1 .61 0.16 Other Industry 2.16 0.21 Residential 0.12 0.01 Nonspecified - - Consumer Prices (1 993) ($/mmbtu) Natural Gas - Residential 1.95 7.20 ¢/m3 Natural Gas - Industry 2.77 10.24 ¢/m3 Natural Gas - Power 1.04 3.79 ¢/m3 Electricity - Residential - - 0/kWh Electricity - Commercial - - 0/kWh Electricity - Industry - - 0/kWh Fuel Oil - - C/liter Gasoline - - 0/liter Diesel - - ¢/liter Kerosene - - 0/liter Annex 1 Country Profiles 59 Table A1.6 India Area: 3.288 '000 km2 Population: 929 m Per Capita Income (bank method): 350 US$ Gross Domestic Investment: 24 % of GDP (1995) Current Account balance: -2 % of GDP (1995) GDP (1995) (Million US$) 329,900 Agriculture 69,682 (30%) Industry 58,705 (29%) [Manufacturing 36,932 (18%)] Services 86,211 (41%) Foreign Trade and Energy (1995) (Million US$) Imports 38,256 Exports 32,502 Fuels 6,885 (18%) Fuels 618 (2%) Nonfuel Primary Products 2,354 (6%) Nonfuel Primary Products 6,114 (19%) Manufactures 29,017 (76%) Manufactures 25,770 (79%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 30.60 46.63 4.46 69.46 Gas 14.89 - - 14.89 Coal 126.04 5.41 0.05 133.64 Electricity - 0.13 0.02 0.11 Hydro 7.10 - - 7.10 Nuclear 1.43 1.43 Reserves (31 Dec 1994) (million toe) Petroleum 791.23 5,776 m bbl Gas 629.48 24,967 bcf (707 bcm) Coal 35,910.07 75,842 m tons Nuclear (Capacity) 0.47 5,410 GWh/yr Hydro (Capacity) 6.26 73,021 GWh/yr Hydro (Exploitable) 226.87 2,638,011 GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 19.41 1.88 Reinjected 0.10 0.01 Flared, Vented 2.00 0.19 Transit/production losses 0.50 0.05 Net production 16.80 1.62 Imports Exports - Consumption 16.80 1.62 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat Generation - - Energy Sector Chemical/Petrochemical 7.32 0.71 Other Industry 1.64 0.16 Residential 0.19 0.02 Nonspecified Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 4.28 15.83 0/m3 Natural Gas - Industry 4.28 15.83 ¢/m3 Natural Gas - Power 4.28 15.83 ¢/m3 Electricity- Residential 11.87 3.48 0/kWh Electricity - Commercial 26.20 7.68 0/kWh Electricity - Industry 22.20 7.68 0/kWh Fuel Oil 4.47 16.69 0/liter Gasoline 21.37 65.88 0/liter Diesel 6.28 22.04 0/liter Kerosene 2.84 9.41 0/liter LPG 7.16 16.68 0/liter 60 Natural Gas Trade in Asia and the Middle East Table A1.7 Indonesia Area: 1,919 '000 km2 Population: 193 m Per Capita Income (bank method): 980 US$ Gross Domestic Investment: 32 % of GDP Current Account balance: -4 % of GDP GDP (1995) (Million US$) 198,100 Agriculture 33,677 (17%) Industry 83,202 (42%) [Manufacturing 47,544 (24%)] Services 81,221 (41%) Foreign Trade and Energy (1995) (Million US$) Imports 44,477 Exports 46,019 Fuels 3,845 (8%) Fuels 9,749 (21%) Nonfuel Primary Products 22,497 (51%) Nonfuel Primary Products 12,634 (27%) Manufactures 18,135 (41%) Manufactures 23,636 (51%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 77.86 15.09 59.75 Gas 53.27 - 30.85 22.42 Coal 16.96 0.21 12.28 4.89 Electricity - - Hydro 1.64 1.64 Nuclear - - Reserves (31 Dec 1994) (million toe) Petroleum 791.64 5,779 m bbl Gas 1,623.38 64,388 bcf (1,824bcm) Coal 26,299.07 38,878 m tons Nuclear (Capacity) - - GWh/yr. Hydro (Capacity) 2.29 26,700 GWh/yr. Hydro (Exploitable) 291.39 3,388,271 GWh/yr. Gas Balance (1995) (bcm/y) (bct/d) Gross production 84.81 8.22 Reinjected 15.41 1.49 Flared, Vented 5.00 0.49 Transit/production losses 1.30 0.13 Net production 63.10 6.12 Imports - - Exports 33.11 3.21 Consumption 29.99 2.90 Gas Consumption (1994) (bcm/y) (bcf/d) Power/heat Generation - - Commercial & Public 2.72 0.26 Chemical/Petrochemical 3.52 0.34 Iron and Steel Industry 0.81 0.08 Residential 0.71 0.07 Other Industry 0.10 0.01 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 0.59 2.18 0/m3 Natural Gas - Industry 3.00 11.09 ¢/m3 Natural Gas - Power 3.00 11.09 ¢/m3 Electricity - Residential 29.10 8.53 ¢/kWh Electricity- Commercial 34.15 10.01 ¢/kWh Electricity - Industry 19.62 5.75 ¢/kWh Fuel Oil 0.78 2.83 0/liter Gasoline 8.65 26.67 ¢/liter Diesel 3.94 13.82 ¢/liter Kerosene 3.21 10.67 0/liter LPG 6.18 14.41 0/liter Annex 1 Country Profiles 61 Table A1.8 Iran, Islamic Republic of Area: 1,648 '000 km2 Population: 59.6 m Per Capita Income (bank method): 2,200 US$ Gross Domestic Investment: 33 % of GDP (1993) Current Account balance: -4 % of GDP (1993) GDP (1993) (Million US$) 110,258 Agriculture 25,711 (23%) Industry 31,240 (28%) [Manufacturing 15,398 (14%)] Services 53,306 (48%) Foreign Trade and Energy (1993) (Million US$) Imports 26,745 Exports 18,235 Fuels 4,379 (16%) Fuels 16,376 (83%) Nonfuel Primary Products 76 (1%) Nonfuel Primary Products 1,216 (7%) Manufactures 22,290 (83%) Manufactures 644 (4%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 186.34 8.93 135.75 59.52 Gas 31.13 - - 31.13 Coal 0.94 0.94 Electricity Hydro 0.95 0.95 Nuclear - - - Reserves (31 Dec 1994) (million toe) Petroleum 12,226.03 89,250 m bbl Gas 18,697.79 741,609 bcf (21,009 bcm) Coal 170.15 234 m tons Nuclear (Capacity) - - GWh/yr. Hydro (Capacity) 1.05 12,260 GWh/yr. Hydro (Exploitable) - - GWh/yr Gas Balance (1995) (bcm/y) (bcf/d) Gross production 75.54 7.32 Reinjected 25.84 2.50 Flared, Vented 11.60 1.12 Transit/production losses 3.00 0.29 Net production 35.10 3.40 Imports 0 - Exports 0.10 - Consumption 35.10 3.4 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat Generation Energy Sector - - Chemical/Petrochemical 1.2 0.12 Iron and Steel Industry 12.18 1.18 Residential 10.70 1.04 Nonspecified - - Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - ¢/m3 Natural Gas - Industry - - ¢/m3 Natural Gas - Power - - 0/in3 Electricity - Residential - - 0/kWh Electricity - Commercial - - 0/kWh Electricity - Industry - - 0/kWh Fuel Oil - - 0/liter Gasoline - - 0/liter Diesel - - 0/liter Kerosene - - 0/liter LPG - - 0/liter 62 Natural Gas Trade in Asia and the Middle East Table A1.9 Jordan Area: 89.2 '000 km2 Population: 4.2 m Per Capita Income (bank method): 1,500 US$ Gross Domestic Investment: 36 % of GDP Current Account balance: -9 % of GDP GDP (1995) (Million US$) 6,600 Agriculture 3,960 (6%) Industry 1,850 (28%) [Manufacturing 920 (14%)] Services 4,360 (66%) Foreign Trade and Energy (1995) (Million US$) Imports 3,696 Exports 1,771 Fuels 480 (13%) Fuels - ( -%) Nonfuel Primary Products 598 (16%) Nonfuel Primary Products 1,067 (60%) Manufactures 2,618 (71%) Manufactures 704 (40%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum - 3.89 3.89 Gas 0.28 - 0.28 Coal - - Electricity - - Hydro - - Nuclear - - Reserves (31 Dec 1994) (million toe) Petroleum 0.04 - m bbl Gas 5.04 200.00 bcf (6 bcm) Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) - 0.07 GWh/yr Hydro (Exploitable) - 89.00 GWh/yr Gas Balance (1995) (bcm/y) (bcf/d) Gross production 0.30 0.03 Reinjected Flared, Vented Transit/production losses - - Net production 0.30 0.03 Imports - - Exports - - Consumption 0.30 0.03 Gas Consumption (1993) (bcm/y) (bcf/d) Power/Heat Generation 0.22 0.02 Energy Sector - - Chemical/Petrochemical - - Iron and Steel Industry Residential - Nonspecified 0.05 0.00 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - ¢/m3 Natural Gas - Industry - - ¢/m3 Natural Gas - Power - - ¢/m3 Electricity - Residential - - 0/kWh Electricity - Commercial - - 0/kWh Electricity - Industry - - 0/kWh Fuel Oil - - 0/liter Gasoline - - 0/liter Diesel - - 0/liter Kerosene - - 0/liter Annex 1 Country Profiles 63 Table Al.10 Kazakstan Area: 2.717 '000 km2 Population: 16.6 m Per Capita Income: 1,040 US$ Gross Domestic Investment: 22 % of GDP (1995) Current Account balance: -3 % of GDP (1995) GDP (1995) (Million US$) 17,600 Agriculture 8,450 (48%) Industry 7,200 (41%) Services 1,940 (11%) Foreign Trade and Energy (1993) (Million US$) Imports 5,692 Exports 5,197 Fuels 1,138 (20%) Fuels 1,351 (26%) Nonfuel Primary Products 1,480 (26%) Nonfuel Primary Products 1,663 (32%) Manufactures 3,074 (54%) Manufactures 2,183 (42%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 21.23 11.94 12.01 21.16 Gas 7.25 11.76 4.21 11.80 Coal 51.28 1.09 15.01 37.37 Electricity - 2.32 1.31 1.01 Hydro 0.66 - - 0.66 Nuclear - - Reserves (31 Dec 1994) (million toe) Petroleum 2,640 18,855 m bbl Gas 1,660 64,979 bcf (1,840 bcm) Coal 5,280 8,000 m tons Nuclear (Capacity) 0.08 908 GWh/yr Hydro (Capacity) 0.94 10,895 GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 8.05 0.78 Reinjected - - Flared, Vented - - Transit/production losses 2.01 0.19 Net production 6.04 0.58 Imports 13.06 1.26 Exports 4.67 0.45 Net Consumption 14.43 1.40 Gas Consumption (1 993) (bcm/y) (bcf/d) Power/Heat generation 4.93 0.48 Energy Sector - - Chemical/Petrochemical - - Industrial 2.00 0.19 Commercial - - Residential 2.00 0.19 Nonspecified 5.50 0.53 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 1.12 4.20 ¢/m3 (as of July 1996) Natural Gas - Industry 2.26 8.37 ¢/m3 Natural Gas - Power 2.26 8.37 ¢/m3 Electricity - Residential 4.40 1.29 ¢/kWh Electricity - Commercial - - ¢/kWh Electricity - Industry 6.62 1.94 ¢/kWh Fuel Oil 1.70 6.36 ¢/liter Gasoline 3.78 11.65 ¢/liter Diesel 2.80 9.81 ¢/liter 64 Natural Gas Trade in Asia and the Middle East Table A1.1 1 Korea, Republic of Area: 120.5 '000 km2 Population: 43.6 m Per Capita Income (bank method): 7,210 US$ Gross Domestic Investment: 37 % of GDP (1993) Current Account balance: -1.5 % of GDP (1 993) GDP (1993) (Million US$) 304,874 Agriculture 21,777 (7%) Industry 134,503 (44%) [Manufacturing 84,545 (28%)] Services 148,594 (49%) Foreign Trade and Energy (1993) (Million US$) Imports 81,413 Exports 76,394 Fuels 14,651 (18%) Fuels 1,685 (2%) Nonfuel Primary Products 14,947 (18%) Nonfuel Primary Products 3,743 (5%) Manufactures 51,814 (64%) Manufactures 70,966 (93%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum - 97.20 14.41 82.79 Gas - 4.13 - 4.13 Coal 4.34 23.39 27.73 Electricity - - Hydro 0.52 0.52 Nuclear 15.15 15.15 Reserves (31 Dec 1994) (million toe) Petroleum - - m bbl Gas - - bcm Coal - 224 m tons Nuclear (Capacity) 21.24 247,020 GWh/yr Hydro (Capacity) 1.00 11,630 GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1995) (bcm/y) (bcf/d) Gross production 10 Reinjected - - Flared, Vented - - Transit/production losses - - Net production - - Imports 9.53 0.92 Exports - - Consumption 9.53 0.92 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat generation Energy Sector - - Chemical/Petrochemical - - Commercial 0.16 0.01 Residential 3.71 0.36 Industry 0.67 0.06 Nonspecified - - Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - /Im3 Natural Gas - Industry 6.53 24.17 0/m3 Natural Gas - Power 5.82 21.55 0/m3 Electricity - Residential 34.36 10.07 0/kWh Electricity - Commercial 35.89 10.52 c/kWh Electricity - Industry 19.48 5.71 0/kWh Fuel Oil 8.48 31.65 ¢/liter Gasoline 24.65 76.00 0/liter Diesel 7.46 26.16 0/liter Kerosene 17.29 57.31 0/liter Annex 1 Country Profiles 65 Table A1.12 Kyrgyz Republic Area: 198 '000 km2 Population: 4.5 m Per Capita Income (bank method): 690 US$ Gross Domestic Investment: 16 % of GDP Current Account balance: -13 % of GDP GDP (1995) (Million US$) 3,100 Agriculture 1,240 (40%) Industry 680 (22%) [Manufacturing - Services 1,180 (38%) Foreign Trade and Energy (1993) (Million US$) Imports 672 Exports 409 Fuels 282 (42%) Fuels 41 (10%) Nonfuel Primary Products 34 (5%) Nonfuel Primary Products 25 (6%) Manufactures 356 (53%) Manufactures 344 (84%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 0.09 1.17 0.06 1.20 Gas 0.03 0.98 - 1.01 Coal 0.67 0.42 0.24 0.86 Electricity - 0.49 0.57 -0.07 Hydro 0.77 - - 0.77 Nuclear - -- Reserves (31 Dec 1994) (million toe) Petroleum - - m bbl Gas - - bcm Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 1.28 14,925 GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 0.03 0.00 Reinjected - - Flared, Vented Transit/production losses - - Net production 0.03 0.00 Imports 1.00 0.10 Exports - - Consumption 1.03 0.10 Gas Consumption (bcm/y) (bcf/d) Power/Heat generation 0.22 0.02 Energy Sector - - Industry 0.47 0.05 Commercial - - Residential - - Nonspecified 0.34 0.03 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 0.90 0.32 ¢/m3 Natural Gas - Industry 2.66 0.94 ¢/m3 Natural Gas - Power 2.66 0.94 ¢/m3 Electricity - Residential 1.94 0.57 ¢/kWh Electricity - Commercial 3.55 1.04 0/kWh Electricity - Industry 3.55 1.04 0/kWh Fuel Oil 2.75 10.26 0/liter Gasoline 8.57 26.42 0/liter Diesel 7.14 25.07 0/liter Kerosene - - 0/liter LPG 9.04 21.06 ¢/liter 66 Natural Gas Trade in Asia and the Middle East Table A1.13 Myanmar Area: 678.5 '000 km2 Population: 43.7 m Per Capita Income (bank method): US$ Gross Domestic Investment: 14 % of GDP (1993) Current Account balance: - % of GDP (1993) GDP (1993) (Million US$) 37,749 Agriculture 22,420 (59%) Industry 3,755 (10%) [Manufacturing 2,782 (7%)] Services 11,573 (31%) Foreign Trade and Energy (1993) (Million US$) Imports 825 Exports 539 Fuels 48 (6%) Fuels 5 (1%) Nonfuel Primary Products 88 (11%) Nonfuel Primary Products 517 (96%) Manufactures 689 (84%) Manufactures 16 (3%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 0.73 0.03 0.76 Gas 1.29 - 1.29 Coal 0.03 0.01 0.04 Electricity - - - Hydro 0.13 0.13 Nuclear Reserves (31 Dec 1994) (million toe) Petroleum 6.85 50 m bbl Gas 247.8 9,800 bcf (278 bcm) Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 0.21 2,420 GWh/yr Hydro (Exploitable) 31.46 365,880 GWh/yr Gas Balance (1995) (bcm/y) (bcf/d) Gross production 1.43 0.14 Reinjected Flared, Vented Transit/production losses Net production 1.43 0.14 Imports Exports Consumption 1.43 0.14 Gas Consumption (1994) (bcm/y) (bcf/d) Power/HeatGeneration Energy Sector Chemical/Petrochemical Industry 1.1 0.11 Residential Nonspecified Consumer Price ($/mmbtu) Natural Gas - Residential - - ¢/m3 Natural Gas - Industry - - ¢/i3 Natural Gas - Power - - ¢/m3 Electricity - Residential - - ¢/kWh Electricity - Commercial - - 0/kWh Electricity - Industry - - ¢/kWh Fuel Oil 10.19 38.04 ¢/liter Gasoline 18.77 57.86 0/liter Diesel 10.84 38.04 0/liter Kerosene 12.91 42.80 ¢/liter LPG 13.27 30.91 0/liter Annex 1 Country Profiles 67 Table A1.14 Oman Area: 212.5 '000 km2 Population: 1.6 m Per Capita Income (bank method): 6,480 US$ Gross Domestic Investment: - % of GDP (1993) Current Account balance: -3 % of GDP (1993) GDP (1993) (Million US$) 11,520 Agriculture 461 (4%) Industry 5,990 (52%) [Manufacturing 461 (4%)] Services 5,069 (44%) Foreign Trade and Energy (1993) (Million US$) Import 3.674 Exports 5,555 Fuels 70 (2%) Fuels 5,229 (94%) Nonfuel Primary Products 739 (20%) Nonfuel Primary Products 55 (1%) Manufactures 2,865 (78%) Manufactures 270 (5%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 39.84 0.29 38.31 1.82 Gas 4.22 - - 4.22 Coal - - Electricity - - Hydro - - Nuclear Reserves (31 Dec 1994) (million toe) Petroleum 661.37 4,828 m bbl Gas 560.93 22,248 bcf (630 bcm) Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) - - GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcfld) Gross production 7.79 0.76 Reinjected 2.28 0.22 Flared, Vented 0.31 0.03 Transit/production losses 0.36 0.03 Net production 4.84 0.47 Imports Exports 0.25 - Consumption 4.59 0.45 Gas Consumption (1993) (bcm/y) (bcf/d) Power/HeatGeneration 1.65 0.16 Energy Sector 0.83 0.08 Chemical/Petrochemical Other Industry Residential Nonspecified 1.86 0.18 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - ¢/m3 Natural Gas - Industry - - ¢/m3 Natural Gas - Power - - ¢/m3 Electricity - Residential - - ¢/kWh Electricity - Commercial - - o/kWh Electricity - Industry - - ¢/kWh Fuel Oil - - 0/liter Gasoline - - 0/liter Diesel - - 0/liter Kerosene - - 0/liter 68 Natural Gas Trade in Asia and the Middle East Table A1.15 Pakistan Area: 808.9 '000 km2 Population: 129.7 m Per Capita Income (bank method): 460 US$ Gross Domestic Investment: 19 % of GDP (1993) Current Account balance: -4 % of GDP (1993) GDP (1995) (Million US$) 60,500 Agriculture 15,730 (26%) Industry 15,125 (25%) [Manufacturing 10,285 (17%)] Services 29,645 (49%) Foreign Trade and Energy (1993) (Million US$) Imports 9,360 Exports 7,264 Fuels 1,534 (16%) Fuels 88 (1%) Nonfuel Primary Products 2,076 (22%) Nonfuel Primary Products 1,435 (20%) Manufactures 5,749 (61%) Manufactures 5,741 (79%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 2.95 10.76 1.45 12.26 Gas 15.98 - - 15.98 Coal 1.58 0.62 2.20 Electricity - - - Hydro 2.49 2.49 Nuclear 0.15 0.15 Reserves (31 Dec 1994) (million toe) Petroleum 27.85 203 m bbl Gas 693.34 27,500 bcf (779 bcm) Coal 310.44 576 m tons Nuclear (Capacity) 0.25 2,900 GWh/yr Hydro (Capacity) 4.15 48,265 GWh/yr Hydro (Exploitable) 1.29 15,001 GWh/yr Gas Balance (1995) (bcm/y) (bcf/d) Gross production 18.22 1.77 Reinjected - - Flared, Vented Transit/production losses - - Net production 18.22 1.77 Imports - - Exports - - Consumption 18.22 1.77 Gas Consumption (1994) (bomly) (bcf/d) Power/HeatGeneration Energy Sector - - Chemical/Petrochemical 3.75 0.36 2.81 0.27 Residential 2.35 0.23 Commercial 0.43 0.04 Consumer Prices (1993) ($/mmbtt) Natural Gas - Residential 1.34 4.94 ¢/m3 Natural Gas - Industry 2.01 7.45 ¢/m3 Natural Gas - Power 2.01 7.45 ¢/m3 Electricity - Residential 8.77 2.57 0/kWh Electricity - Commercial 32.21 9.44 ¢/kWh Electricity - Industry 15.46 4.53 ¢/kWh Fuel Oil 2.33 8.69 0/liter Gasoline 13.70 42.22 o/liter Diesel 5.60 19.65 0/liter Kerosene 5.81 19.26 0/liter Annex 1 Country Profiles 69 Table A1.16 Tajikistan Area: 143.1 '000 km2 Population: 5.8 m Per Capita Income (bank method): 370 US$ Gross Domestic Inves tment: 17.4 % of GDP Current Account balance: 0 % of GDP GDP (1995) (Mil/ion US$) 2,200 Agriculture 462 (21%) Industry 1,166 (53%) [Manufacturing - Services 572 (26%) Foreign Trade and Energy (1995) (Million US$) Imports 628 Exports 657 Fuels 188 (30%) Fuels 20 (3%) Nonfuel Primary Products 126 (20%) Nonfuel Primary Products 440 (67%) Manufactures 314 (50%) Manufactures 197 (30%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 0.04 3.79 0.14 3.69 Gas 0.03 1.01 - 1.04 Coal 0.12 0.09 0.04 0.17 Electricity - 0.45 0.55 -0.10 Hydro 1.47 - - 1.47 Nuclear Reserves (31 Dec 1994) (million toe) Petroleum - - m bbl Gas 25.45 1,000 bcf (28 bcm) Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 1.47 2.45 GWh/yr Hydro (Exploitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 0.04 0.00 Reinjected - - Flared, Vented Transit/production losses Net production 0.04 0.00 Imports 1.13 0.11 Exports Consumption 1.17 0.11 Gas Consumption (bcm/y) (bcf/d) Power/Heat generation 0.55 0.05 Energy Sector Industry Residential - - Nonspecified 0.62 0.06 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - ¢/m3 Natural Gas - Industry - - ¢/m3 Natural Gas - Power - - /Im3 Electricity - Residential - - 0/kWh Electricity - Commercial - - G/kWh Electricity - Industry - - 0/kWh Fuel Oil - - ¢/liter Gasoline - - 0/liter Diesel - - 0/liter Kerosene - - ¢/liter 70 Natural Gas Trade in Asia and the Middle East Table A1.17 Thailand Area: 514 '000 km2 Population: 58.7 m Per Capita Income (bank method): 2,720 US$ Gross Domestic Investment: 43 % of GDP Current Account balance: -8 % of GDP GDP (1995) (Million US$) 167,200 Agriculture 18,390 (11 %) Industry 63,540 (38%) [Manufacturing 48,490 (29%)] Services 85,300 (51%) Foreign Trade and Energy (1995) (Million US$) Imports 70,881 Exports 56,036 Fuels 7,731 (11 %) Fuels 1,121 (2%) Nonfuel Primary Products 2,920 (4%) Nonfuel Primary Products 17,932 (32%) Manufactures 60,230 (85%) Manufactures 36,984 (67%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 3.94 25.54 2.89 26.59 Gas 9.59 - - 9.59 Coal 4.52 0.72 - 5.24 Electricity - 0.03 - 0.03 Hydro 0.32 - - 0.32 Nuclear - - Reserves (31 Dec 1994) (million toe) Petroleum 29.88 218 m bbl Gas 155.36 6,162 bcf (175 bcm) Coal 332.67 1,211 m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 0.39 4,587 GWh/yr Hydro (Exploitable) 1.52 17,678 GWh/yr Gas Balance (1 995) (bcm/y) (bcf/d) Gross production 11.36 1.10 Reinjected - - Flared, Vented - - Transit/production losses 0.95 0.08 Net production 10.41 1.00 Imports - - Exports Consumption 10.41 1.00 Gas Consumption (1994) (bcm/y) (bcf/d) Power/Heat Generation Energy Sector - - Chemical/Petrochemical 0.25 0.02 Other Industry 0.41 0.04 Residential Nonspecified Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - - Natural Gas - Industry - -¢ Natural Gas - Power 2.59 9.58 ¢/m3 Electricity - Residential 18.59 5.44 ¢/kWh Electricity - Commercial 24.12 7.07 0/kWh Electricity - Industry 34.05 9.98 0/kWh Fuel Oil 3.58 13.40 0/liter Gasoline 11.01 33.93 0/liter Diesel 8.89 31.19 0/liter Kerosene 10.63 35.23 0/liter Annex 1 Country Profiles 71 Table A1.18 Turkey Area: 780.6 '000 km2 Population: 69.5 m Per Capita Income (bank method): 1,980 US$ Gross Domestic Investment: 23 % of GDP (1993) Current Account balance: -1 % of GDP (1993) GDP (1995) (Million US$) 99,696 Agriculture 14,567 (15%) Industry 29,908 (30%) [Manufacturing 22,975 (23%)] Services 55,221 (55%) Foreign Trade and Energy (1993) (Million US$) Imports 22,871 Exports 14,715 Fuels 3,780 (17%) Fuels 235 (2%) Nonfuel Primary Products 3,528 (15%) Nonfuel Primary Products 3,973 (27%) Manufactures 15,563 (68%) Manufactures 10,507 (71%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 4.37 21.97 2.19 23.36 Gas 0.18 4.00 - 4.18 Coal 20.14 3.32 - 17.29 Electricity - 0.02 0.03 -0.01 Hydro 2.28 - - 2.28 Nuclear - - Reserves (31 Dec 1994) (million toe) Petroleum 66.80 488 m bbl Gas 9.35 371 bcf (11 bcm) Coal 4,949.84 8,568 m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 3.19 37120 GWh/yr Hydro (Exploitable) 37.22 432,870 GWh/yr Gas Balance (1995) (bcm/y) (bct/d) Gross production 0.20 0.02 Reinjected - Flared, Vented Transit/production losses Net production 0.20 0.02 Imports 6.90 0.67 Exports - - Consumption 7.10 0.69 Gas Consumption (1993) (bcm/y) (bcf/d) Power/Heat generation 2.29 0.22 Energy Sector 0.01 - Chemical/Petrochemical 0.65 0.06 Iron and Steel 0.04 Industrial 0.61 0.06 Residential 0.34 0.03 Nonspecified 0.70 0.07 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 7.57 28.0 ¢/m3 Natural Gas - Industry 3.79 14.0 ¢/m3 Natural Gas - Power 3.84 14.2 ¢/m3 Electricity - Residential 31.39 9.2 0/kWh Electricity - Commercial - - ¢/kWh Electricity - Industry 31.73 9.3 0/kWh Fuel Oil 4.17 15.6 M/liter Gasoline 26.79 82.6 0/liter Diesel 15.27 53.6 0/liter Kerosene - - ¢/liter 72 Natural Gas Trade in Asia and the Middle East Table A1.19 Turkmenistan Area: 488.1 '000 km2 Population: 4.5 m Per Capita Income (bank method): 920 US$ Gross Domestic Investment: - % of GDP Current Account balance: 1.3 % of GDP GDP (1995) (Million US$) 4,100 Agriculture 779 (19%) Industry 2,624 (64%) [Manufacturing 533 (13%)] Services 697 (17%) Foreign Trade and Energy (1993) (Million US$) Imports 543 Exports 1,145 Fuels 109 (20%) Fuels 905 (79%) Nonfuel Primary Products 212 (39%) Nonfuel Primary Products 23 (2%) Manufactures 223 (41%) Manufactures 126 (11%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 4.72 2.12 2.42 4.42 Gas 49.52 - 42.86 6.66 Coal - 0.10 - 0.10 Electricity - 0.09 0.34 -0.25 Hydro 0.06 - - 0.06 Nuclear Reserves (31 Dec 1994) (million toe) Petroleum 567 4,050 m bbl Gas 2,576 100,964 bcf (2,860 bcm) Coal - - m tons Nuclear (Capacity) 0.10 1,160 GWh/yr Hydro (Capacity) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 54.97 5.32 Reinjected Flared, Vented _ _ Transit/production losses 1.61 0.16 Net production 53.36 5.16 Imports - - Exports 47.56 4.60 Consumption 5.80 0.56 Gas Consumption (1993) (bcm/y) (bcf/d) Power/Heat generation 3.81 0.37 Energy Sector Industry Commercial - - Residential - - Nonspecified 1.99 0.19 Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential 0.04 0.15 0/m3 Natural Gas - Industry 0.06 0.24 ¢/m3 Natural Gas - Power 0.06 0.24 ¢/m3 Electricity - Residential 0.27 0.08 ¢/kWh Electricity - Commercial 0.27 0.08 ¢/kWh Electricity - Industry 0.85 0.25 o/kWh Fuel Oil 0.78 2.92 0/liter Gasoline 1.19 3.69 0/liter Diesel 1.11 3.90 0/liter Annex 1 Country Profiles 73 Table A1.20 Uzbekistan Area: 447.4 '000 km2 Population: 22.9 m Per Capita Income: 930 US$ Gross Domestic Investment: 21 % of GDP Current Account balance: -0.2 % of GDP GDP (1995) (Million US$) 21,400 Agriculture 7,062 (33%) Industry 8,132 (38%) [Manufacturing 4,066 (19%)] Services 6.206 (29%) Foreign Trade and Energy (1995) (Million US$) Imports 3,598 Exports 3,805 Fuels 60 (2%) Fuels Nonfuel Primary Products 688 (19%) Nonfuel Primary Products Manufactures 2,850 (79%) Manufactures Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 3.25 5.53 0.14 8.64 Gas 35.36 1.91 3.31 33.86 Coal 1.35 0.26 0.06 1.55 Electricity - - 0.01 0.01 Hydro 0.63 - 0.63 Nuclear - _ _ Reserves (31 Dec 1994) (million toe) Petroleum 170 1,211 m bbl Gas 1,682 65,967 bef (1,868 bcm), Coal - - m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 1.05 12,210 GWh/yr Hydro (Expoitable) - - GWh/yr Gas Balance (1993) (bcm/y) (bcf/d) Gross production 39.14 3.79 Vented, Flared - - Reinjected - - Transit/production losses 1.32 0.13 Net production 37.82 3.66 Imports 2.12 0.21 Exports 3.67 0.35 Consumption 37.60 3.64 Gas Consumption (1993) (bcm/y) (bcf/d) Power/Heat generation 14.97 1.45 Energy Sector - - Iron and Steel Industry - - Industrial - - Commercial - - Residential - - Nonspecified 22.63 2.19 Consumer Prices (1993) ($/mmbtuJ Natural Gas - Residential 0.03 0.12 ¢/m3 (As of April 1995) Natural Gas - Industry 0.52 1.84 ¢/m3 (As of April 1995) Natural Gas- Power 0.52 1.84 0/m3 (As of April 1995) Electricity - Residential 0.64 0.19 0/kWh Electricity - Commercial 5.53 1.62 0/kWh Electricity - Industry 8.46 2.48 0/kWh Fuel Oil - - ¢/liter Gasoline 14.96 46.12 0/liter Diesel - - ¢/liter 74 Natural Gas Trade in Asia and the Middle East Table A1.21 Vietnam Area: 329.6 '000 km2 Population: 73.5 m Per Capita Income (bank method): 250 US$ Gross Domestic Investment: 27 % of GDP Current Account balance: -8 % of GDP GDP (1995) (Million US$) 20,300 Agriculture 5,887 (29%) Industry 5,887 (29%) [Manufacturing 5,887 (29%)] Services 8,526 (42%) Foreign Trade and Energy (1995) (Million US$) Imports 7,227 Exports 5,026 Fuels - (-%) Fuels 1,024 (20%) Nonfuel Primary Products - (-%) Nonfuel Primary Products - (-%) Manufactures - (-%) Manufactures - (-%) Primary Energy (1993) (million toe) Production Imports Exports Consumption Petroleum 6.42 3.60 6.40 3.62 Gas 0.23 - - 0.23 Coal 2.95 0.01 0.97 1.99 Electricity - - Hydro 1.25 1.25 Nuclear - - Reserves (31 Dec 1994) (million toe) Petroleum 68.49 500 m bbl Gas 93.29 3,700 bcf (105 bcm) Coal 123.11 182 m tons Nuclear (Capacity) - - GWh/yr Hydro (Capacity) 2.08 24,230 GWh/yr Hydro (Expoitable) - - GWh/yr Gas Balance (1995) (bcm/y) (bcf/d) Gross production 1.81 0.18 Reinjected Flared, Vented 0.47 0.05 Transit/production losses Net production 1.34 0.13 Imports Exports _ _ Consumption 0.34 0.13 Gas Consumption (1993) (bcm/y) (bcf/d) Power/Heat Generation 0.25 0.25 Energy Sector Chemical/Petrochemical - - Iron and Steel Industry Residential Nonspecified Consumer Prices (1993) ($/mmbtu) Natural Gas - Residential - ¢/in3 Natural Gas - Industry - ¢/m3 Natural Gas - Power - - ¢/m3 Electricity- Residential 14.54 4.26 0/kWh Electricity - Commercial 24.23 7.10 0/kWh Electricity- Industry 14.54 4.26 0/kWh Fuel Oil 3.18 11.88 0/liter Gasoline 7.72 23.81 ¢/liter Diesel 6.46 22.66 0/liter Kerosene 6.82 22.62 0/liter Annex 2 Gas Balance in Selected Countries Table A2.1 Gas Balance in Selected Countries (Unit: BCM/Y) Year Region/country 2000 2005 2010 Middle East Turkey Demand 5.85 7.90 11.50 Imports (extension)a 5.40 5.40 5.40 Production 0.1 0.1 0.1 Supply gap 0.35 2.40 6.00 Supply gap (if the current CIS 5.75 7.80 11.40 supply stops) Israel Demand 0.87 1.50 2.00 Production 0.00 0.00 0.00 Supply gap 0.87 1.50 2.00 South Asia Pakistan Demand 27.47 36.26 47.84 Production 27.00 28.80 28.50 Supply gap 0.47 7.46 19.34 India Demand 27.87 47.03 70.48 Production 19.50 26.20 35.00 Supply gap 8.37 20.83 35.48 Southeast Asia Thailand Demand 14.96 22.01 31.72 Production 9.1 11.40 13.80 Supply gap 5.86 10.61 17.92 Singapore" Demand 1.46 1.46 1.46 Imports (extension) 1.46 1.46 1.46 Production 0.0 0.0 0.0 Supply gap 0.0 0.0 0.0 (continues on next page) 75 76 Natural Gas Trade in Asia and the Middle East (Table A2.1 continued) Year Region/country 2000 2005 2010 East Asia China Demand 29.55 38.40 49.35 Production 20.6 22.30 25.70 Supply gap 8.95 16.10 23.65 South Korea Demand 9.75 12.75 15.30 Imports (extension) 7.90 6.10 3.80 Production 0.00 0.00 0.00 Supply gap 0.65 2.85 5.40 Taiwan Demand 4.95 7.05 10.80 Imports (extension) 0.50 4.10 6.10 Imports (new contracts) 3.50 2.00 0.00 Production 0.95 0.50 0.50 Supply gap 0.0 0.45 4.20 Japan Demand 48.30 57.15 68.10 Imports (extension) 4.70 13.00 1.1( Imports (new contracts) 43.60 41.50 33.30 Production 0.00 0.00 0.00 Supply gap 0.00 2.65 33.70 a Currently Turkey imports about 5 BCM/Y from the CIS via Ukraine, Romania. and Bulgaria. However, the continuation of supply from this route is uncertain. Turkey also imports 0.4 BCM/Y of LNG from Algeria. b Singapore currently imports about 1.5 BCM/Y of piped gas from Malaysia. Source: World Bank (1994b, 1994d); Ishiguro and Akiyama (1995); International Energy Agency (1994b, 1994c, 1995d); Cedigaz (1994b). Annex 3 Main Gas Reserves in Selected Gas Producers Table A3.1 Selected Proven and Probable Gas Fields in Middle Eastern and Former Soviet Union Countries Recoverable Recoverable gas condensate Field name Basin (bco (thousand bl) Field type Azerbaijan Bakharskoye Kobystan 3,530 70,000 A Bulla-More Kura 2,780 80,000 A Sanggachaly More Kobystan 2,140 45,000 A Kazakstan* Karachaganak N Caspian 48,000 8,360,000 A (oil and condensate) Tengiz Emba 12,925 - A Urikhtau Emba 1,500 145,000 A Zhanazhol Emba 3,450 212,000 A (oil) lmashevskoye N Caspian 4,500 258,000 N Oman Ahud Fahud Salt 1,000 50,000 A Sath Nihayda Ghaba Salt 2,000 50,000 A Sath Rawl Ghaba Salt 9,500 175,000 A Yibal C Oman Ptf 5,000 40,000 A Iran Agha Jari Zagros 20,500 - A Ashar Zagros 12,000 - N Ahwaz Zagros 15,000 - A Assaluyeh Zagros 20,000 - N B-Structure W gulf 50,000 - A Bibi Hakimeh Zagros 10,000 - A Dalan Qatar Arch 12,000 - N Barod (darius) W gulf 7,160 - N Dehluran Zagros 8,000 - A F-structure W gulf 17,000 - A G-structure W gulf 15,000 - N Gachsaran Zargos 25,000 - A (continues on next page) 77 78 Natural Gas Trade in Asia and the Middle East (Table A3.1 continued) Recoverable Recoverable gas condensate Field name Basin (bco (thousand bi) Field type Iran (continued) Kangan Zargos 100,000 200,000 A Khangiran N Afghan 18,000 - N Kuh-l-Mand Zargos 16,000 - A Marun Zargos 50,000 - A Nar Zargos 100,000 - N Paris Zargos 9,500 - N Pars W Gulf 100,000 - N Pars South Qatar arch 10,800 3,000,000 N Pazan Zargos 38,000 - A Rag-A safid Zargos 19,250 - A Sarkhun Zargos 7,000 70,000 N South Gashu Zargos 10,000 - N Varavi Zargos 16,000 - N Uzbekistan Adamtashskoye Gissar 1,050 23,000 N Dengizkul Severnyy Chardzhou 1,650 - N Dengizkul' Vostochnyy Chardzhou 4,300 16,750 N Gazliinskoye Gazli Upi 25,070 12,000 A Gumbulak Gissar 1,090 9,400 N Kandym Chardzhou 5,235 31,039 N Kemachi Yuzhnyy Chardzhou 1,670 14,500 A Kokdumalak Kagan Upl 5,300 536,000 A Kultanskoy Chardzhou 1,330 14,070 N Shakhpakhty Assake-Aud 1,600 - N Shurtan Kagan Upl 18,760 20,000 N Tandyrcha Yuzhnaya Gissar 1,300 11,720 N Uchkyr Tuzkoy Tr 1,523 3,000 N Urtabulak Chardzhou 3,510 11,000 N Zevardy Chardzhou 6,400 60,000 N Turkmenistan Achak Balkhui Dp 5,320 17,000 N Balkui/Ashurbay Balkhui Dp 1,720 14,000 N Barsagel'meskoye W Trkmenia 1,550 30,000 A Bayram Ali Murgab-Tad 1,800 - N Beurdeshik Beurdeshik 2,900 15,500 N Chartak Malay-bag 1,500 - N Gugurtli Chardzhou 2,800 - N Karabil Badkhyz-ka 1,260 - N Kirpichli Zaunguzd 5,790 62,500 N Korpedzhe W Trkmenia 30,000 30,580 N (continues on next page) Annex 3 Main Gas Reserves in Selected Gas Producers 79 (Table A3.1 continued) Recoverable Recoverable gas condensate Field name Basin (bcfl (thousand bl) Field type Turkmenistan (continued) Koturtepe W Trkmenia 2,290 50,000 A Malay Malay-Bag 2,620 - N Naip Balhui 5,970 43,200 N Naip Yuzhnyy Tlim Tr 1,030 - N Samantepe Chardzhou 3,490 12,000 N Sayrab Uch-Adzi 2,000 - N Shatlyk Murgab-Tad 33,410 103,000 N Sovietabad Badkhyz 36,900 95,000 N Tedzen Bakharrdok 1,540 1,730 N Uch adzhi Uch-Adzhi 1,590 - N Zevardy Chardzhou 6,450 60,000 A Tajikistan Kyzyl-Tumshukskoye Vaksh Dpn 1,920 - N UAE - Abu Dhabi Bab Rub al Kli 30,000 50,000 A Bu Hasa Rub al Kli 9,500 - A Ghasha Rub al Kli 5,000 7,000 N Nasr Rub al Kli 5,000 - N Saath Al Raaz Rub al Kli 5,500 - A Umm Shaif Rub al Kii 32,300 - A Zakum Rub al Kli 13,000 - A Zubbaya Rub al Kli 3,000 8,000 A UAE - Dubai Fateh Rub al Kli 1,600 - A Margham Rub al Kli 4,000 9,000 N UAE - Sharjah Sajaa Rub al Kli 4,000 40,000 A Yemen AI-Raja-Jannah Marib-Shab 2,250 45,000 N Alif Marib-Shab 1,750 - A As'ad Al-Kamil Marib-Shab 2,570 77,000 A Yaa Jeza 5,000 - N (continues on next page) 80 Natural Gas Trade in Asia and the Middle East (Table A3.1 continued) Recoverable Recoverable gas condensate Field name Basin (bcfl (mbl) Field type RUSSIAN FAR EAST Republic of Sakha (Yakutia) Tambey Severnyy Middle Yamal Swell 1,100 30,000 N Bovanenko Nurminsk Swell 76,300 64,000 A Ludlovskoye South Barents Sea Basin 8,000 - N Novoportovskoye Western Siberia Basin 3,600 - A Srednevilyuskoye L - N Tolon Mastakhskoye L - N Sobolokh Nedzhlinskoye L - N Srednebotuobinskoye L - A Srednetyungskoye L - N Nizhnekhamakinskoye L - N Chayadinskoye L - A Sakhalin region Arktun Dagin offshore L - A AStrakhanckaya L - N Chavio offshore 4,900 86,000 A Lunsk offshore 1,300 250,000 A Oduptu offshore 3,000 20,000 A Piltun Astokh offshore 2,300 20,000 A Vengayakha Western Siberia Basin 2,600 - A Vostochno Ossoiskaya L - N Yahno Lunskaya L - N Irkutsk region Dulisminskoye L - N Kovyktinskoye L - N Vakunaiskaya L - N Sugdinskaya L - N Ust liginskaya L - N Note: A = associated gas field; N = nonassociated gas field: L = classified information. Source: Petroleum Economist Ltd. (1993); Petroconsultants (1996). Data from Kazakgaz Company (1996). Annex 4 Basic Gas Trade Planning Model-Brief Discussion on Each Task A4.1 Perhaps the first step for formulating a long-term gas trade scheme would be to prepare a comprehensive diagnosis of the gas reserves required to ensure adequate supply, the targets for market size and competitive conditions, and the appropriate infrastructure for transporting gas efficiently. Because of interfuel competition and competition among natural gas suppliers, (e.g., in European markets), it is more practical to adopt market-oriented planning rather than supply-source-oriented planning. Task 1: Gas Reserve Assessment A4.2 The step involves assessing potential gas supply sources on a field-by-field basis, with detailed long-term production profiles. Information on gas reserves is bound to change as exploration proceeds. Creating accurate gas supply scenarios, therefore, requires expert and flexible assessments based on the views of experienced geologists and other experts. Task 2: Gas Market Analysis A4.3 For each gas-consuming sector (electric power, fertilizer, cement, commercial, residential, etc.) in the target market, one must assess the medium-to-long- term and per consumption demand, assuming that development of each sector takes the path of least financial resistance. As much as possible, the projection of gas demand should be based on an estimate of micro or bottom-up demand. A few demand scenarios could be drawn in conjunction with the expected economic growth in the country and from analyses of market conditions, the investment plans of bulk consumers, and relative prices of alternative sources. By aggregating gas demand projections for all the sectors (postulating several trial price paths), a demand curve for each consumption center can be built up over time (see Figures A4.1 and A4.2). 81 82 Natural Gas Trade in Asia and the Middle East Figure A4.1 Typical Demand over Time Price ($/mm Btu) 8 6 i 4 2 - l _-___ 2000 D 2010 Quantity (BCMY) 5 10 15 Figure A4.2 Aggregated Demand for Gas over Time Quantity (BCMY) 15 at P=$2/mm Btu 10 5 at P=$4/mmBtu at P=$8/mmBtu 0 1995 2000 2005 Task 3: Infrastructure Diagnosis A4.4 The next step in the planning model is to review gas supply infrastructure, including gas processing, gas pipelines, compressor stations, and gas storage. The design of the infrastructure needs to reflect seasonal and daily variations of gas demand. In that context, one can then evaluate needs for new infrastructure, modernization of existing facilities, or both. Environmental and safety issues should also be reviewed for improvement. Annex 4 Basic Gas Trade (Export) Planning Model 83 Task 4: Gas Supply Costs A4.5 In this phase of the planning one analyzes the cost of supply from major supply options, including investment costs and operating costs, payments to suppliers, and other relevant expenses. The gas supply cost includes all expenses relevant to production, transmission, and distribution. Task 5: Gas Market Values A4.6 For each of the target export markets, one must analyze prices being paid, prices of alternative fuels (current and future), and possible future prices for supplies. Then one examines netback values and marginal incremental costs of gas for each category of users (such as power, district heating, industry, and commercial and residential consumers), comparing alternative fuels and gas. Next, one computes the weighted average market values of gas (the market value of gas is defined as the maximum a gas supplier could charge a customer and still remain competitive with other fuels). The value of gas in power generation is obtained by comparing gas use in a modem combined-cycle gas- turbine (CCGT) plant with use of currently available fuels (generally, coal or fuel oil) in a conventional steam turbine plant. The value of gas in industry is set by the competing oil products or coal. In the case of natural gas used as a feedstock for petrochemicals, the value of the gas will be measured in comparison with imported options of petrochemical products. For residential and commercial users, gas oil, kerosene, LPG, and fuel oil are usually competitive. If the target market is in a country that is currently importing gas, an appropriate reference to the market value would be the sales prices of imported gas at the national border. Task 6: Gas Balance A4.7 In this step, the planner draws a gas balance over time for each market. The aggregated demand curves should be matched with the maximum supply scenario(s) derived from Tasks 1 and 2 above. An optimal gas supply scenario would be determined for each reserve scenario. Task 7: Evaluation of Additional Infrastructure A4.8 In close linkage with gas utilization strategy and the above market analysis, one evaluates the production. transmission, storage, and distribution infrastructure facilities to meet the expected demand. Then, one identifies needs for new installation and/or modernization of the infrastructure from the supply source to the markets. A technical conceptual design will be required with reasonably accurate cost estimate. Task 8: Gas Utilization Strategy A4.9 At this point, the planner must review the role of the gas sector in the national economy and plan to develop a least-cost gas reserve. Also, one should review the existing institutional and regulatory frameworks for needs of modernization. Then, one 84 Natural Gas Trade in Asia and the Middle East can establish an economically sound strategy to promote the proposed gas utilization including creation of draft gas sales and transit contracts and enhancement of investment opportunities in the country. The substance of this task will be developed in parallel with the above tasks. For a country that has gas reserves, one might consider an incentive system to promote development of proven reserves and exploration for new ones. Task 9: Investment Option A4.10 One should identify the need for investments to improve the operational performance, efficiency, and flexibility of gas transmission and distribution as well as the need to increase gas production and transmission to supply additional gas to the target markets. Then, one summarizes the needs for investments and ranks the proposed investment projects using such economic and financial indicators as net present values, internal rates of return, discount cash flows, and so on. In addition, one evaluates the technical and environmental appropriateness of each project. Task 10: Priority Investments A4.11 The planner will draw up the ownership structure of the project and the form of the project company. Then, he or she will evaluate various schemes for implementing the project (such as BOO, BOT, and use of World Bank guarantees). Once these structures are determined, the planner can proceed to formulate a comprehensive project implementation proposal that can attract financiers. Task 11: Financial Options A4.12 Finally, the planner will determine the needs for funding and contact potential investors and financiers. This requires evaluating project risks and mitigation measures including securities to lenders. Financial advisors can help in evaluating costs of available financial options, conditions, and other factors. This task forms a critical part of any project preparation, and for this reason an initial survey of options must be made at a very early stage of project formulation. Annex 5 Principles of GasTrade Contracts: Sample LNG Sales Contract A5.1 The following is an excerpt from a draft contract between an LNG seller and buyer. * Effective period of the contract: about 22 years If the Seller and the Buyer agree before four years from the termination year of the original contract, the sales contract could be extended. * Delivery The Buyer off-takes a fixed quantity of LNG at an agreed price or if not off-take, pays an agreed penalty. (Take-or-pay close) The delivery is the Buyer's port. * Quantity of service Each year within the agreed sales period, the Buyer receives the agreed upon volume of LNG. However, during the build-up period of 12 months, the Buyer can decrease its off- take quantity with a maximum adjustable quantity of about 25% of the originally agreed sales volume. For the rest of the contract period, such an adjustable quantity is a maximum of about 12% of the originally agreed upon volume. * Sales price The following price formula applies: PC = PL + PT where Pc = sales price. PL is the "LNG related component" that links with the price of crude oil produced by the Seller's country. More specifically, PL is written as follows: PL = PA x Ax/Ay where PA = Initial setting value Ax = The arithmetic average of the actual FOB prices of the crude in the gas export country, inclusive of condensate but excluding premium and spot oil prices. AY = the average crude oil price at the time of the gas sales contract signing. 85 86 Natural Gas Trade in Asia and the Middle East PT is the "transportation related component" which varies based on the following escalation formula: PT = PB x (1.025)" where PB = Initial setting value n = the number of years after the contract signing * Quality Calorific Value In the gaseous state, the calorific value is minimum 1,100 Btu per standard cubic feet (scf) and maximum 1,160 Btu per scf. Compositions Composition Methane (CH4) Min. 85 mol % Nitrogen (N2) Max. 1.0 mol % Butane (C4) Max. 2.0 mol % Pentane (C5) Max. 0.1 mol % Hydrogen sulfide (H2S) Max. 0.25 grains/100 scf Sulfur content Max 1.3 grains/100 scf * Force Majeure provisions Natural disasters (e.g., fire, flood, earthquake, typhoon), war and civil disturbances, labor disputes, misconduct of the governments - Force Majeure that may be attributed to the Seller's side: Accidents of the LNG plant, the delay of the LNG plant construction (despite "reasonable" countermeasures), decrease of the LNG reserves below the minimum acceptable level, delay of LNG tanker construction (despite "reasonable" countermeasures), accidents, natural disasters, labor disputes - Force Majeure that may be attributed to the Buyer's side: Accidents of the LNG receiving terminal, delay of the receiving terminal construction (despite "reasonable" countermeasures). If the delivery of LNG stops for a continuous period of 42 months, the sales contract could be canceled with a 180 day advance notice from the Buyer or the Seller. Annex 5 Principles of Gas Trade Contracts: Sample LNG Sales Contract 87 Gas Pricing Formula for Piped Gas (to West European markets) Pg = PO + oc (HEL- HEL0 ) + 3 (HSL-HSL0) where Pg = Ruling gas price PO = Actual gas price HEL = Price of light oil at the moment of the indexation HEL0 = Price of light oil at the moment of P0 HSL = Price of heavy fuel oil at the moment of the indexation HSL0 = Price of heavy fuel oil at the moment of P0 cx, I .... Factors to be negotiated (close to "1") Annex 6 Publicly Announced Potential Gas Trade Projects in Asia and the Middle East Table A6.1 Potential Gas Trade Projects in Asia and the Middle East Estimated capital Timing: Gas Gas investment plannied com- Project name exporter importer Gas trade (US$ million) missioninlg Egypt-Israel Gas Egypt Israel 2.6 BCMY 200 (up to the Israeli 2000 Pipeline by 2000 and border, 250 km) 6.2 BCMY by 2005 Gulf-South Asia Gas Qatar Pakistan 16.5 BCMY Up to 4,000 (1,620 1998 km offshore pipeline) Qatar LNG Trade Qatar Thailand, 28 BCMY 18,000 (including all 1997-2000 India, (including the proposed 3 Turkey all the projects) (Japan, proposed 3 Taiwan) projects) Oman-India Gas Oman India 10.3 BCMY 3,100 (submarine 1999 Trade pipeline) Oman LNG Trade Oman India, 9 BCMY 6,400 2000 Thailand, (including China all the (Korea, proposed Japan) gas trade transactions) Myanmar-Thailand Myanmar Thailand 5.4 BCMY 1,350 (325 km 1998 Gas Trade submarine pipeline and 450 km onshore pipeline) Malaysia-Thailand Malaysia Thailand 3.1-6.2 Under Gas Trade BCMY consideration Russian Sakha-South Russia Korea 15.5 BCMY 5,000 (3,800 km Not known Korea (Initial onshore pipeline) consideration) (continues on next page) 89 90 Natural Gas Trade in Asia and the Middle East (Table A6.1 continued) Estimated capital Timing: Gas Gas investment planned com- Project name exporter importer Gas trade (US$ million) missioning Bangladesh-India Gas Bangla- India 8.2 BCMY 1,900 (550 km Not known Trade desh onshore pipeline) Yemen LNG Trade Yemen East and 6.9 BCMY 3,000 Not known South Asia Turkmenistan- Turkmen- Pakistan 20 BCMY 3,000 (2,000 km Not known Pakistan Gas Trade istan onshore pipeline) Turkmenistan-Turkey Turkmen- Turkey 10 BCMY 4,500 (1,900 km Not known Gas Trade istan onshore and offshore pipelines) Turkmenistan-China Turkmen- China 28 BCMY 4,400-5,000 (6,200 Not known Trans Asian Pipeline istan km onshore pipeline) Annex 7 Netback Values for Gas in Power Generation Share of Primary Energy Sources for Power Generation A7.1 A preliminary computation has been made for two cases, one for coal replacement and the other for fuel oil replacement. As presented below, power generation in Asia and the Middle East is dominantly based on coal and fuel oil. Coal Prices in Selected Countries China A7.2 According to the SAR of the Yangzhou Thermal Power Project issued in February 1994, the economic price of coal is 301.1 Yuan per ton. Using the shadow exchange rate of 9 Yuan per U.S. dollar, one ton of coal in China is estimated at about US$33.5 per ton, which is equivalent to $1.7 per MMBtu. The coal for the power plant has a calorific value of 5,100 kcal per kg. India A7.3 According to the SAR of the Private Power Utilities (BSES) Project issued in May 1991, the cost of ordinary grade coal with a calorific value of about 5,000 kcal per kg was Rs 630 per ton. Using the exchange rate of Rs 19 for one dollar at that time, the coal cost is estimated at $1.7 per MMBtu. Turkey A7.4 According to IEA (1993b) the steam coal price for power generation was $56.73 per TCE. A ton of coal equivalent (TCE) has a heat value of 7,000 Kcal/Kg or about 27.78 MMBtu per ton. Therefore, the steam coal price is estimated at about $2.0 per MMBtu (=$56.73/27.78). At present, Turkey is using a substantial amount of lignite. However, in the long-run Turkey is expected to import more steam coal. Japan A7.5 According to Coal Statistics International (1994), the average import price of steam coal to Japan during January to June 1995 was $45.56 per ton. Assuming an average calorific value of 6,700 Kcal/ton, the imported steam coal price for power is estimated at about $1.7/MMBtu. Taiwan A7.6 According to Coal Statistics International (1994), the average FOB price of Australian steam coal to Taiwan during January to June 1995 was $30.91 per ton. Coal Week International (1995) reports that the current coal transport cost from Australia to 91 92 Natural Gas Trade in Asia and the Middle East Taiwan is about $7.30 per ton. Therefore, the imported coal price to Taiwan is estimated at $38.2 per ton (=$30.91 + $7.30). Assuming that the calorific value of the imported coal is about 6,700 Kcal/ton, the price of the coal is about $1.4/MMBtu. South Korea A7.7 It is assumed that the imported steam coal price is similar to that of Japan. Israel A7.8 It is assumed that the imported steam coal price is similar to that of Turkey. Fuel Oil Prices in Selected Countries A7.9 According to Platt's Oil Price Handbook (1994) and Platt's Oilgram (1995), the average daily prices of fuel oil in 1994 were $82.61 (CIF) in the Mediterranean region; $78.61 (CIF) in the Arabian Gulf region; $79.90 (CIF) in Singapore; and $93.58 (C&F) in Japan. Converting to $/MMBtu, these prices are about: $2.2/MMBtu; $2.1/MMBtu; $2.l/MMBtu; and $2.5/MMBtu respectively. It is assumed that the fuel oil price in Korea is similar to that in Japan. Similarly, the price in Thailand is assumed to be that of Singapore. The imported fuel oil price in Pakistan was estimated at $2.3/MMBtu, assuming a transport cost of $9.5/ton from the Arabian Gulf. (According to Platt's Oilgram (1995), the transport cost by a 30,000 DWT clean tanker from Arabian Gulf to India is $9.5 per ton.) A7.10 Table A7.1 and A7.2 present typical netback values for gas as substitute for coal- and fuel-oil-fired plants, respectively. Annex 7 Netback Values for Gas in Power Generation 93 Table A7.1 Typical Netback Value for Gas (Combined Cycle) as Substitute for 600 MW Coal Plant (at coal price of $1.7 per MMBtu) GAS VALUE IN POWER 600 MW Coal Plant 600MW C.C. PLANT (Including FGD and 15% contingency) (including 15% contingency) Efficiency 34% Efficiency 45% Rated Capacty 600 MW Rated Capacity 600 MW Load Factor 76% Load Factor 76% Unit mv. cost $1300/kw Unit inv.cost $650/kw Ope. cost 2.5% of Inv. cost Ope. cost 4% of Inv. cost Cost of Coal $1.7/MMBTU Plant inst. penod 3 years Plant Inst. period 5 years Year Capex Coal Consump. Coal Cost Opex Capex + Capex Opex Capex + Gas Gas Opex Opex Consump Consump (mm US$) (10^s MMBTU) (mm US$) (mm US$) (mm US$) (mm US$) (mm US$) (mm US$) (10^6 m3) (10'6 MMBTU) 1 78 0 0 0 76 117 0 117 0 0 2 156 0 0 0 156 175.5 0 175.5 0 0 3 234 0 0 0 234 97.5 0 97.5 0 0 4 234 0 0 0 234 0 15.6 15.6 841 30.3 5 76 0 0 0 78 0 15.6 15.6 841 30.3 6 0 40.07 68.119 195 87.619 0 15.6 15.6 841 30.3 7 0 40.07 68119 19.5 87.619 0 15.6 15.6 841 30,3 8 0 40.07 68.119 19.5 87.619 0 15.6 15.6 841 30.3 9 0 40.07 68.119 19.5 87.619 0 15.6 15.6 841 30.3 10 0 4007 68.119 19.5 87.619 0 15.6 15.6 841 30.3 11 0 40.07 68.119 19.5 87.619 0 156 15.6 841 30.3 12 0 40.07 68.119 19 5 87619 0 15.6 15.6 841 30.3 13 0 40.07 68.119 19.5 87.619 0 156 15.6 841 30.3 14 0 40.07 68 119 19.5 87.619 0 15.6 15.6 841 30.3 15 0 40.07 68119 19.5 87.619 0 15.6 15.6 841 30.3 16 0 40.07 68.119 19.5 87.619 0 15.6 15.6 841 30.3 17 0 40.07 68.119 19.5 87.619 0 15.6 15.6 841 30.3 18 0 40.07 68.119 19.5 87.619 0 15.6 15.6 841 30.3 19 0 4007 68.119 19.5 87.619 0 15.6 15.6 841 30.3 20 0 40.07 68.119 19.5 87.619 0 15.6 15.6 841 30.3 21 0 40.07 68119 19.5 87.619 0 15.6 156 841 30.3 22 0 40.07 68.119 19.5 87.619 0 15.6 15.6 841 30.3 Total 780 681.19 1158.023 331.5 2269.523 390 296.4 686.4 15979 575.7 NPV@15% $ 512.21 $120.47 $204.80 $58.63 $775.64 $298.55 $63.58 $362.13 $3,427.4 $123.49 Gas netback value= $ 3.35 per MMBTU 94 Natural Gas Trade in Asia and the Middle East Table A7.2 Typical Netback Value for Gas (Combined Cycle) as Substitute for 600 MW Fuel Oil Plant (at fuel oil price of $2.1 per MMBtu) GAS VALUE IN POWER 600 MW Fuel Oil Plant 600MW C.C. PLANT (including FGD and 15% contingency) (including 15% contingency) Efficiency 36% Efficiency 45% Rated Capacity 600 MW Rated Capacity 600 MW Load Factor 76% Load Factor 76% Una inv. cost $1000/kw Unit inv.cost $650/kw Ope. cost 2% of Inv. cost Ope. cost 4% of Inv. cost Cost of F.O. $2.1/MMBTU Plant inst. period 3 years Plant inst. period 4 years Year Capex F.O. Consump. F.O. Cost Opex Capex + Capex Opex Capex + Gas Gas Opex Opex Consump Consump (mm US$) (10^ MMBTU) (mm US$) (mm US$) (mm US$) (mm US$) (mm US$) (mm US$) (10^cm3) (10^ MMBTU) 1 90 0 0 0 90 117 0 117 0 0 2 210 0 0 0 210 175.5 0 175.5 0 0 3 180 0 0 0 180 97.5 0 97.5 0 0 4 120 0 0 0 120 0 15.6 15.6 841 30.3 5 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 6 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 7 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 8 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 9 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 10 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 11 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 12 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 13 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 14 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 15 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 16 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 17 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 18 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 19 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 20 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 21 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 22 0 37.84 79.464 12 91.464 0 15.6 15.6 841 30.3 Total 600 681.12 1430.352 216 2246.352 390 296.4 686.4 15979 575.7 NPV@15% $ 424.01 $132.58 $278.42 $42.04 $744.48 $298.55 $63.58 $362.13 $3,427.4 $123.49 Gas netback value= $ 5.51 per MMBTU Annex 8 Sample Calculation of Gas Transport Costs The sample calculations presented below (with data for different volume and distance scenarios in Tables A8.1 through A8.9) are based on the following major assumptions: Onshore Pipeline Pipeline installed cost $20 per inch-diameter over I m length Pipeline annual operating cost 1% of the initial capital investment Gas compressor stations With provision of 50% stand-by units Design pressure level 1,200 psi (about 83 Bar) No. of gas compressor stations Million tons per year 5 10 20 1,200 km 7 8 9 3,800 km 22 25 29 7,600 km 44 50 58 Gas compressor station installed cost $1.3 million per installed turbo-compressor unit Gas compressor station annual operating Fixed cost = 3% of the initial capital investment cost Variable cost = fuel gas, estimated at an overall thermal efficiency of 25% and at $1 per MMBtu Offshore Pipeline Pipeline installation cost $40 per inch diameter over 1 m length Compressor installation cost $3.5 million per installed turbo-compressor unit Other factors Similar to the above onshore pipeline case LNG Liquefaction plant installation cost $1,600 million for 4 million tons/year Regasification plant installation cost $450 million for 4 million tons/year LNG cargo vessel $250 million for 125,000 m3 (gross 53,000 ton LNG) Speed of LNG cargo vessel 19 knot (= 34.5 km/h) Loading and unloading LNG 2 days each for a LNG cargo vessel LNG liquefaction plant annual operating 5% of the initial capital investment cost Regasification plant annual operating cost 3% of the initial capital investment Annual operating cost of LNG cargo 7.5% of the initial capital investment 95 96 Natural Gas Trade in Asia and the Middle East Table A8.1 Onshore Pipeline Transport Costs (5 MMt/y X 3,800 km) Onshore Pipeline Transport Cot BMY :32 inch x 3800 Km; 330x 1.5 MW _____ EXPENDITURE, OPE COST, Gross MM US$ MM US$ MM US$_ Year Gas Sales Plro Tariff Revenue Pipe line Comp StnC Net Rev. jMMT pa. US$IMMBtu M US$ _ _ 1 0 3.41 0 243 64.5 0 0 -307.5 2 0 3.41 0 607 161.25 0 _ 0 -768.25 3 0 3.41 0 730 193.5 0 0 -923.5 4 0 3.41 0 486 129 0 0 -615 5 1.25 3.41 181 243 64.5 8.0 17.6 -152.4 6 2.5 3.41 381 122 32.25 10.9 24.0 192.0 3.75 3.41 563 0 0 18.7 41.1 503.0 8 5 3.41 _ 753 0 0 24.3 53.4 675.3 9 5 3.41 753 0 0 _ 24.3 53.4 675.3 10 5 3.41 753 0 24.3 53.4 675.3 11 5 3.41 753 0 24.3 53.4 675.3 12 5 3.41 1 753 0 0 24.3 53.4 675.3 13 5 3.41 753 0 0 24.3 53.4 675.3 14 6 t3.41 753 0 0 24.3 53.4 675.3 15 5 3.41 753 0 0 24.3 53.4 675.3 1 5 3 41 7530 0 2A.3 53.4 675 3 217 5 3.41 1753 0 0 24.3 53.4 675.3 ~22 ~5 -3 418 -75-3 - 4-O _ _24.3 53.4 -1675.3 23 5 | 3.41 753 0 0 24.3 534 675.3 24 5 341 753 O _ 24.3 53.4_ 675.3 25 3 41 _> 7-53 0~ X _0 24.3 53.4 675.3 ~22 5 1 43.41 1 '753 0 1 0 243 |53.4 675.3 _ 23 5 < ~~~~~~753 - - 0 0 0 - 43 5. 67-5.3 271 534 5 0 1 0 2. |53.4 67. | 261 5 1 3.41 1753 0 1 0 243 15.4 675.3 | 291 5 1 .1 730 0 °2. |53.4 675.3 |To-tal 117.5 | 17692 2431 64-5- 572.5 1-257.9 12785.1 |NV@15% Sz ui 1,6-02 |4516 $3 IFG consumption taken into account. IA.\Onpivel Annex 8 Sample Calculation of Gas Netback Costs 97 Table A8.2 Onshore Pipeline Transport Costs (10 MMt/y X 3,800 km) Onshore Pipeline Transport Cost 10 MMt/y (13.8 BCMY) 44 inch x 3800 Km; 600x1.5 MW EXPENDITURE, OPE COST, Gross MM US$ MM US$ MM US$ Year Gas Sales Proj Tariff Revenue Pipeline Comp Stn. Pipeline Comp Stn Net Rev. MMT p.a. US$/MMBtu MM US$ 1 0 2.52 0 334.5 117 0 0 -451.5 2 0 2.52 0 836.25 292.5 0 _ 0 -1128.75 3 0 2.52 0 1003.5 351 0 0 -1354.5 4 0 2.52 0 669 _ 234 0 0 -903 5 2.5 2.52 252 334.5 117 11.0 32.0 -242.9_ 6_ 5 2.52 569 167.25 58.5 15.1 43.7 284.7 7 7 7.5 2.52 842 0 0 _ 25.8 _---74.7 741.2 8 10 i 2.52 1126 _ 0 0 -33.5 97.0 995.2_ 9 10 2.52 1126 0 0 33.5 97.0 995.2 10 10 2.52 1126 0 0 33.5 97.0 995.2 11 1 0 2.52 1126 0 0 33.5 97.0 995.2 12 10 2.52 1126 0 0 33.5 97.0 995.2 13 10 2.52 1126 0 0 33.5 97.0 995.2 14 _ 10 2.52 1126 0 0 33.5 _ 97.0 995.2_ 15 10 2.52 1126 0 0 33.5 97.0 995.2 164 10 2.52 1126 0 0 33.5 97.0 995.2 17 10 2.52 1126 0 0 33.5 97.0 995.2 18 10 2.52 1126 0 0 33.5 97.0 995.2 19 10 2.52 1126 0 0 33.5 97.0 995.2 20 10 2.52 1126 0 0 33.5 97.0 995.2 21 10 2.52 1126 0 0 33.5 97.0 995.2 22 10 2.52 1126 0 0 33.5 97.0 995.2 23 10 2.52 1126 0 0 33.5 97.0 995.2 24 10 2.52 1126 0 0 33.5 97.0 995.2 25 10 2.52 1126 0 0 33.5 97.0 995.2 26 10 2.52 1126 0 0 33.5 _97.0 995.2 275 10 2.52 1126 0 0 33.5 97.0 995.2 28 10 2.52 1126 0 0 33.5 97.0 995.2 29 10 o 2.52 1126 0 0 33.5 97.0 995.2 Total 235 26426 3345 1170 787.7 2284.6 18839.0 NPV @ 15% $3,378 $2,204 $771 $102 $295 $7 FG consumption taken into account. T _ - T.r/IRR 15.03% A:\Onpipe3.x1s 98 Natural Gas Trade in Asia and the Middle East Table A8.3 Onshore Pipeline Transport Costs (20 MMt/y X 3,800 km) Onshore Pipeline Transport Cost 20 MMt/y (27.6 BCMY) 56 inch x 3800 Km; 1044x1.5 MW EXPENDITURE, OPE COST, Gross MM US$ mm US$ MM US$ Year Gas Sales Proj Tariff Revenue Pipeline COmp Stn. Pipeline Comp Stn Net Rev. MMT p.a. US$/MMBtu MM US$ 1[ 0 1.754 0 425.6 203.5 0 0 -629.1 2 0 1.754 _ 0 1064 508.75 0 A 0 -1572.75 3_ 0 1.754 0 1276.8 610.5 0 0 -1887.3 4 0 1.754 0 851.2 407 0 _ 0 -1258.2 5 5 1.754 385 425.6 203.5 14.0 55.7 -313.6 6L_ 10 1.754 803 212.8 101.75 _ 19.2 75.9 392.9 7 15 1.754 1189 0 0 32.8 130.0 1026.6 8-, 20 -1.754 1590 0 0 _ 42.6 168.8 1378.5 9 20 1.754 1590 0 0 42.6 168.8 1378.5 10 20 1.754 1590 0 0 42.6 168.8 1378.5 = 11 -20 -- 1.754 1590 0 0 42.6 168.8 1378.5 12 20 1.754 1590 0 0 42.6 168.8 1378.5 13 20 1 1754 1590 0 0 42.6 168.8 1378.5 14 20 1.754 1590 0 0 42.6 168.8 1378.5 15 20 1.754 1590 0 0 42.6 _ 168.8 1378.5 16 20 1.754 1590 0 0 42.6 168.8 1378.5 17 20 1.754 1590 0 0 42.6 168.8 1378.5 18 20 - 1.754 1590 0 0 42.6 _ 168.8 1378.5 19 20 1.754 1590 0 0 - 42.6 _ 168.8 1378.5 20 20 1.754 1590 0 -0 42.6 168.8 1378.5 21 20 1.754 1590 0 0 42.6 168.8 1378.5 22 20 1.754 1590 0 0 42.6 168.8 1378.5 23 20 1.754 1590 0 0 42.6 168.8 1378.5 24 20 1.754 1590 0 0 42.6 _ 168.8 1378.5 25 20 1.754 1590 0 0 42.6 168.8 1378.5 263 20 1.754 1590 0 0 42.6 168.8 1378.5 27 20 1.754 1590 0 0 42.6 168.8 1378.5 28 20 1.754 1590 0 0 42.6 168.8 1378.5 29 20 1.754 -1590 0 0 42.6 168.8 1378.5 Total 470 37353 4256 2035 1002.3 3974.6 26085.6 NPV @ 15% $4,786 $2,804 $1,341 $129 $513 (SI) FG consumption taken into account. ____ I - IRR 15.00% A:\Onpipe5.xJs Annex 8 Sample Calculation of Gas Netback- Costs 99 Table A8.4 Offshore Pipeline Transport Costs (5 MMt/y X 3,800 km) Offshore Pipeline Transport Cost 5 MMt/y (6.9 BCMY) 32 inch x 3800 Km; 330x 1.5 MW EXPENDITURE, OPE COST, Gross MM US$ MM US$ MM US$ Year Gas Sales Proj Tariff Revenue Pipeline Comp Stn. Pipeline Comp Stn Net Rev. MMT p.a. US$/MMBtu MM US$ 1 0 7.2 0 486.4 173 0 0 -659.4 2 0 7.2 0 1216 432.5 _ 0 _ 0 -1648.5 3 0 7.2 0 1459.2 519 0 0 -1978.2 4 0 7.2 0 972.8 346 0 0 -1318.8 5 1.25 7.2 382 486.4 173 16.1 31.9 -325.8 6 2.5 7.2 805 243.2 86.5 21.9 43.6 409.8 7 3.75 7.2 1189 0 _ 0 37.5 _ 74.5 1076.5 8 5 7.2 1590 0 0 48.6 96.8 1444.5 9 5 7.2 1590 0 0 48.6 96.8 1444.5 10 5 7.2 1590 0 0 48.6 96.8 1444.5 11 5 7.2 1590 0 0 _ 48.6 96.8 1444.5 12 5 7.2 1590 0 0 48.6 96.8 1444.5 13 5 7.2 1590 0 0 48.6 96.8 1444.5 14 5 7.2 1590 0 0 48.6 96.8 1444.5 15 5 7.2 1590 0 0 ° 48.6 96.8_ 1444.5 16 5 7.2 1590 0 0 48.6 96.8 1444.5 17 5 7.2 1590 0 0 48.6 96.8 1444.5 18 5 7.2 1590 0 0 48.6 96.8 1444.5 19 5 7.2 1590 0 0 48.6 96.8 1444.5 20 5 7.2 1590 0 0 48.6 96.8 1444.5 21 5 7.2 1590 0 0 48.6 96.8 1444.5 22 5 7.2 1590 0 _ 0 48.6 96.8 1444.5 23 5 7.2 1590 0 0 48.6 96.8 1444.5 24 5 7.2 1590 0 0 48.6 96.8 1444.5 25 5 7.2 1590 0 0 48.6 96.8 1444.5 26 5 7.2 1590 0 0 48.6 96.8 1444.5 27 5 7.2 1590 0 0 48.6 96.8 1444.5 28 5 7.2 1590 0 0 48.6 96.8 1444.5 29 5 7.2 1590 0 0 48.6 96.8 1444.5 Total 117.5 37354 4864 1730 1145.5 2280.0 27335.0 NPV @ 15% $4,785 $3,205 $1,140 $148 $294 1 S2) FG consumption taken into account. IRR 15.00% AA0ffpipe1 1 - _ . _F - 0- - - 100 Natural Gas Trade in Asia and the Middle East Table A8.5 Offshore Pipeline Transport Costs (10 MMt/y X 3,800 km) Offshore Pipeline Transport Cost 10 MMt/y (1 3.8 BCMY) 44 inch x 3800 Km; 600x 1.5 MW EXPENDITURE, OPE COST, Gross MM US$ MM US$ MM US$ Year Gas Sales Proj Tariff Revenue Pipeline Comp Stn. Pipeline Comp St Net Rev. MMT pa. US$/MMBtu MM US$ 1- 0 5.37 0 668.8 315 0 0 -983.8 2 0 5.37 0 1672 787.5 0 0 -2459.5 3 0 5.37 0 2006.4 945 0 0 -2951.4 4 o 0 5.37 _ 0 1337.6 630 0 0 -1967.6 5 2.5 5.37 578 668.8 315 22.1 58.1 -485.9 55.37 | 1213 334.4 157.5 30.1 79.3 611.5 7 7.5 5.37 _1794 0 _ 0 0 51.5 135.7 1606.4 8 _ 10 5.37 2399 0 0 - 66.9 176.2 2155.6 9 10 5.37 2399 0 _ 0 66.9 176.2 2155.6 10 10 5.37 2399 0 0 66.9 176.2 2155.6 11 10 5.37 2399 0 0 66.9 176.2 2155.6 12 10 5.37 2399 0 0 66.9 176.2 2155.6 13 10 5.37 _ 2399 0 4 0 66.9 -176.2 2155.6 14 _ 10 5.37 -2399 0 0 66.9 176.2 2155.6 15 10 5.37 2399 0 0 66.9 176.2 2155.6 16 10 5.37 2399 0 0 66.9 176.2 2155.6 17 10 1 5.37 2399 0 0 66.9 176.2 2155.6 18 _ 1 0 5.37 2399 0 0 66.9 176.2 2155.6 19 10 5.37 2399 0 0 66.9 176.2 2155.6 20 10 5.37 2399 0 0 66.9 176.2 2155.6 21 10 5.37 2399 0 0 66.9 176.2 2155.6 22 10 5.37 2399 0 0 66.9 176.2 2155.6 23 10 5.37 2399 0 0 66.9 176.2 2155.6 24 10 _ 5.37 2399 0 0 66.9 176.2 2155.6 25 10 5.37 2399 0 0 66.9 176.2 2155.6 26 10 5.37 2399 0 0 66.9 1i76.2 2155.6 27 10 5.37 2399 _ 0 0 66.9 176.2 2155.6 28 10 5.37 -2399 0 0 66.9- 176.2 2155.6 29 1 0 5.37 2399 0 0 66.9 176.2 2155.6 Total 235 56355 6688 3150 1575.0 4149.8 40792.4 NPV @ 15% $7,220 $4,407 $2,076 $203 $535 ($I) FG consumption taken into account. ; AIRR 15.00% lA:\Offpipe3.XlS - X000 0 Annex 8 Sample Calculation of Gas Netback Costs 101 Table A8.6 Offshore Pipeline Transport Costs (20 MMt/y X 3,800 kin) Offshore Pipeline Transport Cost 20 MMt/y (27.6 BCMY) ~56 inch x 3800 Kin; 1044x 1.5 MW EXPENDITURE, -OPE COST, Gross mm LIS$ mm LUS$ mm LUS$ Year Gas Sales Proj Tariff Revenue Pipeline Comp Stn. Pipeline Comp Stn Net Rev. MMT_p.a_ _US$/MMBtu MM US$00 -19. I 0 ~~3.82 0 851.2 548 0 192 2 0 3.82 0 2128 1370 0 0 -3498 3 0 3.82 0 2553.6 1644 0 0 -4197.6 4 0 3.82 0 1702.4 1096 0 0 -2798.4 5 5 3.82 839 851.2 548 28.1 101.2 -689.5 6 10 3.82 1748 425.6 274 38.3 138.0 872.1 7 15 3.82 2590 0 0 65.5 236.1 2288.6 8 20 3.82 3462 0 0 85.1 306.6 3070.8 9 20 3.82 3462 0 0 85.1 306.6 3070.8 10 20 3.82 3462 0 0 85.1 306.6 3070.8 11 20 3.82 3462 0 0 85.1 306.6 3070.8 12 20 3.82 3462 0 0 85.1 306.6 3070.8 13 20 3.82 3462 0 0 85.1 306.6 3070.8 14 20 3.82 3462 0 0 85.1 306.6 3070.8 15 20 3.82 3462 0 0 85.1 306.6 3070.8 16 20 3.82 3462 0 0 85.1 306.6 3070.8 17 20 3.82 3462 0 0 85.1 306.6 3070.8 18 20 3.82 3462 0 0 85.1 306.6 3070.8 19 20 3.82 3462 0 0 85.1 306.6 3070.8 20 20 3.82 3462 0 0 85.1 306.6 3070.8 21 20 3.82 3462 0 0 85.1 306.6 3070.8 22 20 3.82 3462 0 0 85.1 306.6 3070.8 23 20 3.82 3462 0 0 85.1 306.6 3070.8 24 20 3.82 3462 0 0 85.1 306.6 3070.8 25 20 3.82 3462 0 0 85.1 306.6 3070.8 26 20 3.82 3462 0 0 85.1 306.6 3070.8 27 20 3.82 3462 0 0 85.1 306.6 3070.8 28 20 3.82 3462 0 0 85.1 306.6 3070.8 29 20 3.82 3462 0 0 85.1 306.6 3070.8 Total 470 1 f 8~~~135~ 8512 1 ~~ 2004-.6 I -7219:8- .-5813-5:0 NV15% .7,li 9,423 1 $59T _932J 1 FG co-nsu'mp,tio-n t,ak,e,n into account. A:\Off pipe5.x1s 102 Natural Gas Trade in Asia and the Middle East Table A8.7 LNG Transport Costs (5 MMt/y X 3,800 km) Transport Cost by LNG 5 MMt/y (6.9 BCMY) 3800 Km EXPENDITURE, OPE COST, MM US$ MM US$ MM US$ Year Gas Sales Proj Tariff Gross Rev. Liquefac Ship Regas Liquefac Ship Regas Net Rev. 125,000m3 MMT p.a. US$/MMBtu MM US$ (4 ships) 1 0 3.62 0 187 100 52.6 0 0 0 -339.6 2 0 3.62 0 467.5 250 131.5 0 0 0 -849 3 0 3.62 0 561 300 157.8 0 0 0 -1019 4 0 3.62 0 374 200 105.2 0 0 0 -679 5 1.25 3.62 225 187 100 52.6 46.8 37.5 7.9 -207 6 3.75 3.62 675 93.5 50 26.3 84.2 67.5 14.2 339 7 5 3.62 899 0 0 0 93.5 75.0 16 715 8 5 3.62 899 0 0 0 93.5 75.0 26.3 705 9 5 3.62 899 0 0 0 93.5 75.0 26.3 705 10 5 3.62 899 0 0 0 93.5 75.0 26.3 705 11 5 3.62 899 0 0 0 93.5 75.0 26.3 705 12 5 3.62 899 0 0 0 93.5 75.0 26.3 705 13 5 3.62 899 0 0 0 93.5 75.0 26.3 705 14 5 3.62 899 0 0 0 93.5 75.0 26.3 705 15 5 3.62 899 0 0 0 93.5 75.0 26.3 705 16 5 3.62 899 0 0 0 93.5 75.0 26.3 705 17 5 3.62 899 0 0 0 93.5 75.0 26.3 705 18 5 3.62 899 0 0 0 93.5 75.0 26.3 705 19 5 3.62 899 0 0 0 93.5 75.0 26.3 705 20 5 3.62 899 0 0 0 93.5 75.0 26.3 705 21 5 3.62 899 0 0 0 93.5 75.0 26.3 705 22 5 3.62 899 0 0 0 93.5 75.0 26.3 705 23 5 3.62 899 0 0 0 93.5 75.0 26.3 705 24 5 3.62 899 0 0 0 93.5 75.0 26.3 705 25 5 3.62 899 0 0 0 93.5 75.0 26.3 705 26 5 3.62 899 0 0 0 93.5 75.0 26.3 705 27 5 3.62 899 0 0 0 93.5 75.0 26.3 705 28 5 3.62 899 0 0 0 93.5 75.0 26.3 705 29 5 3.62 899 0 0 0 93.5 75.0 26.3 705 Total 120 21585 1870 1000 526 2281.4 1830.0 616.5 13461.0 NPV @ 15% $2,891 $1,232 $659 $347 $318 $255 $79 $1 IRR 15.010/ A:\LNG2.xls 27 rounds per ship Annex 8 Sample Calculation of Gas Netback Costs 103 Table A8.8 LNG Transport Costs (10 MMt/y X 3,800 km) Transport Cost by LNG 10 MMtVy (13.8 BCMY) 3800 Km EXPENDITURE, OPE COST, MM US$ MM US$ MM US$ Year Gas Sales Proj Tariff Gross Rev. Liquefac Ship Regas Liquefac Ship Regas Net Rev. 125.000m3 MMT p.a. US$/MMBtu MM US$ (8 ships) 1 0 3.16 0 303.8 200 85.5 0 0 0 -589.3 2 0 3.16 0 759.5 500 213.75 0 0 0 -1473 3 0 3.16 0 911.4 600 256.5 0 0 0 -1768 4 0 3.16 0 607.6 400 171 0 0 0 -1179 5 2.5 3.16 393 303.8 200 85.5 76.0 75.0 12.8 -361 6 7.5 3.16 1178 151.9 100 42.75 136.7 135.0 23.1 588 7 10 3.16 1570 0 0 0 151.9 150.0 26 1243 8 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 9 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 10 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 11 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 12 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 13 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 14 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 15 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 16 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 17 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 18 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 19 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 20 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 21 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 22 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 23 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 24 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 25 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 26 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 27 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 28 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 29 10 3.16 1570 0 0 0 151.9 150.0 42.75 1226 Total 240 37684 3038 2000 855 3706.4 3660.0 1002.1 23422.7 NPV @ 15% $5,048 $2,002 $1,318 $563 $517 $511 $128 $9 IRR 15.03% A:\LNG4.xJs 27 rounds per ship 104 Natural Gas Trade in Asia and the Middle East Table A8.9 LNG Transport Costs (20 MMt/y X 3,800 km) Transport Cost by LNG 20 MMtIy (27.6 BCMY) 3800 Km EXPENDITURE, OPE COST, MM US$ MM US$ MM US$ Year Gas Sales Proj Tariff Gross Rev. Liquefac Ship Regas Liquefac Ship Regas Net Rev. 125,000m3 MMT p.a. US$/MMBtu MM US$ (16 ships) 1 0 2.78 0 494 400 139 0 0 0 -1033 2 0 2.78 0 1235 1000 347.5 0 0 0 -2582.5 3 0 2.78 0 1482 1200 417 0 0 0 -3099 4 0 2.78 0 988 800 278 0 0 0 -2066 5 5 2.78 691 494 400 139 123.5 150.0 20.9 -636.6729 6 15 2.78 2072 247 200 69.5 222.3 270.0 37.5 1025.7013 7 20 2.78 2763 0 0 0 247.0 300.0 42 2174.0084 8 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 9 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 10 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 11 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 12 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 13 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 14 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 15 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 16 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 17 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 18 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 19 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 20 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 21 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 22 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 23 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 24 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 25 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 26 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 27 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 28 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 29 20 2.78 2763 0 0 0 247.0 300.0 69.5 2146.2084 Total 480 66305 4940 4000 1390 6026.8 7320.0 1629.1 40999.1 NPV@15% $8,882 $3,255 $2,636 $916 $841 $1,021 $208 $5 IRR 15.01% A:\LNG6.>ds 27 rounds per ship References Althius, Jaap, Hossein Razavi, Anil Malhotra, and P. 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