Report No. 19037-VN Fueling Vietnam's Development- New Challenges for the Energy Sector (In Two Volumes) Volume II: Annexes December, 1998 Energy & Mining Development Sector Unit Vietnam Country Department East Asia and Pacific Document of the World Bank Currency Equivalents Currency Unit = Dong (D) US$1.00 = D12,990 (July 98) Fiscal Year January I - December 31 Date of last Sector Report June 18, 1993 Weights and Measures bbl - barrel bm3 - billion cubic meter bcf - billion cubic feet bcm - billion cubic meter bpd - barrel per day dwt - deadweight ton GWh - GigaWatt - hour (I million kiliwatt - hours) ha - Hectare kcal - kilocalorie (3.97 British thermal units) km - kilometer (0.62 miles) kV - kilovolt (1,000 volts) kW - kilowatt kWh - kilowatt - hour m - meter m3 - cubic meter mm - millimeter mmb - million barrels mmcf - million cubic feet mt - million tons MW - mega watt ppm - parts per million t - ton tcf - trillion cubic feet toe - tons of oil equivalent Conversion Factors 1 million tons of oil equivalent is = 1.5 million tons of coal = 3 million tons of lignite - I .111 bcm of natural gas = 39.2 bcf of natural gas - 107 bcf per day of gas = 12,000 GWh of electricity Vice President Jean-Michel Severino Director Andrew Steer Sector Manager Yoshihiko Sumi Task Manager Anil Malhotra Abbreviations and Acronyms ADB - Asian Development Bank AFTA - ASEAN Free Trade Area ASEAN - Association of South East Asia Nations BOT - Build - Operate - Transfer BP - British Petroleum BTP - Bulk Transfer Price CC - Combined Cycle CIEM - The Central Institute of Economic Management COALIMEX - Coal Import-Export and Material Supply Corporation Doi Moi - Vietnam's economic renewal program launched in 1986 EDI - Economic Development Institute EHV - Extra High Voltage Transmission Line El - Energy Institute of Vietnam EIA - Environmental Impact Assessment ENPEP - Energy and Power Evaluation Program ESAF - Enhanced Structural Adjustment Facility ESMAP - Energy Sector Management Assistance Program EVN - Electricity of Vietnam FDI - Foreign Direct Investment GDP - Gross Domestic Product GEF - Global Environment Facility GSA - Gas Supply Agreement GT - Gas Turbine HCMC - Ho Chi Minh City HVAC - High Voltage Alternative.Current HVDC - High Voltage Direct Current IDF - Institutional Development Fund IMF - International Monetary Fund IUCN - International Union for the Conservation of Nature LPG - Liquified Petroleum Gas LRMC - Long Run marginal Cost MIS - Management Information System MOI - Ministry of Industry MPI - Ministry of Planning and Investment NEAP - National Environment Action Plan NGO - Non-Governmental Organization NPESD - National Plan for Environment and Sustainable Development ODA - Official Development Assistance OECD - Organization for Economic Cooperation and Development OECF - Overseas Economic Cooperation Fund PCI - Power Company I PC2 - Power Company 2 PC3 - Power Company 3 PCI - Pulverized Coal Injection PETECHIM - Petroleum Equipment Import Corporation PETROLIMEX - Importer and Exporter of Petroleum Products PVN - PetroVietnam PHRD - Population Human Resource Development PIDC I - Power Investigation and Design Company 1 PIDC2 - Power Investigation and Design Company 2 PSC - Production Sharing Contracts RAP - Resettlement Action Plan RoW - Right of Way SAC - Structural Adjustment Credit SCP - State Committee on Pricing SIDA - Swedish International Development Agency SOE - State Owned Enterprises SUC - Standard Unit Costs T&D - Transmission & Distribution TA - Technical Assistance TR - Transferable Rubles UNDP - United Nations Development Program UNEP - United Nations Environment Program VITTEP - Vietnam Institute of Tropical Technology and Environmental protection VOC - Volatile Organic Compounds WASP - Wein Automatic System Planning Package WB - World Bank FUELING VIETNAM'S DEVELOPMENT NEW CHALLENGES FOR THE ENERGY SECTOR Volume II ANNEXES TO THE REPORT ANNEX 1. ECONOMIC GROWTH AND ENERGY DEMAND HISTORICAL ENERGY CONSUMPTION 1.1. Energy and the Economy ........................................................ I 1.2. Population and Estimated GDP by Sector (1980-1995) .......................................................2 1.3. Consumption of Modern Energy (1980-1995) ........................................................3 1.4. Supplies of Modern Energy (1980-1995) ........................................................4 1.5. Consumption of Main Petroleum Products (1980-1995) .......................................................5 1.6. Production and Consumption of Natural Gas and Crude Oil (1980-1995) ..................................6 1.7. Consumption of Coal (1980-1995) ..................................7 1.8. Electricity Consumption (1980-1995) ..................................8 1.9 Energy Balance and Commodity accounts 1995 ..................................9 Graphs: 1.10. Consumptionofmodernenergy- 1980-95 .10 ENERGY DEMAND FORECASTS 1.11. Forecast Population of Viet Nam ........................................................ 1 1.12. Macroeconomic Forecast for Base Case ....................................................... 12 1.12. Macroeconomic comparison with Thailand, Malaysia, Philippines, and Korea .................. 13 1.13. Base Year Prices of Key Energy Products ....................................................... 14 1.14. Forecast of Opportunity Value Energy Prices ....................................................... 15 1.15. Electricity Demand Forecasts for Three Scenarios ....................................................... 16 1.16. Electricity Demand Forecast under Efficiency Measures .................................................... 17 1.17. Energy Balance and commodity accounts 2005 ....................................................... 18 Demandforecasts for Base case scenario 1.18. Summary of Electricity Demand for Viet Nam ....................................................... 19 1.19. Northern Region Electricity Demand ....................................................... 20 1.20. Hanoi Electricity Demand ....................................................... 21 1.21. Rural North Electricity Demand ....................................................... 22 1.22. Central Region Electricity Demand ....................................................... 23 1.23. Southern Region Electricity Demand ....................................................... 24 1.24. Ho Chi Minh City Electricity Demand ....................................................... 25 1.25. Rural South Electricity Demand ....................................................... 26 1.26. Petroleum Product Demand Forecast ....................................................... 27 1.27. Coal Demand Forecast ....................................................... 28 1.28. Gas Consumption Forecast .......................................... 29 1.29. Summary of Modem Energy Consumption Forecast .30 Graphs 1.30. Population ........................................ 31 1.31. Regional share of GDP ........................................ 32 1.32. Sectoral share of GDP ........................................ 33 1.33. Electricity demand forecast for scenarios ........................................ 34 1.34. Electricity demand under efficiency measures ........................................ 35 1.35. Base case electricity demand - by sector ........................................ 36 1.36. Petroleum Product demand ........................................ 37 1.37. Coal Demand ........................................ 38 1.38. Natural Gas Demand Forecast ........................................ 39 1.39. Diesel Conservation ........................................ 40 1.40. Primary Modem Energy Forecast ........................................ 41 1.41. Shares of Prim a ry En ergy Forecast ........................................ 42 1.42. Modern Energy per US$000 GDP ........................................ 43 1.43. Typical Composition of Energy Prices in Engergy sector ........................................ 44 ANNEX 2.1. THE POWER SECTOR 2.1.1. Vietnam Electric Power System - Historical Data ........................................ 46 2.1.2. Existing Power System in 1998 ........................................ 47 2.1.3. Electricity Generation Balance in 1996 (TWh, estimated) ........................................ 48 2.1.4. Trends in Electricity Generation and Consumption ........................................ 48 2.1.5. Electricity Generation Demand Forecasts ........................................ 49 2.1.6.a Electricity Tariffs (at May 1997) ........................................ 50 2.1.6.b Electricity Tariffs (at Dec 1998) ........................................ 50 2.1.7. Estimated Seasonal Plant Load Factors ........................................ 50 2.1.8. Hydro Plant Investment Options ........................................ 51 2.1.9. Thermal Plant Investment Options ......................................... 52 2.1.10. Comparative cost assumptions .53 2.1.11. Comparative cost estimates, c/kWh .54 2.1.12. Cases Examined in Power System Analysis .55 2.1.13. Comparison of Investment Plans for 5 Cases, to 2010 .56 2.1.14. Evaluation and Ranking of Cases (Indicators) .58 2.1.15. Fuel Consumption Forecasts in Power Generation .59 2.1.16. Son La Hydro Plant: NPV Analysis .59 2.1.17. Power system losses .60 2.1.18. DSM and energy efficiency .60 2.1.19. Comparison of Investment Plans .61 2.1.20. Summary of Generation costs .62 Graphs: 2.1.21. Regional Character of Viet Nam's Power System .63 2.1.22. Increasing Electricity Intensity per unit of GNP, 1974-1993 .63 2.1.23. Monthly Generation Mix for the Year 2000 (Base case) .64 2.1.24. Typical Daily Load Curves (PC2, 1995) .65 2.1.25. Annual Variation in Demand (1995) .65 2.1.26. Comparative Generation Costs-New Plant .66 2.1.27. Breakeven Fuel Prices (Netback Values) .66 2.1.28. Gas Demand in Power Generation .67 2.1.29. Monthly Gas Swing (Base case) .67 2.1.30.a Fuel Use Forecast - Fuel Consumption in Power Generation - Gas Demand .. 68 2.1.30.b Fuel Use Forecast - Fuel Consumption in Power Generation Domestic Coal Demand ..69 2.1.31. Generation Forecast for the year 2005 ........................................................ 70 ANNEX 2.2. UPSTREAM OIL AND GAS 2.2.1. Exploration activities in Vietnam .72 2.2.2. Exploration History and Discovered Reserves Potential .73 2.2.3. Expected Oil and Associated Gas Production .74 2.2.4. Production Prospects from Speculative Gas Reserves (bcm) - Nam Con Son Basin .75 2.2.5. Production Prospects from Speculative Gas Reserves (bcm) - Son Hong Basin .76 2.2.6. Estimates of Development Cost of Associated Gas .77 2.2.7. Development Cost Estimates of Non Associated gas - Lan Tay, Lan Do & Hai Thach .78 2.2.8. Development Cost and Associated Gas Economic cost - Cuu Long Basin .79 2.2.9. Hydrocarbon Production and Supply Cost of Gas .80 2.2.10. Cost of Exploration and Development for Speculative Reserves ........................................ 81 Graphs: 2.2.11. Potential Oil Production from discovered reserves- Cuu Long Basin ................................. 82 2.2.12. Potential Gas production from discovered reserves - Cuu Long and Nam Con Son (Blocks 6.1 and 5.2) ........................................................ 83 ANNEX 2.3. DOWNSTREAM OIL AND GAS 2.3.1. A note on issues in gas pricing ....................................................... 85 2.3.2. Organization of PVGC ....................................................... 96 ANNEXES 2.4: THE COAL SECTOR 2.4.1. Coal Reserves in Coalfield under exploitation .109 2.4.2. Coal Demand .110 2.4.3. Vinacoal Production Capacity .Ill 2.4.4. Mine head Production costs .112 2.4.5. Elements in Production Costs .113 2.4.6. Port Facilities .113 2.4.7. Anthracite Production and Trade .114 ANNEX 3: ENERGY AND ENVIRONMENT 3.1. Ambient Air Quality standards .116 3.2. Emission Standards from Stationary Sources .117 3.3. Coal mining disturbed area and production .118 3.4. Hydroelectric Plant incremental investments .118 3.5. Thermal plant incremental investments .119 3.6. Environmental costs under the base case scenario . 119 ANNEX 4: INVESTMENT PRIORITIES AND FINANCING STRATEGIES 4.1. Energy sector financing requirements- 1998-2002 .......................................... 121 4.2. The need for government guarantees .122 ANNEX 5: INSTITUTIONAL DEVELOPMENT AND REGULATION 5.1. Vietnam Energy sector organization ........................................ 128 5.2. EVN Organization ........................................ 129 5.3. Petrovietnam organization ........................................ 130 5.4. Vinacoal organization ........................................ 131 5.5. Power Sector Policy Statement ........................................ 132 5.6: Action Plan for Institutional Reform of the Power Sector ........................................ 136 ANNEX 6: AN AGENDA FOR ACTION 6.1. Energy Sector Policy Reform Agenda ........................................ 141 ANNEX 1. ECONOMIC GROWTH AND ENERGY DEMAND HISTORICAL ENERGY CONSUMPTION 1.1. Energy and the Economy ........................................................1 1.2. Population and Estimated GDP by Sector (1980-1995) ........................................................2 1.3. Consumption of Modem Energy (1980-1995) ........................................................3 1.4. Supplies of Modem Energy (1980-1995) ........................................................4 1.5. Consumption of Main Petroleum Products (1980-1995) .......................................................5 1.6. Production and Consumption of Natural Gas and Crude Oil (1980-1995) .................................6 1.7. Consumption of Coal (1980-1995) .................................7 1.8. Electricity Consumption (1980-1995) .................................8 1.9 Energy Balance and Commodity accounts 1995 .................................9 Graphs: 1.10. Consumption of modem energy- 1980-95 .10 ENERGY DEMAND FORECASTS 1.11. Forecast Population of Viet Nam ....................................................... 11 1.12. Macroeconomic Forecast for Base Case ....................................................... 12 1.12. Macroeconomic comparison with Thailand, Malaysia, Philippines, and Korea .................. 13 1.13. Base Year Prices of Key Energy Products ....................................................... 14 1.14. Forecast of Opportunity Value Energy Prices ....................................................... 15 1.15. Electricity Demand Forecasts for Three Scenarios ....................................................... 16 1.16. Electricity Demand Forecast under Efficiency Measures .................................................... 17 1.17. Energy Balance and commodity accounts 2005 ....................................................... 18 Demand forecastsfor Base case scenario 1.18. Summary of Electricity Demand for Viet Nam ....................................................... 19 1.19. Northern Region Electricity Demand ....................................................... 20 1.20. Hanoi Electricity Demand ....................................................... 21 1.21. Rural North Electricity Demand ....................................................... 22 1.22. Central Region Electricity Demand ....................................................... 23 1.23. Southern Region Electricity Demand ....................................................... 24 1.24. Ho Chi Minh City Electricity Demand ....................................................... 25 1.25. Rural South Electricity Demand ....................................................... 26 1.26. Petroleum Product Demand Forecast ....................................................... 27 1.27. Coal Demand Forecast ........................................................ 28 1.28. Gas Consumption Forecast ....................................................... 29 1.29. Summary of Modem Energy Consumption Forecast ....................................................... 30 Graphs 1.30. Population ....................................................... 31 1.31. Regional share of GDP ....................................................... 32 1.32. Sectoral share of GDP ....................................................... 33 1.33. Electricity demand forecast for scenarios ....................................................... 34 1.34. Electricity demand under efficiency measures ....................................................... 35 1.35. Base case electricity demand - by sector ....................................................... 36 1.36. Petroleum Product demand ....................................................... 37 1.37. Coal Demand ....................................................... 38 1.38. Natural Gas Demand Forecast ........................................................ 39 1.39. Diesel Conservation ....................................................... 40 1.40. Primary Modern Energy Forecast ....................................................... 41 1.41. Shares of Primary Energy Forecast ....................................................... 42 1.42. Modem Energy per US$000 GDP ....................................................... 43 1.43. Typical Composition of Energy Prices in Engergy sector ................................................... 44 Annex 1.1 Page 1 of I ENERGY AND THE ECONOMY 1990 1991 1992 1993 1994 1995 1996 1997 EXPORTS in US $ million TOTAL 1731 2042 2475 2985 4054 5198 7330 8955 ENERGY 428 629 803 914 941 1105 1461 1530 Crude oil 390 581 756 844 866 1024 1346 1419 Coal- 38 48 47 70 75 81 115 111 Energy/exports as % 25 31 32 31 23 21 20 17 IMPORTS TOTAL 1772 2105 2535 3532 5245 7543 10481 10313 ENERGY 356 485 615 614 696 856 1079 1094 Energy/Import as % 20 23 24 17 13 11 10 11 Net Energy contribution 72 144 188 300 245 249 382 436 Trade Balance (44) (65) (60) (547) (1196) (2345) (3153) (1358) Enery/trade balance 164 222 313 55 20 11 12 32 Source: Vietnam: Rising to the Challenge (December, 1998) - 1 - Annex 1.2 Page I of I POPULATION AND ESTIMATED GDP BY SECTOR IN VIET NAM (Trillion 89 Dong) 1980 to 1995 Gross National Approx Product Industry Annual Population Us$/Capita Year Agriculture (incI Constr) Other WB Adjust Total Change millions (199OUS$) 1980 6.672 3.407 2.993 4.705 17.776 53.722 148 1981 6.896 3.441 3.215 4.879 18.431 3.7% 54.927 150 1982 7.621 3.721 3.248 5.253 19.844 7.7% 56.170 158 1983 8.218 4.199 3.488 5.725 21.629 9.0% 57.376 169 1984 8.685 4.484 3.733 6.084 22.986 6.3% 58.770 175 1985 9.077 5.039 3.744 6.432 24.292 5.7% 59.872 182 1986 9.207 5.268 3.983 6.650 25.108 3.4% 61.109 184 1987 8.892 5.866 4.168 6.813 25.740 2.5% 62.452 185 1988 9.197 6.095 4.495 7.216 27.002 4.9% 62.910 192 1989 11.470 6.792 9.831 0 28.093 4.0% 63.367 199 1990 11.642 6.990 10.894 0 29.526 5.1% 66.200 200 1991 11.894 7.598 11.794 0 31.286 6.0% 67.800 207 1992 12.751 8.623 12.617 0 33.991 8.6% 69.400 220 1993 13.235 9.723 13.778 0 36.736 8.1% 71.026 232 1994 13.751 11.049 15.182 0 39.982 8.8% 72.510 247 1995 14.335 12.389 16.495 0 43.220 8.1% 73.900 262 AAG 1985/1990 na na na 4.0% 2.0% 1.9% AAG 1990/1995 4.3% 12.1% 8.7% 7.9% 2.2% 5.6% 1980 to 1988 is based on previous Net Material Product system, plus adjustment for depreciation and services . Population data, 1990 to 1995, from the PIP, 1996 - 2000, June 1996. The GDP in 1995 is estimated on basis of sectoral average growth rates in period 1990 to 1994. The June 1996 PIP document suggests that growth in 1995 was probably slightly higher, at just over 9% per year. Source: General Statistical Office and Mission estimates - 2 - Annex 1.3 Page 1 of 1 CONSUMPTION OF MODERN ENERGY IN VIETNAM 1980 to 1995 Total MODERN* Pet Products Nat Gas Coal Electricity ENERGY mill barrels bill cf 000tons GWh 000 TOE 1980 13.000 0.000 4052 2800 4812 1981 13.250 0.000 4509 2818 5179 1982 13.750 0.000 4983 2973 5596 1983 14.000 0.000 5015 3108 5633 1984 14.002 0.000 5010 3597 5653 1985 14.461 0.000 5083 3860 5761 1986 16.173 1.236 5500 4151 6325 1987 18.454 1.201 6139 4597 7097 1988 19.140 1.059 5808 5048 6965 1989 18.356 1.059 3801 5666 5507 1990 21.742 1.165 4039 6185 6224 1991 18.726 0.706 4602 6573 6283 1992 24.384 0.706 4445 6941 6977 1993 31.329 0.530 4473 7833 7973 1994 35.897 2.437 4757 9284 8942 1995 38.144 7.014 5069 11193 9692 AAG 1985/1990 8.5% -4.5% 9.9% 1.6% AAG 1990/1995 11.9% 43.2% 4.6% 12.6% 9.3% *lNote: Total Modem Energy includes conversion losses in use of oil, gas and coal but only hydro component of electricity to avoid double counting; gas products such as methanol are included in gas. Electricity is amount consumed. Source: Compiled by Mission -3 - SUPPLIES OF MODERN ENERGY IN VIET NAM 1980 to 1995 PETROLEUM COAL Total Self- Crude NATURAL GAS Total Electricity MODERN Supply Offshore Offshore Offshore Onshore Domestic Exports Generation ENERGY Ratio Production Prodts+Crude (flared) (Ba Ria) (Thai Binh) Production less Imports before losses SUPPLIES (exports) (Imports) mill barrels mill barrels bill cf bill cf bill cf 000tons 000tons GWh % Hydro 000 TOE 1980 0.0 13.0 0.000 0.000 0.000 4987 635 3559 42% 5306 76.1% 1981 0.0 13.3 0.000 0.000 0.000 5725 928 3726 40% 5671 80.9% 1982 0.0 13.8 0.000 0.000 0.000 6040 673 3974 39% 6170 78.3% 1983 0.0 14.0 0.000 0.000 0.000 6085 402 4125 30% 6352 75.3% 1984 0.0 14.0 0.000 0.000 0.000 4819 470 4779 33% 5465 72.1% 1985 0.0 14.5 0.000 0.000 0.000 5327 569 5065 29% 5796 73.9% 1986 0.3 16.6 0.250 0.000 1.236 5953 588 5527 25% 6540 73.4% 1987 2.1 18.8 1.500 0.000 1.201 6428 188 6050 23% 7480 71.9% 1988 5.1 19.5 4.125 0.000 1.059 6798 304 6783 26% 7857 78.4% 1989 11.2 18.7 10.524 0.000 1.059 3860 525 7792 49% 5939 89.6% 1990 20.0 22.1 19.070 0.000 1.165 4918 677 8679 62% 7446 102.8% 1991 29.0 19.1 28.500 0.000 0.706 5899 1135 9152 69% 7652 128.1% 1992 40.7 24.8 41.300 0.000 0.706 5888 1266 9652 75% 8531 135.8% 1993 46.7 31.7 44.500 0.000 0.530 6051 1335 10665 75% 9701 130.7% 1994 51.1 36.3 49.100 2.260 0.177 7091 2318 12284 75% 10730 134.2% 1995 58.6 38.5 60.500 6.590 0.424 8091 2735 14636 72% 11921 139.3% AAG 1985/1990 8.9% -1.6% 3.5% 11.4% 5.1% AAG 1990/1995 11.7% 10.5% 32.2% 11.0% 9.9% * Note: TOTAL MODERN ENERGY SUPPLIES are gross supply before losses and stock changes; but after exports and imports, and it includes all conversion losses in oil gas and coal, but only hydro component of electricity to avoid double counting; Petroleum product consumption in period 1980 to 1983 is estimated. Flared gas in 1986 and 1987 estimated. , Source: Compiled by Mission CD o - CONSUMPTION OF MAIN PETROLEUM PRODUCTS in VIETNAM (000 Barrels) 1980 to 1995 Petrol Kero Av Fuel Diesel Fuel Oil Other LPG TOTAL TOTAL 000 bbls mill Tons 1980 13,000 1.753 Est 1981 13,250 1.787 Est 1982 13,750 1.854 Est 1983 14,000 1.888 Est 1984 2,896.8 1,166.3 1,087.8 6,139.0 2,607.6 100.0 5.0 14,002 1.888 1985 2,938.1 1,203.0 614.5 6,280.8 3,319.4 100.0 5.0 14,461 1.964 1986 2,737.3 1,347.9 660.0 7,373.2 3,949.9 100.0 5.0 16,173 2.211 1987 3,586.4 1,433.7 949.7 8,109.3 4,264.9 100.0 10.0 18,454 2.509 1988 4,453.0 1,454.0 1,054.0 8,111.0 3,904.0 149.0 15.0 19,140 2.580 1989 3,882.0 2,111.0 872.0 7,334.0 3,767.0 370.0 20.0 18,356 2.476 1990 5,800.0 1,681.0 802.0 8,626.8 4,344.0 465.0 23.0 21,742 2.917 1991 4,278.3 1,474.5 623.2 7,868.8 4,002.6 439.2 39.6 18,726 2.530 1992 6,433.6 1,244.5 1,126.5 10,544.8 4,454.1 512.4 68.3 24,384 3.269 1993 7,913.7 1,604.4 1,368.2 14,562.7 5,119.2 585.6 174.8 31,329 4.196 1994 9,877.5 1,887.8 1,769.8 16,402.5 4,972.9 695.4 291.3 35,897 4.773 1995 10,693.1 3,025.5 1,527.0 16,184.1 5,559.1 805.2 349.5 38,144 5.062 AAG 1985/1990 14.6% 6.9% 5.5% 6.6% 5.5% 36.0% 35.7% 8.5% AAG 1990/1995 13.0% 12.5% 13.7% 13.4% 5.1% 11.6% 72.3% 11.9% (p 3 Note: Other Products are estimated for 1984 to 1986, and TOTAL for 1980 to 1983 x Diesel and FO do not include amounts going to the power sector Source: Energy Institute, and Petrolimex, and Mission estimates Annex 1.6 Page 1 of I PRODUCTION AND CONSUMPTION OF NATURAL GAS AND CRUDE OIL IN VIETNAM 1980 TO 1995 Natural Gas Crude Oil Offshore Offshore Refin Year Estimated Estimated Estimated Gas to Ba Ria Onshore (eXDort) Cons Production Flared Gas used Losses/Comp Elect (elect gen) (Bach Ho + Dai Hung) at Fields Own Use Gen to ThaiBinh mill b/yr Mill b/yr 1.00% 20.00% of Production of Raw Gas Raw Gas Raw Gas Raw Gas Liquids, etc Dry Gas Dry Gas mill cf/yr mill cf/yr mill cf/yr mill cf/yr mill cf/yr mill cf7yr 1980 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.00 1981 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.00 1982 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.00 1983 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.00 1984 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.00 1985 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.00 1986 250.0 247.5 2.5 0.0 0.0 1,236.0 0.30 0.39 1987 1,500.0 1,485.0 15.0 0.0 0.0 1,200.7 2.07 0.39 1988 4,125.0 4,083.8 41.3 0.0 0.0 1,059.4 5.11 0.39 1989 10,524.0 10,418.8 105.2 0.0 0.0 1,059.4 11.23 0.39 1990 19,070.0 18,879.3 190.7 0.0 0.0 1,165.4 19.98 0.39 1991 28,500.0 28,215.0 285.0 0.0 0.0 706.3 29.01 0.39 1992 41,300.0 40,887.0 413.0 0.0 0.0 706.3 40.70 0.39 1993 44,500.0 44,055.0 445.0 0.0 0.0 529.7 46.69 0.39 1994 49,100.0 45,783.8 491.0 565.0 2,260.1 176.6 51.06 0.39 1995 60,500.0 51,657.8 605.0 1,647.4 6,589.7 423.8 58.61 0.39 Sums 259,369 245,713 2,594 2,212 8,850 8,264 265 4 Source: Energy Institute, Petrovietnam, Vietsovpetro, Mission estimates - 6 - CONSUMPTION OF COAL IN VIET NAM (O0Otons/year, of clean coal) 1980 to 1995 TOTALS CONSUMPTION BY INDUSTRIAL ACTIVITY Consumption OTHER EST TOTAL Electricity IN MAIN DOMESTIC LOCAL ALL Year Generation Cement Chem/Fert Railway Textile Paper Machin Food INDUSTRIES Cons/losses Prod/Cons CONS 1980 1,281 110 196 97 51 10 52 83 1,880 2,172 4,052 1981 1,440 147 130 49 66 64 45 95 2,035 2,474 4,509 1982 1,570 229 173 43 73 81 49 82 2,300 2,683 4,983 1983 1,766 278 198 139 77 94 46 125 2,721 2,295 5,015 1984 1,703 326 201 182 85 125 37 191 2,849 2,162 5,010 1985 1,960 364 182 44 80 113 34 149 2,927 2,156 5,083 1986 2,297 460 196 89 89 149 40 133 3,452 2,048 5,500 1987 2,503 340 237 105 96 152 38 127 3,598 2,542 6,139 1988 2,858 397 333 100 82 155 31 102 4,058 1,284 466 5,808 1989 1,968 402 240 42 91 121 32 85 2,979 365 457 3,801 1990 1,560 521 217 34 81 130 29 68 2,639 700 700 4,039 1991 962 582 450 20 97 161 130 na 2,402 1,500 700 4,602 1992 654 585 391 11 160 124 120 na 2,045 1,700 700 4,445 1993 519 603 435 11 93 186 126 na 1,973 1,800 700 4,473 1994 837 593 430 8 96 165 128 na 2,257 1,800 700 4,757 1995 1,009 629 425 8 111 186 200 na 2,569 1,800 700 5,069 AAG 1985/1990 -4.5% 7.4% 3.5% -4.9% 0.2% 2.8% -3.2% -14.5% -2.1% -4.5% AAG 1990/1995 -8.3% 3.8% 14.4% -24.7% 6.6% 7.4% ?? -0.5% 4.6% Note: The Other Domestic Consumption/losses are estimated to roughly balance consumption in Viet Nam with supplies available. Source: Energy Institute, MOI, and Mission estimates -x o Annex 1.8 Page I of I ELECTRICITY CONSUMPTION IN VIET NAM (GWhlyr Sales) 1980 to 1995 Year Industry Residential Agricultural Other TOTAL 1980 2,800 estimated 1981 1,516 691 316 295 2,818 1982 1,658 717 246 352 2,973 1983 1,754 763 237 354 3,108 1984 2,031 843 308 415 3,597 1985 2,108 985 303 464 3,860 1986 2,204 1,094 331 522 4,151 1987 2,383 1,243 387 584 4,597 1988 2,579 1,332 449 688 5,048 1989 2,617 1,880 470 699 5,666 1990 2,845 2,035 587 718 6,185 1991 3,069 2,052 809 643 6,573 1992 3,197 2,163 975 606 6,941 1993 3,476 2,520 1,144 693 7,833 1994 3,944 3,130 1,360 849 9,284 1995 4,614 4,043 1,526 1,010 11,193 AAG 1985 - 90 6.18% 15.62% 14.13% 9.12% 9.89% AAG 1990 - 95 10.15% 14.72% 21.06% 7.06% 12.60% Source: Energy Institute, MOI - 8- ENERGY BALANCE FOR VIET NAM, 1995 Coal in Vietnam Crude Oil GaSoline Aviation Turb Kersene Oesel Heusy Fuel Oil LPG Other Petrolesre On shor Ga fshr Hydr-o Eetct o fuel I Pedocts todigeoan Prdootto 3095 hhI 0 I __________ 0 0 __________ 0 __________ 0________T__ tO 145 24450 2615 Ff..eand Loss -T40 5 0 0 0 0 6 0 -1276 0 0 -1426 Gas Injeckon ________ 0 0 0 0 0 0 0 0 0 0 0 0 -15 ImPorts 0 40 1296 199 395 2227 710 32 184 0 0 0 0 5164 Exports -1475 -7991 0 -65 o 0 0 0 0 0 0-93 Bonkers 0 0 0 0 0 0 0 0 0 0 0 h h ______ Stock Change 0 0 0 0 0 0 0 0 0 O0 Other SupplV y 0 0 0 0 0 0 0 0 0 0 372 PrimaryuEnergySnpp2 y | 2733l 4 1296 134 59 0 104 j0 204 2645 Dj l06o %AllPrimaryEnergy 25.6% 0.4% 12.1% 1.3% 3.7% 20.8% 7.4% 03% 1.7% 01% 9% 24 1000 ChaTeoal production 0 DiG 0 0 0 0 0l 0 0 0l 0 0 PetholetmRefining 40 _ 3 10 20 0 0 0 0 ° GasManufacture 0 0 a 0 0 0 0 0 0 0 0 0 Power Generatioa Us.Tul Energy 171 0 0 - ° °10 -7 0 0 D 6 -892 1234 0 Losses 0 ° n ° -31 -166 0 0 -10 781 -1753 0 -2411 Trans and DitstLosses I 0 0 6 ol 0 6 0 0 4 029-0 Owninse/LanCs 6 -61000 0 0 0 0 01 -292 Om Um I Losses 0 0 0 -20 0 0 03 29 OtherConvermion1 0 6 0 6 0 60 0 .. 028 0 OlherConwrniono 00 0 0 l 0 0 0 0 0 0 0 D 0 | Net SupplyAvailable gD| 302981 34 | ° 944 | %NetSupply Available 27.5% 0.D% 16.4% 1.7% 5.0% 27.7% 7.0% 0.4% 2.3% 0.0% 0.0% 0.0% 11.9% 100.0% ResidenmtaiCommerclal 13431 0 0 6 399 0 a 34 0 0j0 0 341 2115 industry 647 0 0 0 6 1161 612 6 9 0 a 0 389 2944 Transport 0 0 1302 135 0 1103 33 0 0 0 0 0 0 26731 Agricottune 0 0 0 0 0 6 9 0 0 o a 6 0 al OtherConsumption 0 6 9 - 0 0 14 0 0 o - 0 214 22el Non-Energy Ues 9 0 D 0 0 0 0 0 184 0 0 0 0 1841 OtherConsumpionl 6 01 01 0 0 0 0 0 0 0 0 0 6 oltmrConnamlton2 0 0l 0l ol 01 ol ol9ol 01 0l ol 0 ol 0 0 o Total Consumptlon 2189 13023 1 14 . Stat. DW. 2.2204SE-16 7.28584E-17 0 0 -2.77S6E-17 -2.2204E-16 -S.5511E-17 0 0 0 -8.3287E-17 0 D 0 % Alt Secondary Energy 27.5% 0.0% 16.4% 1.7% S.0% 27.7% 7.0% 0.4% 2.3% 0.0% 0.0% 0.0% 11.9% 100.0% Commodity Account 'Jielnam ICoal is telnom ICrode OIl Gasoline iAvialiosTalk IKerosene ~ Dieset -lenny FuelOil ILPG jOther Peroteom {Ooshoro Gas gOffokore Gas gHydra |Etotedncy - 1995 I Ithoo Ootomotie PnodoG5 Und 000 ton 000 bbl 000 bbl 600 bbl 000 l 000 60 bb 000 bbl 000 bbl Mill di Mill cf GvVlh GWh Category COAL PETRO PETRO PETRO PETRO PETRO PETRO PETRO PETRO NATGAS NATGAS ELEC ELEC PrnmaryEnergy 0.639215586 0.136344106 0.121222507 0.130592776 0.130692778 0.137630 0.142171672 0.091222755 0.228225348 0.023042102 0.62470779B 0.25 0.25 Secondary Energy 0.S39215688 0.136344155 0.121222607 0.130592778 0.130592778 0.137935 0.142171672 0.091222755 0.228225348 0.023042102 0.024707796 0.084299 0.084299 Indigoenous Preodion 7391 58610 0 0 0 0 0 0 0 423.a 60500 10581.9 0 Flare and Loss -277 0 0 0 0 0 0 0 0 0 -51657.8 0 0 Gas injecton 0 0 0 0 0 0 0 0 0 0 -605 0 0 Imports 0 293 106593. 1627 3025.6 16184.1 5569.1 349.6 805.2 0 0 0 0 EPpods -2735 -56610 0 -600 0 0 0 0 0 0 0 0 0 Bunkes 0 0 0 0 0 ° 0 0 0 0 0 0 Stock Change 0 0 0 0 0 0 0 0 0 0 0 0 0 Other Supply 1 690 0 0 0 0 0 0 0 0 0 C 0 0 Other Supply 2 0 0 O 0 0 0 0 0 0 0 0 0 0 PrmaryEnergy S.ppyy 5069 293 10693.1 1027 3025.6 16184.1 5559.1 349.5 805.2 423.8 8237.2 10581.6 0 Charcoal Pnduction 0 0 0 0 0 0 0 0 0 0 0 0 0 Peroleum Refining 0 -293 50 10 20 130 70 20 0 0 0 0 0 Gas Manufacture 0 0 0 0 0 0 0 0 0 0 0 0 0 Fuel to Power -1009 0 0 0 0 -300 -1700 0 0 -423.0 -9099.7 -10581.8 0 Power Ge,raled GVh 2028.2 0 0 0 0 120.4 900 0 0 2 1003.7 10581.8 14636.1 Trans and Dist Losses 0 0 0 0 0 0 0 0 0 0 -1647.5 0 -3105 Ow Use YLosses 0 0 0 0 0 0 0 0 0 0 0 0 -333 Othor Convenrsion 0 0 0 0 0 0 0 0 0 0 0 D 0 Other Convesion 2 0 0 0 0 0 0 0 0 0 0 0 0 0 Net SupplyyAailabel 4060 0 10743.1 1037 3045.5 16014.1 3929.1 369.5 905.2 0 0 0 11198.1 Residentiallcommn,rce 2490 0 0 0 3040.0 0 0 369.5 0 0 0 0 4046 W Industry 1670 0 0 0 0 8000 3600 0 0 0 6 0 4619.1 TransD0 0 10743.1 1037 0 014.1 229.1 0 0 0 0 0 0 C0 Agricultural 0 0 0 0 0 0 0 0 0 0 0 0 Olher Consumption 0 0 0 0 0 0 1°0 0 0 0 2533 _ Non-Energy Use 0 0 0 0 0 0 0 0 805.2 0 0 0 0 Other Consumplionf 0 0 0 0 0 0 0 0 0 0 0 0 0 Other Consumption 2 0 0 0 0 0 0 0°0 0 0 0 Total Consumption 4060 0 10743.1 1037 3045.5 16014.1 3929.1 369.5 605.2 0 0 0 11198.1 Statit. Di 0 0 0 0 0 0 0 o 0 0 0 0 |CONSUMPTION OF MODERN ENERGY (Primary Energy) L in VIETNAM 1980 to1995 12,000 10,000 U 8000 -=- 6,000 _ ~ 4,000 O .... . .............. 1960 1961 1982 1963 1964 1985 1966 1987 1968 1989 1990 1991 1992 1993 1994 1995 Years -o POPULATION OF VIETNAM (millions) i~u iIP~ un iou ion iou zoo~ zooi u~a z~o au~ s 11M1_ 228! 2Xfe 2GC 888 20C5 nuna z12 S _ ZEA Z Northem Region 31.2 31.8 32.5 33.2 33.8 34,5 35.2 35.9 38.7 37.4 38.2 38.9 39.6 40.4 41.1 41.8 42.5 43.2 43.9 44.6 45.3 48.0 48.8 47.2 47.8 48.5 Urban 4.4 R=S 28.8 Cermial Region 0.0 9.2 9.4 9.6 9.8 10.0 10.2 10.4 10.8 10.8 11.0 11.3 11.5 11.7 11.9 12.1 12.3 1Z5 12.7 12.9 13.1 13.3 13.5 13.6 13.8 14.0 Urban 1.5 Rur 7.5 Soulhem Region 28.5 27.1 27.8 28.2 28.8 29.4 30.0 30.6 31.2 31.8 32.5 33.1 33.7 34.3 35.0 35.8 38.2 38.8 37.4 37.9 38.5 39.1 39.7 40.2 40.7 41.2 Urban 7.5 Rurl 19.0 TOTAL POPULATION 88.030 08.050 89.479 70.938 72.392 73.852 75.301 78.e91 78.452 80.044 1.009 83.327 04.827 88.354 87.908 89.490 91.101 92.572 93.90 95.432 98.920 98.432 99.732 101.048 102.382 103.733 Main Chios (etknalted He Nol 2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.9 3.0 3.1 3.3 3R4 3.6 3.8 4.0 4.2 4A 4.8 4.9 5.1 0.3 506 5.8 0.0 0.3 Hal "Pom 1.5 1. 1.0 1.7 1.8 1.9 2.0 2.0 2.1 2.2 2.3 2.5 2.8 2.7 2.8 3.0 3.1 3.3 3.5 3.0 3.8 4.0 4.2 4.3 4.5 4.7 QuOng Nam-Do Nang 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.9 3.0 3.1 3.3 3.5 3.0 3.8 4.0 4.2 4.4 4.0 4.8 5.0 5.2 5.4 Ho ChliMin 4.1 4.2 4.4 4.0 4.8 5.1 5.3 5.5 5.8 8.1 0.4 0.7 7.0 7.4 7.7 8.1 8.5 .09 94 9.9 10.3 10.9 11.3 11.8 12.2 12.7 HoChilMAneoo s 4.0 4.2 4.4 4.0 4.8 5.0 5.2 S.5 5.7 6.0 6.3 0.0 0.9 7.3 7.6 8.0 8.4 8. 9.3 9.7 10.2 10.7 11.1 11.9 12.1 12.5 TOTAL MAIN CTIES 13.3 13.9 14.5 15.2 15.9 18.8 17.3 18.2 19.0 18.9 20.9 21.8 22.9 24.1 25.3 28.6 27.9 29.3 30.7 323 33S 35s 37.0 38.5 40.0 41.0 POP EX MAIN CITIES 53.3 54.1 54.9 55.0 S6.5 57.3 58.0 58.7 59.4 60.1 80.0 61.6 61.9 02.3 82.6 02.9 03.2 03.2 63.2 032 03.0 02.0 62.7 82.6 62.3 82.1 Percent 80.0% 79.6% 70.1% 78.8% 78.1% 77.6% 77.0% 76,4% 75.8% 75.1% 74.5% 73.8% 73.0% 72.1% 71.2% 70.3% e9.4% 68.4% 87.3% ee2% 08.0% 03.0% 02.9% 81.9% 80.9% 69.9% EdL Total PopgroAh 2.10% 2.10% 2.10% 2.05% 2.03% 2.03% 2.03% 2.03% 2.03% 2.03% 2.03% 1.80% 1.80% 1.80% 11.0% 1.80% 1.50% 11.5% 1.81% 1.06% 1.56% 1.32% 1.32% 1.32% 1.32% 1.32% Es. Urn Pop Wolh 450% 4.50% 4.50% 4.580 4.80% 4.50% 4.75% 4.75% 4.75% 4.75% 4.73% 500% 5.00% 500% 5.00% 5.00% 5.0D% 5.00% 5.00% 5.00% 5.00% 4.00% 4.00% 4.00% 4.00% 4.00% ReAtIr RuralPopOP rlh 1.50% 1.50% 1.48% 1.47% 1.38% 1.34% 1.31% 122% 1.19% 1.10% 1.13% 1.10% 0.60% 0.81% 0.50% 0.51% 046% 0.04% -0.03% 40.11% -020% .0.20% -20% .0.20% -0.33% -R0A% FFn Years Two yea he Year FIften Yars 1991 101995 109D t101997 1998 to 2000 200110 2010 TdOpoPAllsn 289% 2.03% 2.03% 1.61% Urban 4.50% 4.02% 4.7J% 4.71% Rural 1.43% 127% 1.18% 0.14% Turnd toWoMd PoptF_0n Prqft5nW, A Word Bank 8ook.1994 1880. _Q X -o 0 _ Annex 1.12 Page 1 of 2 ECONOMIC GROWTH FORECAST VIET NAM Case B NORTHERN REGION - HANOI + RURAL GDP Growth Rates 1991-95 1996-1997 1998-2000 2001-2015 ForecstAvge Percent of Regional Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agrnculture 3.71% 3.90% 300% 3.50% 3.4% 42.34 36.10 31.49 18.60 Constr 25.99% 13.87%b 6.88% 9.88% 9.2% 3.49 7.86 9.20 13.35 Industry 10.70% 11.00% 6.78% 9.00% 8.5% 16.88 19.93 22.10 28.39 Trade/other 6.38% 7.65% 6.35% 7.65% 7.3% 37.29 36.10 37.20 39.65 Percent of Viet Nam Economy NORTH 7.08% 7.5% 5.4% 7.2% 6.7% 38.21 36.55 34.81 33.40 GOP HANOI GDP Growth Rates 1991-95 19956-1997 1998-2000 200t-2015 Forecst Avge Percent of Local Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agriculture 4.56% 4.00% 3.00% 3.50% 7.22 5.86 4.93 2.54 Constr 11.46% 13.00% 6.00% 9.00% 5.19 5.80 6.28 7.02 Industry 10.82% 11.00% 6.00% 9.00% 23.84 25.87 27.02 30.24 Tradelother 8.58% 8.00% 6.00% 8.00% 63.75 62.47 61.77 60.20 Percent of Viet Nam Economy Hanoi GDP 9.02% 8.9% 5.8% 8.2% 7.6% 6.01 6.29 6.22 6.85 RURAL GDP Growth Rates NORTH 1991-95 1996-1997 1998-2000 2001;-201 Forcat Avgs Percent of Local Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agriculture 3.69% 3.90% 3.00% 3.50% 48.90 42.39 37.27 22.75 Constr 29.33% 14.00% 7.00% 10.00% 3.17 8.29 9.84 14.98 Industry 10.66% 11.00% 7.00% 9.00% 15.58 18.70 21.03 27.92 Trade/other 5.53% 7.50% 6.50% 7.50% 32.35 30.62 31.86 34.35 Percent of Viet Nam Economy Rural North 6.70% 7.2% 5.3% 7.0% 6.5% 32.20 30.26 28.59 26.54 CENTRAL REGION GDP Growth Rates 1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Regional Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agriculture 0.65% 3.50% 3.00% 3.00% 3.0% 46.58 37.22 32.69 20.97 Constr 15.80% 10.00% 8.00% 9.00% 8.8% 3.80 6.12 7.00 10.50 Industry 7.62% 7.00% 7.00% 7.00% 7.0% 19.39 21.66 22.79 25.89 Trade/other 8.40% 8.00% 7.00% 7.00% 7.0% 30.23 35.00 37.52 42.64 Percent of Viet Nam Economy CENTRAL 5.27% 6.3% 5.7% 6.1% 5.9% 11.06 9.72 9.12 7.49 GDP SOUTHERN REGION - HCMC + RURAL GDP Growth Rates 1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Regional Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agriculture 1.53% 3.39% 3.00% 3.49% 3.4% 37.76 26.14 20.60 11.05 Constr 18.84% 16.00% 8.00% 8.79% 8.6% 2.21 3.36 3.85 4.37 Industry 15.95% 14.50% 7.69% 8.83% 8.6% 26.92 36.20 39.99 45.69 Trade/other 10.05% 12.00% 7.00% 8.52% 8.2% 33.11 34.29 35.56 38.89 Percent of Viet Nam Economy SOUTH 9.28% 10.9% 6.4% 7.9% 7 5% 50.73 53.73 56.07 59.11 GDP HO CHI GDP Growth Rates MIN 1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Local Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agriculture 1.16% *3.00% 3.00% 3.00% 3.85 2.38 1.76 0.84 Constr 22.58% 16.00% 8.00% 9.00% 3.71 6.00 6.50 7.25 Industry 12.90% 14.50% 7.10% 8.50% 35.98 38.57 39.68 41.32 Trade/other 9.96% 12.00% 7.00% 8.00% 56.46 53.04 52.06 50.59 Percent of Viet Nam Economy HCMC GDP 11.34% 13.0% 7.0% 8.2% 7.9% 14.87 17.29 19.06 21.06 RURAL GDP Growth Rates SOUTH 1991-95 1996-1997 1998-20W0 2001-2015 ForecstAvge Percent of Local Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agriculture 1.54% 3.40% 3.00% 3.50% 51.82 37.42 30.31 16.70 Constr 14.72% 16.00% 8.00% 8.50% 1.59 2.11 2.48 2.78 Industry 17.75% 14.50% 8.00% 9.00% 23.16 35.07 40.16 48.11 Trade/other 10.13% 12.00% 7.00% 9.00% 23.43 25.39 27.05 32.41 Percent of Viet Nam Economy Rural South 8.37% 9.9°h 6.1% 7.7% 7.2% 35.86 36.43 37.00 38.06 - 12- Annex 1.12 Page 2 of 2 TOTAL ECONOMY VIETNAM Case 1 Vietnam GDP Growth Rates 1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Viet Nam Economy Actual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015 Agnculture 2.3% 3.7% 3.0% 3.4% 3.3% 40.49 30.86 25.49 14.32 Constr 22.0% 14.2% 7.4% 9.4% 8.9% 2.87 5.28 6.00 7.83 Industry 13.8% 13.1% 7.4% 8.8% 8.5% 22.25 28.84 32.20 38.43 Trade/other 8.4% 10.0% 8.8% 8.1% 7.8% 34.39 35.02 36.31 39.42 TOTAL ECON 8.05% 9.24% 6.00% 7.50% 7.07% 100.00 100.00 100.00 100.00 Approx GDP per Capita 894.26 VN Notes: est GDP level in 1992 18 billion US$ GDP in 1990 istherefore 14.99 billion US$, 92.761 in2015 Pop in 1990 66.7 million 66.7 check Pop in 1995 73.9 million Pop in 2015 is about 103.73 GDP Growth Rates Thailand 1965-80 1970-1980 1980-1991 Percent of Thai Economy Historical Historical 1965 1970 1980 1991 Agriculture 4.6% 4.4% 3.8% 32.00 26.00 23.00 12.00 Constr (in Ind) Industry 9.5% 9.5% 9.6% 23.00 25.00 29.00 39.00 Trade/other 7.4% 7.2% 8.0% 45.00 49.00 48.00 49.00 TOTAL ECON 7.30% 7.10% 7.90% 100.00 100.00 100.00 100.00 GNP per capita (US$/person) 1,570 Source: WB World Development Report GDP Growth Rates Malaysia 1965-80 1970-1980 1980-1991 Percent of Malaysian Economy Historical Historical 1965 1970 1980 1991 Agriculture na 4.9% 3.7% 28.00 29.00 22.00 17.30 Constr (in Ind) Industry na 9.6% 7.7% 25.00 25.00 38.00 43.80 Trade/other na 8.3% 4.7% 47.00 46.00 40.00 38.90 TOTAL ECON 7.40% 7.90% 5.70% 100.00 100.00 100.00 100.00 GNP per capita (US$/person) 2,520 Source: WB World Development Report, and ADB Asian Development Outlook GDP Growth Rates Philippines 1965-80 1970-1980 1980-1991 Percent of Philippines Economy Historical Historical 1965 1970 1980 1991 Agriculture 3.9% 4.0% 1.1% 26.00 29.00 25.00 21.00 Constr (in Ind) Industry 7.7% 8.2% -0.5% 27.00 32.00 39.00 35.00 Tradelother 5.0% 5.1% 2.8% 47.00 39.00 36.00 44.00 TOTAL ECON 5.70% 6.00% 1.10% 100.00 100.00 100.00 100.00 GNP per capita (US$/person) 730 Source: WB World Development Report, and ADB Asian Development Outlook GDP Growth Rates Korea 1965-80 1970-1980 1980-1991 Percent of Korean Economy Historical Historical 1965 1970 1980 1991 Agriculture 3.0% 2.7% 2.1% 38.00 26.00 15.00 8.00 Constr (in Ind) Industry 16.4% 15.2% 12.1% 25.00 29.00 40.00 45.00 Trade/other 9.6% 8.8% 9.3% 37.00 45.00 45.00 47.00 TOTAL ECON 9.90% 9.60% 9.60% 100.00 100.00 100.00 100.00 GNP per capita (US$/person) 6,330 Source: WB World Development Report, and ADB Asian Development Outlook - 13 - Annex 1.13 Page 1 of 1 VIET NAM Case B BASE YEAR PRICES OF KEY ENERGY PRODUCTS 1996 DOLLARS INTERNATIONAL CIF PRICES OR SUPPLY PRICES 1995 mill cal/ Cents/ Price unit mill kcal Crude Oil US$/B 25.00 1,512 1,653 Diesel US$/B 31.00 1,463 2,119 Heavy Fuel Oil US$/B 23.00 1,532 1,501 Nat Gas (cost) US$/mcf 1.90 252 754 LNG US$/mcf 3.45 252 1,369 Int Coal US$/ton 46.00 6,000 767 Dom Coal (north) US$1ton 25.00 5,500 455 Dom Coal (south) US$/ton 39.00 5,500 709 PARAMETERS AND CONVERSION FACTORS (Parameters with * are "driving" parameters) crude 1512 mill cal/B Diesel 1463 mill cal/B Heavy Fuel Oil 1532 mill cal/B MCF gas 252 mill cal/MCF MCF equiv 0.167 B crude oil Int Coal 6000 mill cal/ton Vietnam Coal 5500 mill cal/ton INTERNATIONAL FOB PRICES OR SUPPLY PRICES 1995 FOB Price Linkage Ratios * Deliv Costs* Crude Oil * 20.00 US$/B 5 /B Diesel 26.00US$/B Diesl/crude 1.3000 5 /B Heavy Fuel Oil 18.00 US$/B HFO/Crude 0.9000 5 /B Nat Gas Cost * 1.90 US$/mcf % growth/yr 2.00% /mcf LNG (delivered) 3.45 US$/mcf LNG/HFO 0.1500 /mcf Int Steam Coal 36.00 US$/ton Coal/HFO 2.0000 10 /ton Coal Costs north * 23.00 US$/ton % growth/yr 2.00% 2 /ton Coal Costs south * 23.00 US$/ton % growth/yr 2.00% 16 /ton OTHER ASSUMPTIONS (PARAMETERS) Effective Exchange Rate * 11000 d/US$ Escalation in Oil Price 1.00% per yr - 14 - VIET NAM Case B VIET NAM Case B FORECAST OPPORTUNITY VALUE PRICES FOR ENERGY PRODUCTS FORECAST OPPORTUNITY VALUE PRICES FOR VIETNAM ENERGY ______________________________ __ PRODUCTS Crude Oil Diesel Fuel Natural LNG Int Domestic Coal in US Cents per Million Kilo Calories (1996 Dollars) Oil Gas Coal north south Cost Fob Cif Cif Cif at Ba Cif Cif Cif Cif Crude Diesel Fuel Natural LNG Int Domestic Coal Ria End (1996 Dollars --without inflation) End Oil Oil Gas Coal north south Year US$/bbl US$/bbl US$/bbl US$/bbl US$/ton Year Cif Cif Cif in Cif Cif Cif Cif US$/mcf US$/mcf US$/ton US$/ton South 1995 20.00 25.00 31.00 23.00 1.90 3.45 46.00 25.00 39.00 1995 1653 2119 1501 754 1369 767 455 709 1996 20.20 25.20 31.26 23.18 1.94 3.48 46.36 25.46 39.46 1996 1667 2137 1513 769 1380 773 463 717 1997 20.40 25.40 31.52 23.36 1.98 3.50 46.72 25.93 39.93 1997 1680 2155 1525 784 1391 779 471 726 1998 20.61 25.61 31.79 23.55 2.02 3.53 47.09 26.41 40.41 1998 1694 2173 1537 800 1402 785 480 735 1999 20.81 25.81 32.06 23.73 2.06 3.56 47.46 26.90 40.90 1999 1707 2191 1549 816 1413 791 489 744 2000 21.02 26.02 32.33 23.92 2.10 3.59 47.84 27.39 41.39 2000 1721 2210 1561 832 1424 797 498 753 2001 21.23 26.23 32.60 24.11 2.14 3.62 48.21 27.90 41.90 2001 1735 2228 1574 849 1435 804 507 762 2002 21.44 26.44 32.88 24.30 2.18 3.64 48.60 28.42 42.42 2002 1749 2247 1586 866 1446 810 517 771 2003 21.66 26.66 33.15 24.49 2.23 3.67 48.98 28.95 42.95 2003 1763 2266 1599 883 1458 816 526 781 2004 21.87 26.87 33.44 24.69 2.27 3.70 49.37 29.49 43.49 2004 1777 2285 1611 901 1469 823 536 791 2005 22.09 27.09 33.72 24.88 2.32 3.73 49.77 30.04 44.04 2005 1792 2305 1624 919 1481 829 546 801 2006 22.31 27.31 34.01 25.08 2.36 3.76 50.16 30.60 44.60 2006 1806 2324 1637 937 1493 836 556 811 2007 22.54 27.54 34.30 25.28 2.41 3.79 50.57 31.17 45.17 2007 1821 2344 1650 956 1505 843 567 821 2008 22.76 27.76 34.59 25.49 2.46 3.82 50.97 31.75 45.75 2008 1836 2364 1664 975 1517 850 577 832 2009 22.99 27.99 34.89 25.69 2.51 3.85 51.38 32.35 46.35 2009 1851 2385 1677 995 1529 856 588 843 2010 23.22 28.22 35.19 25.90 2.56 3.88 51.79 32.95 46.95 2010 1866 2405 1690 1015 1542 863 599 854 2011 23.45 28.45 35.49 26.11 2.61 3.92 52.21 33.57 47.57 2011 1882 2426 1704 1035 1554 870 610 865 2012 23.69 28.69 35.79 26.32 2.66 3.95 52.63 34.21 48.21 2012 1897 2446 1718 1056 1567 877 622 876 2013 23.92 28.92 36.10 26.53 2.71 3.98 53.06 34.85 48.85 2013 1913 2468 1732 1077 1579 884 634 888 2014 24.16 29.16 36.41 26.75 2.77 4.01 53.49 35.51 49.51 2014 1929 2489 1746 1098 1592 892 646 900 2015 24.40 29.40 36.72 26.96 2.82 4.04 53.93 36.18 50.18 2015 1945 2510 1760 1120 1605 899 658 912 2016 24.65 29.65 37.04 27.18 2.88 4.08 54.37 36.86 50.86 2016 1961 2532 1774 1143 1618 906 670 925 2017 24.89 29.89 37.36 27.40 2.94 4.11 54.81 37.56 51.56 2017 1977 2554 1789 1166 1631 913 683 937 2018 25.14 30.14 37.69 27.63 3.00 4.14 55.26 38.27 52.27 2018 1994 2576 1803 1189 1645 921 696 950 2019 25.39 30.39 38.01 27.86 3.06 4.18 55.71 38.99 52.99 2019 2010 2598 1818 1213 1658 929 709 964 AAG to 2010 1.00% 0.81% 0.85% 0.79% 2.00% 0.79% 0.79% 1.86% 1.25% o X > Annex 1. 1 5 Page 1 of I Cases B, A and C Electricity Forecasts, 1997 to 2010 Base Low High Case B Case Case Case with Case B Case A Case C prices up to LRMC Year Demand Demand Demand Demand MW MW MW MW 1990 1,546 1,546 1,546 1,546 1991 1,638 1,638 1,638 1,638 1992 1,744 1,744 1,744 1,744 1993 1,934 1,934 1,934 1,934 1994 2,260 2,260 2,260 2,260 1995 2,714 2,714 2,714 2,714 1996 3,161 3,161 3,161 3,161 1997 3,585 3,585 3,585 3,585 1998 3,942 3,807 4,012 3,942 1999 4,363 4,067 4,521 4,350 2000 4,779 4,298 5,039 4,734 2001 5,343 4,718 5,719 5,244 2002 5,939 5,152 6,455 5,757 2003 6,617 5,638 7,303 6,335 2004 7,340 6,143 8,226 6,941 2005 8,195 6,739 9,325 7,655 2006 9,114 7,363 10,536 8,408 2007 10,163 8,069 11,932 9,261 2008 11,358 8,863 13,547 10,222 2009 12,690 9,735 15,372 11,281 2010 14,123 10,650 17,389 12,401 - 16- Annex 1.1 6 Page 1 of I Case B Electricity Forecast and variations, 1997 to 2010 No Loss Loss Reduction Program, and Reduction Base with Prices LRMC Case non-price up to Prices DSM LRMC and by 2002 DSM Year Demand Demand Demand Demand Demand MW MW MW MW MW 1990 1,546 1,546 1,546 1,546 1,546 1991 1,638 1,638 1,638 1,638 1,638 1992 1,744 1,744 1,744 1,744 1,744 1993 1,934 1,934 1,934 1,934 1,934 1994 2,260 2,260 2,260 2,260 2,260 1995 2,714 2,714 2,714 2,714 2,714 1996 3,161 3,161 3,161 3,161 3,161 1997 3,585 3,585 3,585 3,585 3,585 1998 3,942 3,942 3,942 3,942 3,942 1999 4,377 4,363 4,358 4,350 4,348 2000 4,838 4,779 4,762 4,734 4,727 2001 5,425 5,343 5,304 5,244 5,229 2002 6,058 5,939 5,867 5,757 5,731 2003 6,802 6,617 6,506 6,335 6,297 2004 7,568 7,340 7,182 6,941 6,888 2005 8,499 8,195 7,981 7,655 7,583 2006 9,496 9,114 8,833 8,408 8,316 2007 10,667 10,163 9,803 9,261 9,145 2008 11,921 11,358 10,902 10,222 10,077 2009 13,396 12,690 12,123 11,281 11,103 2010 14,974 14,123 13,427 12,401 12,186 - 17 - if t ~~* I 1 1- . . . . .f . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .- 1.}°~~~~~~~~~~~~~~~ II II II LI~ I U Li _ I H H H~~~~~~~~~~~~~~~~~~~~~~C II II H~~~~~~~~ II II ii..naAa ~~o~oo~o~ oooo~~oooo~~ Li LI Li H~~~~~~~~~ . ...C t3 ~ ~ ~ ~ - I1 o~~~oooLo Iooooooe,i~~~~~~~~~~~~~~~~~, !ooo~~~~~~~~oL~~~~,o ~~~l AlflF ......... ..... .. ..... 0 .. . . .0 . ~ j0 L I'l XQUUV~~~~~~~~~~~~I I VIET NAM Case B SUMMARY OF ELECTRICITY DEMAND FORECASTS - ALL REGIONS GENERATION REQUIREMENTS ALALES LOQSSFACETGIQ Average Total End-Use Elctdcity Annual ANNUAL SALES NET NON-TECH TECH ENERGY Demand MAXIMUM CONSUMPTION Elastidty ELECTRICrrY DEMAND BY CATEGORY (OWvAH) DEMAND IN REGIONAL GENERATION Load DEMAND PER CAPrTA of Sales FISCAL OTHER/ UNSERVED NON-TECH GROWTH COUNTRY TRANSFERS DEMAND Factor POP KWFVYR/ wrt YEAR INDUSTRY RESIDENT SER55851 DEMAND LOSSES -TOTAL 9 GviH GVltH % S GvVl l% MVi .E15 PERSON GDP 1990 2845.0 2035.0 1304.8 217.7 508.4 6910.9 6,185 0.0 5.9% 22.9% 8676.6 64.21% 1545.8 66.7 100.3 1991 3069.1 2051.6 1453.0 43.2 518.2 7135.1 3.2% 6,574 0.0 5.7% 22.5% 9152.8 64.00% 1638.1 68.1 104.2 0.84 1992 3196.9 2163.4 1580.5 133.5 545.1 7619.4 6.8% 6,941 0.0 5.6% 22.4% 9651.4 63.42% 1744.4 69.5 107.7 0.72 1993 3476.4 2520.4 1836.6 68.4 594.2 8496.1 11.5% 7,833 0.0 .6% 21.0% 10665.3 63.23% 1934.2 70.9 118.8 1.60 1994 3943.8 3130.4 2209.4 45.0 617.5 9946.2 17.1% 9,284 0.0 5.0% 19.4% 12285.6 62.67% 2260.3 72.4 136.7 2.22 1995 4619.4 4046.4 2532.2 29.1 722.9 11949.9 20.1% 11,198 0.0 4.9% 18.6% 14636.2 62.49% 2714.4 73.9 161.3 2.38 1996 5377.9 4999.4 2966.2 0.0 750.6 14094.0 17.9% 13,343 0.0 4.4% 16.8% 16949.1 62.07% 3161.1 75.4 186.9 209 1997 6163.4 5831.1 3308.7 0.0 8464 16149.6 14.6% 15,303 0.0 4.4% 15.7% 19146.4 61.84% 3585.1 76.9 209.9 1.57 1998 6739.9 6506.4 3712.8 0.0 934.1 17893.4 10.8% 16,959 0.0 4.4% 15.4% 21146.1 62.10% 3941.9 78.5 227.9 1.82 1999 7372.0 7270.1 4167.9 0.0 1031.7 19841.7 10.9% 18,810 0.0 4.4% 15.1% 23379.6 61.66% 4363.5 80.1 247.7 1.82 2000 8065.0 8135.4 4680.4 0.0 1132.6 22013.3 10.9% 20,881 0.0 4.4% 14.4% 25706.3 61.25% 4778.8 81.7 269.3 1.83 2001 8968.5 9187.1 5251.8 0.0 1265.5 24672.8 12.1% 23,407 0.0 4.4% 14.1% 28730.7 61.36% 5342.5 83.0 297.1 1.68 2002 9974.4 10375.8 5893.3 0.0 1412.4 27655.9 12.1% 26,243 0.0 4.4% 13.8% 32071.0 61.50% 5938.7 84.4 327.8 1.67 2003 11094.5 11719.3 6613.8 0.0 1427.2 30854.7 11.6% 29,428 0.0 4.0% 13.5% 35678.9 61.59% 6616.9 65.7 359.9 1.67 2004 12341.8 13238.2 7422.6 0.0 1595.8 34598.7 12.1% 33,003 0.0 4.0% 13.3% 39895.8 62.29% 7340.0 87.1 397.2 1.66 2005 13731.1 14955.4 8331.4 0.0 1779.6 38797.6 12.1% 37,018 0.0 4.0% 12.8% 44491.2 61.94% 8195.2 88.5 438.3 1,65 2006 15278.6 16897.1 9351.9 0.0 1986.8 43514.4 12.2% 41,528 0.0 4.0% 12.4% 49670.2 62.26% 9114.5 89.9 483.8 1.64 2007 17002.5 19092.8 10498.2 0.0 2213.1 48806.6 12.2% 46,593 0.0 4.0% 11.8% 55328.5 62.00% 10163.3 91.4 534.1 1.63 2008 18923.2 21576.0 11785.7 0.0 2483.3 54768.3 12.2% 52,285 0.0 4.0% 11.8% 62083.5 62.57% 11357.8 92.8 589.9 1.63 2009 21063.4 24384.8 13232.2 0.0 2771.4 61451.7 12.2% 58,680 0.0 4.0% 11.3% 69284.8 62.52% 12689.8 94.3 651.4 1.62 2010 23448.3 27562.1 14857.1 0.0 3096.2 68963.8 12.2% 65,868 0.0 4.0% 10.9% 77406.2 62.89% 14123.3 95.9 719.4 1.61 2011 26106.4 31156.7 16682.8 0.0 3460.2 77406.2 12.2% 73,946 0.0 4.0% 10.5% 86504.8 62.88% 15807.0 97.4 794.7 1.61 2012 29069.3 35224.0 18734.1 0.0 3868.0 86895.4 12.3% 83,027 0.0 4.0% 10.1% 96700.7 63.53% 17568.5 99.0 878.1 1.60 2013 32372.1 39826.5 21039.1 0.0 4343.8 97581.5 12.3% 93,238 0.0 4.0% 10.1% 108595.3 63.39% 19753.5 100.6 970.4 1.60 2014 36054.4 45035.3 23629.3 0.0 4878.8 109597.9 12.3% 104,719 0.0 4.0%h 10.1% 121971.0 63.76% 22095.6 102.2 1072.7 1.59 2015 40160.3 50931.1 26540.1 0.0 5480.6 123112.0 12.3% 117,631 0.0 4.0% 10.1% 137014.2 63.68% 24850.3 103.8 1185.9 1.59 AAG90-1995 10.2% 14.7% 14.2% 7.3% 11.6% 12.6% 11.0% 11.9% AAG 96-1997 15.5% 20.0% 14.3% 8.2% 16.3% 16.9% 14.4% 14.9% MG 98-2000 9.4% 11.7% 12.3% 10.2% 10.9% 10.9% 10.3% 10.1% AAG2001-15 11.3% 13.0% 12.3% 11.1% 12.2% 12.2% 11.8% 11.6% AAG96-2015 11.4% 13.5% 12.5% 10.7% 12.4% 12.5% 11.8% 11.7% AAG98-2010 10.8% 12.7% 12.2% 10.5% 11.8% 11.9% 11.3% 11.1% Resulting overall elasticity of dernand for genertion with respect to totea GDP, in the period 1998 to 2010, is 1.60 Resultirng overall elasticity of Electricity Sales wilh respect to total GDP, in the period 1998 to 2010, is 1.68 e > 0 O - - 00 VIET NAM Case B NORTHERN REGION ELECTRICITY DEMAND FORECAST Results of Regional Forecast GDP Growth Rates GDP Elasticities InlUial Population (millons) 1991-95 1099-1997 1998-2000 2001-2015 Forecst Avge 1991-95 1996-1997 1998-2000 2001-2015 Pop in 1990 % Rural Adtuals Aduals Ranal 20.8 8509% Agricltare 3.7% 3.9% 3.0% 3.5% Total 31.2 Constr 26.0% 13.9% 6.9% 9.9% Industry 10.7% 11.0% 6.8% 9.0% Tnade/other 6.4% 7.6% 6.4% 7.7% ResuRing Eleoctdity sales GDP NORTH 7.1% 7.5% 5.4% 7.2% 6.7% to regional GDP 1.30 1.96 1.73 1.60 Population Growth Uroan 4.5% 4.6% 4.8% 4.7% Runal 1.4% 1.3% 1.2% 0.1% Total 2.1% 2.0% 2.0% 1.6% Res Mvs Use per vr In 1990 Growth in Use per Consumer 2.000 3.0% 3.0% 3.0% 3.0% GENERATION REQUIREMENTS LOSS FACTORS ENERGY LOAD IN REGION ANNUAL SALES Non Tech Tech Required TRANSFER GENERATION Demand PEAK ELECTRICITY DEMAND IN REGION, BY CATEGORY (GEm) DEMAND IN for REGION TO OTHER IN Load Demand FISCAL OTHERI UNSERVED NON-TECH REGION GROWTH REGION REGIONS REGION Factor YEA INDUSTRY RESIDENT SERVICES DEMAND LOSSES TOTAL % __gm % _W GvH G. H .V% MW 1990 1468.0 055.7 838.2 94.0 313.0 3570.5 3161.9 7% 28% 4798.8 69.2 4068.0 68.2% 8274 1991 1433.8 884.7 961.8 23.0 340.3 3644.2 2.1% 3280.3 7% 26% 4861.1 260.8 5121.9 6508% 8431 1992 1460.5 897.9 1059.2 64.8 354.6 3842.0 5.4% 3422.9 7% 25% 5065.3 349.5 5414.8 65.3% 885.0 O 1993 1514.9 1003.5 11956 19.0 371.7 4101.7 08.% 3714.0 7% 23% 5309.5 441.0 5750.5 65.0% 932.9 1994 1624.9 1178.2 14388 10.9 3472 4000.0 12.1% 4241.9 6% 21% 5787,0 1379.0 7166.0 644% 1025.2 1095 1883.4 1498 2 1563.8 9.1 412.3 5330.9 16.0% 4915.4 6% 22% 6872 2 2500.0 9372.2 64.1% 1224.1 1996 2050.5 1822.0 1848.5 0.0 303.0 9084 0 14.0% 5721.6 5% 16% 7260.9 2849.8 10107.7 63.8% 1300.1 1997 2300.0 2043.0 2060.0 0.0 402.7 9865.7 12.8% 9403.0 5% 15% 8054.9 2820.0 10874.9 93.8% 1441.1 1998 2536.3 2224.3 23037 0.0 441.5 7505.0 9.3% 7064.3 5% 15% 8830.4 2810.0 11940.4 94.2% 1570.9 1999 2725.7 24218 2576.3 0.0 4828 82060 9.3% 7724.0 5% 15% 9650.1 1140.0 10795.1 64.3% 17154 2000 2929.5 2639 8 2802.0 0.0 521.5 8969.7 9.3% 8448.2 5% 14% 10429 9 -800.0 9929.9 64.6% 1842.5 2001 3217.4 2954.9 3243.0 0.0 501.2 9999.2 11.4% 9415.0 5% 14% 11923.5 -490.0 11193 5 64.6% 2052.5 2002 3533.0 3310.8 3049.3 0.0 647.8 11141.5 11.5% 1049398 0% 14% 12955.3 -1730.0 11225.3 64.9% 2279.1 2003 3880.9 3710.0 4109.7 00 570.0 12298.2 101% 11007.6 4% 14% 14265.4 -890.0 13375.4 64.9% 2510.8 2004 4202.3 4157 3 4621.5 00 035 2 13677.3 11.5% 13041.1 4% 14% 15993.5 330.0 19233.0 5.5% 2770.4 2005 4681 3 4658.6 5200.9 0.0 709.3 15250.1 11.5% 14540.8 4% 14% 17732.6 -1940.0 15792.6 65.5% 3090.2 2006 5141.4 5220.3 5853.1 00 781.4 169963 11.5% 19214.8 4% 13% 19535.9 -1140.0 18395.9 65.8% 33913 2007 56498 5849.8 6507.2 0.0 071.5 18955.3 115% 18083.8 4% 13% 217877 -3220.0 18507.7 05.7% 3780.6 2008 6201.8 6555.3 7413.5 0.0 972.1 21142.7 11.5% 20170.7 4% 13% 24302.0 -470.0 23032.0 66.0% 4203.9 2009 6611.5 73455 03430 0.0 10t44 23505.4 7.65% 23501.0 41% 13% 27109.7 -180.0 26929.7 66.0% 4691.0 2010 7481.1 0231 7 9390 9 00 1195.4 29299 0 11.5% 25103.6 4% 12% 29885.3 860.0 30745.3 69.2% 0151.3 2011 8216.5 9224.4 105697 0.0 13101 29328.7 115% 20010.0 4% 11% 32953.0 1340.0 342936 66.2% 5981.7 2012 9024.2 10330.9 11896.0 0.0 1453.9 32711.0 11.5% 31257.0 4% 10% 36346.3 7220.0 43506.3 66.7% 6220.4 2013 9911.4 116037 13390.5 00 1622.6 365082 11.6% 340056 4% 10% 405646 6490.0 47054.6 667% 6943.7 2014 10855.0 12980.8 15072.2 00 1811 1 407500 11.6% 38938.9 4% 10% 45277.8 85300 530078 67.0% 7720.1 , ;> 2015 11955.7 14546.6 16955.6 00 2021.0 45490.0 11.6% 434602 4% 10% 50544.4 7750.0 50294.4 66.9% 0619.3 PO AAG 90-1995 51% 114% 133% 56% 8.4% 9.2% 7.4% 14.0% 8.A% AAG 96-1997 119% 16.0% 14.6% -1.2% 134% 14.7% 0.3% 7.7% 805% MAG 98-2000 7.5% 89% 11 8% 90% 9.3% 9.3% 9.0% -4.0% 6.5% MAG 2001-15 9.8% 121% 125% 95% 114% 115% 11.1% 12.8% 10.8% AAG 96-2015 9.7% 12.1% 12.7% &.3% 113% 11.5% 10.5% 96% 10.3% Note Peak Load in Region is ralculaled from generatlon required to sONve tho demand in the region VIET NAM Case B HANOI PC ELECTRICITY DEMAND FORECAST Parameters f9r Frorecalino Lo[g-Ron GDP Grooth Rates GDP Elasticities Proe Elasticitv Initial Populatlon (millions) 1991-95 1996-1997 1998-2000 2001-2015 ForecstAvge Linkfrom Linkto 1801-gs 1998-1997 199D-2000 2001-2015 (negative) Pop i1990 4.8% A.t..hc Actuals Rural 0.1 4.8% Agriculture 4.6% 4.0% 3.0% 3.5% Total 2.1 Constr 1105% 13.0% 6.0% 90% Industry 10.8% 11.0% 6.0% 9.0% IndGDP Industry 0.41 1.11 1.05 1.05 0.6 Trade/other 8.6% 8.0% 6.0% 6.0% Trade/O GDP Other/Services 1.74 1.59 1.50 1.40 096 GDP HANOI 9.0% 8.9% 5.8% 8.2% 7.6% GDP Residential 1.20 2.20 1.50 1.50 0.8 Populatlon Growth Urban 4.5% 4.6% 4.8% 4.7% Residental 2.40 4.22 1.85 2.60 0.5 Rural 1.4% 1.3% 1.2% 0.1% Total 2.1% 2.0% 2.0% 1.6% Res MWh/ Use per yr in 1899 Growth In Use per Consumer 25000 3.0% 3.0% 3.0% 3.0% GENERATION REQUIREMENTS LOSS LOAD IN FACTO,RS ENERGY ANNUAL SALES NON-TECH TECH Required TRANSFER Generation Demand PEAK ELECTRICITY DEMAND IN REGION, BY CATEGORY (GWH) DEMAND IN for REGION TO OTHER IN Load Demand FISCAL OTHER/ UNSERVED NON-TECH REGION GROWTH REGION REGIONS REGION Factor YEAR INDUSTRY RESIDENT SERVICES DEMAND L,OSSE5 TOTAL % GWH % % GWH GWH GWH % MW 1990 249.8 427.9 125.7 45.4 79.7 828.3 803.2 7% 28% 1219.0 - - 58.0% 239.9 1991 291.1 444.2 214.2 7.6 98.5 1055.6 13.7% 849.5 7% 28% 1407.1 - - 58.0% 276.9 1992 238.0 412.3 235.7 7.0 91.8 905.6 -5.8% 888.0 7% 25% 1311.2 - 57.7% 259.4 1993 210.7 468.6 269.3 13.5 94.9 1057.0 7.2% 948.6 7% 23% 1356.1 - 57.6% 268.8 1994 260.3 568.6 266.1 10.9 89.6 1195.5 13.1% 1095.0 6% 21% 1493.9 - - 56.5% 301.8 1998 309.8 714.3 251.8 9.1 107.0 1392.1 16.4% 1275.9 6% 22% 1783.9 - - 55.5% 368.9 1996 324.5 810.7 284.0 0.0 96.4 1615.6 16.1% 1519.2 5% 16% 1927.9 - - 54.5% 404.1 1997 390.0 1020.0 320.0 0.0 107.8 1837.8 13.6% 1730.0 5% 15% 2156.0 - 54.7% 449.9 1998 414.6 1109.4 349.8 0.0 117.0 1989.8 8.3% 1872.8 5% 15% 2341.0 - - 55.1% 485.3 1999 440.7 1206.7 380.2 0.0 126.7 2154.3 8.3% 2027.5 5% 15% 2534 - - 55.0% 526.0 2000 468.5 1312.4 414.4 0.0 135.5 2330.8 8.2% 2195.3 5% 14% 2710.2 - 55.4% 558.8 2001 512.7 1473.6 460.8 0.0 151.1 2598.2 1'.5% 2447.1 0% 14% 3021.1 - 55.3% 823.9 2002 561.2 1654.5 512.4 0.0 168.4 2896.5 11.5% 2728.1 5% 14% 3368.1 - 55.6% 691.5 2003 614.2 1807.7 560.8 0.0 148.4 3190.1 10.1% 3041.7 4% 14% 3709.4 - 55.5% 763.1 2004 672.2 2085.8 633.8 0.0 160.4 3557.1 11.5% 3391.7 4% 14% 4136.2 - 56.0% 843.6 2000 730.8 2341.9 704.6 0.0 184.5 3966.8 11.0% 3782.3 4% 14% 4612.5 - 55.9% 942.5 2006 805.3 2629.4 783.5 0.0 203.3 4421.5 11.5% 4218.3 4% 13% 5082.2 56.2% 1032.4 2007 681.4 2952.3 871.3 0.0 226.7 4931.7 11.5% 4705.0 4% 13% 5668.6 - 56.1% 1153.6 200 9864.7 3314.8 96890 0.0 252.9 5501.3 11.5% 5248.3 4% 13% 6323.3 - 56.4% 1279.3 2009 1055.9 3721.8 1077.4 0.0 282.2 6137.2 11.6% 5855.0 4% 13% 704.3 - 56.3% 1429.6 2010 115506 4178.8 1198.1 0.0 311.1 6043.5 11.5% 6532.5 4% 12% 7776.7 56.7% 1566.7 2011 1264.8 4691.9 1332.2 0.0 343.0 7632.0 11.5% 7288.9 4% 11% 8575.2 56.6% 1730.4 2012 1384.4 5268.0 1481.4 0.0 378.3 8512.1 11.5% 8133.8 4% 10% 94579 - 57.0% 1894.7 2013 1515.2 5914.8 1647.4 0.0 422.2 9499.6 11.6% 90774 4% 10% 10555.1 - 56.9% 2117.0 2014 1698.4 6941.1 1831.9 0.0 471.2 10602.5 11.6% 10131.3 4% 10% 1170.6 - - 57.2% 2349.6 2015 1815.1 7456.5 2037.0 0.0 526.0 11834.6 11.6% 11308.6 4% 10% 13149.6 - - 57.1% 2626.7 AAG 90-1995 4.4% 10.8% 14.9% 6.1% 6.4% 9.7% 7.9% 0.9% AAG 6-1997 12.2% 19.5% 12.7% 0.4% 14.9% 16.4% 9.9% 10.7% MAG 98-2000 8.3% 68.% 900% 7.9% 8.2% 8.3% 7.9% 7.5% AAG2001-15 .5% 12.3% 11.2% 9.5% 11.4% 11.5% 11.1% 10.9% MG 96-2015 9.2% 12.4% 11 0% 8.3% 11.3% 11.5% 10.5% 10.3% Note: Peak Load in Reglon is catculated from generation required tv serve the domand in the region t0: VIET NAM Case B RURAL NORTH PCI ELECTRICITY DEMAND FORECAST Parametes for Forecasting GDP Growth Rat- Long-Run GOP Growth Rates GDP Elastociies E !t!01J959.9y Initial Populabon (millions) 1991-95 1996.1997 199862000 2001-2015 ForecstAvge jmnkfrm LinktO 1991-95 1996-1997 1998.2000 2001-2015 (negative) Pop in 1990 % Rual Artuals Acruals Rural 28.7 91.8% Agnwlture 3.7% 3.9% 3.0% 3.5% Total 29.1 Constr 29.3% 14.0% 7.0% 10.0% Industry 10.7% 11.0% 7.0% 9.0% Ind GOP Industry 0.49 1t0o 1.10 1.10 0.6 Tdadavother 5.5% 7.9% 6.5% 7.5% Trade/OGDP Other/Services 2.35 2.02 1.90 1.70 0.6 GDP RURAL N 8.7% 7.2% 5.3% 7.0% 6.5% GDP ResIdential 1.79 2.28 1.70 1.70 0.5 Population Growth Urban 4.5% 4.6% 4.8% 4.7% Residential 2.67 3.56 1.89 2.91 0.5 Ruml 1.4% 1.3% 1.2% 0.1% Total 2.1% 2.0% 2.0% 1.8% Res MWI Use per vr In 1990 Growth In Use per Consumer 2.000 3.0% 3.0% 3.0% 3.0% GENERATION REQUIREMENTS LOSS FACTOR ENERG LOAD IN REGION ANNUAL SALES NON-TECH TECH Required TRANSFER Genenation Demand PEAK ELECTRICITY DEMAND IN REGION, BY CATEGORY (GWrt) DEMAND IN for REGION TO OTHER IN Load Dereand FISCAL OTHER/ UNSERVED NON-TECH REGION GROWrH REGION REGIONS REGION Factor YEA INDUSTRY RESIQEN I S3RIMCES DEMAND LOSSES TOTA GWH % G GWH GGW % M 1990 1218.4 427.8 712.5 494 234.1 2642.2 2358.7 7% 28% 35798 - 69.0% 592.2 1991 1142.7 440.5 747.9 16.0 241.8 2588.6 -2.0% 2330.8 7% 26% 3454.1 69.0% 571.4 1992 1227.5 485.6 823.5 57.0 262.8 2000.4 10.3% 253696 7% 25% 3754.0 - - 6.0% 630.2 1993 1304.2 534.9 926.3 2.6 276.7 3044.7 686% 2765.4 7% 23% 3953.4 - - 67.5% 66896 1994 1364.6 609.6 1172.7 0.0 257.6 3404.5 11.8% 3146.9 6% 21% 4293.2 - - 67.2% 729.3 1995 1573.5 753.9 1312.0 0.0 305.3 3944.8 15.9% 3939.5 6% 22% 5088.4 - - 67.1% 865.7 1996 1726.0 911.9 1594.5 0.0 266.6 4469.0 13.3% 4202.3 5% 16% 5332.9 - 67.1% 907.1 1997 1970.0 1023.0 1740.0 0.0 294.9 5027.9 12.5% 4733.0 5% 15% 5898.6 - - 67.1% 1003.1 1998 2121.7 1114.9 1954.9 00 324.5 5516.0 9.7% 5191.5 5% 15% 6489.4 - - 97.4% 1098.3 1999 2285.1 1215.1 2196.3 0.0 356.0 9052.5 9.7% 5696.5 5% 15% 7120.6 - - 67.5% 1203.5 2000 2461.0 1324.3 2467.8 0.0 366.0 6639.9 97% 6252.9 5% 14% 7719.6 - - 67.9% 129B.5 2001 2704.6 1491.1 27822 0.0 430.1 7398.0 11.4% 6997.9 5% 14% 8602.3 9 67.9% 1445.5 2002 2972.4 1956.3 3136.9 0.0 4794 8245.0 11.4% 7795.6 5% 14% 9597.2 - - 6892% 1905.8 2003 3296.7 1892.4 3536.9 00 422.2 9079.1 10.1% 8655.9 4% 14% 10556.0 _- 98.1% 1756.2 2004 3590 1 2071.6 3987.8 0.0 470.7 10120.2 11.5% 9649.5 4% 14% 11767.6 - - 68.9% 1949.9 2005 3945.5 2316.7 4490.3 0.0 524.8 11283.3 11.5% 10758.5 4% 14% 13120.1 - 58.9% 2174.0 2005 4336.1 2590.9 5099.5 0.0 578.1 12574.7 11.4% 11996.5 4% 13% 14453.7 - - 69.1% 2387.0 2007 4765.4 2897.6 5715.9 0.0 644.0 14023.6 11.5% 13378.8 4% 13% 16119.1 - - 69.1% 2661.9 2009 5237.1 3240.5 64447 00 719.1 156415 11.5% 14922.3 4% 13% 17978.7 6 9.4% 29592 2009 5755.6 3624.0 7206.4 0.0 802.2 17448.2 11.6% 16646.0 4% 13% 20055.4 6 9.4% 3300.7 2010 6325.4 4052.9 8192.8 00 884.3 19455.5 115% 185712 4% 12% 22108.5 - _ 69.6% 3626.6 2011 6951.7 4532.5 9237.4 0.0 975.1 21696.7 11.5% 207216 4% 11% 24378.4 - - 09.6% 3998.4 2012 79399 5069.0 10415.2 0.0 10755 24199.5 11.5% 23124.0 4% 10% 26858.4 - 70.1% 4377.5 2013 8396.2 50689 11743.1 0.0 1200.4 27008.6 116% 25808.2 4% 10% 30009: - 70.1% 4884.6 2014 9227.4 0339 8 13240.4 00 1339.9 30147.5 11 6% 29807.6 4% 10% 33497.2 - 70 4% 5434.1 2015 10141 0 7090 1 14928.5 0.0 1455.8 33655.3 11.6% 32109.5 4% 10% 37394.0 -8 - 70.4% 6064.9 > MG 90-1995 5.2% 12.0% 13.0% 5.5% 83% 9.1% 73% 79% u MG 96-1997 11 9% 16.5% 15.2% -1 7% 12.9% 14.0% 7.7% 7.6% CD CD AAG 98-2000 7 7% 90% 12.4% 9.4% 9.7% 9.7% 9.4% 9.0% AAG 2001-15 9.9% 110% 12.8% 95% 11.4% 11 .5% 11.1% 10.8% AAG 96-2015 9.5% 11.5% 129% 0.3% 11.5% 11.0% 10.5% 102% Note. Peak Load in Region is calculated from generali.nr reqire to0 servo the demand m the m.ogn VIET NAM Case B CENTRAL REGION PC3 ELECTRICITY DEMAND FORECAST Parameters for Forecasng, an4 Resets of R.glonal Forecast Long-Run GDP Grawth Rates GDP EIestIclOos r Eli9 0iIxnatal Populalo (0961090) 1991-95 1996-t997 1990-2000 2001.2015 Forecst Avge .nk.1 Lnkto 1991-95 1996.1997 1998-2000 2001-2015 (negatcH) Pop in 1999 e Ral Actuals Artuals Rural 7. 5 S3.6% Agrdcuttum 0.7% 3.5% 390% 3.0% Total 9.0 Constr 15.8% 10.0% 8.0% 9.0% Irdustry 7.6% 7.0% 7.0% 7.0% Ind GOP Industry 1.20 2.31 1.50 1.40 0.0 Tradeother 8.4% 8.0% 7.0% 7.0% TradelO GDP O_ter/SerAles 2.04 2.09 2.50 1.90 0.6 GOP CENTRAL 5.3% 6.3% 5.7% 8.1% 5.9% GDP Redldential 4.54 3.74 3.93 2.50 Resulting eleddtlty sales to Reginal GDP 3.49 3.31 3.21 2.28 0.5 Population Growth Uroan 4.5% 4.6% 4.8% 4.7% Residertlal 5.32 5.06 4.70 3.23 0.5 Rural 1.4% 1.3% 1.2% 0.1% Total 2.1% 2.0% 2.0% 1.0% Res MW1v Use mr Yr In 1 9J0 Growth In UWe per Consumer 1.5w0 3.0% 3.0% 3.0% 3.0% GENERATION REQUIREMENITS LOSS FALCTORS ENB LOAD IN REGION ANNUAL SALES NON-TECH TECH RequIrd TRANSFER GENERATION Demand PEAK ELECTRICITY DEMAND IN REGION, BY CATEGORY (G0vH) DEMAND IN for REGION TO OTHER IN Load Demand FISCAL OTHERI UNSERVED NON-TECH REGION GROWTH REGION REGIONS REGION Fador YEAR INDUSTRY REBIDET MM= DEMAND LOSSES TOTAL _ % _ __Gv Gw -H -% _MW 1990 179.4 162.5 92.3 7.7 28.8 470.6 434.2 5% 20% 575.1 -218.0 357.1 61.0% 107.6 1991 187.2 174.9 107.0 1.8 31.1 501.8 6.6% 489.1 5% 20% 821.4 -384.0 237.4 61.0% 116.3 1992 195.0 219.9 118.9 17.7 35.4 587.9 17.2% 534.8 5% 20% 708.6 -484.0 224.6 60.5% 133.7 1993 221.6 253.5 153.0 5.7 41.7 676.3 15.0% 628.9 5% 20% 833.2 -086.2 247.0 60.0% 159.5 1904 253.7 350.5 178.9 13.4 51.0 848.1 25.4% 782.8 5% 20% 1038.4 -762.0 276.4 59.0% 200.9 1995 284.1 474.9 251.4 3.7 51.0 1065.1 25.6% 1010.3 4% 17% 1275.1 -900.0 375.1 58.0% 251.0 1965 338.3 587.6 304.5 0.0 61.2 1291.6 21.3% 1230,4 4% 18% 1530.7 -1000.0 530.7 57.9% 301.5 1997 383.4 723.1 365.7 0.0 72.4 1544.6 19.6% 1472.2 4% 15% 1811.0 -1320.0 491.0 57.6% 359.2 1998 423.7 884.6 429.7 0,0 04.8 1822.7 18.0% 1738.0 4% 14% 2119.5 -1030.0 489.5 57.S% 421.1 1999 468.1 1082.2 504.9 0.0 100.3 2155.4 18.3% 2055.2 4% 14% 2506.3 -1390.0 1116.3 57.0% 502.2 2000 517.3 1323.9 593.3 0.0 117.3 2551.7 18.4% 2434.4 4% 13% 2933.0 1130.0 4093.0 53.9% 586.3 2001 008,0 1525.5 672.2 0.0 133.3 2898.9 13.6% 2765.6 4% 13% 3332.1 690.0 4022.1 56.7% 670.5 2002 623.7 1757.9 761.5 0.0 149.7 3292.7 13.6% 3143.1 4% 12% 3741.8 260.0 4001.8 56.9% 750.2 2003 8e4.8 2025.6 862.8 0.0 170.2 3743.4 13.7% 3573.2 4% 12% 4253.9 -270.0 3983.9 55.7% 055.8 2004 751.9 2334.2 977.6 0.0 193.5 4257.2 13.7% 4003.7 4% 12% 4837.7 -760.0 4077.7 57.2% 900.9 2005 025.8 2689.7 1107.8 0.0 220.1 4843.1 13.8% 4622.9 4% 12% 5503.5 440.0 5063.5 57.0% 1102.5 2006 800.0 3099.4 1254.9 0.0 250.5 5511.4 13.8% 0260.8 4% 12% 6262.9 -200.0 6002.9 57.2% 1249.5 2007 995.3 3571.6 1421.8 0.0 261.08 270.5 13.8% 5988.7 4% 11% 7045.5 80.0 7125.5 57.0% 1410.1 2008 1092.8 4115.6 1610.9 0.0 320.9 7140.3 13.9% 6819.4 4% 11% 8022.8 -000.0 7122.8 57.3% 1598.9 2009 1199.9 4742.5 1825.2 0.0 305.5 8133.2 13.9% 7767.6 4% 11% 9138.4 -990.0 8148.4 57.1% 1828.7 2010 1317.5 5464.9 2067.0 0.0 410.5 0266.9 13.9% 8800.4 4% 11% 10412.2 -2270.0 8142.2 57.4% 2072.0 2011 1446.7 6297.3 2343.0 0.0 474.7 10561.6 14.0% 10087.0 4% 11% 11867.0 -3740.0 8127.0 57.2% 2309.3 2012 1588.4 7256.6 2654.6 0.0 541.2 12040.7 14.0% 11499.6 4% 11% 13528.9 .3870.0 9658.9 57.6% 2682.8 2013 1744.1 8321.9 3007.7 0.0 617.1 13730.8 14.0% 13113.0 4% 11% 15427.8 4220.0 11207.8 57.4% 3067.7 2014 1915.0 9035.0 3407.7 0.0 703.9 15002.2 14.1% 14958.3 4% 11% 17598.0 -6400.0 11198.0 57.7% 3482.5 2015 2102.7 11103.3 3060.9 0.0 803.1 17870.1 14.1% 1706.89 4% 11% 20078.7 -8910.0 11168.7 57.5% 3983.6 MG 9D-1995 9.6% 23.9% 22.2% 12.1% 17.7% 18.4% 17.3% 1.0% 18.5% MG 96-1997 18.2% 23.4% 20.6% 19.2% 20.4% 20.7% 19.2% 14.4% 19.6% MG 99-2000 10.5% 22.3% 17.5% 17.4% 18.2% 18.3% 17.4% 102.3% 17.9% MG 2001-15 9.8% 15.2% 13.3% 13.7% 13.9% 13.9% 13.7% 7.0% 13.6% CD MG 00-2015 10.5% 17.1% 14.6% 14.8% 15.1% 15.2% 14.8% 18.5% 14.8% Note: eak Lod in Rgion i 0lwlaed fro genemion mqimd towme lh deman in th regi0 - Note: Peah Lead in Region is onlooloted from genoomlIen rmelreund to serve the demand in the region VIET NAM Case B SOUTHERN REGION ELECTRICITY DEMAND FORECAST R rOI of ReOOD Freca,t GDP GreSM Rates GOP E laOe InItral Populaion (nri4m) 191.95 1990-1917 19984000 2001-2015 Forect Avge 1991-5 1998-19W7 1W06-2000 2001-2015 Pop in 10 % Rural Actuclo ~~~~~ ~ ~~~~ ~~~~~~~~~~~Rural la.4 806.4% Agaudre 1.5% 3.4% 3.0% 3.5% Total 26.5 Conotr 18.8% 16.0% 8.0% 0.8% Industry 15.9% 14.5% 7.7% 8.8% TradeIother 10.0% 12.0% 7.0% 8.5% Resulot GEGd48y Salos GDP SOUTH 9.3% 10.9% 6.4% 7.9% 7.5% to reginl GOP 1.68 1.61 1.87 1.53 Population Gmwth Urban 4.5% 4.8% 4.8% 4.7% Rural 1.4% 1.3% 1.2% 0.1% Tota 2.1% 2.0% 2.0% 1.6% Res MWV UNe o vr In I0 Growt h Use rfer Corowmw 2.000 3.0% 3.0% 3.0% 3.0% GENERATION REQUIREMENTS LO 8sFACTORS LOADINREGioN ANNUAL SALES NON-TECH TECH Required TRANSFER GENERATION Demnd PEAK ELECTRICITY DEMAND IN REGION. BY CATEGORY 11WF4 DEMAND IN for REGION TO OTHER IN Load Demand FISCAL OTHERI UNSERVED NON-TECH REGION GROWTH REGION REGIONS REGION Factor YEM IN DY RESI D T ERIC EMAN LOSSES T AL % _ % % M v Gym % 1900 1197.6 1016.8 374.3 115.3 105.8 2569.8 2588.7 5% 17% 3302.8 148.8 3451.6 01.7% 610.7 1991 1448 1 02.0 3842 18.0 146.8 2989.1 4.2% 2824.3 4% 19% 3670.3 1232 3793.5 61.7% 878.7 1092 15354 1045.6 402.4 51.0 1551 3189.5 6.7% 2083.4 4% 19% 3877.6 134.5 4012.1 61.0% 72S.8 1903 1739.9 1203.4 487.2 48.7 180.9 3718.1 16.8% 3490.5 4% 19% 4522.5 148.2 4067.7 61.3% 842.8 1904 n.2052 1601.7 692.0 20.7 218.4 4498.0 21.0% 4258.9 4% 18% 5460.1 417.0 4843.1 80.3% 1034.2 1895 2451.0 2103.3 717.1 16.2 259.6 5548.0 23.3% 0272.2 4% 15% 64e8.9 -1_00.0 488.9 S9.8% 1239.4 1"6 2089.0 2589.2 813.2 0.0 326.3 6717.8 21.1% 8301.5 4% 18% 8157.6 -1846.8 6310.8 59.7% 1589.4 1997 3420.0 3065.0 883.0 0.0 371.2 7739.2 15.2% 7388.0 4% 17% 9280.8 -1500.0 7780.8 ,9.4% 1784.9 1W98 3780.0 3397.5 979.5 0.0 407.8 8064.8 10.7% 8157.0 4% 16% 10198.2 .1180.0 9010.2 09.7% 1949.9 199 4178.1 3766.1 1088.5 0.0 448.7 9479.4 10.7% 9030.7 4% 16% 11218.2 250.0 11408.2 59.7% 2140.9 2000 4618.2 4174.8 1205.2 0.0 493.7 10491.9 10.7% 8898.2 4% 15% 12343.5 -330.0 12013.5 60.0% 2347.9 2001 5183.1 4707.0 1336 0e0 051.0 11777.7 12.3% 11228.7 4% 10% 13770.1 -230. 1545.1 80.0% 2019.9 2002 5017.1 5307.0 142.4 0e0 615.0 13221.6 12.3% 12606.6 4% 14% 15373.9 14700 16e43.9 W0.3% 2909.4 200oo3 0528.8 5983.7 1644.2 0.0 686.4 14843.1 12.3% 14156.7 4% 14% 17159.7 110.0 183107 80.3% 3250.2 2004 7327.6 6746.7 1823.7 0.0 766.2 16694.2 12.3% 15898.1 4% 13% 19154.3 430.0 19584.3 e0.7% 3603.7 2005 8224.3 7607.1 2022.9 0.0 050.2 18704.5 12.2% 17054.3 4% 12% 21255.1 20.0 23835.1 90.8% 4002.5 2006 9230.7 8577.3 2243.9 0.0 904.9 21006.8 12.3% 20051.9 4% 12% 23871.3 1340.0 25211.3 00.9% 4473.6 2007 10380.4 9671.4 2489.1 0.0 1059.8 23580.7 12.3% 22520.9 4% 11% 2649S.2 3140.0 29535.2 80.0% 4069.9 2008 11628.5 10905.1 2761.2 0.0 1190.3 20485.3 12.3% 25284.9 4% 11% 29750.7 1370.0 31128.7 01.2% 5555.1 2000 13051.9 12296.5 3083.2 0.0 1321.5 29733.1 12.3% 28411.6 4% 10% 33038.8 1170.0 34206.8 81.1% 6172.2 2010 14649.7 13865.5 3398.3 0.0 1464.4 33397.9 12.3% 31913.6 4% 10% 37108.8 1410.0 38518.8 81.4% S900.0 2011 18443.3 15635.0 3770.2 0.0 1667.4 37510.0 12.3% 3984.4 4% 10% 41684.2 2400.0 44084.2 81.3% 7757.0 2012 18458.9 17630.5 4182.9 0.0 1873.0 42143.0 12.3% 40270.0 4% 10% 4682.5. -3350.0 43475.8 S1.7% 8066.3 2013 2071e6. 19880.9 4841.0 0.0 2104.1 47342.8 12.3% 45238.5 4% 10% 52602.9 -227.0 50332.9 81.8% 9742.1 2014 23253.9 22418.9 5149.3 0.0 2393.8 53185.7 12.3% 00821.0 4% 10% 59095.2 -2130.0 06986.2 e1.0% 10093.1 2015 20101.5 25281.2 5713.6 0.0 2655.6 59752.0 12.3% 57096.4 4% 10% 86391.1 1180.0 87551.1 61.9% 12247.4 MG 90-1995 15.4% 15.6% 13,9% 9.4% 14.1% 15.3% 14.5% 7.2% 15.2% AG 98-1997 10.1% 20.7% 11.0% 19.6% 18.1% 18.2% 19.6% 26.2% 20.0% MG 98-2C00 10.5% 10.9% 10.9% 10.0% 10.7% 10.7% 10.0% 15.6% 9.6% MG2Do1-IS 12.2% 12.8% 10.0% 11.9% 12.3% 12.3% 11.9% 12.2% 11.0% AG 98.2015 12.0% 13.2% 10.9% 12.3% 12.0% 12.6% 12.3% 14.0% 12.1% Note: Peak Load kI Region is calcated from generaion reqimd tlo sowm the dtnd in ther regin o _ VIET NAM Case B HO CHI MIN CITY PC ELECTRICITY DEMAND FORECAST Parameters for Forecasting Long-Run GDP Growh RateS GDP Etosstiast rk Eria~I~sy 1n0160 PonuteloWn (otWlloos) 19;1.90 199sr1997 1592000 2001-2016 FomecstAvge Unkfrorp Linkto 1991-95 1906&1997 1996-2000 2001-2015 (negativoe Pop 11n m0 %Rural Acduals Actuals Rural 1.4 20.8% Agriulunue 1.2% 3.0% 3.0% 3.0% Total 4.9 ConsIr 22.6% 16.0% 8.0% 9.0% Industry 12.9% 14.5% 7.1% 8.5% IndGOP Irdustry 1.09 1.35 1.40 1.40 0.6 Trade/other 10.0% 12.0% 7.0% 8.0% Trade/OGDP OthedSarvNes 1.70 0.89 1.00 1.30 0.8 GOP HCMC 11.3% 13.0% 7.0% 8.2% 7.9% GDP Restdential 1.43 1.61 1.o0 1.80 0.5 Population Growdh Urban 4.5% 4.8% 4.8% 4.7% ResidenUat 3.80 4.52 2.37 2.79 0.5 Rural 1.4% 1.3% 1.2% 0.1% Total 2.1% 2.0% 2.0% 1.8% Rcs MvWW Use oervyrnI0n 2 Gnwth In Use per Consumer 2.000 2.0% 2.5% 2.5% 2.5% GENERATION REQUIREMENTS LQkiL9jMENRG LQAWJIN 00GQA ANNUAL SALE NON-TECH TECH Requked TRANSFER GENERATION Deramrd PEAK ELECTRICITY DEMAND IN REGION, BY CATEGORY (GvVH) DEMAND IN for REGION TO OTHER IN Load Demand FISCAL OTHER/ UNSERVEO NON-TECH REGION GROWTH REGION REGIONS REGION Fator YEAR INDU6 RES DEN SrRVICE DEMAND LOSSES AL % - % GW GW W 1990 600.0 520.0 200.0 43.3 08.4 1511.7 1380.0 5% 17% 1760.7 61.5% 325.8 1991 764.0 0455 202.9 12.7 78.6 1803.6 8.1% 1012.3 4% 1r% 1988.3 - 61.5% 364.8 1992 827.0 651.0 227.9 24.2 84.0 1723.1 7.5% 1015.0 4% 19% 2099.0 - - 61.0% 392.8 1593 943.0 668.0 279.0 35.5 98.0 2023.5 17.4% 1890.0 4% 19% 2448.8 - - 61.9% 4516 1994 1121.0 844.0 350.0 3.9 118.7 2437.6 20.5% 231S.0 4% 18% 2907.9 - 80.5% 5600. 1995 1276.4 113019 438.4 0.6 138. 299.9 21.4% 2814.7 4% 18% 3464.2 --00% 869.1 1996 1588.3 1340.9 0830.0 '170.4 3810.9 22.0% 3435.0 4% 10% 4394. - - 052% 830.09 1997 1827.0 1811.0 535.0 0.0 200.2 4173.2 15.6% 3973.0 4% 17% 5004.4 - - 59.7% 8.5 1998 2008.8 1792.1 594.9 0.0 219.6 4815.4 10.8% 4395.7 4% 16% 9494.6 - - 60.0% 1045.3 198 2298.3 1993.6 661.6 0.0 241.7 5105.1 10.6% 4883.4 4% 18% 6041.5 - - 59.% 1150.6 2000 2427.8 2217.8 735.6 0.0 200.7 5646,9 10.6% 5381.2 4% 15% 6843.4 - - 60.2% 1209.2 2001 2718.7 2S06.0 812.2 0.0 298.3 6334.1 12.2% 6037.8 4% 15% 7408.4 . - 60.2% 1405.1 1 2002 2058.8 3838.5 898.8 0.0 330.5 7105.5 12.2% 8779.0 4% 14% 8262.2 - - 80.% 1560.8 2003 3401.7 3211.2 99.9 0.0 358.8 7971.3 12.2% 7602.7 4% 14% 9215.4 -60.3% 1743.9 (An 2004 3806.5 3632.8 1092.8 0.0 411.2 8943.3 12.2% 6532.1 4% 13% 10279.7 8 60.7% 1933.0 2000 4259.5 4109.8 1206,5 0.0 456.0 10031.6 12.2% 9575.8 4% 12% 11399.7 - - 60,6% 2147.9 1 2006 4766.4 4849.5 1331.9 0.0 511.8 11259.6 12.2% 10747.8 4% 12% 12795.0 - - 0.8.% 2401.1 2007 5333.5 0260.0 1470.5 0.0 567.7 12631.8 12.2% 12064.0 4% 11% 14193.0 - - 60.7% 2868.0 2008 59682 5980.7 1623.4 0.0 637.3 14179.6 12.3% 13542.4 4% 11% 15932.2 - - 61.0% 2992.8 2009 6878.5 732.1 1792.2 0.0 707.1 15909.9 12.2% 15202.8 4% 10% 17677.7 60,9% 331590 2010 7473.2 7619.1 1978.6 0.0 793.9 17861.6 12.3% 17007.9 4% 10% 19848.4 - 61.1% 3700.6 2011 8382.5 9816.2 2164.4 0.9 891.3 20004.4 12.3% 19163.1 4% 10% 22292.6 - 1.0% -4160.3 2012 9307.8 9747.6 2411.6 0.0 1000.8 22517.0 12.3% 21518.8 4% 10% 25019.5 61.3% 4665.9 2013 10471.2 11027.5 26Q24 0.0 1123.8 20284.8 12.3% 24161.1 4% 10% 28094.3 - - 61.2% 5237.0 2014 11717.3 12475.5 2939.2 0.0 126.0 26394.0 12.3% 27132.0 4% 10% 3154.9 - - 61.5% S097.3 2010 13111.8 14113.7 3244.9 0.0 1417.2 31687.4 12.3% 30470.2 4% 10% 35430.5 - - 61.4% 6598.0 AAG90l1995 14.1% 16.2% 16.9% 9.4% 14,4% 15.3% 14.5% 15.1% AAG 96-1997 19.6% 20.9% 10.7% 20.2% 18.8% 18.8% 20.2% 20.5% AAGW9-2000 9.9% 11.2% 112% 8.9% 10.B% 10.6% 9.0% 9.6% AAG2001-15 11.9% 13.1% 10.4% 11.J% 12.2% 12.3% 11A.% 11.7% AAG 96-2010 12.4% 13.8% 10.6% 12.3% 12.8% 12.8% 12.3% 12.2% Note: Peaal Load In Regl Is Calaed fem genatoo raqaed tonna Or deAran the reglo O - n4S) VIET NAM Case B RURAL SOUTH PC2 ELECTRICITY DEMAND FORECAST Parameter for ForecassRnh Long-Run GDP GrnAh Rates GDP Elaslrtles Proe Elastirav Iniiial Populaon (mnilions) 1991-95 1996-1997 1998-2000 2001-2015 Forest Avge jflklrots ilnko t 991-99 1996-1997 1998-2000 2001-2015 (negative) Pop in 1990 % Rurl Actuals Anutool Rural 17.0 78.7% Agnruiltre 1.5% 3.4% 3.0% 3 S% Total 21.6 ConSir 14.7% 16.0% 8.0% 8.5% Industry 17.8% 14.5% 8.0% 9.0% Ind GDP Industry 0.95 1.13 1.40 1.40 0.6 Tradelother 10.1% 12.0% 7.0% 9,0% Trade/O GDP Other/Srvieces 0.99 0.95 1.50 1.30 0.6 GDP RURALS 8.4% 9.9% 6.1% 7.7% 7.2% GDP Rensidential 1.00 2.09 1.70 1.60 0.5 Populatlion Growth Urban 4.5% 4.6% 4.8% 4.7% Residcental 3.34 4.43 2.19 2.61 0.5 Rural 1.4% 1.3% 1.2% 0,1% Tot.1 2.1% 2.0% 2.0% 1.6% Res MWViW Use DOe vr in 1990 Growth in Use per Consumer 2.000 2.0% 2.5% 2.5% 2.5% GENERATION REQUIREMENTS LOSS FACTORS ENE Ij&QN..EG1N ANNUAL SALES NON-TECH TECH Re4uiFred TRANSFER GENERATION Demand PEAK ELECTRICITY DEMAND IN REGION, BY CATEGORY (GWVH) DEMAND IN for REGION TO OTHER IN Load Demand FISCAL OTHER/ UNSERVED NON-TECH REGION GROWTH REGION REGIONS REGION Factor YFAR INDUSTRY RESIDENT SERVICES DEMAN LOSSES TOTAL _..G GWH % - G GvV GWvH _ MW 1990 537 6 495.8 174.3 72.0 77.4 1358.1 1208.7 5% 17% 1542.1 - 62.0% 283.9 1991 684,1 446.5 181.4 5.3 98.2 1385,0 2.0% 1312.0 4% 19% 1705.0 - - 62.0% 313.9 1992 708.4 484.6 175.4 26.8 71.1 1466.3 5.8% 1368.4 4% 19% 1778.5 - - 61.0% 332.8 1993 796.9 595.4 208.2 11.2 82.9 1694.6 15.6% 1600.5 4% 19% 2073.7 - - 60.5% 391.3 1994 944.2 757.7 242.0 16.8 99.7 2060.4 21.6% 1943.9 4% 18% 2492.2 - - 60.0% 474.2 1990 1175 .5 1001.3 280.7 10.6 121.0 2589.1 25.7% 2457.5 4% 15% 3024.9 - - 50.0% 580.3 1999 1402.8 1248.3 305.0 0.0 150.9 3106.9 20.0% 2956.0 4% 18% 3772.8 - - 59.1% 728.6 1997 1593.0 1454.0 348.0 0.0 171.1 3506.1 14.8% 3395.0 4% 17% 4276.4 . 58.9% 828.4 1998 1771.4 1605.4 384.5 0.0 188.1 3949.4 10.7% 3791.3 4% 16% 4701.7 - - 59.3% 904.7 1999 1960.8 1772.5 424.9 0.0 207.1 4374.3 10.8% 4167.2 4% 16% 5179.7 * 59.4% 990.4 2000 2190.4 1957.0 469.5 0.0 228.0 4845.0 10.8% 4617.0 4% 15% 0700.0 - - 59.8% 1088.8 2001 2400 .4 2198.0 024.5 0.0 254.7 5442.9 12.4% 5190.9 4% 10% 9399.7 - 9.0% 121. 2002 27773.2 2408.9 590.0 0.0 2$4.5 9119.1 12.4% 5031.6 4% 14% 7111.7 609.2% 1348.6 2003 3127.1 2772.5 654.4 0.0 317.8 6871.8 12.4% 6594.0 4% 14% 7944.3 - 60.2% 1506.3 2004 3521.1 3113.8 730.9 0.0 305.0 7720.9 12.4% 7365.9 4% 13% 8874. - - 60.7% 1970.2 2005 3964.8 3497.2 519.5 0.0 394.2 0672.7 12.3% 0278.5 4% 12% 9855.3 - - 60.7% 1854.6 2006 4454.4 3927.8 912.0 0.0 443.1 9747.2 12.4% 9304.1 4% 12% 11076.3 - - 61.0% 2072.0 2007 5026.9 4411.3 1018.7 0.0 492.1 10949.0 12.3% 10456.9 4% 11% 12302.2 - - 61.0% 2301.7 2008 5960.3 4954.4 1137.9 0.0 553.1 12305.6 12.4% 11752.6 4% 11% 13826.5 - - 91.4% 2572.3 2009 6373.5 0064.4 1271.0 0.0 014,4 13823.2 12.3% 13200.9 4% 10% 15359, -6 1.4% 2057.2 2010 7176.5 6249.4 1419.7 0.0 6900.5 1536.1 12.4% 14845.6 4% 10% 17292.4 61.7% 3193.5 2011 8080.8 7018.8 1585.8 0.0 776.1 17461.4 12.4% 19985.4 4% 10% 19401,6 - - 61.7% 3588.9 2012 0099.9 7992.9 1771.3 0.0 072.2 19925.5 12.4% 15753.2 4% 10% 21900,1 - 62.1% 4005.7 2013 10245.4 8053.4 1978.6 0.0 900.3 22007.8 12.4% 21077.4 4% 10% 245096. 621% 4505.2 2014 11536.3 9943.4 2210.1 0.0 1101.9 24791.7 12.4% 23589.8 4% 10% 27549.3 - - 624% 5036.4 2015 12989.9 11167.6 2468.7 0.0 1238.4 27654.6 12.4% 26920.2 4% 10% 30985.0 - 62.4% 5990.2 MG 90-1995 19.09% 15.0% 10.0% 9.3% 13.8% 15.2% 14.4% 15.4% MG 9-1997 16.4% 20.5% 11.3% 18.9% 17.4% 17.5% 18.9% 19.5% MG 98-2000 11,2% 10.4% 10.5% 10.1% 10.8% 10.8% 10.1% 9.5% AAG 2001-15 12.96% 12.3% 11.7% 1 1.0% 12.4% 12.4% 11.9% 11.9% MG 920.15 12.8% 12.8% 1,1t% 12.3% 12.6% 12.7% 12.3% 12.1% Note: Peak Load In Region Is calculated from generation required to salve the demand In the region o -R 9 i VIET NAM Case B PETROLEUM PRODUCT DEMAND FORECAST Parameters for Forecasting Long-,Run GDP Growth Rates GOP Elas8lr8es L0ong-ERunM 1991-95 1996-1997 1998-2000 2001-2015 ForecstAvge Uikomt LinU 1991-95 19961997 1998-2000 2001-2015 (negathe) Aciuals Agricfltue 2.3% 3.7% 3.0% 3.4% 3.3% Constr 22.0% 14.2% 7.4% 9,4% 8.9% Industry 13.8% 13.1% 7.4% 8.8% 8.5% Ind GOP Olherj 0.84 1.00 1.00 1.00 0.9 Trade/o4her 8.4% 10.0% 68% 8.1% 7.8%A Ind GDP Diese4l 0.89 lnd GDP Av Fuel 1.00 Total GDP 8.0% 9.2% 8.0% 7.5% 7.1% Total GDP PETROL 1.62 1.60 1.60 1,60 0.7 led GOP FUEL OIL 0.29 0.00 0.00 0.00 0.9 Indt GDP LPG 5.24 1.00 1.50 1.50 0.9 Population Growth ~ ~~~~~~~Total GDP Kerosene 1.55 1.20 1.20 1.20 0.9 Populatlon Growth Uroan 4.5% 4.6% 4.8% 4.7% Ruil 1.4% 1.3% 1.2% 0.1% Total 2.1% 2.0% 2.0% 1.6% PETROLEUM PRODUCT DEMAND (000 Barrels per year) ANNUAL TransMnIdtAar etc For Elect Gee AV TOTAL GROWTH YEAR DIESEL FUELOIL PIES1EL FUEL OQ ETROL Kerosene LPG FUELS OTHE MILLS 0OT %rFr Total for (Esy Gas) ElectnicEty 1990 7826.8 3344.0 800.0 1000.0 5800.0 1681.0 23.0 802.0 465.0 21.742 2,916.8 1991 7068.8 3002.0 800.0 1000.0 4278.3 1474.5 39.6 623.2 439.2 18.726 2,529.7 -13.9% 1560.0 1992 9644.8 3454.1 900.0 1000.0 6433.6 1244.5 68.3 1128.5 512.4 24.384 3,209.2 30.2% 962.0 1993 13762.7 4119.2 800.0 1000.0 7913.7 1604.4 174.8 1368.2 585.0 31.329 4,190.1 28.5% 854.0 1994 15402.5 3972.9 1000.0 1000.0 9077.5 1887.8 291.3 1769.8 695.4 35.897 4,772.6 14.6°b 519.0 1995 13984.1 4059.1 2200.0 1500.0 10893.1 3025.5 349.5 1527.0 805.2 38.144 5,002.1 6.3% 837.0 1996 1569503 4291.5 2333.1 161 12024.6 3334.0 410.3 1727.4 10. 42.77 ,616.2 11.1% 100.0 1997 17615,9 4537.3 2024.5 1719.2 13521.9 367506 500.6 1954.1 1030.4 47.180 6,243.7 11.3% 1451.4 1998 10776.2 4568.9 3343.2 1055.2 14517.2 39092 556.4 2099.2 1107.0 50.836 6,725.5 7.7% 2151.5 1999 20012.9 4504.4 1692.5 1133.3 15585.8 4157.0 610.4 2255.2 1189.2 51.449 6,773.6 1.2% 2500.0 2000 21331.1 4943.8 1224.8 952.0 16733.0 4421.7 607.4 2422.7 1277.5 53.994 7,093.4 4.9% 2400.0 2001 23070.3 5 20.1 1211.0 005.0 16358.2 4781.7 777. _2630.3 13896 58.290 7,646.3 8.0% 2300.0 2002 24843.3 5302.8 1215.4 102. 20141.2 5170.0 86001 2806.4 1511.0 62.938 8,243.3 9.0% 2500.0 2003 20010.6 5492.0 1237.1 1030.7 22097.3 5591.0 995.9 3117.0 1644.1 68.017 8,895.4 8.1% 2800.0 2004 20933.7 5607.9 1234 2 10321 24243.5 6047.0 1127.0 3391.3 1788.3 73.485 9,595.6 8.0% 3600.0 2005 31224.9 58900. 1245.0 1024.1 259801 6539.2 1275.3 3600.0 1945.2 79.431 10,356.3 8.1% 4600.0 2050 33097.0 6101.0 1245.0 1025.4 2181.4 70715 1443.0 40124 215.8 85.93 11,182.0 8.1% 3800.0 2007 3536.1 6316.6 1245.0 1026.1 32015.6 7647.1 16329 4364.3 2301.4 92.917 12,0785 8.2% 4350.0 2008 39245.5 6544.0 1245.0 1027.4 35125.0 0269.6 1847.5 4747.2 2503.2 100.555 13,052.3 8.2% 3900.0 2009 42353.7 6777.5 1225.5 1006.2 38536.4 8942.7 2090.9 5163.6 2722.0 108.819 14,104.5 8.2% 4100.0 2010 45707.7 7019.3 1200.9 1011.5 42279.2 50757 23206.1 5616.5 2951.6 117.841 15,251.4 83% 4000.0 201i 49327.2 012.2 46385.5 __.102 10457.0 2677.3 610902 3221.4 127.695 1,502.2 4% 5200.0 2012 53233,4 7529.0 1237.8 1017.5 50890.6 11309.1 3029.6 66450 3504.0 138.396 17,861.6 6.4% 6300.0 2013 57440.9 7797.6 771.4 630.2 55833.2 12229.7 3428.2 7227.9 3811.4 149.187 19,214.7 7 8% 8300.5 2014 61996.2 0075.8 699.2 838.1 61255.9 13225.2 3679.3 7061.9 4145.7 162.279 20,079.7 8.8% 11200.0 2015 65905.8 8363.9 1628.9 606.5 67205.3 14301,8 4389.7 8551.5 4509.3 176.545 22,687.2 8.8% 15600.0 -1995 12.3% 21500.0 -Ij~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~210. MG 905 12.3% 4.0% 22.4% .4% 13.0% 12.5% 72.3% 13.7% 11.8% 11.6% MAG 96-1997 12.2% 5.7% 9.2% 7.1% 12.5% 10.2% 19.7% 13.1% 13.1% 11.2% MG 98-2000 6.6% 2.9% -22.4% -17.6% 7.4% 6.4% 11.1% 744% 7.4% 4.6% C AAG 2001-15 7.0% 3.6% 1.9% -2.2% 9.7% 81% 13.2% 8.8% 8 8% 8.2% c - MG 96-2015 0.1% 3.7% .15% -3.6% 9.6% . 1% 13.5%, 0.% 9. 0% 5.0%1 MG 68-2015 7.6% 3.4% -5.8% -4.0% 9.2% 7.7% 12.7% 0.5% 8.5% 7.3% VIET NAM Case B COAL DEMAND FORECAST Parameters for FoRecasing Lofg-Run GDP Grwth Rates GDP E bstj9s Prie 1991-95 1986-19W7 1928D2000 2001-2015 ForecstAWge Unlkfr Unk 1991-95 18S-1997 1998-2000 2001-01 -- eg Acualb (aegare) Agriouture 2.3% 3.7% 3.0% 3.4% 3.3% Constr 22.0% 14.2% 7.4% 9.4% 8.9% lndustry 13.8% 13.1% 7.4% 8.8% 8.5% Ind GDP Industry 0.55 0.50 0.50 0.45 0.6 T,adeOWer 8.4% 10.0% 6.6% 8.1% 7.8% Total GOP 8.0% 9.2% 6.0% 7.5% 7.1% EotM AAG% 3.0% 3.0% 3.0% t evel aftr 2004 PopAldlon Growth Urban 4.5% 4.6% 4.8% 4.7% Lhba pop Renidtial 2.73 Rral 1.4% 1.3% 1.2% 0.1% Rural Pop Reskta 8.57 1.00 1.00 1.00 0.8 Totat 2.1% 2.0% 2.0% 1.e% COAL DEiMAND (000 TONS per year) ANN6JAL Domestic Us For BEect Gen TOTAL GROWTH YAR INWSTRY RESIDN NORTH SOUTH E1"5 T TOta tar _x -111 m om _tall ME -do 61m1(ifloltl, IEYP. Gea) Hligh Gas) (Ex Ga) 01lh Gas) °° 1W0 1079.0 1400.0 1560.0 1S60.0 0.0 0.0 677.0 4716.0 4718.0 1580.0 1991 1440.0 2200.0 9862.0 952.0 0.0 0.0 1135.0 ST37.0 5737.0 21.8% 21.6% 982.0 1992 1391.0 2400.0 854.0 654.0 0.0 0.0 1260.0 5711.0 5711.0 -0.5% -0.5% 654.0 1883 1454.0 200.0 519.0 519.0 0.0 0.0 1338.0 808.0 5806.0 1.7% 1.7% 519.0 lo4 1420.0 2800.0 837.0 837.0 0.0 0.0 2318.0 7075.0 7075.0 21.8% 21.8% 837.0 1995 1560.0 2500.0 1009.0 1009.0 0.0 0.0 2735.0 7804.0 7804.0 10.3% 10.3% 1009.0 1996 1800.0 2800.0 1451.4 1451.4 0.0 0,0 3600.0 9451.4 9451.4 21.1% 21.1% 1451.4 1997 1918.1 2832.9 2151.5 2151.5 0.0 0.0 3708.0 10410.5 10410.5 10.1% 10.1% 2151.5 1908 19894 2603.5 2500.0 2500.0 0.0 0.0 3019.2 10972.1 10072.1 5.4% 5.4% 2500.0 1999 2063.3 2094.3 2400.0 2400.0 0.0 0.0 3933.8 11091.4 11091.4 1.1% 1.1% 2400.0 2000 2139.9 2725.6 2300.0 2200.0 0.0 0.0 4051.8 11217.3 11217.3 1.1% 1.1% 2300.0 2001 2224.4 2729.4 2500.0 2500.0 0.0 0.0 4173.4 11827.1 11627.1 3.7% 3.7% 2600.0 2002 2312.2 2733.2 2800.0 2800.0 0.0 0.0 4298.6 12144.0 12144.0 4.4% 4.4% 2800.0 2003 2403.4 2737.1 3600.0 3600.0 0.0 0.0 4427.5 13168.0 13168.0 8.4% 8,4% 3600.0 2004 2498.3 2740.9 4600.0 4600.0 0.0 0.0 4500.0 14339.2 14339.2 8.9% 8.9% 4600.0 2005 2598.9 2744.7 3800.0 300.0 0.0 0.0 4500.0 13341.7 13841.7 -4.9% 4.9% 300.0 2006 2099.4 2748.6 4300.0 4320.0 0.0 0.0 4500.0 14248.0 14240.0 4.4% 4.4% 4305.0 2007 2809.0 2752.4 3900.0 3900.0 0.0 0.0 4500.0 13958.4 13958.4 -2.0% -2.0% 3900.0 2008 2016.7 2758.3 4100.0 4100.0 0.0 0.0 4500.0 14273.0 14273.0 2.3% 2.3% 4100.0 2009 3031.9 2760.2 4000.0 4000.0 0.0 0.0 4800.0 14292.0 14202.0 0.1% 0.1% 4000.0 2010 3151.5 2784.0 3700.0 3700.0 1500.0 1500.0 4500.0 15815.6 1561S.6 9.3% 9.3% 52000 2011 3275.9 2767.9 3400.0 3400.0 28000 290O.0 40000 16843.9 16843.9 7.9% 7.9% 6300.0 2012 3405.2 2771.8 3900.0 380.0 4400.0 44000. 4500.0 18977.0 18977.0 12.7% 12.7% 8300.0 2013 3539.7 2775.7 5100.0 5100.0 6100.0 6100.0 4500.0 230153 220153 16.0% 16.0% 11200.0 2014 3679.4 2T79.6 5700.0 5700.0 9600.0 9900.0 4500.0 28559.0 2559.0 20.8% 20.6% 15600.0 2015 3824.6 2783.5 8400.0 6400.0 15100.0 15100.0 450.0 32608.1 32808.1 22.8% 22.8% 21500.0 1 . . > MG 901995 7.7% 12.3% 4i.3X% -.3% 32.2% 10.8% 10.6% CDQi AAG 90167 10.9% 2.6% 46.0% 46.0% 16.4% 15.5% 15.5% - X MG 98-2000 3.7% 1.2% 2.2% 2.2% 3.0% 2.5% 2.5% 0 MG2001-15 329% 0.1% 7.1% 7.1% 0.7% 7.4% 7.4% AAG9802015 4.6% 0.5% 9.7% 9.7% 2.5% 7.4% 7.4% , ._ MG96-2010 3.9% 0.4% 4.3% 4.3% 1.J% 3.2% 3.2% VIET NAM Case B GAS CONSUMPTION FORECAST bcm/yr Demand, with Expected Natural Gas Availability Demand, with Altemative Natural Gas Availability Onshore gas Offshore gas Total Onshore gas Offshore gas Total for elect industry for elect Fertilizer Methanol industry bcm/vr for elect industry for elect Fertilizer Methanol industry bcm/vr 1990 0.033 0.000 0.033 0.033 0.000 0.033 1991 0.020 0.000 0.020 0,020 0.000 0.020 1992 0.020 0.000 0.020 0.020 0.000 0.020 1993 0.015 0.000 0.015 0.015 0.000 0.015 1994 0.005 0.064 0.069 0.005 0.064 0.069 1995 0.012 0.187 0.199 0.012 0.187 0.199 1996 0.011 0.310 0.321 0.011 0.310 0.321 1997 0.011 0.793 0.804 0.011 0.793 0.804 1998 0.011 1.000 1.011 0.011 1.000 1.011 1999 0.011 1.800 1.811 0.011 1.800 1.811 2000 0.011 2.100 2.111 0.011 2.100 2.111 2001 0.011 1.700 1.711 0.011 1.700 1.711 2002 0.011 2.300 0.200 0.100 2.611 0.011 2.300 0.200 0.100 0.100 2.711 2003 0.011 2.600 0.600 0.115 3.326 0.011 2.600 0.600 0.500 0.120 3.831 2004 0.011 2.800 0.600 0.132 3.543 0.011 2.800 0.600 0.500 0.144 4.055 2005 0.011 3.900 0.600 0,152 4.663 0.011 3.900 0.600 0.500 0.173 5.184 2006 0.011 4.400 0.600 0.175 5.186 0.011 4.400 0.600 0.500 0.207 5.718 2007 0.011 5.600 0.600 0.201 6.412 0.011 5.600 0.600 0.500 0.249 6.960 2008 0.011 5.900 0.600 0.231 6.742 0.011 5.900 0.600 0.500 0.299 7.310 t'i 2009 0.011 6.500 0.600 0.266 7.377 0.011 6.500 0.600 0.500 0.358 7.969 2010 0.011 6.800 0.600 0.306 7.717 0.011 6.800 0.600 0.500 0.430 8.341 2011 0.011 7.200 0.600 0.352 8.163 0.011 7.200 0.600 0.500 0.516 8.827 2012 0.011 7.600 0.600 0.405 8.616 0.011 7.600 0.600 0.500 0.619 9.330 2013 0.011 8.200 0.600 0.465 9.276 0.011 8.200 0.600 0.500 0.743 10.054 2014 0.011 8.200 0.600 0.535 9.346 0.011 8.200 0.600 0.500 0.892 10.203 2015 0.011 8.300 0.600 0.615 9.526 0.011 8.300 0.600 0.500 1.070 10.481 AAG 90-1995 -18.3% 43.2% -18.3% 43.2% AAG 96-1997 -4.3% 105.9% 101.0% -4.3% 105.9% 101.0% AAG 98-2000 0.0% 38.4% 38.0% 0.0% 38.4% 38.0% AAG 2001-15 0.0% 9.6% 15.0% 10.6% 0.0% 9.6% 20.0% 11.3% MG 96-2015 -0.4% 20.9% 21.3% -0.4% 20.9% 21.9% AAG 98-2010 0.0% 18.0% 19.0% 0.0% 18.0% 19.7% Sums to yr 2010, in 0.3 48.8 5.0 0.0 1.7 55.7 0.3 48.8 5.0 4.1 2.1 60.2 bcm JCD CD x VIET NAM Case B SUMMARY OF MODERN ENERGY CONSUMPTION FORECAST (Primary Energy, in TOE) Petroleum Natural Coal Hydro Total Petroleum Natural Coal Hydro Total Products Gas Products Gas 000 TOE 000 TOE 000 TOE 000 TOE 000 TOE _ % _ _ _ 1990 2900 33 2177 1342 6452 1990 45.0% 0.5% 33.7% 20.8% 100.0% 1991 2498 20 2480 1579 6578 1991 38.0% 0.3% 37.7% 24.0% 100.0% 1992 3253 20 2396 1807 7475 1992 43.5% 0.3% 32.0% 24.2% 100.0% 1993 4179 15 2411 1987 8592 1993 48.6% 0.2% 28.1% 23.1% 100.0% 1994 4789 68 2564 2312 9733 1994 49.2% 0.7% 26.3% 23.8% 100.0% 1995 5088 197 2732 2645 10663 1995 47.7% 1.8% 25.6% 24.8% 100.0% 1996 5653 318 3154 3001 12126 1996 46.6% 2.6% 26.0% 24.7% 100.0% 1997 6294 796 3613 2919 13621 1997 46.2% 5.8% 26.5% 21.4% 100.0% 1998 6781 1001 3855 2875 14513 1998 46.7% 6.9% 26.6% 19.8% 100.0% 1999 6863 1793 3858 3125 15640 1999 43.9% 11.5% 24.7% 20.0% 100.0% 2000 7203 2090 3862 3820 16975 2000 42.4% 12.3% 22.8% 22.5% 100.0% 2001 7776 1694 4018 4200 17688 2001 44.0% 9.6% 22.7% 23.7% 100.0% 2002 8396 2387 4229 4208 19219 2002 43.7% 12.4% 22.0% 21.9% 100.0% 2003 9074 2699 4711 4230 20714 2003 43.8% 13.0% 22.7% 20.4% 100.0% 2004 9803 2914 5303 4533 22553 2004 43.5% 12.9% 23.5% 20.1% 100.0% 2005 10596 4023 4927 4720 24267 2005 43.7% 16.6% 20.3% 19.5% 100.0% 0 2006 11458 4541 5254 5395 26648 2006 43.0% 17.0% 19.7% 20.2% 100.0% 2007 12395 5755 5098 5595 28843 2007 43.0% 20.0% 17.7% 19.4% 100.0% 2008 13414 6082 5268 6743 31506 2008 42.6% 19.3% 16.7% 21.4% 100.0% 2009 14517 6711 5278 7525 34030 2009 42.7% 19.7% 15.5% 22.1% 100.0% 2010 15720 7047 5991 8215 36973 2010 42.5% 19.1% 16.2% 22.2% 100.0% 2011 17033 7489 6653 8750 39925 2011 42.7% 18.8% 16.7% 21.9% 100.0% 2012 18462 7937 7803 11225 45427 2012 40.6% 17.5% 17.2% 24.7% 100.0% 2013 19901 8591 9441 11795 49728 2013 40.0% 17.3% 19.0% 23.7% 100.0% 2014 21648 8660 11890 12335 54533 2014 39.7% 15.9% 21.8% 22.6% 100.0% 2015 23551 8839 15150 12475 60015 2015 39.2% 14.7% 25.2% 20.8% 100.0% AAG90-1995 11.9% 43.2% 4.6% 14.5% 10.6% AAG96-1997 11.2% 101.0% 15.0% 5.0% 13.0% AAG 98-2000 4.6% 38.0% 2.3% 9.4% 7.6% AAG 2001-15 8.2% 10.1% 9.5% 8.2% 8.8% > AAG 96-2015 8.0% 20.9% 8.9% 8.1% 9.0% AAG98-2010 7.3% 18.3% 4.0% 8.3% 8.0% AAG 10-2015 8.4% 4.6% 20.4% 8.7% 10.2% AAG 01-2010 8.1% 12.9% 4.5% 8.0% 8.1% Forecast Population Case B Forecast VIET NAM, 1990 TO 2010 Total Rural 100.0 ,Urba 80.0-_ 0 :- 60.0- 40.0 - 20.0 - 0.0- , 1985 1990 1995 2000 2005 2010 2015 O Years Regional Shares of GDP in the Economy, Case B Forecast VIET NAM, 1990 TO 2010 40.0 R -.- Rural North -x- Ho Chi Min City 30.0 _0_- A Central Region 25.0 - - Hanoi S g ~~~~~~200 -_ UL ~2.0 -~ ___ __ _ _ _ ___ _ ___ _ 150 QO~.,.,, 4 , _ , 4 4 1986 1990 1995 2aao 2005 2010 2015 UOP Years Sector Shares of GDP in the Economy, Case B Forecast VIET NAM, 1990 TO 2010 46.0 40.0 30.0 2S.0 20.o t / -*--- Industr a _ j ~services = 1985 1 2W5= 2015 _ X Electricity Demand, MW, Cases A, B, C, and B with higher prices 1997 to 2010 20,000 18,000 16,000 14,000 12,000 1800 01 2 3 2 6,000 _ -Y 4 000 . _ _~~~~~~~~~~~~~~~~~ Case C, High Case_ 4,000 Case B, prices rernain at present levels Case B, prices phased up to LRMC 2,000 Case A, Low Case 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010; Years - o Electricity Demand, MW, Case B and Variations 1997 to 2010 16,000 1 2 ,0 0 0 - -- - - -- - - . -------------------------------- .--.--.--.--.--.--..-..-..-..-..-..-.. .. .. -- - - -- - - -- - - - - -- - - - - -- - - - - -- - - - - - -- - - - - I o , o o o - -- - - - - - .. ,. .. . . .. .... . ... -- - - - - - - - - -- - - - - - -- -- -- - - - - - - - -- - - - - - - - ...... ... .. . .... . . . 6 ,0 0 - -- - - - - - -- - - - - - - - - - - - - - - - - - .... . .... :.... .I- - - - - - - - - - - - - - - - - --- -- --- -- -- --- -- --- -- -- --- -- -- 14,000-n . .... A Case B, no Loss Red-tion 4,000~~ ~ ~ ~ ------------------ -----+ Case B, prices remain at present levels---- -44 Case B with non-price DSM 2,000 ------------------------------........ . ......... - - Case B, prices phased up to LRMC - Case B with LRMC prices and DSM 0 I I I I I I I I 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Years -x o _ Forecast of Electricity Demand, Sales by Sector in Viet Nam, 1997 to 2010 Case B 30,000 - 25,000 -iResidential 20,000 - Industry ~Other____ __ f 15,000 i___ 10,000 - -= 5,000 i , = - 0 I ' I I I , . Years i Forecast of Petroleum Product Demand, in Viet Nam, 1995 to 2010 Case B 50,000 45,000 - Diesel 40,000 - Petrol, 35,000-h-4-- er 00 30,-- Fuel Oil 0 * mn 25,000 20,000 15,000 10,000 0 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Year o- _% Forecast of Coal Demand, in Viet Nam, 1995 to 2010 Case B 6,000 5,000 Power Industry 4,000.. Residential 3,000 i= . 2,000/ _ - 1,00 k '~~~~~~~~~~~~~ - 0 19901991 1992 19931994199519961997 19981999 20002001 2002 20032004 20052006 20072008 20092010 Years 0W Forecast of Natural Gas Demand, in Viet Nam, 1995 to 2010 Case B- | t ~~~~~Power Sector l o E ~~~~~Fertilizer/ 3.0- 2.0- 1.0' 199019911992199319941995199619971998199920002001200220032004200520062007200820092010 ..0t -x o - 00, Estimate of Diesel Conservation, wth higher diesel taxes in Viet Nam, 1998 to 2010 sax - Case B - No Rice Change --- gher Taxes in 1998, approx ........................... .. 45% diesel tax ER O - -- ---- ---- -- - ---- ---- -- - ---- ---- --- .... ........ ..... ..... .... ... .. ........................................... ...... ......... .......... .. - - --- - --- - 15 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~.. F.... ..... ... ........ .... ... ... .... . . - - - - - - - - - 2ROO -, ----------------------------------- . ..................... ------------ .----..... ........................ ---- 15Si -.----------................................................--------------------------------------------------------------------------------- 0~~~~ 1900 1991 1912 19g3 1994 1905 1908 1997 1908 1909 2000 201 2a02 2003 2m4 2005 2)00 2)07 2008 2M09 2D10 Yew o- ! Forecast of Primary Modern Energy, in Viet Nam 1995 to 2010 Case B 1,000 Petroleum Products 18,000 16,000 -a-Natural Gas 14,000 -l- Coa 12,000 10,000 I- 0 8,000 6,000 4,000 2,000' --Sw- 0 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Year t-e Forecast Shares of Primary Energy in Viet Nam 1995 to 2010 Case B 60.0%- 50.0% X 40.0% a) ( 30.0%0 20.0%.0 + Petroleum Products --9 Hydro 10.0% - -_ Gas Coal 0.0%1 1W 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Years tIt o - _ Forecast of Primary Modern Energy per GDP (1996$), in Viet Nam 1995 to 201 0 Case B 7m0 MO ------------------------------------------------------------------------------------------------------------------------------------ 0 0 1400 f ~~~~~~~~~1990 1991 1992 1993 1994 1995 1996 1997 199B 1999 2DOO a2o 200Q210 2a4 tri ao 20037M 00 200B as 210 Y 0~~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~ ____ _ Vietnam Energy Sector Oil RESOURCE PO WER PLANT TRANSMISSION DISTRIBUTION DEVELOPMENT "'Increase least cost vLower cost of VEfficient and reliable /Least cost distribution resource exploration / convertion transmission /Expansion of coverage development Composition of Prices in the Energy Sector (Cents/kwh) Wellhead Gas Capacity O&M Bus bar Transmission Distribution Retail C Transport cost cost price --aprice 1-1.4 0.6 1.6 0.4 3.6-4.0 1.6 2.4 7.6-8.0 Annex 2.1 ANNEX 2.1. THE POWER SECTOR 2.1.1. Vietnam Electric Power System - Historical Data ......................................... 46 2.1.2. Existing Power System in 1998 ......................................... 47 2.1.3. Electricity Generation Balance in 1996 (TWh, estimated) ......................................... 48 2.1.4. Trends in Electricity Generation and Consumption ......................................... 48 2.1.5. Electricity Generation Demand Forecasts ......................................... 49 2.1.6.a Electricity Tariffs (at May 1997) ......................................... 50 2.1.6.b Electricity Tariffs (at Dec 1998) ......................................... 50 2.1.7. Estimated Seasonal Plant Load Factors ......................................... 50 2.1.8. Hydro Plant Investment Options ......................................... 51 2.1.9. Thermal Plant Investment Options ......................................... 52 2.1.10. Comparative cost assumptions .53 2.1.11. Comparative cost estimates, c/kWh .54 2.1.12. Cases Examined in Power System Analysis .55 2.1.13. Comparison of Investment Plans for 5 Cases, to 2010 .56 2.1.14. Evaluation and Ranking of Cases (Indicators) .58 2.1.15. Fuel Consumption Forecasts in Power Generation .59 2.1.16. Son La Hydro Plant: NPV Analysis .59 2.1.17. Power system losses .60 2.1.18. DSM and energy efficiency .60 2.1.19. Comparison of Investment Plans .61 2.1.20. Summary of Generation costs .62 Graphs: 2.1.21. Regional Character of Viet Nam's Power System .63 2.1.22. Increasing Electricity Intensity per unit of GNP, 1974-1993 .63 2.1.23. Monthly Generation Mix for the Year 2000 (Base case) .64 2.1.24. Typical Daily Load Curves (PC2, 1995) .65 2.1.25. Annual Variation in Demand (1995) .65 2.1.26. Comparative Generation Costs-New Plant .66 2.1.27. Breakeven Fuel Prices (Netback Values) .66 2.1.28. Gas Demand in Power Generation .67 2.1.29. Monthly Gas Swing (Base case) .67 2.1.30.a Fuel Use Forecast - Fuel Consumption in Power Generation - Gas Demand .. 68 2.1.30.b Fuel Use Forecast - Fuel Consumption in Power Generation Domestic Coal Demand.. 69 2.1.31. Generation Forecast for the year 2005 .70 - 45 - Viet Nam Electric Power System -- Historical Data 1 1976 1877 1975 1979 1950 1591 1952 15532 1954 1999 M95 1997 19e 199 199 1991 10922 199 1? 4 1999 Viet Nam Generation 2964.6 3362.6 3705.7 3775.6 3559.1 3726.3 3674.4 4125.3 4776.5 506-4.7 5526.7 6049.7 6793.3 7791.9 0676.5 9152.0 9652 1066s 12264 14636.1 Theeral 1854.9 1955.2 2083.8 2023.3 1740.7 1844.4 1951.8 2295.9 2618.1 3017.7 3627.1 4155.2 4432.9 2402.0 2841.1 2424.7 1887 1775.8 2124 2929.1 Hydra 631.0 1133.1 1330.8 1447.0 1488.2 1 506.9 1559.6 1223.2 1589.0 1472.1 1481.9 1375.7 1785.8 3828.3 5388.7 8318.5 7228 7548.2 9248 10581.8 Diesel 275.6 244.8 289.8 285.7 316.0 333.6 331.6 389.5 272.4 409.2 394.8 405.7 425.8 436.5 410.7 306.8 318.8 316.9 282 120.4 Gas T,ubimi 3.1 0.5 1.2 20.1 14.2 41.4 101.6 216.7 190.0 160.7 103.1 1`18.1 139.3 68.I 58.0 10`1.0 218 826.3 832 1004.8 O.. Use 195.5 206.7 214.8 224.1 205.8 2M5. 235.8 270.8 202.0 323.9 377.2 414.7 447.7 444.0 278.7 318.6 264.6 263.5 208 338.0 rans/dis loss 550.7 548.4 750.1 825.4 837.4 712.2 1285.7 750.4 864.0 874.3 1003.0 1035.1 1309.6 1884.5 2115.0 2256.7 2501 3590.2 2708 3124.0 Sales 2218.4 2498.5 2748.1 2726.1 2515.9 2799.1 2963.1 3104.1 3612.5 3866.5 4146.8 4899.9 5826.8 5663.4 6164.6 6973.7 6940.8 7633.4 9386.5 11192.8 Industry 1117.71 128. 12481.0 1490.0 123737.54 13499. 1659.4 1738.1 2074 2113. 2.197.01 2~351 I2089.7 2821.01 2845.0 306.1:,, 316775 3476.4 3946.0 4614.0 AgHeatara 219. 5. 8. 282. 3. 1. 206.1 242.8 35. 085 322 387.2 441.0 462. 508 886 91 1143.5 13600.0 i525,7 Cammerval 116.21 138. 12542,2 229.8 323.1 260.1 312.4 324.1 382.4 427.7 482.31 547.01 600.1 656.5 66.9 550.61 548.81 628.9 765.0 905.5 TranspDrl 27. 7 21.1 2. 42. 34.4 304.4 27.2 30.8 38.5 35.9 40.61 38.21 36.4 41.4 51.1 53.81 55.71 64.2 06.0 154.2 Reside.1Ial 738.7 790.4 79i.5 873.2 547.5 654.4 718.0 768.5 857.2 880.9 1094.4 1243.4 1396.5 1882.2 2035.0 2851. 2183 2520.4 3131.0 4843.4 PCI Gemertion 1665.8 1539.1 2088.5 2197.6 16. 19.9 2115.5 21 97.9 2646.6 2546.9 3236.6 2637.3 3873.3 4266.6 4966.6 9121.5 5414.6 8759.5 T166.1 9372.9 Theraal 1202.1 13. 1096 1650.8 1420.7 13454. 1822. 1079.1 2816.0 2302.1 2656.0 3064.9 5438.7 2722.3 2068.0 1365.5 851.4 63. 101 226 Hydra 383.3 303.9 444.5 500.6 373.8 467.4 459.5 390.7 430.2 365.7 477.9 354.6 293.0 1585.5 2956.8 3709.5 4549 5051.1 6080.0 7541.1 Dilesel 20.1 54.5 85.4 70.3 81.5 52.4 32.8 19.6 6.2 2.6 7.7 10.11 11.03 8. 8. 10.9 8.5 5. 103 . GaseTarSine 0.0 5.0 0.8 19.9 13.8 41.2 1DO.2 209.5 188.2 158.5 97.0 107.8 129.3 379 56 35.2 5.5 134 4.4 1. Own Use 131.3 148 .6 159.7 175.0 154.2 169.3 181.5 204.0 241.6 254.7 302.2 332.9 360.9 353.9 282.4 214.6 162.4 148.6 185.8 Trans/dis lass 245.2 330.5 410.7 481.3 445.8 322.8 329.6 338.7 413.6 446.8 506.1 571.5 606.8 1506.2 1395.3 1305.8 1522 1489.4 1425 15.8516 Sale" 1229.5 1360.0 1814.8 1531.3 1269.8 1503.8 1653.9 1688.2 1981.4 2146.2 2380.3 2632.5 2924.8 2988.5 3231.1 3841.1 3773.1 4185.8 4651.7 4918.4 rtdustry 701.6 790. 069.3 940..7 651.0 789.2 891.1 944.2 1117,1 1142.5 1244.4 15 44.3 1464.9 '1354.6 1466.0 11433.8 1466 1514.9 1625 1583.4 Agcsre 215.62 242.5 275. 253.0 193.5 260.5 215.6 152.7 252.1 242.7 26. 268.3 343.6 354.7 486.5 874.0 827.1 069.1 1188 1298.8 Cmercial 67.0 88.1 116.5 1 69.8 126.1 163.3 198,7 202.4 248.5 293.6 330.3 348.9 548.9 355.9 342.1 260.8 207.3 202.5 229.2 254.9 ranspod ~~~~~27.7 20.8 23.3 33.3 24.3 24.5 26.0 16,0 25. 18.5 22.9 21.0 20.9 24.0 29.2 27.0 24.8 o 24 29.9 30.8 Resdential 217.5 215.2 229,9 234.0 212.9 266.3 277.5 288m. 9 352.5 445.7 513.9 610.4 846.5 875.4 655.7 854.7 897,9 103.5 1178 1468.2 rarfer . - . . - - - . - . 69.2 260.8 549.5 441 409.8 Gee.- Purchases 5625 Gneration 1279.8 1418.1 1499.4 1451.0 1544.8 18578.8 1698.2 1732.9 11900.2 1966.4 2826.7 2233.9 2553.3 3868.7 3452.6 3793.1 4813 4667.9 4844 4377.2 Therneal 692.8 524.5 524.5 425.6 320.0 409.5 459.1 716.8 800.1 715.6 871.1 1080.4 994,2 739.7 840.8 1055.2 1530 1138.5 1052 986.5 Hydr 444,5 775.8e 882.0 542.5 1110.3 1035.5 10906.1 929.0 1157.4 1081.3 918.9 1015.5 1489.4 2228.4 24184.0 2550.0 2618 3789.8 3080 2388.7 Diesel 179.1 117.0 93.0 82.8 114.1 130.3 1268.6 179.1 140.9 162.3 131.6 117.7 58.7 76.3 75.9 119.1 149.5 126 113.6 77.2 Gas Turbine 2.1 5.5 0.4 0.2 0.4 0.2 1.4 8.2 1.8 7.2 8.1 10.3 19.9 38.3 52.1 65.8 212.5 812.9 628 1003.7 PursIhases 781 Own Use 62.2 58.2 52.2 45.6 37.1 41.9 50.3 62.4 55.3 83.8 68.3 74.8 78.5 81.3 06.3 97.9 96.3 110.2 95.4 Trans/dis lass 285.6 298.0 315.2 318.5 300.6 305.5 954.0 372.9 485.7 306.5 398.9 489.5 053.5 606.3 643.4 729.7 822.6 933.6 1542 10.8316 Sales 931.'2 1863.9 1132.8 10986.9 1142.1 1173.1 1309.9 1297.6 1439.2 1622A 1887.5 1749.2 1968.3 0387.1 2702.9 2966.8 31309 3681.6 4487 5272.2 lndusOy 467.2 468. 1 067.9 657.3 626.6 650.3 O"6 863.9 788.8 841.8 919.8 884,8 959.'3 1054.8 1167.6 1448.1 1535 1739.9 2065 2451.9 dAgarecfu 0.0 2.6 7,2 19.8 23.8 32.4 265 26.5 29.3 32.6 34,8 41.8 52,4 658 71.5 75.2 87 59.8 154.7 118.9 Caramerclal 48.2 46.6 26.5 47.5 71.3 81.4 98. 10. 11.3 O1.0 118.0 169.6 220.4 269 8.3 8.1 62 355.8 44. 546.7 Trensport 0.0 0.0 0.0 5.7 6.6 6.8 7.6 5.8 1 1.8 11.0 11.4 1 1.6 18.5 10.5 14.5 18.9 23.4 31.9 41.7 52.3 ResIdential 406.4 468.5 498.8 381.7 379.3 370,7 3805. 355.5 424.3 448.9 492.8 529.9 657.5 969.6 1016.8 982.0 1546 1263.4 1602 2103.3 Transfers 19.4 28.1, 26 1 28.9 20.7, 31.4 41.1 87.3 75.1 78.1. 80.7 91.6 110.7 120.1. 134.2 141.2. 149.1. 181.1 228.2. PC 3 Gn+Pars/rosa 99.8 123.5 149.6 186.9 '175.2 '166.3 286.3 261.8 386.8 327.5 342.1 375.1 429.4 484.7 865.8 638.4 626.6 649.6 103 Purchases 15.4 ~~~~~~~26.1 26.1 28.9 30.7 31.4 41.1 87.3 75.1 75.1 80.7 91.8 110..7 126.1 23.64 492.0 4082 402 73517 noatioaln 80. 98.4 120.8 137.8 144.5 164.9 164.2 194.5 231.7 2494 262.4 278.8 318.7 364.6 307.1 237.4 224.6 346.8 274 886.5 Hydra ~~~~ ~~~3.7 3.6 4.3 4.4 4.1 4.0 4.0 3.7 5.4 5.1 7.1 5.6 3.1 9.4 28.1 06.6 60.7 65.6 119.3 851.8 DIsel 76.4 52.8 116.5 132.8 140.4 198.6 160.2 198.8 226.3 244.3 286.3 272.9 310.6 351.3 328.7 180.8 163.8 181.2 187.5 35.0 GsTurddee 3.9 0.3 0.0 0 0 0 OeUse 2.0 1.9 3.0 3.5 4.5 3.8 3.8 4.4 9.1 51.7 5.7 7.0 8.3 8.8 10.0 8.1 5.8 6.7 7.2 Trans/dls fass 19.5 19.9 24.2 25.6 26.0 28.9 32.1 38.9 44.7 47,8 48.0 53.7 69.5 78.0 116.2 184.2 156.7 162.2 241 14.5016 Sale. 77.6 100.7 122. 136.81 144.7 152.6: 168.4 218.6 287.8 274.8 269.4 388.4 301.6 397.9 424.2 469.1 824.8 6261.9 782.8 1808.2 Industry 8.9 20.1 43.6 90.0 58 9. 71.8 188.0 121.7 126.2 132.7 144.9 185.5 161.6 176.4 '187.2 196 231.6 253.7 278.8 o) Agdcafuar 2.9 6. 7. I3.2 16.4 183 19. 2. 25. 32.2 34.4 37.3 46.0 41.8 40.4 50.4 60.5 78.9 74.7 1108.9 -* e- Commeroia 1.0 0. 8.~7 1 2. 13.7 15.4 1. 2.1 235.6 23.8 29.0 28.5 30.91 3'3.8 36.5 43.7 50.5 88.8 90,2 124.2 ranspart 0.8 0.2 1.5 3.5 3.5 30 3.6 4.8 6.1 6..4 6.4 5.6 7.0 6.5 7.4 7.9 7.5 8.4 13.7 21.5 ResIdential 8~~~4.8 73. 629 571 5.3 57. 59.7 69.1 88.0 52.2 87.9 93.1 103.3 134.2 162.5 174.9 219.9 252.5 358.5 471.9 Annex 2.1.2 Page 1 of 1 Existing Capacities in Power System of Vietnam Existing Plants Installed MW Available MW A. Northern Power System 2731.9 2652.9 Hydro: - Thac Ba 108 108 - Hoa Binh 1,920 1,920 - Small Hydro 16.7 16.7 Thermal: - Ninh Binh 100 100 - Uong Bi 105 100 - Pha Lai 440 400 Gas Turbine: - Thai Binh 34 0 Diesel 8.2 8.2 B. Central Power System 284.77 275.77 Hydro: - Vinh Son 66 66 - Small Hydro 29 20 Diesel 189.77 189.77 C. Southern Power System 1873.1 1657.7 Hydro: - Da Nhim 160 160 - Tri An 400 400 - Thac Mo 150 150 - Small Hydro 3.7 3.7 Thermal: - Thu Due 165 156 - Can Tho 33 32 Gas Turbine: - Thu Duc 128.4 101 - Old Baria 46 68 - New Baria 225 30 - Can Tho 75 204 - Phu My 2.1 288 288 Diesel 199 65 Grant Total 4889.77 4586.37 Source: EVN -47 - Annex 2.1.3 Electricity Generation Balance in 1996 (TWh) North Centre South Total Demand 7.2 1.4 8.2 16.9 Hydro 7.7 0.3 3.8 11.8 generation Thermal 2.4 0.2 2.5 5.1 generation Net regional -2.9 0.9 1.9 0 imports Source: Mission estimates Annex 2.1.4 Trends in Electricity Generation and Consumption Period Generation growth rate, Consumption growth rate, %pa %pa 1981-93 9.2 8.9 1994 15.2 19.5 1995 19.2 21.6 1996 15.9 19.2 1997 (estimate) 13.0 Source: Institute of Energy statistics; 1997 Mission estimate - 48 - Annex 2.1.5 Page 1 of I Electricity Generation Demand Forecasts Year Scenario A - Low Scenario B - Base Scenario C - High IEnergy Bse c Demand Demand Peak Deman Peak DemandPeak GWh demand GWh demand GWh demand GDWh demand 1996 16949 3161 16949 3161 16949 3161 16969 2000 23106 4298 25706 4779 27113 5039 30105 2005 36682 6739 44491 8195 50933 9326 53601 2010 58697 10650 77406 14123 96394 17389 87816 Elect GDP Elect GDP Elect GDP Elect GDP growth growth growth growth growth growth growth growth rate % rate % rate %pa rate % pa rate % rate % rate % rate % pa pa pa pa pa pa 1998- 6.5 4.0 10.3 6.0 12.3 10.0 15.4 9.5 2000 2001- 9.9 6.0 11.8 7.5 13.7 9.5 11.3 9.0 2010 Source: Mission estimates, IE - 49 - Annex 2.1.6.a Summary of Electricity Tariffs, as at May 15, 1997 Typical Price Max. Price US cents/kWh US cents/kWh Residential 151 to 250 kWh/month 7.8 351 kWh and up 10.8 Commercial >6 kV, Normal Times 9.5 >6 kV, Peak Times 13.8 Industrial >20kV <1 10 6.3 >2OkV<110 7.8 Notes: assumes 11, 600 VND to US$. The lowest residential tariff is USc4.3/kWh - a kind of "life-line Source: Tariff Schedule. Annex 2.1.6.b Summary of Electricity Tariff, as at December 15, 1998 Typical Price Max. Price US cents/kWh US cents/kWh Residential 151 to 250 kWh/month 5.9 351 kWh and up 8.2 Commercial >6 kV, Normal Times 7.8 >6 kV, Peak Times 12.3 Induatrial >20kV 2OkV<110 11.4 Notes: assumes 13,900 VND to US$. The lowest residential tariff is Usc3.3/KkWh. This tariff is pre-VAT tariff. 10% of VAT will be added. Annex 2.1.7 Estimated Seasonal Plant Load Factors average plant load Annual average Wetseason Dry season factors, % 1996 2000 1996 2000 1996 2000 Hydro plant 48 51 62 64 35 38 Thermal plant 58 55 38 40 77 69 Source: WASP analysis (Base case 50) - 50 - Annex 2.1.8 Page I of I Hydro Plant Investment Options Earliest Northern C Central and Southern Commissioning Region Capacit M Region Capacit MW Year 1999 Song Hing 70 1999 Yaly #1, 2 360 2000 Yaly #3, 4 360 2001 Ham Thuan 236 Da Mi 236 2004 Dai Ninh 300 2005 Dai Thi 250 Sezan 3 220 Thuong Kon Tum 260 2006 Ban Mai 350 Buon Kuop 85 Plei Krong 120 2007 Son La #1, 2 600 Dong Nai 8 140 A Vuong 145 2008 Son La #3, 4 600 An Khe 116 2009 Son La #5, 6 600 2010 SonLa#7, 8 600 Sezan4 366 Dong Nai 4 200 2011 SonLa#9, 10 600 2012 SonLa#11, 12 600 SonCon2 50 Huoi Quang 600 Rao Quan 90 2015 > Other medium 500 Other medium hydro 500 hydro Source: Institute of Energy -51 - Annex 2.1.9 Page I of I Thermal Plant Investment Options in WASP Model Earliest Capacity Capacity Commissioning Northern Region (unit size) Southern Region (unit size) Year MW MW 1997 PhuMy2.1 GT 144 1999 Ba Ria CC 156 PhuMy2.1 GT 288 Phu My 1 GT 213 2001 PhaLai2.1 (coal) 300 PhuMy2.1 ST 144 Pha Lai 2.2 (coal) 300 Phu My further 300 CCGT (2.2, 3, 4) 2003 Quang Ninh (coal) 300 2007 Coal (domestic or 500 imported) 2008 New coal 500 Source: Institute of Energy - 52 - Annex 2.1 .1 0 Page 1 of I Comparative cost assumptions Var. Fixed Plant type Capital l Ei c cost, ye O&M cost O&M cost $/k Efficincy cos' years c/kWh $. kW mth CCGT: Gas 500 48% 2.10 25 0.40 0.30 $/MBtu ST: Coal North 900 38% 27.4 30 0.40 0.72 $/t ST: Coal 900 34.2% 27.4 30 0.60 0.72 North>EHV>Sth $/t ST: Coal South 900 38% 41.4 30 0.40 0.72 (Domestic.) $/t ST: Coal South 900 38% 47.8 30 0.40 0.72 (Imported.) $/t ST: Fuel Oil 450 31% 23.9 20 0.28 0.51 $/bbl GT: Diesel 350 34% 32.2 20 0.83 0.20 $/bbl Source: IE, WASP input data 'Fuel cost assumptions are for the year 2000, and are based on a forecast of opportunity value prices (see Annex 1). The costs include delivery to the power station in each region. The forecast for crude oil price in 2000 is $21/bbl fob. Using current prices, the oil product generation options would be lower cost, eg the fuel oil plant fuel cost would be around 3.7c/kWh and the generation cost would be 5.03c/kWh. - 53 - Annex 2.1.11 Page 1 of I Comparative cost estimates, c/kWh yCapital Var Fixed Total Plant type cot Fuel cost O& & pot Total Fuelcos O&M O&M Opcost CCGT: Gas 0.97 1.49 0.40 0.06 1.95 2.92 ST: CoalNorth 1.68 1.13 0.40 0.15 1.68 3.36 ST: Coal 1.68 1.25 0.60 0.15 2.00 3.68 North>EHV>Sth ST: Coal South 1.68 1.70 0.40 0.15 2.26 3.93 (Domestic) ST: Coal South 1.68 1.80 0.40 0.15 2.35 4.03 (Imported) ST: Fuel Oil 0.93 4.33 0.28 0.11 4.72 5.64 GT: Diesel 0.72 5.59 0.83 0.04 6.46 7.18 Source: Mission estimates. Common assumptions are a 65% load factor and a 10% discount rate - 54 - Annex 2.1.12 Page 1 of 1 Main Cases Examined in Power System Analysis Demand Case Description, purpose scenario BASE 50 BT Base case demand scenario (scenario B) With minimum Take-or-pay contract assumed for gas supply; new gas plant assumed to run for a minimum of 5000 hrs pa (approximately 56% load factor). 52 B Base case demand scenario No minimum take-or-pay on gas. 54 BTDN Base case demand scenario With minimum Take-or-pay on gas. Dai Ninh hydro plant delayed by 1 year. 56 BTC Base case demand scenario With minimum Take-or-pay on gas. CCGT plant capital cost at higher figure of $450/kW. LOW 60 LT Low case demand scenario (scenario A) With minimum Take-or-pay on gas 62 L Low case demand scenario. Other assumptions as base case. 64 LTDN Low case demand scenario. Other assumptions as base case. 66 LTC Low case demand scenario. Other assumptions as base case. HIGH 80 HT High case demand scenario. (scenario C) Other assumptions as base case. 82 H High case demand scenario. Other assumptions as base case. 84 HTDN High case demand scenario. Other assumptions as base case. 86 HTC High case demand scenario. Other assumptions as base case. - 55 - Annex 2.1.13 Page 1 of 2 Comparison of Investment Plans for 3 Cases, to 2010 Case 50 BT Case 60 LT Case 80 HT (Base demand) (Low demand) (High demand) Total Total Total Year New Plant new New Plant new New Plant new capacity capacity capacity MW MW MW 1997 Phu My 2.1, GT 144 Phu My 2.1, GT 144 Phu My 2.1, GT 144 Phu My 2.1, GT 288 Phu My 2.1, GT 288 Phu My 2.1, GT 288 1999 Ba Ria new, CC 344 Ba Ria new, CC 344 Ba Ria new, CC 344 PhuMy 1.1, GT 557 PhuMy 1.1, GT 557 PhuMy 1.1, GT 557 Phu My 2.1, GT 845 Phu My 2.1, GT 845 Phu My 2.1, GT 845 Yaly 1 1025 Yaly 1 1025 Yaly 1 1025 2000 BaRianew, CC 1081 BaRianew,CC 1081 BaRianew, CC 1081 Phu My 1.2, GT 1507 Song Hinh 1151 Phu My 1.2, GT 1507 Song Hinh 1577 Yaly 2, 3,4 1691 Song Hinh 1577 Yaly 2, 3,4 2117 Yaly 2, 3,4 2117 2001 PhaiLai2.1 2417 PhuMyl.2,GT 2117 PhaiLai2.1 2417 Phai Lai 2.2 2717 Phai Lai 2.1 2417 Phai Lai 2.2 2717 Phu My 2.1 2861 Phu My 2.1 2861 (+ST=CC) (+ST=CC) Phu My 2.1 3005 Phu My 2.1 3005 (+ST=CC) (+ST=CC) Phu My new 3305 Phu My new 3305 Ham Thuan 3605 Ham Thuan 3605 Da Mi 3777 Da Mi 3777 2002 Phu My new 4077 Phai Lai 2.2 2717 Phu My new 4077 Phu My 2.1 2861 Phu My new 4677 (+ST=CC) Phu My 2.1 3005 (+ST=CC) 2003 Quang Ninh 1 4377 Phu My new 3305 Quang Ninh 1 4977 Quang Ninh 2 4677 Quang Ninh 1 3605 Quang Ninh 2 5277 Phu My new 4977 Phu My new 5577 - 56 - Annex 2.1.13 Page 2 of 2 2004 Quang Ninh 3 5277 Phu My new 3905 Quang Ninh 3 5877 Dai Ninh 5577 Phu My new 6177 Dai Ninh 6477 2005 Phu My new 6477 Quang Ninh 2 4205 Dai Thi 6727 Sesan 3 6697 Phu My new 4505 Phu My new 7627 Dai Ninh 4805 Sesan 3 7847 2006 Phu My new 6997 Sesan 3 5025 Quang Ninh 4 8147 Dai Thi 7247 Phu My new 5325 Phu My new 9047 Quang Ninh 4 7547 Thuong Kon Tum 9307 Thuong Kon Tum 7807 2007 Phu My new 8707 Quang Ninh 3 5625 Quang Ninh 5 9607 Buon Kuop 8792 Dai Thi 5875 Ban Mai 9957 Plei Krong 8912 Phu My new 6175 Phu My new 10257 new Coal (South) 10757 Dong Nai 8 10897 Buon Kuop 10982 Plei Krong 11102 A Vuong 11247 2008 Quang Ninh 5 9212 Phu My new 6475 PC1 T 11747 Ban Mai 9562 Quang Ninh 4 6775 Son La 1, 2 12347 Phu My new 9862 Son La 1, 2 7375 Phu My new 12947 Dong Nai 8 10002 new Coal (South) 13447 Son La 1, 2 10602 2009 A Vuong 10747 Phu My new 7975 PC1 T 13947 Phu My new 11347 Thuong Kon Tum 8235 Son La 3, 4 14547 Son La 3, 4 11947 Son La 3, 4 8835 new Coal (South) 16047 An Khe 12063 An Khe 16163 2010 Phu My new 12663 Buon Kuop 8920 new Coal (North) 16663 new Coal (South) 13163 Plei Krong 9040 new Coal (North) 17163 PC1 T 13663 PhuMynew 9640 SonLaS,6 17763 Son La 5, 6 14263 Notes: Plants: GT = gas turbine, CC = combined cycle, ST = steam turbine, +ST=CC = conversion of gas turbine to CCGT by addition of ST unit, Phu My new = new CC units at Phu My (in WASP we have not identified alternative gas projects separately) Source: WASP analysis - 57 - Annex 2.1 14 Page 1 of I Financial Evaluation of Cases Case 60 LT 50 BT 80 HT Criterion: (ow) (base) (high) Efficiency (minimum cost) - costs to 2005' 3614 4678 5261 - costs to 2010 5814 8001 9843 - cost per unit of demand2 23.2 27.1 29.7 Financeability - investment to 2005, $M 2800 3931 4495 - investment to 2010, $M 6092 9522 12322 - Investment affordability 8.1% 9.8% 10.0% (% of GDP) Source: Mission estimates; WASP and PSDP models The cumulative present worth of investment and operating costs, discounted at 10%. These cost estimates are calculated in the PSDP spreadsheet model and vary slightly from those calculated in WASP due to a slightly different calculation method (in particular, average fuel costs have been used over the whole period, rather than specific costs for each year, and the cost of energy not served has been omitted), but the ranking of cases by cost is the same. 2 The present worth of costs to 2010 divided by the present worth of demand, to give an indicator of cost per unit electricity generated. - 58 - Annex 2.1.15 Fuel Consumption Forecasts in Power Generation B1 Base+nil B2 Base + max CASE B Base A Low demand C High demand transfers exports Gas Coal Gas CoaT Gas Coal Gas Coal Gas coal Year bcm Mt bcm Mt bcm Mt bcm Mt bcm Mt 1996 0.3 1.5 0.3 1.5 0.3 1.5 0.3 1.5 0.3 1.5 1997 0.8 2.2 0.8 2.1 0.8 2.2 0.8 2.2 0.8 2.2 1998 1.4 2.4 1.4 2.4 1.4 2.5 1.4 2.4 1.4 2.4 1999 2.0 2.1 1.9 2.0 2.1 2.1 2.0 2.1 2.0 2.1 2000 1.7 2.8 1.9 2.0 1.9 2.9 2.1 2.0 2.5 1.0 2001 1.8 3.8 T2. -TO 3.9 2.3 3.0 3.0 1.2 2002 2.0 4.7 2.0 3.9 2.2 4.9 2.4 3.9 3.2 2.0 2003 2.3 4.9 2.2 3.9 2.6 4.9 2.7 4.1 3.5 2.2 2004 2.5 5.8 2.3 4.9 2.9 5.8 3.2 4.0 3.6 3.0 2005 3.3 5.9 3.0 4.9 3.5 5.9 4.1 4.0 4.5 3.0 2006 3.4 6.8 2.9 5.8 4.0 6.9 4.6 4.0 5.0 3.0 2007 3.9 6.8 3.2 5.8 4.5 6.9 5.1 4.0 5.6 3.0 2008 4.5 6.6 3.7 5.5 4.8 6.6 5.7 3.6 6.0 2.7 2009 4.8 6.6 3.9 5.6 5.3 6.6 5.6 3.7 5.8 2.7 2010 5.3 6.6 4.2 5.5 5.6 6.6 6.0 3.6 6.0 3.6 2011 6.4 6.6 5.47 7 . 3.7 7. 7 2012 7.2 6.7 6.6 5.6 7.8 6.9 7.9 4.0 7.9 4.0 2013 8.0 6.9 6.8 6.7 8.4 7.1 8.2 5.1 8.2 5.1 2014 8.5 7.2 7.6 6.8 8.8 7.3 8.5 7.2 8.5 7.2 2015 8.8 7.4 8.1 7.0 9.0 7.7 8.8 7.4 8.8 7.4 Source: Wasp results Annex 2.1.16 Son La Hydro Plant: NPV Analysis NPV of Son La Large, $M, Base Case Demand Low Demand evaluated up to year: 2010 -41 -128 2015 261 161 2017 333 303 2020 463 n/a Source: WaspRuns - 59 - Annex 2.1.17 Statistics and Projection of Power Production and Losses 1985 1990 1991 1992 1993 1994 1995 2000 2005 2010 planned planned planned Sale Power 3,866 6,185 6,575 6,941 7,833 9,284 11,185 Gwh Growth Rate 9.2 6.4 5.3 13.0 18.5 20.0 18.0 15.0 12.0 Self-services 1,201 2,493 2,569 2,723 2,823 3,000 3,451 5,474 8,187 10,330 and loss Gwh __ Self-service 23.7 28.7 28.1 28.2 26.6 24.4 23.6 18 15 12 and losses % Total 5,608 8,673 9,152 9,652 10,665 12,284 14,636 30,100 53,600 87,816 Production Gwh Source: Vietnam DSM Assessment - Phase 1, Hagler Bailly Consulting, Inc. Annex 2.1.18 DSM Program Demand Impact Year 2000 Gwh Saving Benefit/Cost NPV Program MW Gwh Ratio US$ mil. Load Management 535 1,968 13.2 396 Com'l Appl. Stands & Bldg. Codes 166 1,633 2.1 82 Residential Lighting Standards 92 277 6.8 114 Residential Refrigerators 39 268 4.0 25 Motor Standards 34 301 29.0 36 Industrial Audits 28 244 18.0 42 Large Project Energy Effic. Review 22 191 185.5 32 Industrial Lighting Efficiency 8 65 2.0 6 JV Internation Interim Bldg. Stands. 4 39 50.7 18 Public Lighting 2 145 3.5 23 Total Package Analyzed 930 5131 5.9 774 Source: Vietnam DSM Assessment - Phase 1, Hagler Bailly Consulting, Inc. - 60- Annex 2.1.19 Page I of 1 COMPARISON OF INVESTMENT PLANS 1998-2010 Low Demand Case Base Demand Case High Demand Case Total New Capacity in MW 1998 288 288 288 1999 1025 1025 1025 2000 1691 2117 2117 2001 2417 3777 3777 2002 300 4077 4677 2003 3605 4977 5577 2004 3905 5577 6427 2005 4805 6697 7847 2006 5325 7807 9307 2007 6175 8912 11247 2008 7375 10602 13447 2009 8835 12063 16163 2010 9640 14263 17763 Comparison of I nvesment Plans 1998-2010 20000 S18000 :~16000 aL 14000 *~DTad~ U 12000 10000 uBase Demand Case 13000 ~~~~~~~~~~~~~~~~High Deanad Case 0 Nc Nq 169 °° IV l - - le ° ° - 61 - Annex 2.1.20 Page 1 of I Summary of Generation Costs Case (Bow demand) (base demand) (high demand) Minimum generation costs to meet demand of each case - PV costs of Investments & Operating, to 3,614 4,678 5,261 2005 (PV $mill) ' - PV costs of Investments & Operating, to 5,814 8,001 9,843 2010 (PV$mill) - AIC cost, cents per kWh 2 3.9 4.2 4.5 Scope of Generation Investment - investments to 2005, $mill 2,800 3,931 4,495 - investments to 2010, $mill 6,092 9,522 12,322 - Investment as Percent of GDP, to 2010 3 1.2% 1L6% 1.9% Source: Mission estimates; WASP and PSDP models 'The cumulative present value (PV) of investment and operating costs, discounted at 10%. These cost estimates are calculated in the PSDP spreadsheet model and vary slightly from those calculated in WASP due to a slightly different calculation method (in particular, average fuel costs have been used over the whole period, rather than specific costs for each year, and the cost of energy not served has been omitted), but the ranking of cases by unit cost is the same. 2 The present value of incremental generation costs to 2015 divided by the present value of incremental energy generated, to give an indicator of average cost per unit of new electricity generation. 3 Calculated by the cumulative actual investment from 1997 to 2010 divided by the cumulative GDP over the same period, un-discounted. - 62 - Annex 2.1.21 Figure 1: Regional Character of Viet Nam's Power System Northern Region Central Region Southern Region Annex 2.1.22 Figure 2: Increasing Electricity Intensity per unit of GNP, 1974-1993 1 200.... _ { |- Pakistan _ * India -Malaysia 1000 . Philippines .Thailand E °) 800 _ x 0 200 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1988 1987 1988 1989 1990 1991 1992 1993 Source: Mission estimates based on World Bank statistics - 63 - Annex 2.1.23 Page I of 1 Figure 3: Monthly Generation Mix for the Year 2000 (Base case 50) 2500 2000 _ - -_ 1500 0 500 s~~~~~~~~~~~~~r a s E]Ohrtema 0 J F M A M J J A S 0 N D M onths 5000 4500~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 4000 . 3 5 0 0 J O ; 3500 3000 0 E 2500 0 J F M A M J J A S 0 N D M onthsl Source: WASP analysis, base case 50 - 64 - Annex 2.1.24 Figure 4: Typical Daily Load Curves (PC2, 1995) 1.2 E 0 8 'O0.6 10.4 E ........Wnter -....Summe 00.2 0 1 3 5 7 9 11 13 15 17 19 21 23 Hours Source: EVN statistics Annex 2.1.25 Figure 5: Annual Variation in Demand (1995) 1.2 0 0.6 0.2 z J F M A M i J A S 0 N D Months Source: Institute of Energy statistics - 65 - Annex 2.1.26 Figure 6: Comparative Generation Costs-New Plant 8,0 7.0j ' . .i Fixed w . ; bIe O&M6-0 nor68.0 .. . EFuel on . Capital co5. ck 4,0 ', Wh 3.0 2.0 10 0.0 CCGT: Gas ST: Coal ST: Coal ST: Coal ST: Coal ST: Fuel Oil GT: Diesel North North>EHV> South (Dom.) South (Imp.) Sth Source: Mission estimates Annex 2.1.27 Figure 7: Breakeven Fuel Prices (Netback Values) 4'C0 3.50 26 .00 3250 0i i 20 25 30 35 40 45 50 55 Coal price, $It (cif) Source: Mission estimates, based on 65% load factor and 10 A discount rate - 66 - Annex 2.1.28 Figure 8: Gas Demand in Power Generation 12.0~~~~~~~~~~~~~~nnx212 - Base Gas bcm E Low demand Gas bcm E0 3 .06. c -~~~~~~~~~~~High demand Gas E b5m 0 05 4-0-Base+ Nil Transfers '5 ~~~~~~~~~~~~~~~Gas barn 2.0 ~~~~~~~~~~~~~~~Base+ 'exports' Gas born 0.0 ~ ~ 0 C~'J 0 ej IT 0)0 0) 00 0 - - 0)0) 0 0 00 Source: WaspRuns Annex 2.1.29 Figure 9: Monthly Gas Swing (Base case) 0.45 0.40 0.35 0 0.30 0. 0.25 E 0.2 0 0.05 -21 0.00 J F M A M i J A S 0 N D Months Source: PSDP-6 - 67 - Fuel Use Forecasts - Fuel Consumption in Power Generation 10 . O80: HT : : 9 * 50: BT . ... . 60: LT E in:m82: H su- S ~~~0 52: B/ '; gr z40-1 _*w62: L g X mi :- 3 -~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~--- T ....... t 0..= 2 t .E-0i~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~.. .. ... ... . C~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~C '0t ::(@ ' 't ?;9 ( X 0~~~~~~~~~~~~~~~~o Fuel Use Forecasts - Fuel Consumption in Power Generation mo80: HT N 0~~~~~~5:B 8 2D* o _ 52: B ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ - mm*4~~~~~~~~62: L ~ ~ ~ ~ ~ ~ ~ Annex 2.1.31 Page 1 of I Generation Forecast for the year 2005 0.50 0.45 0 40 0 0.35 CL 0.30 E 10 0.25 0.20 E 0.15 0 ~ ~ 20 0.0 0.00 J F M A M J J A SON D Months -70 - Annex 2.2 ANNEX 2.2. UPSTREAM OIL AND GAS 2.2.1. Exploration activities in Vietnam ......................................... 72 2.2.2. Exploration History and Discovered Reserves Potential ......................................... 73 2.2.3. Expected Oil and Associated Gas Production ......................................... 74 2.2.4. Production Prospects from Speculative Gas Reserves (bcm) - Nam Con Son Basin ......................................... 75 2.2.5. Production Prospects from Speculative Gas Reserves (bcm) - Son Hong Basin ......................................... 76 2.2.6. Estimates of Development Cost of Associated Gas ......................................... 77 2.2.7. Development Cost Estimates of Non Associated gas - Lan Tay, Lan Do & Hai Thach ......................................... 78 2.2.8. Development Cost and Associated Gas Economic cost - Cuu Long Basin ......................................... 79 2.2.9. Hydrocarbon Production and Supply Cost of Gas .............. ........................... 80 2.2.10. Cost of Exploration and Development for Speculative Reserves .81 Graphs: 2.2.11. Potential Oil Production from discovered reserves- Cuu Long Basin .82 2.2.12. Potential Gas production from discovered reserves - Cuu Long and Nam Con Son (Blocks 6.1 and 5.2) .83 - 71 - Annex 2.2.1 Page 1 of 1 Exploration Activities in Vietnam ward Block Basin Operator Wellse Discoveries Awarded _ _ Drilled 1969 Red River Petrovietnam Gas (Tien Hai, 1975) 1974 12, 04 N Con Son Pecton 4 Oil 1975 09, 05 C Long S, N C Son Mobil 1, 1 Bach Ho, Dia Hung 1978 28, 29 N C Son Bow Valley 2 Dry 15 C Long Deminex 4 1979 04, 12 N C Son Agip 6 Gas in 12 1981 05, 10, 11 N C Son Veitsovpetro 4 Oil (Dai Hung 1988) 09, 15 C Long Vietsovpetro 5 Oil (Bach Ho, Rong 1980) 1988 06, 12E,19 N C Son ONGC 2 Gas in 6 (Miocene Lst) 112,114,116 S Hong Shell Relinquished 106 S Hong Total 3 Relinquished 1989 117,118,119 S Hong British Petroleum Gas (C02>70%) 115 S Hong IPL 22 N C Son Cairn 17,21 C Long, N C Son Enterprise 5 21 Relinquished 46,50,51 Malay Thu Chu Petrofina 111 S Hong Sceptre 03,12W,20 N C Son Petro-Canada 1991 120,121 S Hong BHP 01,02 C Long Petronas Oil (Ruby&Emerald 1994) 1992 10 N Con Son Shell 3 Relinquished 1996 11-02 N C Son PEDCo 8 Gas (R Doi & R V Dai) 05-03 N C Son AEDC-Teikoku, 4 Gas (Moc Tinh, 1993) Mobil, BP, Statoil 05-2,06,12E N C Son BP, S Statoil, 5 Wet Gas (Hai Thach,1995) ONGC 11-1 N C Son Total 3 Oil & Gas (Ca Cho 1995) 102 Red River Idemitsu 04-2, 04-1 N C Son Lasmo - Cieco 15-2 C Long JVPC 5 Oil (Rang Dong, 1994) 04-1 N C Son British Gas 04-3 N C Son Occidental 1993 05-la N C Son BHP 3 Oil (Dai Hung) Onshore Red River Anzoil I Gas (Song Tra Ly) 104 S Hong OMV 1994 05-lb N C Son Mobil (MJC) 2 Oil&Gas (Thanh Long Tay) 05-2 N C Son BP, Statoil 5 Oil & Gas (Kim Cuong Tay and Hai Thach 1995) 1995 133, 134 N C Son Conoco 1996 B-52, B-54 Malay Thu Chu Unocol - 72 - Annex 2.2.2 Page 1 of I Exploration History and Discovered Reserves Potential Wells Potential Reserves Total Reserves Year Drilled Discoveries Oil AG NAG Accretion Company _____ ____________ MMbIs Bcm Bcm MMboe MMboe 1970 6 Tai Hai 2.83 18 6 18 Petrovienam 1971 2 0.00 8 18 1972 0.00 8 18 1973 0.00 8 18 1974 5 Bach Ho 300 5.10 0.00 332 13 350 Mobil 1975 1 0.00 14 350 1976 2 0.00 16 350 1977 0.00 16 350 1978 1 0.00 17 350 1979 8 0.00 25 350 1980 2 0.00 27 350 1981 Bach Ho 650 14.16 0.00 739 27 1089 Vietsovpetro 1982 0.00 27 1089 1983 0.00 27 1089 1984 3 0.00 30 1089 1985 0.00 30 1089 1986 0.00 30 1089 1987 1 Dia Hung 150 3.97 0.00 175 31 1264 MobilNVSP 1988 0.00 31 1264 1989 1 0.00 32 1264 1990 9 0.00 41 1264 1991 9 0.00 50 1264 1992 4 Lan Do 11.90 75 54 1339 BP 1993 16 Lan Tay, Moc Tinh, 110 2.83 95.18 726 70 2065 BP R Doi 1994 21 R Dong, Ruby, 680 25.50 840 91 2905 JVPC, Mobil Emerald 1995 17 H Thach, ANZ 90 28.33 268 108 3173 BP, ANZOIL 1996 18 Bunga:Kekwa,Orkid 70 9.92 19.83 126 3173 ,Raya 1997 8 134 3173 TOTAL 126 2050 61 158 3173 Reserves Discovered v.s Exploration Drilling 4000 3500 3000 8 2500 2000 1500 1000 . * * 500 0 t I I I 0 20 40 60 80 100 120 140 Number of Exploration Wells - 73 - Expected Oil and Associated Gas Production From Discovered Reserves Oil Production MMbls Associated Gas Bcm Condensate LPG Year Bach Ho R Dong Ruby Others* Total Bach Ho R Dong Ruby Others Total MM bls MM tone 1997 52.0 8.4 60.4 1.26 1.3 1.08 1998 58.5 13.1 8.4 73.0 1.42 0.34 1.8 1.50 1999 66.0 19.7 9.1 9.5 87.8 1.60 0.47 0.24 2.3 1.97 2000 66.0 26.3 13.7 11.0 95.4 1.60 0.47 0.36 2.4 2.07 0.31 2001 56.1 32.8 18.2 17.0 107.0 1.36 0.85 0.47 0.33 3.0 2.58 0.39 2002 47.7 32.8 18.2 20.0 103.8 1.16 0.85 0.47 0.39 2.9 2.46 0.37 2003 40.5 32.8 18.2 21.0 98.9 0.98 0.85 0.47 0.41 2.7 2.32 0.35 2004 34.5 32.8 18.2 19.0 95.6 0.84 0.85 0.47 0.37 2.5 2.17 0.33 2005 29.3 32.8 18.2 17.5 92.3 0.71 0.85 0.47 0.34 2.4 2.03 0.31 2006 24.9 32.8 15.8 16.3 84.8 0.60 0.85 0.41 0.32 2.2 1.87 0.28 2007 21.2 29.3 13.5 15.4 74.7 0.51 0.76 0.35 0.30 1.9 1.65 0.25 2008 18.0 22.6 11.5 13.1 61.3 0.44 0.59 0.30 0.26 1.6 1.35 0.21 2009 15.3 17.2 8.1 11.1 48.1 0.37 0.45 0.21 0.22 1.2 1.07 0.16 2010 13.0 13.5 5.6 10.3 37.8 0.31 0.35 0.15 0.20 1.0 0.87 0.13 2011 11.0 10.2 3.9 6.8 20.9 0.27 0.27 0.10 0.13 0.8 0.66 0.10 2012 9.4 7.7 2.6 4.8 15.1 0.23 0.20 0.07 0.09 0.6 0.50 0.08 2013 8.0 6.0 1.8 2.5 10.3 0.19 0.16 0.05 0.05 0.4 0.38 0.06 2014 6.8 4.6 1.2 1.7 7.5 0.16 0.12 0.03 0.03 0.3 0.30 0.05 2015 5.8 3.5 1.2 4.7 0.14 0.09 0.00 0.02 0.3 0.22 0.03 2016 4.9 2.6 0.8 3.4 0.12 0.07 0.00 0.02 0.2 0.17 0.03 Total 588.9 373.1 177.8 215.8 1182.8 14.3 9.5 4.6 3.5 31.9 27.2 3.45 -o CD C Production Prospects From Speculative Gas Reserves (Bcm) NAM CON SON BASIN Discovery date 1997 1998 1999 - 2000 2001 2002 2003 2004 2005 2006 2007 2008 Total Expected Gas 23 48 48 0 0 0 0 24 0 24 20 12 0 199 Reserves Bcm On Stream 2001 2002 2003 0.57 0.6 2004 1.13 1.20 2.3 2005 1.13 2.41 1.20 4.7 2006 1.13 2.41 2.41 0.0 5.9 2007 1.13 2.41 2.41 0.0 0.0 5.9 2008 1.13 2.41 2.41 0.0 0.0 0.0 5.9 2009 1.13 2.41 2.41 0.0 0.0 0.0 0.0 5.9 2010 1.13 2.41 2.41 0.0 0.0 0.0 0.0 0.60 6.6 2011 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 7.2 2012 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 0.60 7.8 2013 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.50 8.9 2014 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.30 9.6 2015 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 10.0 2016 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 10.0 2017 1.08 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 9.9 2018 0.97 2.18 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 9.6 2019 0.83 1.86 2.29 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 9.0 2020 0.67 1.50 2.05 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 8.2 2021 0.52 1.18 1.71 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 7.4 2022 0.40 0.91 1.35 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 6.7 2023 0.31 0.70 1.03 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 6.0 > 2024 0.24 0.54 0.78 0.0 0.0 0.0 0.0 1.14 0.0 1.20 0.99 0.60 5.5 a 2025 0.19 0.43 0.59 0.0 0.0 0.0 0.0 1.02 0.0 1.20 0.99 0.60 5.0 >x Total 19.9 41.8 42.3 0.0 0.0 0.0 0.0 18.4 0.0 16.3 12.4 6.9 159 o Production Prospects From Speculative Gas Reserves (Bcm) SON HONG BASIN Discovery date 1997| 1998 1999 2000 2001 |202 2003 2004 0062007 2008 2009 Total Expected Gas 12 0 0 48 24 24 12 0 0 24 0 12 0 157 Reserves Bcm___ On Stream 2001 2002 2003 2004 0.30 0.30 2005 0.60 0.00 0.60 2006 0.60 0.00 0.00 0.60 2007 0.60 0.00 0.00 1.20 1.80 2008 0.60 0.00 0.00 2.39 0.60 3.59 2009 0.60 0.00 0.00 2.39 1.20 0.60 4.79 2010 0.60 0.00 0.00 2.39 1.20 1.20 0.30 5.69 2011 0.60 0.00 0.00 2.39 1.20 1.20 0.60 0.00 5.99 2012 0.60 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 5.99 2013 0.60 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 0.60 6.58 2014 0.60 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 1.20 0.00 7.18 2015 0.60 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 1.20 0.00 0.30 7.48 2016 0.60 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 1.20 0.00 0.60 7.78 2017 0.60 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 1.20 0.00 0.60 7.78 2018 0.54 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 1.20 0.00 0.60 7.72 2019 0.46 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 1.20 0.00 0.60 7.64 2020 0.37 0.00 0.00 2.39 1.20 1.20 0.60 0.00 0.00 1.20 0.00 0.60 7.56 2021 0.29 0.00 0.00 2.28 1.20 1.20 0.60 0.00 0.00 1.20 0.00 0.60 7.36 2022 0.23 0.00 0.00 1.93 1.14 1.20 0.60 0.00 0.00 1.20 0.00 0.60 6.89 2023 0.17 0.00 0.00 1.64 0.97 1.14 0.60 0.00 0.00 1.20 0.00 0.60 6.32 > 2024 0.14 0.00 0.00 1.40 0.82 0.97 0.57 0.00 0.00 1.20 0.00 0.60 5.69 2025 0.11 0.00 0.00 1.19 0.70 0.82 0.51 0.00 0.00 1.20 0.00 0.60 5.12 _x Total 10.4 0.0 0.0 40.8 19.8 19.1 9.2 0.0 0.0 15.0 0.0 6.3 0.0 120.4 o Annex 2.2.6 Page 1 of 1 Estimates of Development Cost of Associated Gas Million US $ 1996 Year MM$ 1 2 3 4 5 Total Exploration and Delineation 0 0 Feasibility & Front Engineering 4 4 Drilling& Completion of Wells 0 0 0 Offshore Structures (Water Depth:60 m) 30 10 20 Utilities 20 3 4 6 7 Dehydration and Compression 70 11 14 21 25 Floating Storage & Off-loading 0 0 0 Offshore Pipelines (16, 120 km & 12", 150 km) Line pipes, valves and fittings 41 20 20 Transport 4 2 2 Coating, Laying, Hook-up 118 18 47 53 Compression 30 5 12 14 EPC and Management 47 5 5 14 14 9 Contingencis 54 1 3 1 1 20 19 LPG Facilities 90 18 36 36 Total Cost (Excluding Bach Ho Pipeline) 503 6 39 124 188 146 -77- Annex 2.2.7 Page 1 of I Lan Tay, Lan Do and Hai Thach Development Cost Estimates Oil and gas Most likely Scenario Million US $ 1996 Lan Tay and Lan Do Year 1 MM [ 1 2 3 4 5 Total Exploration and Delineation 60 60 Feasibility & Front Engineering 2 2 Drilling& Completion of Wells 98 32 66 Flowlines 24 8 16 Offshore Structures (Water :125 m) & Facilities 76 11 15 23 27 Process Facilities (Oil and Gas), onshore 125 19 25 38 44 Floating Storage & Off-loading 0 0 0 Offshore Pipelines (24",380 km) Line pipes, valves and fittings 140 70 70 Transport 14 7 7 Coating and Laying 173 26 69 78 Phase I Compression 18 3 7 8 EPC and Management 84 8 8 25 25 17 8 8 7 10 11 Contingencies 113 2 6 26 42 38 Total Cost (Excluding Exploration Cost) 866 12 44 197 321 293 Facilities 12 44 54 127 187 Pipelines 0 0 142 194 106 Cost / Well MM$ Platform wells Wells 8 6 Sub-sea Wells 2 25 Flowlines: km/well 4 Hai Thach Field Year MM S 1 2 3 4 - Total Exploration and Delineation 80 80 Feasibility & Front Engineering 10 10 Drilling& Completion of Wells 120 40 80 Flowlines 24 8 16 Offshore Structures 120 18 24 36 42 Topside Facilities (Oil and Gas) 175 26 35 53 61 Floating Storage & Off-loading 60 24 36 Offshore Pipelines (20", 40 km) Line pipes, valves and fittings 12 6 6 Transport 3 2 2 Coating and Laying 18 3 7 8 Phase I Compression 0 0 0 0 EPC and Management 80 8 8 24 24 16 8 8 20 22 15 Contingencis 92 3 8 14 30 39 Total Cost (Excluding Exploration Cost) 714 21 60 107 228 299 Facilities 21 60 91 209 289 Pipelines 0 0 16 19 10 Cost / well MM $ Platform wells Wells 10 12 Sub-sea Wells 0 25 Flowlines: km/well 4 - 78 - Development Cost and Associated Gas Economic Cost Cuu Long Basin Associated Gas Bcm LPG Capital Cost MM$ Operating Expenses MM$ Year MMcmd MM Ton Field Pipelines LPG Total Field & Pipelines LPG Total Bach Ho R Dong Ruby Others Total Stractures Offshore Onshore Facilities Compress Offshore Onshore 1997 1.26 1.3 3.5 0.15 1998 1.42 0.34 1.8 4.8 0.21 18.00 18.0 36.0 1999 1.60 0.47 0.24 2.3 6.3 0.28 24.00 59.0 40.0 36.0 159.0 2000 1.60 0.47 0.36 2.4 6.6 0.29 49.00 107.0 30.0 36.0 222.0 5.5 4.2 1.8 5.4 16.8 2001 1.36 0.85 0.47 0.33 3.0 8.3 0.34 68.00 88.0 30.0 186.0 9.5 6.4 2.5 5.4 23.8 2002 1.16 0.85 0.47 0.39 2.9 7.9 0.33 9.5 6.4 2.5 5.4 23.8 2003 0.98 0.85 0.47 0.41 2.7 7.5 0.32 9.5 6.4 2.5 5.4 23.8 2004 0.84 0.85 0.47 0.37 2.5 6.9 0.30 9.5 6.4 2.5 5.4 23.8 2005 0.71 0.85 0.47 0.34 2.4 6.5 0.28 9.5 6.4 2.5 5.4 23.8 2006 0.60 0.85 0.41 0.32 2.2 6.0 0.26 9.5 6.4 2.5 5.4 23.8 2007 0.51 0.76 0.35 0.30 1.9 5.3 0.23 9.5 6.4 2.5 5.4 23.8 2008 0.44 0.59 0.30 0.26 1.6 4.3 0.19 9.5 6.4 2.5 5.4 23.8 2009 0.37 0.45 0.21 0.22 1.2 3.4 0.15 9.5 6.4 2.5 5.4 23.8 2010 0.31 0.35 0.15 0.20 1.0 2.8 0.12 9.5 6.4 2.5 5.4 23.8 2011 0.27 0.27 0.10 0.13 0.8 2.1 0.09 9.5 6.4 2.5 5.4 23.8 2012 0.23 0.20 0.07 0.09 0.6 1.6 0.07 9.5 6.4 2.5 5.4 23.8 2013 0.19 0.16 0.05 0.05 0.4 1.2 0.06 9.5 6.4 2.5 5.4 23.8 2014 0.16 0.12 0.03 0.03 0.3 1.0 0.04 9.5 6.4 2.5 5.4 23.8 2015 0.14 0.09 0.00 0.02 0.3 0.7 0.03 9.5 6.4 2.5 5.4 23.8 2016 0.12 0.07 0.00 0.02 0.2 0.6 0.02 9.5 6.4 2.5 5.4 23.8 Total 14.3 9.5 4.6 3.5 31.9 3.77 159.0 254.0 100.0 90.0 603.0 158.1 105.8 41.8 91.8 397.4 Source: World Bank Mission, October 1997 -oo Hydrocarbon Production and Supply Cost of Gas (without taxes and royalties) Gas Development: Block 6.1 &5.2 Lan Tay, Lan Do and Hai Thach Fields fifiliomU.SS 1996 Year Sala Gas (Bcm) Condesuate (MMbls) LPG (1M tone) Explonaion _ Operating Expen Bk61 Bk 5.2 Total Bk61 BkS.2 Total Bk6 Bk 5.2 Total F1ild Pipeline Told Fild P4dilins Toda Bk6.1 Bk 5.2 Blk6.1 Bk 5.2 O,sho Rk 61 Bk 15.2 Bk61 Bkr5.2 Onsho re r 1997 140 12.0 152.0 1998 0.00 44.0 44.0 1999 0.00 54.0 21.0 142.0 217.0 2000 1.20 1.20 0.06 0.00 0.06 127.0 60.0 194.0 381.0 11.9 11.9 2001 2.07 2.07 0.45 0.45 0.10 0.00 0.10 187.0 91.0 106.0 16.0 15.0 415.0 23.1 8.6 6.63 0.23 38.5 2002 2.33 2.33 0.76 0.76 0.10 0.00 0.10 209.0 19.0 228.0 23.1 19.1 6.63 0.23 49.0 2003 2.63 1.12 3.75 0.75 3.83 4.58 0.10 0.09 0.00 0.19 289.0 10.0 299.0 23.1 33.5 6.63 1.13 0.23 64.6 2004 2.63 1.82 4.45 0.75 6.81 7.56 0.10 0.15 0.00 0.25 23.1 33.5 6.63 1.13 0.23 64.6 2005 2.63 1.82 4A5 0.74 6.61 7.35 0.10 0.15 0.00 0.25 23.1 33.5 6.63 1.13 0.23 64.6 2006 2.63 1.82 4.45 0.73 6.43 7.16 0.10 0.15 0.00 0.25 23.1 33.5 6.63 1.13 0.23 64.6 2007 2.63 1.82 4.45 0.73 6.25 6.98 0.10 0.15 0.00 0.25 23.1 33.5 6.63 1.13 0.23 64.6 2008 2.63 1.82 4.45 0.72 6.07 6.79 0.10 0.15 0.00 0.25 15.0 15.0 23.8 33.5 6.63 1.13 0.23 65.3 2009 2.63 1.82 4.45 0.71 5.90 6.61 0.10 0.15 0.00 0.25 12.0 120 24.4 33.5 6.63 1.13 0.23 65.9 2010 2.63 1.82 4.45 0.70 5.72 6.42 0.10 0.15 0.00 0.25 12.0 12.0 25.0 33.5 6.63 1.13 0.23 66.5 2011 2.63 1.82 4.45 0.69 5.54 6.23 0.10 0.15 0.00 0.25 25.0 33.5 6.63 1.13 0.23 66.5 2012 2.63 1.82 445 0.69 5.37 6.06 0.10 0.15 0.00 0.25 25.0 33.5 6.63 1.13 0.23 66.5 2013 2.63 1.82 4.45 0.68 5.19 5.87 0.10 0.15 0.00 0.25 25.0 33,5 6.63 1.13 0.23 66.5 2014 2.63 1.82 4.45 0.67 5.00 5.67 0.10 0.15 0.00 0.25 25.0 33.5 6.63 1.13 0.23 66.5 2015 2.63 1.82 4.45 0.66 4.82 5.48 0.10 0.15 0.00 0.25 25.0 33.5 6.63 1.13 0.23 66.5 2016 2.63 1.82 4.45 0.65 4.62 5.27 0.10 0.15 0.00 0.25 25.0 33.5 6.63 1.13 0.23 66.5 2017 2.21 1.82 4.03 0.64 3.61 4.25 0.08 0.15 0.00 0.23 25.0 33.5 6.63 1.13 0.23 66.5 2018 1.88 1.82 3.70 0.50 2.83 3.33 0.07 0.15 0.00 0.21 25.0 33.5 6.63 1.13 0.23 66.5 2019 1,61 1.52 3.14 0.39 2.23 2.62 0.05 0.12 O.00 0.17 20,0 33.5 6.63 1.13 0.23 61.5 2020 1.29 1.27 2.56 0.31 1.76 2.07 0.04 0.10 0.00 0.14 16.0 33.5 6.63 1.13 0.23 57.5 2021 1.03 1.06 2.09 0.25 1.40 1.65 0.03 0.09 0.00 0.12 12.8 26.8 6.63 1.13 0.23 47.6 2022 0.29 0.89 1.17 0.19 1.11 1.30 0.03 0.07 0.00 0.10 10.2 24.1 6.63 1.13 0.23 42.3 2023 023 074 0.97 0,15 0.78 0.93 0.02 0.06 0.00 0.08 8.2 21.7 6.63 1.13 0.23 37.9 2024 0.62 0.62 0.54 0.54 0.05 0.00 0.05 19.5 6.63 1,13 0.23 27.5 2025 0.52 0.52 0.38 0.38 0.04 0.00 0.04 17.6 6.63 1.13 0.23 25.6 Total 5 1 35 86 15.5 92.8 186.3 2.0 2.8 4.8 140.0 463.0 670.0 442.0 45.0 15.0 1775.0 514.0 740.4 165.8 28.9 5.6 1451.7 Supply Cost of Gas form Blocks 6.1&5.2 (without taxes and royalties) Supply Cost of Gas form Block 6.1 Only (without taxes and royalties) us S/'MMbfteu Supply Cost of Gas form Blocks 6.1 and 5.2 (without taxes and royalties) flS SIMbtu Discount Rate 15% Discount Rate 15% laniant Van Liquids Value Jxploration Wellhead Phu Liquid Exploration Welhlead Pho Cost Y s cost My Value Includ Included 0.92 1.49 Includ Included 1.10 95 ed1 ed Includ Excludet 1.47 1.25 Includ Excluded 1.01 1.59 It ed ed go Excluded Included 1.72 2.29 Excluded Included 1.37 2.22 (D CD Excluded Excluded 1.47 2.35 Excluded Excluded 1.01 1.86 _ Heat Value; 1000 Oil Price 8/ 18.0 LPG Price 120.O O Btu/Scf bl S/tone Source: World Bank Mission, October 1997 Cost of Exploration and Development for Speculative Reserves Cost MM $ 1996 Year Plays Finds Seismic Expl. Expected No.of Seismic Total Wells Reserves Wells Drilling Facilitie s 1km Discov. Dry Gas Oil Dev. Infill Explo. Dev. Infill S/Total (1) Bcm mmbls 1997 2 1 3000 1 5 24 2.1 62 62 64 1998 6 2 2000 2 9 60 1.4 114 114 115 1999 4 1 4000 1 5 48 30 7 2.8 62 42 104 115 222 2000 1 0 6000 0 1 0 80 19 4.2 10 .114 124 537 665 2001 4 1 4000 1 5 48 0 20 2.8 62 120 182 978 1163 2002 4 1 2000 1 5 24 10 3 1.4 62 18 80 808 889 2003 4 1 5000 1 5 24 150 15 3.5 62 90 152 499 655 2004 10 2 5000 2 9 36 30 9 3.5 114 54 168 617 788 2005 2 0 2000 0 1 0 70 33 3 1.4 10 198 208 638 847 2006 10 2 4000 2 9 24 10 17 8 2.8 114 102 216 601 820 2007 12 2 2000 2 9 44 0 12 8 1.4 114 72 186 531 718 2008 6 1 5000 1 5 12 40 9 1 3.5 62 54 6 122 332 458 2009 6 1 1000 1 5 12 100 14 6 0.7 62 84 36 182 482 664 00 2010 2 0 2000 0 1 0 0 11 4 1.4 10 66 24 100 638 740 73 14 47000 15 74 357 520 169 30 32.9 920 1014 66 2000 6775 8808 ASSUMPTIONS Success Ratio 1/4 -1/8 Drilling MM $ Cost/Well Drilling Ratios Exploration well 12 Facilities $/ boe 3 Delineation/deve 1/4 Exploration well 10 lopment InfilV 1/2 Development / 6 Development Infill Source: World Bank Mission, October 1997 ° s- Potential Oil Production From Discovered Reserves Cuu Long Basin 120 -I,~ . . . .. ... . 100 220 80.... 00 ~~60 40 2 0 0 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 O Bach Ho ES R Dong LS Ruby El Others - -; Potential Gas Production From Cuu Long & Nam Con Son Basin (Bk-6.1 & Bk-5.2) 7.00 - _.... 6.00 5.00- *~4.00 Q3.00- W- 2.00 1.00- 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 LiAG-Cuu Long 0 NAG Bk-6.1 MNAG Bk-5.2 rD Annex 2.3. ANNEX 2.3. DOWNSTREAM OIL AND GAS 2.3.1. A note on issues in gas pricing .......................... 85 2.3.2. Organization of PVGC .......................... 96 - 84 - Annex 2.3.1 Page 1 of 11 A NOTE ON ISSUES IN GAS PRICING Background 1. Pricing of natural gas is a new issue in Viet Nam. It has been contentious in all countries especially because gas is a commodity that requires significant infrastructure in the form of a fixed transmission and distribution system. It has also been called a "continental" energy product because only a small fraction of natural gas is traded overseas. This differentiates the problem of natural gas pricing from oil pricing because oil prices are established through integrated markets worldwide. It also means that the balance of natural gas supply and demand within a country tends to swing from surplus to shortage, depending on discoveries and market developments, because export and import opportunities are not readily available. These features have called for more complicated and longer term contracting for gas than for oil. In almost all countries, natural gas development has lagged many years behind oil development, but since the energy crisis of the 1970's its day has come. 2. Some of the debates about natural gas pricing involve vicious circles: it is sometimes contended that gas prices must be determined before upstream fiscal terms may be set -- but the upstream fiscal terms play a part in determining the private supply cost of gas which has a bearing on the prices that are acceptable to producers. So, some analysts argue that fiscal terms and prices should be set together as a package. This argument assumes that prices and fiscal terms are necessarily rigid and not responsive to market or investor conditions. A viable arrangement both for prices and fiscal terms must assure that 1) gas prices are responsive to market conditions, notably to the price of alternative fuels competing with natural gas, and 2) fiscal terms are responsive to the actual profitability of investment and operations of gas suppliers. Gas prices, specified in supplier-purchaser contracts, are typically kept responsive to market conditions through indexing gas prices to the prices of alternative fuels, usually to the prices of heavy fuel oil and/or gasoil. Fiscal terms are made responsive to supplier economics by upstream fiscal systems that focus the government's royalties, or share of revenues, on the realized profits of suppliers, or proxies for profits. If either of these conditions are not met, it becomes extremely unlikely that a gas industry can be developed and sustained over the long term. 3. An effective strategy for developing the gas industry is therefore to separately pursue these objectives: a profit-responsive fiscal regime and a market-responsive gas pricing arrangement. The two thrusts can be pursued in sequence. In fact, Vet Nam has proceeded in this manner. The fiscal terms for development and production of Block 6.1 in the Nam Con Son basin have been negotiated and settled, and the parties are now negotiating a suitable gas pricing arrangement. 4. Thus, for natural gas development it is not necessary to first set gas prices, but it may be helpful first to establish a fiscal regime that is progressive, and satisfactory to government and industry over a range of gas prices and costs. Where production is more profitable, the government should get a larger share of revenues and the reverse. This may be done on a contract by contract basis, prescribed or by negotiation. It may be bid by contractors, subject to the guidance of a model contract, or it may be established as a generic regime for all projects. - 85 - Annex 2.3.1 Page 2 of 11 5. While natural gas prices can be made -- and for long term contract viability, must be made -- responsive to market conditions by indexing, there is still the issue of the initial level of prices. From the user's perspective, the price must be less than the price of an alternative fuel (allowing for investment and operating cost differences etc) that could be used for the same purpose. From the supplier's perspective the price must be sufficiently high to cover all the costs of supply and provide for replacing the gas that is produced. Some of the key issues in this balancing act, drawn from recent experience in Viet Nam, are illustrated below: Illustrative Sharing of Benefits from Offshore Gas Development in Viet Nam Value of Non-Cash Total State Share Prc Besh Benefits to Benefits of Total Price Benefits Gas to State Project Implications to PVN & Consumers Benefits per mcf G(NPV) (NPV) (NPV) (NPV) Too Low nil nil nil nil no project in short tern & also discourage other exploration & development i in long term Low 40% 60% 100% 90% develops market in short term but exploration & development slows down effecting longer term supply prospects Middle 50% 50% 100% 85% benefits balanced between upstream and downstream High 60% 40% 100% 80% more benefits upstrearn and private sector gets higher ROR, accelerates short term supply but slows market development Too High 100% nil or 100% 70% Consumers of gas do not negative share in benefits; short and long term excess supply. ___________ __________ ________ __________ Probably no project 6. Through computer cash-flow modelling of the Nam Con Son project, the probable sharing of economic benefits can be estimated along the lines illustrated above. The sharing of benefits from a successful project involves three considerations: 1) the balance between government and the private sector, 2) the balance between upstream and downstream participants, and 3) the balance between short term and longer term benefits to Viet Nam. - 86 - Annex 2.3.1 Page 3 of 11 1) Higher gas prices tend to shift benefits towards the upstream, and shift the share of benefits in favour of the private sector producers. However, the government's share remains high, in the order of 70% or more, and the upstream benefits can be collected in cash by govemment. 2) Lower gas prices shift the benefits towards the downstream: in this case to EVN and/or electricity consumers, and shift benefits away from the private sector producers. Gas prices must be high enough to encourage more exploration and development of gas, otherwise the gas industry will not develop and Viet Narn will become short of gas, even though the first project may be started. Another risk with lower gas prices is that gas may not be used efficiently and the downstream benefits would be dissipated within the gas consuming entities. Lower gas prices call for lower US dollar obligations through the gas chain. 3) Gas prices should balance the benefits between government interests, upstream and downstream, the government and the private sector, and short and long term considerations. 7. The floor price for gas -- on an ongoing basis -- must cover the producers' full cycle costs of supply. Otherwise the gas industry could not be sustained for lack of supplies. It may be argued that, having discovered gas, the gas price should cover only the half cycle costs to develop and produce it, but that would be short-sighted and would lead to a supply crisis in the longer termn: and perhaps sooner rather than later. Natural gas, of course, is a non-renewable resource and for a continuing gas industry, all the gas that is produced must be replaced through finding new supplies, and clearly, for an expanding industry which is the objective in Viet Nam, more new gas must be found than is produced. 8. For purposes of estimating an approximate floor price, the expected exploration, development, and operating costs, and the production levels for gas from the Nam Con Son basin have been estimated', and the results are summarized below. Estimates of Natural Gas Supply Costs, for Nam Con Son Gas Development (1997 dollars) Investments in Expl & Plateau Full Cycle Supply Cost, to Phu Devel and Pipelines Production levels My US$mill bcm/yr Without Taxes With Taxes & Royalties & Royalties US$/millBtu US$/millBtu Block 6.1 500 2.6 1.70 - 2.20 2.30 - 2.80 Block 5.2 660 2.1 1.30 - 1.80 na Pipelines 500 Notes: Assumes discount rate of 15% real for production, and 12% for pipelines. The range of supply costs is determined by production rates, cost contingencies, level of liquids production, etc. The private supply cost for Block 5.2 will depend on as yet unknown fiscal terms (Exploration amounts are also estimated). Total production of 50.3 bcm from Block 6.1 and 37.4 bcm from Block 5.2 is estimated. "Analysis of the Integrated Gas Chain", Herath and Malhotra, ASTDR Report No 16 - 87 - Annex 2.3.1 Page 4 of 11 9. The maximum market price for gas, is determined by the price that consumers would Just be willing to pay rather than to use an alternative fuel. The maximum value in the power sector is estimated to be in the range of US$3.60/mill Btu to US$4.00/mill Btu, which would give generation costs in a CCGT plant of between 4.50 cents per kWh to 4.75 cents per kWh . The estimated maximum or economic value of gas is summarized below: Maximum Value of Natural Gas in Various Uses US$ per mill Btu Electricity: Combined Cycle generation plant 2.75-7.00 Fertilizer Plant 2.20 to 2.60 Industry (depends on type of industry) 2.50 to 3.00 Mission estimates 10. A viable gas price must lie between the floor price and the maximum market value. However, both limits on this range will fluctuate. The floor price may decrease, for example if low cost gas is discovered, and the maximum price will increase if for example the price of alternative fuels increases. Therefore it is unlikely that a fixed gas price will be suitable over a long period of time. For this reason, given that gas contracts are typically long term, the majority of contracts worldwide contain gas prices that are indexed to the fuel oil price. The contracts typically include a "base" price and an indexation of the base price linked to fuel oil, and sometimes to gasoil. The result is a long term contract -- and a long term commitment to buy and sell gas -- but with some short term flexibility of price. Many contracts also have a clause in them that provides for periodic renegotiation of at least some of the pricing terms, for example of the design of the price index. The gas buyer looks for an indexation that ensures competitiveness of the gas price, against other fuels, at the burner tip. For example, a power generator will link the gas price to prices of alternative fuels for power generation such as oil products and sometimes coal. Some principles of gas price indexing are summarized below: - 88 - Annex 2.3.1 Page 5 of 11 Principles of Gas Price Indexing Principles Comments The gas consumer: as buyer of gas, wants an Example: Power companies all over the index that ensures competitiveness of the gas world link gas price to alternative fuels price against his alternative fuels, delivered to his such as coal and fuel oil (Canada, US, plant. Europe, Thailand). An index should not introduce volatility and Many indexes use several terms in them uncertainty into the price but should shift the and use averages over a number of months price gradually so that the gas price keeps in line or years, to smooth out random with alternative fuels, after a lag. fluctuations, and/or they use formulas that smooth out fluctuations An index is not intended to introduce speculation Example: a simple index of inflation or bias in the price but rather to be fair to both the would be biassed upwards and unfair to seller and the buyer. the buyer. The components of an index should reflect the While one of EVN's alternatives is coal, actual fuel alternatives available to the gas buyer, the seller would not accept indexing the in the region where the gas is delivered. In the gas price to domestic coal prices because case of EVN, the alternatives are fuel oil and coal. coal prices to EVN are capped by MPI and The components are sometimes weighted in the SCP. An international coal price index index, in the ratio that the alternative fuels might could be used. But a suitably designed be used by the consumer. index using only fuel oil would be simpler and should suffice. The index used for the purchase of gas by PVGC If the sales and purchase indexes are not should be the same as the index used for pricing the same, PVGC could be squeezed in the the sale of gas to its main customer, EVN. middle. 11. In most countries gas prices are indexed to fuel oil and often to gasoil. Some indexes contain a ceiling and a floor so that gas prices would not spurt up or collapse if the international oil market is upset. - 89- Annex 2.3.1 Page 6 of 11 Example Gas Price Indexes Components of Index Thailand: Proposed Gas price to annual average crude price imported into Japan, as Private Sector Power Plants reported in Japan Exports and Imports Monthly. annual average coal price of Australian coal sold under one year contracts to Japanese buyers, for 6,700 kcal/kg coal as reported in The Tex Report. average price of other gas from the "Thai Gas Pool". The price is the average of field prices which themselves are (Note: the estimated price of gas indexed to fuel oil and some other factors, as below. to be sold to an independent power plant in year 1999 is There is also an adjustment for inflation but only up to the US$3.54 per mill Btu) time of first delivery of the gas. Thailand: Prices at gas fields each field has a similar but slightly different pricing formula. The main index components are fuel oil, but there are also small components related to petroleum equipment costs and US inflation. This was introduced because the field fiscal terms did not properly take into account field costs. The Thai prices include a "ceiling" price and a "floor" price, as well as a "normal " price. Canadian: Gas exports to US monthly average of HFO prices, plus power plant (15 year contract) average spot gas prices last month the index is of form that majority have: Gas price in year t = Base gas price* (A* HFOt/HFOb+B* SPOTgast/SPOTgasb) Canadian: Gas export to US monthly average of LFO and HFO power plant (15 year contract) average other gas prices in same region form of index as above end of every 3 years the price index may be renegotiated at request of one party and acceptance by other. Japan, Brazil, Colombia and West some West European countries have a base gas price plus European countries: gas prices a weighted alternative fuel price. are generally linked to crude oil, form of index is additive: fuel oil or gasoil, and sometimes gas price in mill Btu in year t to coal Base gas price + A*(energy price per mill Btu of FOt). The A factor is called a "pass through factor" and is Pakistan, Egypt and Bolivia: gas reported to be in the range around 0.8 prices are fixed as a percentage of fuel oil or crude oil (e.g. 75% of The fixed percentage form of indexes is the energy value of fuel oil). In gas price per mill Btu in year t = the past, for a few years, Canada energy price per mill Btu of FO*0.75 also had this arrangement. The Thai ceiling prices are in this index form - 90 - Annex 2.3.1 Page 7 of 11 12. Most of the gas contracts in North America index gas prices to fuel oil prices and to other natural gas prices, for example to spot gas prices in neighbouring markets. The use of other gas prices is well suited to conditions in a developed market such as in the United states and Canada, but is not feasible in Viet Nam. The ceiling and floor price provisions of the Thai contracts may be useful. A few contracts in Europe and the Thai contracts include an inflation index, with a small weighting, as one of the factors in the gas price index, but none of them to our knowledge index the gas price solely to US inflation. Such an inflation index is obviously biassed upwards and therefore one sided in favour of the seller. Gas contracts in North America in the 1950s and 1960s often included a simple escalation clause such as a price increase of a few cents per mcf per year, or a small percentage increase, but as soon as oil prices became erratic and higher in the 1970s these contracts were unsustainable and were either broken or re-negotiated. The idea of simple escalation has recently been revived, probably because of the past decade or so of relatively stable oil prices and inflation rates, but it is liable to the same upsets as occurred in the 1970s and therefore does seem like a viable solution for long term contracts. 13. At the initial stages of gas development it has sometimes been the practice of governments to reference the wellhead price to the costs of field appraisal and development, with exploration costs treated as sunk. While this practice may lead initially to low prices for consumers -- if indeed the project proceeds, it has not proved sustainable in the longer term. The problem is that producers will not have incentive to explore for more gas and within a few years gas supplies will be short. An example of this has been the experience of Indonesia. It has recently had to abandon this pricing policy because it was counter-productive in developing its extensive gas reserves. An infamous natural gas shortage occurred, for the same reasons, in the United States during the 1970's. At that time gas prices for gas shipped between the individual States were controlled by the US Federal Power Commission, on the basis of their estimates of supply costs. As in Canada, when oil prices increased in the 1970s this pricing arrangement became unsustainable: no producers wanted to explore for gas because of the relatively low govermnent controlled prices and consumers wanted more gas. There was a huge government created excess demand for gas. Legislation had to be changed and the gas price had to increase, more in line with alternative fuels, to balance supplies and demand. 14. Price indexing brings to a long term contract the advantages of some price flexibility so that the risk of the gas price becoming unacceptable either to the sellers or the buyers is much reduced. The potential foreign exchange advantages should also be mentioned because a suitable index related to oil products, say fuel oil, will tend to hedge Viet Nam's foreign exchange exposure. This is because Viet Nam is a net exported of petroleum products. For example, if the international oil price increases, the natural gas price would increase although less depending on the index weighting and government "take" from profit sharing will increase. The result is that net foreign exchange payments for natural gas will increase less than crude oil export revenues. At the same time the slightly increased gas price will stimulate more gas to be developed. Finally, it should be noted that should oil prices remain constant in real dollar terms, then the oil price and to a degree the gas price, would track US inflation. The long term trend of real dollar oil prices has been about constant over the past 50 years. 15. Natural gas prices in the industrialized countries are generally much higher than in less developed countries. They are typically close to the maximum market values of gas when compared to other fuels at the "bumer tip". This reflects competitive markets and developed pipeline systems, and gas prices are essentially "market determined". The gas price is determined at the market end of the gas chain and the suppliers at the other end of the chain receive a "netback" at the gas field equal to the market price less transportation costs for delivery. - 91 - Annex 2.3.1 Page 8 of II Approximate Range of Natural Gas Prices around the World, in 1997 Region US$ per mill Btu Comments Western Europe Competitive markets Wholesale 4.00 to 4.50 developed pipeline systems, Burner tip 5.00 to 7.00 producers receive netback at field North America Canadian border 3.00, Competitive Wholesale 3.00 to 4.00 markets, developed pipeline systems, Burner tip 4.50 to 5.50 producers receive netback at field South America Ranges widely by country. Wholesale 2.70 to 3.20 Burner tip 3.50 to 4.00 South Asia Pakistan was 2.50 wholesale, but has Wholesale 2.50 to 3.00 been revised upwards because of lack Burner tip 3.20 to 3.50 of exploration South East Asia Korea 5.50 plus (from LNG) Wholesale 3.00 to 3.50 Indonesia 3.00+ to power sector Burner tip 3.50 to 4.00 Thailand 3.00 + to EGAT Yadana at Thai border 3.00 Japan Wholesale 4.00 to 4.50 Bumer tip 4.50 to 5.50 this price is to the power sector. 16. In the past the "merchant" pipeline companies in industrialized countries would purchase gas on their own account and deliver a "bundled" commodity, without distinguishing the cost of the gas itself from its transmission cost. This is no longer the case and although gas prices are determined at the market end of the gas chain, the gas transmission tariff is established separately. The producers receive a netback consisting of the market price less the transportation tariff. 17. The un-bundling of transmission service from the gas commodity has been an important step towards more efficient gas markets in these countries. Viet Nam should follow this trend by assuring that gas prices are negotiated and established with suitable indexing, separately from transmission tariffs. The gas price between PVGC and the producer-shippers could be established alternatively at the platform or at the onshore delivery point, of Phu My. It is assumed that the producers would remain the shippers in either event. Some advantages and disadvantages are summarized below: - 92 - Annex 2.3.1 Page 9 of 11 Advantages and Disadvantages of Pricing Gas Purchased by PVGC, at the Point of Onshore Delivery rather than at the Offshore Platform Advantages Disadvantages Comments Gas would be priced closest to the market place, Perhaps more Today, Most gas which best keeps it correctly aligned to complicated to fix sales in North alternative fuels. the initial price for America and Europe, the first project (but in competitive The pipeline tariff becomes a deduction from easier to negotiate markets, are priced the wholesale buyer's price so that the the initial tariff). at the market, and producers get a netback at the field. The not at the field. producers as shippers on the NCS pipeline, But, approach might would have an incentive to reduce the pipeline be preferred by Thailand has tariff so that the net-back would be higher. private sector and discussed pricing therefore negotiation their gas at the New producers would expect to get the same might be easier. market in Bangkok, downstream market price but may have a for many years, and different net-back because they might have The fiscal terms for the Thai National different transportation costs. They would be producers must take Energy Policy Office encouraged to look for gas closest to the market. account of the cost is again reviewing it. differences in field The NCS negotiations on the pipeline tariff development & North America would be simplified because the producers have production (which practice is for the an incentive to lower the tariff. generally the NCS producer to get a net- terms do) back. The price of gas to PVGC (and on-selling price to EVN) would not go up or down depending on the pipeline tariff. The precedent would be set for one gas price for PVGC, as the wholesale buyer, which is the competitive market solution to pricing. This would encourage exploration and development for new gas. Gas Transmission Tariff 18. Main line transmission of gas, like electricity transmission, is typically a monopoly, with significant economies of scale. There is therefore a strong case for government to intervene in order for main transmission pipelines to be installed for the benefit of all producers who might make discoveries in a region. This means that access to the pipeline should be available to new producers, on fair terms, without discrimination. Lacking any regulatory arrangements to ensure these objectives, the principles should be reflected in the contracts that underpin the pipeline construction and operation. 19. The estimated transmission tariff from the Nam Con Son basin to Phu My has been estimated to be in the range of US$0.80 to US$1.00 per millBtu. The transmission tariff should be based on the following elements negotiated between the parties: - 93 - Annex 2.3.1 Page 10 of II * Cost-based tariffs providing a reasonable return to investors * Levelled tariff to reduce the tariff in the first years * Two part tariff consisting of capacity and commodity charge * Transmission tariffs should include incentives for increasing the throughput on the pipeline and for cost savings. The benefits from greater capacity utilization should be shared between users and owners, by re-establishing the level of the capacity charge in the tariff. 20. The seasonal swing in the power sector's demand for gas varies from a minimum of 100 million cm per month to 270 million per month in 2000, and frbm 270 million per month to 400 million per month in 2005. The power sector must reserve capacity for its peak requirement, which is close to the planned initial capacity of the pipeline, of 3.2 bcm per year. The initial annual requirement for gas by the power sector is 2.4 bcm. This suggests that there should be scope for developing an interruptible market in the off-peak months. 21. The foregoing factors bearing on gas supply costs, gas market value and price indexing determine the boundaries for price negotiations. A range for the possible outcome is indicated below. The gas sales price to the power sector should certainly be higher than the full cycle private sector costs of supply (after fiscal terms) and should be lower than the maximum market value. Range for Non-Associated Natural Gas Price, at Phu My, $/milBtu, in 1997 Min Price Max Price Price of Gas at Phu My Cost Based, Market full cycle Based To Power Sector 2.3 - 2.8, 2.75-7.0 after fiscal terms To Fertilizer 1.50 - 2.30, 2.20 - 2.60 before fiscal terms Note: Gas price to fertilizer based on a fertilizer price of US$ 190 ton is about $ 2.45/millBtu2 Source: Mission Estimates. 22. Gas prices for the power sector could be indexed to the international price of fuel oil as a reasonable compromise between the needs of the power sector and the producers. 23. The economic value of gas used for fertilizer production is estimated to be around $1.40 per millBtu lower than in power generation. The Gas Master Plan referred to benefits from building and operating a fertilizer plant, such as foreign exchange savings from lower imports, local employment and transfer of technology. While there would be direct foreign exchange savings from lower imports, they would be at the expense of an inefficient allocation of gas and the possible earnings of foreign exchange from higher value uses of gas. If transfer of technology is the objective, Viet Nam would be better off to promote projects with growth potential, rather than 2 Based on an urea price of $1 90/t using a 12 discount rate and assuming a Debt/Equity ratio of 70/30. - 94 - Annex 2.3.1 Page 11 of 11 investing in the sub-optimal production of urea. The self-sufficiency argument is also weak because there are many potential sources of fertilizer for import to Viet Nam. Hence, the risk of supply interruption is low. The highest net benefits are obtained when gas is sold into the highest value sectors. The loss of benefits, which would be the same for associated gas as well as non- associated gas, of using 1 bcm of gas in fertilizer production instead of in power is around $ 400 million over a 20 year period, based on the maximum market values shown above. 24. The use of gas in fertilizer can only be considered as economic if Viet Nam had a significant excess supply of gas, much larger than the present discovered reserves. However, if the government is determined to subsidize fertilizer production, the gas price to the fertilizer plant should at least cover the full cycle social supply cost of delivering it, which is estimated above to be in the range of US$1.50 to $2.30 per mill Btu. The use of associated gas for fertilizer has been proposed as a way to avoid subsidizing the ptice of gas used for fertilizer. The economic benefit to Viet Nam, however would be higher if gas is used in power generation. - 95 - Annex 2.3.2 Page 1 of 12 A NoTE ON PVGC ORGANIZATIONAL STRUCTURE3 A. INTRODUCTION 1. The strategic direction for PVGC is defined by its mandate from GOV, what is involved in developing an efficient, competitive gas industry and the economic forces in play. At the same time, PVN has legitimate corporate development objectives. It wishes to develop gas industry expertise and management capacity in each of the distinct business segments: E & P, Gas Transmission, Gas Distribution and Trading. It also wishes to become a significant operating company in its own right, with the capacity and expertise to be competitive and profitable in an open market. The issues of PVGC commercialization and organizational structure needs to be reviewed in the context of the challenges before PVN and PVGC as designated stewards of gas sector development. 2. The Petrovietnam subsidiary, Petrovietnam Gas Company (PVGC) is in a start-up phase with two operating centers (for Bach Ho pipeline operations and for construction services) and two LPG joint ventures generating cash flow. The priority of Petrovietnam (PVN) and PVGC management is clearly project development, specifically the Nam Con Son gas pipeline (NCS Gas Pipeline) project and the Bach Ho gas processing project and related condensate / LPG storage terminal and transport infrastructure (Bach Ho GPP). The NCS Gas Pipeline project is the building cornerstone to development of Vietnam's gas industry. Gas purchase, transport and sales contracts associated with the NCS Gas Pipeline project will also set important precedents concerning how PVN will exercise its gas monopoly trader mandate. The Bach Ho GPP project is the building cornerstone to development of Vietnam's LPG industry. Both projects will make important contributions to economic development and both will generate substantial fiscal revenues for the government. 3. The focus of this study has been on the issues of PVGC commercialization and restructuring to change PVGC into a commercial state gas company focused on its core business areas. The interface of PVGC with PVN headquarters (PVN-HQ) is of course central to both issues. This in turn will be influenced by the course of the Government (GOV) enterprise reform and the restructuring PVN into a commercialized holding company. 4. The scale of development that is envisaged, however, needs to be put in context. Within five to seven years, we foresee five PVGC strategic business units/subsidiaries (SBUs) being established to manage PVGC operated enterprises and PVGC JV interests, aligned by industry function in accordance with international gas industry practice: Transmission, Distribution, Gas Monopoly Trader, LPG/Condensate and Construction Services. Each PVGC SBU will be several-fold the size of PVGC today in terms of revenue generated and operating profits. The PVGC group in total will likely by 2005 be larger than PVN today, not in terms of numbers of employees but with respect to assets deployed and revenues generated 3This note is a draft report prepared under the ESMAP project: "Institutional Reform and Restructuring of the Petrovietnam Gas company" - 96 - Annex 2.3.2 Page 2 of 12 B. THE EVOLVING GAS INDUSTRY STRUCTURE 5. In determining the organization and structure of PVGC, it is necessary to analyze the scale and scope of gas sector development that is in prospect and how the Vietnamese gas industry structure might naturally evolve. Annexe 1 discusses this in some detail the enabling policy and regulatory initiatives that will be required to mobilize international energy company (IEC) capital and expertise, to facilitate restructuring / productivity in state enterprises and to encourage the transition to competitive markets 6. Table 1 sets out a course for evolution of the gas industry structure through the three gas market development phases, and the sequencing of required enabling policy/regulatory measures. This evolution path is based on the experience of gas industry development internationally. Table 1: Likely Evolution of Vietnam's Gas Industry Structure Development Stage Industry Stage Enabling Measures Market Creation Gas Monopoly Trader Gas policy framework One producing PSC PSC fiscal regime Bach Ho pipeline Gas pricing policy NCS pipeline JV Regulatory principles Ba Ria/Phu My distribution re. access and tariffs Market Development/ Gas Monopoly Trader (assisted National Energy Policy Office First Years by Int. Oil Companies?) State Management Petroleum producing PSCs Authority Gas Master Plan for pipeline JVs downstream market Bach Ho pipeline development Ba Ria/Phu My distribution Phu My/HCMC distrib. JVs Market Development! Gas Monopoly Trader (Liberalization of Latter Years Clearinghouse bulk gas market?) Several producing PSCs Regulatory Commission PVGC pipeline network pipeline JVs PVGC Distribution distribution JVs Mature Market PVGC Holding Company Competitive upstream Regulated T&D industries - 97 - Annex 2.3.2 Page 3 of 12 C. PVN AND PVGC TODAY 6. Today, PVGC is an independent cost-account enterprise under PVN with its own charter. PVN is structured like a 'Holding company' with a number of 'affiliates' but has not acquired all the attributes of a 'Holding Company'. The corporate shell given to PVN is a good first step, but a commercialization would confer true autonomy of PVN. Functional departments in PVN supervise and "manage" many affiliate/subsidiary activities. 7. PVGC's present organization is shown in Figure 1. The total number of staff is around 350. The department including administration and management boards has 132 staff members, the operations center, project development center and safety division have a staff of around 180 and the JVs 35 people. 8. PVN has the right to expand or restrain the business scope of PVGC in line with the common strategy of PVN's development and to approve plans of the company. PVN appoints the Director of PVGC and authorizes the director to manage and operate its business according to its charter. As to the PVN - PVGC interface, PVN is not involved in day-to-day management of operations but it does exercise complete control over subsidiary operations and capital investments. The PVN Gas Department decides the yearly operating and investment budgets of PVGC and it makes the decision on what portion of revenues generated from PVGC operations stays with PVGC. The PVN Gas Department also takes the lead in project development and financing, and in the case of a joint venture, in the choice of the strategic partner and negotiation of terms. It takes the lead also in project implementation, supervising the bidding and procurement process and the work of the subsidiary's project management boards. 9. PVGC has a self-operating and self-financing right fully responsible to PVN for its obligations and interests. However, the financial autonomy of PVGC is minimal, which is partly due to the fact that investments are decided by PVN headquarters and approved by MPI. At one point in time, 100 percent of PVN revenues went directly to the State. But step-by-step PVN has been allowed to use portions of revenues it generates to cover operations and to establish modest capital funds. D. OPTIONS FOR PVGC ORGANIZATION 10. Table 1 has set out a course for development of the Vietnamese gas sector. Specific reference is made to the possible timing of when a number of PVGC transmission and distribution companies and joint ventures might be established, and also the likely evolution of the PVGC monopoly trader role. The demands that this will place on PVGC as an organization will need to be recognized. It is not simply a matter of adding staff and expanding the scope of professional and industry competencies to meet the challenge ahead. PVGC will soon have investment interests and operating responsibilities in five distinct business areas: gas transmission, gas distribution, gas trading, LPG/condensate supply/processing/distribution and construction services. How to best organize PVGC in order to develop and manage these operations and investment interests has been a principal focus of the study. 11. In the international gas business, a common practice is to establish subsidiaries by core business segment, recognizing fundamental differences as to how revenues are earned, the different - 98 - Annex 2.3.2 Page 4 of 12 technical and commercial competencies required for success and investor attitudes to risk. These differences are illustrated in Table 2 which presents an overview of the principal business activities of the different PVGC SBU's that are expected to be in place by 2005 and how they will be generating revenues. It is to be noted that most international energy companies would not have a LPG/Condensate SBU within the gas group, and none would have a Construction Services group. The prospective cashflow from the LPG/Condensate SBU which is a part of the Bach Ho GPP project, is large and this SBU is strategically-important to PVGC development over the next years as it could produce sufficient equity capital that will be required to fund development of PVGC's transmission system and distribution ventures. 12. The options for organizing PVGC core business activities that were examined are set out below: Option 1: Organize by core business segment as shown in Table 2, i.e., in five separate core businesses. Option 2: Initially combine PVGC gas transmission and distribution activities in one SBU, and establish SBUs for gas trading, LPG/condensate, and construction services; Option 3: Initially combine gas transmission, distribution and trading activities in one SBU, and establish SBUs for LPG/condensate, and construction services; and Option 4: Initially combine gas transmission and distribution activities in one SBU, establish SBUs for construction services and LPG/condensate, and retain gas trading within PVGC headquarters. Table 2: PVGC Core Business Groups Core Business Activities SBU HQ: functional departments Gas Transmission Systems planning/design Admin./personnel Systems operation/dispatch Finance/account. Systems maintenance/safety Systems planning Marketing transport services Technical support [Revenue Source: provision of transportation services; profit is based on allowed rate of return and size of asset/equity base plus operating effectiveness and throughput utilization incentives.] Gas Distribution Systems planning/design Admin./personnel Systems operation/dispatch Finance/account. Systems maintenance/safety Systems planning Supply contracting market Technical support development systems Customers Customer connections Market research Customer services Commercial Sales [Revenue Source: volumes sold and margin between gas purchase costs and consumer prices, and transportation service fees.] 99 - Annex 2.3.2 Page 5 of 12 Gas Trading Gas purchasing Finance/account. Transport contracting Contract admin. Gas sales Market research - Power Legal/contract. - Large Industrial - Distribution [Revenue source: volumes sold and margin between gas purchase costs and consumer prices, and supply service fees.] LPG/Condensate Domestic Bulk sales Admin./personnel Export bulk sales Finance/account. Condensate processing JV interests Storage terminals Technical support Product transport Commercial LPG bottling distribution Market research/planning [Revenue sources: product sales, product upgrading, fees from storage, terminal and transportation services and JV income.] Construction Services PVN Group projects Admin./personnel PVGC projects Finance/account. Third party contracting Technical support Commercial [Revenue Source: construction services] 13. In examining these options, consideration has been given to the timing of when different gas ventures might proceed and whether they are likely to be PVGC operating companies or joint ventures, in order to determine at what point in time the scale of operations is likely to be of sufficient size to justify establishing a SBU. Also taken into consideration is that PVGC will need to build management capacity and develop certain areas of professional expertise important to the gas industry. 14. While the Option 1 organizational structure is considered the best longer-term solution for PVGC, for the reasons listed in paragraph 12, it would not be an efficient solution at this point in time. In the first stages of gas development the gas distribution business is likely to be limited to the Ba Ria/Phu My region and it is not likely to reach a significant scale until the onshore gas transmission and distribution system is extended to HCMC. Similarly, with respect to gas trading, it is difficult to justify establishing a gas trading SBU at this point in time given the limited number of purchase, transport and sales contracts that are in prospect over the shorter horizon. There is also the matter of when PVN-HQ is going to transfer the Gas Monopoly Trader function to PVGC. 15. Establishing a gas transmission and distribution SBU is considered an immediate priority. Within 3-5 years, PVGC will have in its transmission portfolio, the Bach Ho pipeline, the NCS pipeline/treatment plant joint venture, the Bach Ho gas plant (JV?) and an onshore gas transmission pipeline to HCMC. In addition to responsibility for system operations and dispatch, it will also be responsible for longer term network development planning and system design. The latter is extremely important given the economies of scale in pipeline construction and system operation and should be given immediate priority. - 100 - Annex 2.3.2 Page 6 of 12 16. A placement of the Ba Ria/Phu My distribution project with the gas transmission SBU is a practical solution for an interim period. The project is presently being developed in an integrated manner with the NCS Gas Pipeline project and from a systems design/ operations/ dispatch perspective can be readily managed by the transmission SBU. Moreover, this project is directed at supplying larger industrial clients and the Gas Monopoly Trader will be responsible for gas sales contracting. Once more traditional gas distribution ventures are initiated, directed at supplying hundreds of medium and small industrial and commercial clients, consideration should then be given to establishing a separate SBU for the reasons cited above. 17. On the issue of where to place the Gas Monopoly Trader over an interim period until the scale of gas trading reaches a scale that could justify establishing a separate SBU, the choices examined were placing it with the gas transmission SBU or placing it at PVGC HQ. Placing it with the gas transmission company is not favored. The international experience is that the gas trading group would quickly become subordinate to the technical operating/ system planning groups, exactly at the time when gas market development should be preeminent, not submerged in an engineering- driven SBU. Moreover, once placed with the gas transmission SBU it will prove difficult to extract, particularly if the distribution function is also placed there. We favor a gas trading group being established at PVGC HQ, supported by a strong market research/ planning department and a commercial department with a greatly strengthened market development capacity. It should be possible to create a positive environment for the Gas Monopoly Trader within the HQ structure and its presence in turn would contribute to corporate development strategic planning. 18. Establishing a separate SBU for the LPG/condensate business is also considered a priority to prepare for processing and marketing of the LPG/ condensate production of the Bach Ho GPP. With construction of the Bach Ho GPP, PVGC will have 250,000 metric tons of LPG to market and 90,000(?) metric tons of condensate to market and/or process into blended gasoline and petrochemical feedstock. PVGC will thus be the dominant supplier of LPG to the domestic market, and indeed in the first years of operation will have to export because production will exceed projected total domestic demand by a considerable margin. PVGC also has plans to construct a LPG / condensate storage terminal associated with the BACH HO GPP project and also a LPG storage terminal project at Haiphong. Consideration is also being given to entering the LPG transportation field supplying LPG to companies in the fast-growing LPG bottling distribution retail business, including the two PVGC LPG bottling/distribution joint ventures. These diverse operations and commercial activities would have to be managed and this is best done by forming a stand-alone SBU with a full range of corporate services, particularly as it is likely that once established this SBU will be moved out of the PVGC group. 19. A decision to form a joint venture for the Bach Ho GPP project and the inclusion of the LPG/ condensate storage terminal project in the joint venture would undercut the rationale for establishing a LPG/ condensate SBU. Management functions such as overseeing joint venture interests, this is more efficiently accomplished by a Joint Venture Management Department at PVGC HQ. 20. The construction services group is not a core business activity of PVGC and will prove a distraction to management at a time when it will be pressed to manage development of the other SBUs. A better placement within the PVN Holding Company would be with the Petrovietnam Engineering Construction Company (PVECC). This enterprise does have the advantage of being - 101 - Annex 2.3.2 Page 7 of 12 profitable through construction contracts outside the PVN group of companies. It is recommended that PVGC establish a separate SBU now and consider to divestment. Recommended option 21. It is concluded that the pace and scale of development envisaged will require PVGC to mobilize International Oil Companies (IOC)/ IEC capital and expertise to assist in market development and in development and operation of gas transmission and distribution infrastructure. It is further concluded that attracting IOC/IEC investment raising international project financing will be facilitated an orderly transition from a centrally-controlled, state monopolized gas sector to a market-based gas industry in which competition is encouraged and the natural monopolies are regulated. 22. The recommended option for organizing the PVGC core business activities should bring about a shift in the management approach of PVGC from operations management to corporate strategy and finance, earnings performance of the gas group and the core business SBU's, and to development of major investment ventures. Management at the SBU level will focus as before on operations but with an important shift in priorities, from asset and operations management to profit maximization and enhancement of the company value. The recommended Option 4, implies an initial combination of gas transmission and distribution activities in one SBU, establish SBUs for construction services and LPG/condensate, and retain gas trading within PVGC headquarters. Figure 2 presents an organization chart that would give effect to this option. 23. Table 2 presents a list of the functional departments that one would normally expect to find in stand-alone gas subsidiaries of an international gas company involved in this range of business activities. Although in Option 4 transmission and distribution activities are combined for the Gas Transmission SBU we see the need for only four SBU HQ departments: Administration/personnel, Finance/accounting, systems planning and technical support While this SBU will include a distribution operations group, we do not recommend that the market research, commercial, and contracting competencies shown for the gas distribution SBU be added. The Gas Monopoly Trader group at PVGC-HQ will handle the commercial aspects of Ba Ria/Phu My distribution until a distribution SBU is established. 24. With the proposed commercialization of PVGC, there would be a need to strengthen the capacity and expand the scope of expertise of the Finance/ Accounting Department. PVGC will have control! discretion over PVGC assets and revenues and take responsibility for debt servicing. It will need to control significantly larger and more diverse business operations and over time develop the expertise to take the lead in corporate and project financing of PVGC expansion (post 2005). 25. With the proposed commercialization of PVGC, there would be a need to strengthen the capacity and expand the scope of expertise of a restructured Corporate Planning Department. This group will take the lead in developing both corporate and SBU development strategy and related business plans and coordinate the PVGC group and SBU capital investment and operating budget process. It will become a much more important departmnent than today and be the principal interlocutor on PVGC development strategy with PVN HQ Gas Department. It will need to develop over time the expertise and capacity to take over the lead from PVN-HQ in development of gas projects and negotiation ofjoint ventures (post 2005). - 102 - Annex 2.3.2 Page 8 of 12 26. At the time when the Gas Monopoly Trader function is transferred to PVGC, there will be a need to establish in PVGC-HQ a strong gas marketing group responsible for the Gas Monopoly Trader function supported by Gas Monopoly Trader-dedicated contracting and market research departnents. The Gas Monopoly Trader group should be headed by a Deputy Director reporting directly to the Managing Director. 27. With the proposed transfer of responsibility for project implementation to PVGC, including for international contracting and procurement, a PVGC HQ Project Management Department will need to be established. Forming ad hoc project management boards is a practical approach and should continue with the close collaboration of the SBU technical/planning departments. 28. As PVN-HQ Gas Department is to take the lead for new venture development through the project feasibility stage, the Project Development Department of PVGC HQ should be absorbed by the restructured Corporate Planning Department. 29. As to the role of the Gas Engineering/Technology Department, it will need to change but how depends largely on whether it has a contribution to make to supporting the LPG/Condensate and Construction Service SBUs. It clearly has a contribution to make to the Project Management Department. The systems planning/ technical support competencies for gas transmission and distribution are, however, best placed with the SBU. Also the practice of technical evaluations of SBU operations does not have a role in a commercial gas company. 30. It is recommended that the Construction Service SBU also be structured on a stand-alone basis in preparation for its separation from the group, with any work for the gas group done under contract. 31. If PVGC is going to enter the LPG/condensate supply distribution business as operator then it will need the full range of corporate and technical services listed in Table 2. This is best established on a stand-alone basis. It is a business that is very different from gas and the PVGC-HQ functional departments have not have specific knowledge on this issue. Any LPG commercial expertise residing at PVGC-HQ should be transferred to the SBU. 32. The options for PVGC as it carries out its mandate are: (i) set up PVGC SBU's and hire required expertise; (ii) develop JVs to advance development of gas transmission and distribution expertise; and (iii) develop BOT projects to put in place required transmission infrastructure and operating expertise. BOT projects are recommended JV terms are not satisfactory or it is desirable to put the responsibility for the project outside PVGC. PVN is advised to develop alliances and not trying to develop the gas sector itself, relying on hired expertise. This would be very costly from the national perspective, unduly retarding development of the industry and thereby reducing the benefit flow (most notably with respect to upstream fiscal revenues). Moreover, PVN does not have the financial or management capacity at this time. 33. PVN is advised to take a more balanced approach with greater weight given to the JV Option in the first years, at least through the first stage of the Market Development Phase. A combination of the first two options would meet the corporate development objectives of PVGC as well as its responsibilities to the state. Promoting JVs has proved an effective strategy of mobilizing International Oil Companies/IEC capital and expertise and for achieving the desired transfer of - 103 - Annex 2.3.2 Page 9 of 12 technology and PVN staff development. It might well prove necessary, however, to rely to some extent on the BOT option to alleviate pressure on PVGC' financial and management resource capacity. 34. PVGC Pipelines will continue to operate the Bach Ho pipeline. It will need to take the lead in planning, developing and operating integrated regional gas systems, possibly with the assistance of a twinning technical assistance program with an IEC. PVGC would take the lead in gas market development. At a later stage after the Monopoly Gas Trader function has been transferred to PVGC and the gas market has developed significantly there will be a need to develop and operate a Gas Clearinghouse to manage this function in an efficient manner. As to Gas Distribution, given the nature of the business with the importance of market development expertise, it is advised that the joint venture route for the first utilities. As to PV-E & P, this has important ramifications for gas industry structure and promotion of upstream competition. Most immediate is that PVN has the right to capture and market all associated gas that is not required in oil field operations. This will shortly increase to 150 mmcfd, a significant portion of the market for the next 10 years. 35. But any change in the organization and management of a subsidiary has major implications on the organization of the parent state oil company. E. IMPLICATIONS OF ORGANIZATIONAL CHANGE 36. In state oil holding companies, the usual practice is that management at the holding company level focuses on the issues of corporate strategy and finance, earnings performance of the group and the individual core business SBU's and major investment decisions. Management at the SBU level focuses on SBU operations and asset management, maximizing profits and increasing the value of the company. The process of management control takes on added importance in a holding company framework, involving a comprehensive process of approval of annual SBU business plans and budgets for operations and capital investment, setting SBU performance targets, a fixed schedule for reporting SBU operating and financial results and analysis of business results vis-a-vis business plan and performance targets. A company-wide system of business planning, accounting and performance reporting is invariably imposed. The exercise of these planning and control functions in turn requires appropriate technical expertise and specialization to support the management of the holding company. State oil companies which have successfully made the transition to profitable, competitive energy companies have invariably followed this course. And it is recommended that PVN will be reorganized into a holding company focused on its core business activities 37. The organizational structure of a state oil holding company group would usually include three organizational functions: * Business line functions: to provide overall strategic direction to core business entities while ensuring appropriate control through: (I) direction of SBU corporate development; (ii) review and approval of SBU capital and operating budgets; and (iii) monitoring SBU operating and financial performance. * Corporate staff functions: to be responsible for establishing and monitoring policies, procedures and practices across the PVN group in areas such as finance, legal and commercial affairs, public relations, corporate planning and development, and organizational development. - 104- Annex 2.3.2 Page 10 of 12 The corporate planning and development function has prominence, responsible for managing the annual planning and budgeting cycle and for provision of general planning guidelines to the business line departments. The finance function also has prominence, responsible for establishing a uniform framework of both cost and management accounting for the PVN group, and for: * administering the group financial planning system (budgeting), * evaluating the financial of subsidiaries, * reporting group financial results, * ensuring effective custodianship and reporting by subsidiaries * managing group cash and banking transactions, * managing group taxation obligations, * managing group risk exposure, and * managing group foreign exchange exposure. * Management support services function: responsible for providing administrative services to business line and corporate staff functions within PVN-HQ. I1. For PVN, such a system would mean that PVN headquarters (PVN-HQ) would not directly manage core business subsidiaries, but focus on (i) setting strategic and financial direction for the PVN group of core business subsidiaries and on (ii) management control of the SBUs through approval and monitoring of SBU business and investment plans and capital and operating budgets. It is envisaged that PVN-HQ will also continue to lead the project development process, the structuring of investment proposals and financing, and the setting up of strategic partnerships in business ventures. 2. Consistent with the above PVN holding company concept, the PVN-HQ Gas Business Line Department responsibilities will need to cover the following areas: * an operations control and coordination function to: * review, critique and approve PVGC SBU operating plans and budgets; * consolidate plans and budgets for PVGC and PVGC SBUs; and * analyze actual operating performance of PVGC SBUs against business plan/performance- targets. * an investment planning and development function to: * set longer term strategic direction for PVGC development, and review, critique and approve the PVGC corporate development plan and the annual business plans of PVGC SBUs; * review and approve PVGC annual capital expenditure budgets; * develop and promote potential new gas ventures and conduct scoping economic evaluations of such ventures; and * act as new venture sponsor for gas projects up to the stage of project approval, then hand-off to PVGC for project implementation. - 105 - Annex 2.3.2 Page 11 of 12 1. It is recommended that within this framework of corporate strategic direction set by the PVN group-wide system of SBU approval and control centered on business plans and capital and operating budgets and PVN-HQ, that PVGC management be given full discretion and authorities over PVGC group operations and asset management. PVGC group annual budgets for operations and capital investment budgets once approved by PVN-HQ would provide the reference point for PVGC operations and development, and also the basis for evaluating PVGC performance and ensuring accountability. 2. It is also proposed that revenues generated by PVGC be managed by PVGC, subject to agreement with PVN-HQ on revenue allocation. Specifically, PVGC would retain revenues required to cover agreed operating budgets, agreed capital investment project expenditures, all debt servicing and repayment obligations related to PVGC and its SBUs, and all PVGC tax obligations. Remaining revenues would flow to the PVN Holding Company. F. FINANCIAL INVESTMENT STRATEGIES 3. Given the expansion of the gas business that is foreseen, and the greatly increased demands that will make on both PVN and PVGC organizations, as discussed in the main section it is clear that the present management system is not sustainable and would need to develop with the challenges. Options for financing PVGC corporate development are: - establishing PVGC operated and financed SBUs, hiring third-party expertise as required; - developing projects to be sold as joint ventures, to accelerate the pace of sector development while developing gas transmission and distribution expertise; and - BOT projects primarily to also accelerate development pace but also to acquire transmission and distribution expertise. 1. PVGC will need to pursue all three options, but the mix will be determined by: * what is an acceptable pace of development, availability of equity investment capital to PVGC, D GOV policy towards commercialization of PVN and PVGC, and * GOV progress on implementing financial sector reform and enabling gas sector pricing / regulatory measures. 1. The potential for PVGC to establish 100 percent owned and operated SBUs is limited by availability of both equity and debt capital. PVN and PVGC do not has assured access to revenues generated from operations, thus are not in a position to accumulate equity investment capital or provide required assurances to financial institutions that they can service debt obligations. PVN and PVGC presently rely to a large extent on capital allocations from GOV to fund investments. There is, however, a general shortage of investment funds available to state enterprises and in any event the capital investment requirements of the oil and gas sector are considerable larger than what is likely to be available from state development funds. 2. Commercialization of PVN and PVGC is the key to this constraint. If the companies were assured the revenue (or an agreed share of the revenue) they generate, subject to shareholder agreement on annual dividend payments management would have more authority and discretion over how they develop and operate their business, within a framework of shareholder approval of - 106- Annex 2.3.2 Page 12 of 12 annual business plans and capital and operating budgets, monitoring of financial and operating performance and annual performance review. Until this happens, gas sector development and PVGC corporate development will continue to be constrained and there will be a bias towards joint venture development because they are allowed to operate under more favorable conditions than the state enterprises. G. CONCLUSIONS AND RECCOMMENDATIONS 3. From the above analysis, it is reccommended that the management of PVN and PVGC take the following steps: * Develop PVGC as an independent subidiary of a state oil holding company * Implement the organization of PVGC on lines indicated in the report in stages * Develop a training plan for the staff * Develop a corporate plan for PVGC including the choice of strategic partners and JV's. -107- - 801 - bl 1 .P.... pue UOUPnPOMd aUou.fulV *L-b-Z £11. .-..-.. ---.. ----....------..-----------------------------------------------------------------..-. Srn.!iojT 1 IOJ 9 b Z £11E .-. S-lso3 uo lonpoLJ ur Slu3tUaJG S b Z zl 1.-- - --- sIsoO uoa npo.d petoq aulTN VtbVb Z 111............A.. .do UO.p..npoid IBO3UDuA £E bZ 601 .uoriuvoldxo zopun plogliuo u! saAlaosoa po 1 I1 bZ HOIJ3S IY03 OHI t1Z S3XaNNV bfz xouuv Coal Reserves in Coalfields under Exploitation (down to 1 00m below surface) No. of mines Underground Opencast Reserves (mt) Mine Area - OC UG Mixed In situ Recoverable In situ Recoverable Overburden Stripping ratio ._ _ _ .__ _ _ _ _ _ _ _ _ _ ( m m 3) Strip pin g ratio Oong Bi 3 176 87 12 7 28 3.7-4.0 Hong Gai 2 2 3 77 36 41 41 222 2.7-5.7 Cam Pha 4 1 3 89 45 104 104 675 3.0-6.3 Duong Huy 2 63 36 4 4 20 3.8-5.8 Interior 4 2 1 1 38 38 146 0.7-6.1 VA KTKS 3 - 53 42 112 2.4-4.0 Total 406 205 252 236 - Grand Total In situ reserves: 658 million tons Recoverable reserves: 441 million tons Source: Report of International Mining Consultants Ltd., 1996. of > CD O - Annex 2.4.2 Page 1 of I Coal Demand (million tons) Consuming sector 1995 1996 1997 1998 1999 2000 2005 Actual Projection Electricity 1.00 1.70 2.30 2.40 2.50 3.00 4.0-4.50 (2.15) (3.81) Cement 0.63 0.65 0.80 1.50 1.80 2.0-2.5 3.0-3.5 (2.00) (2.54) Construction 1.24 1.30 1.30 1.40 1.40 1.50 2.50 (1.07) (1.27) All Others 2.20 1.20 1.30 1.30 1.40 1.50 1.6-1.8 (1.76)* (1.93)* Domestic Total 5.07 4.85 5.70 6.60 7.10 8.0-8.5 9.6-10.3 (6.98) (9.55) Export 2.73 3.64 3.7-4.0 3.7-4 0 3.7-4.0 3.7-4.0 NA (3.80) (3.00) Grand Total 7.80 8.49 9.80 10.00 11.10 12.00 NA (10.78) (12.55) - Others include chemicals, paper and pulp, textiles, food and household Figures in parentheses indicate Bank estimates. Source: Vinacoal and MPI, May 1997. - 110- Annex 2.4.3 Page 1 of 1 Vinacoal Production Capacity (million tons per year) 1997 2000 2005 Company Opencast Underground Opencast Underground Opencast Underground Cam Pha 1.94 0.95 2.43 1.19 2.54 1.28 Hong Gai 0.75 0.64 0.88 0.90 1.09 0.85 Dong Bac 0.50 0.15 0.52 0.17 0.63 0.21 Quang Ninh 0.16 0.38 0.16 0.46 0.16 0.48 Khe Tam - 0.61 - 0.96 - 0.74 Geology & Mineral 0.07 0.21 - 0.26 - 0.30 UongBi - 1.07 - 1.78 - 2.43 Totals 3.42 4.01 3.99 5.73 4.42 6.29 Grand Total 7.43 9.72 10.71 Source: MPI, May 1997. - 111 - Annex 2.4.4 Page 1 of I Mine-head production costs, 1995 Number and type of Production Cost per ton (US. mines (thousands of tons) dollars) Deo Nai 1 open-pit mine 500 23.48 Coc Sau 1 open-pit mine 1,511 20.87 Cao San 1 open-pit mine 715 23.48 Cam Pha 3 underground mines 517 31.31 Nui Beo 1 open-pit mine 175 18.06 Ha Tu 1 open-pit mine 924 16.05 Hon Gai 3 underground mines 676 24.08 1 open-pit mine 116 16.05 Uong Bi 4 underground mines 356 32.37 Vang Danh 1 underground mine 525 32.37 Mao Khe 1 underground mine 420 26.97 Interior 5 open-pit mines 472 20.37 Khe Tam 1 open-pit mine 127 31.98 Total 7,034 23.59 Open-pit mines 4,540 20.62 Underground mines 2,494 28.99 Source: International Mining Consultants Ltd. - 112- Annex 2.4.5 Elements in Production Costs Item % Labor 27* Material 22 Fuel 8 Power 3 Insurance, etc. 2 Depreciation 12 Interest 10 Overhead 8 Tax 2 Others 6 Total 100% * The unit labor cost is low, about US $ 4-6/ton Source: Vinacoal, May 1997. Annex 2.4.6 Port Facilities Cua Ong Hon Gai (Cam Pha)HoGi Storage capacity (tons) 400,000 300,000 Berthing depth (m) 9.5 8.5 Channel depth (m) 7.0 7.5 Vessel Size (maximum) 20,000 dwt 15,000 dwt 50,000 dwt at anchorage Loading rate (tons per day)* Sized 2,000 1,500 Fines 6,000 4,000 * Sundays and holidays excepted Source: Vinacoal, May 1997. -113- Annex 2.4.7 Page 1 of I Anthracite Production and Trade (million tons) Year World Export World Production Quality Trade Production 1985 354 62.2 5.3 5.0 0.6 1986 362 62.6 5.9 5.5 0.6 1987 391 61.1 6.3 6.1 0.2 1988 401 61.1 6.0 5.7 0.3 1989 407 60.5 5.1 4.6 0.5 1990 377 60.0 5.1 4.8 0.7 1991 370 58.1 5.2 4.2 0.9 1992 374 57.8 9.2 4.5 3.0 1.6 1993 354 56.4 8.9 5.2 3.8 1.4 1994 346 56.1 9.6 5.6 3.8 1.8 1995 376* 55.0 9.6 7.8 5.0 2.7 1996 na na na 8.5 4.8 3.6 * Major producers - China (69.1%), N. Korea (10.6), Former USSR (10.6), Vietnam (1.9), ROK (1.9), Germany (1.6), Spain (1.6) and USA (1.9) Source: US Geological Survey Statistics, AJM Asia/Pacific Mining Yearbook, 1995, World Coal Institute and others. - 114- Annex 3 ANNEX 3. ENERGY AND ENVIRONMENT 3.1. Ambient Air Quality standards .................................. 116 3.2. Emission Standards from Stationary Sources .................................. 117 3.3. Coal mining disturbed area and production .................................. 118 3.4. Hydroelectric Plant incremental investments .................................. 118 3.5. Thermal plant incremental investments .................................. 119 3.6. Environmental costs under the base case scenario .................................. 119 - 115 - Annex 3.1 Page 1 of 1 Ambient air quality standards in various jurisdictions (micrograms per cubic meter unless otherwise noted) Pollutant and Standard jurisdiction 1 hour | 24 hour 1 year Sulfur dioxide World Health Organization 350 125 40-60 United States 365 80 World Bank 80 Korea, Rep. of 650 365 80 Philippines 180 80 Thailand 780 Vietnam 500 Ncm 300 Ncm Particulates World Health Organization 150-230 60-90 (TSP) United States (PM1 0) 150 50 World Bank 200 (PM10); 300 (TSP) 50 (PMIO); 80 (TSP) Korea, Rep. of 150 (PMIO); 300 (TSP) 80 (PMI0); 150 (TSP) Philippines (TSP) 150-230 60-90 Thailand 120 (PM1O); 330 (TSP) 50 (PM1O); 100 (TSP) Vietnam 300 200 Nitrogen oxide World Health Organization 400 150 United States 100 Korea, Rep. of 280 150 100 Philippines 150 Thailand 320 Vietnam 400 100 Lead World Health Organization 0.5-1.0 (I year) United States 1.6 (3 month) Korea, Rep. of 1.5 (3 month) Philippines 1.5 (3 month) 1.0 (I year) Thailand 1.5 (30 day) Vietnam 5.0 Carbon monoxide World Health Organization 30 mg United States 40 mg 10 mg (8 hour) Korea, Rep. of 16 mg 28 mg (8 hour) Philippines 35 mg 9 mg (8 hour) Thailand 34.2 mg 10.26 mg (8 hour) Vietnam 40 mg 5 mg Ozone World Health Organization 100-200 60 (8 hour) United States 235 235 World Bank 250 Korea, Rep. of 200 120 (8 hour) Philippines 140 60 (8 hour) Thailand 200 Vietnam 200 60 Note: I million micrograms = 1,000 milligrams (mg) = 1 gram. Ncm stands for normal cubic meter. TSP stands for total suspended particulates. PMIO refers to particulates less than 10 microns in diameter. Standards for the Republic of Korea are those in force in 1995; for the Philippines, 1997; for Thailand, 1994; and for Vietnam, 1995. World Bank standards are "trigger values" from the draft Pollution Prevention and Abatement Handbook (1997). Trigger values are those at which emergency airshed management programs should be implemented. Where no value is given, World Bank recommendations follow World Health Organization guidelines. - 116- Annex 3.2 Page I of I Emission standards for stationary sources (milligrams per normal cubic meter unless otherwise noted) Pollutant and Standard Jurisdiction Existing sources l New sources Sulfur oxide United States 920-1,240 (oil and coal post-1971) Japan 644 223 European Economic 400-1,700 (oil, 300-500 megawatts) Community 400-2,000 (coal, 100-500 megawatts) Indonesia 1,500 750 (post-1999) Philippines 1,500 for sulfur dioxide (pre-1994) a 1,000 for sulfur dioxide (1994-97) 700 for sulfur dioxide (post- 1997) Thailand 1,300 52 (gas) 832 (oil and coal, >500 megawatts) 1,170 (oil and coal, 300-500 megawatts) 1,664 (oil and coal, <300 megawatts) Vietnam b 1,500 500 Particulates United States Site-specific Japan 50-800 European Economic 50 (all oil; coal, >500 megawatts) Community 100 (coal, <500 megawatts) Indonesia 300 150 (post-1999) Philippines 500 (pre-1978) 150 (urban and industrial) 300 (post-1978/pre-1994) 200 (other) Thailand 300 (oil); 400 (coal) 120 (oil and coal); 60 (gas) Vietnam b 600 400 Nitrogen oxide United States 350-620 (oil and coal post-1971) Japan 130-400 (oil and coal) 267-411 (oil and coal) European Economic 450 (oil); 650 (coal) Community Indonesia 1,700 for nitrogen dioxide 850 for nitrogen dioxide (post-1999) Philippines 1,500 for nitrogen dioxide 500 (oil); 1,000 (coal) [for nitrogen dioxide] Thailand 940 (coal); 470 (other) [for nitrogen 338 (oil); 658 (coal); 226 (gas) [for nitrogen dioxide] dioxide] Vietnam b 2,500 1,000 Carbon monoxide Philippines 500 500 Vietnaml 1,500 500 Note: Standards for Indonesia are those in force in 1995; for Thailand, 1996; and for Vietnam, 1995. a. Emissions may be greater if ambient standards are achieved through changes in fuel quality, increases in stack height, or other process changes. b. These standards apply to all industrial emissions and are the binding conditions relevant to power plant operations. But in 1996 a draft guideline was prepared that would apply only to thermal power plants. Under this guideline emission limits for new plants would be 50 milligrams per normal cubic meter for particulates, 400-1,500 for sulfur oxide (depending on fuel and size), and 650 for nitrogen oxide (for solid fuels). These standards are not being enforced and have never been fornally passed, however. - 117- Annex 3.3 Disturbed area and production of coal mines Disturbed area Annual production Average production Mine (hectares) (thousands of tons) (tons per hectare per year) Cao Son a 405 715 1.77 Coc6 a 305 1,511 4.95 Deo Nai a 335 500 1.49 Hatu a 615 924 1.50 Hon Gai - 116 Khanh Hoa 61 85 1.39 NaDuong 115 125 1.09 Nong Son a 25 25 1.00 Nui Beo a 105 175 1.67 Nui Hong 50 110 2.20 Total 2,016 4,286 2.13 a. Existing mine on which it is not necessary to pay compensation. Annex 3.4 Incremental investments in hydroelectric plants required to meet environmental standards (millions of US. dollars) Baseline Environmental alternative Capacity Resettlement Compensation Investment Recurrent Plant (megawatts) (per year) (per year) Short-term projects (through 2002) Song Hinh 70 0.50 2.75 15.00 1.00 Yaly 1 and 2 720 3.00 5.00 120.00 10.00 Ham Thuan 236 0.00 2.50 20.00 1.75 Da Mi 236 0.00 0.25 20.00 1.75 Total 3.50 10.50 175.00 24.50 Long-term projects (2003-1 0) Dai Ninh 300 - - - - Sesan 3 and 4 586 - - - - Dai Thi 250 - - - - Buon Kuop 85 - - - - Thuong Kon Tum 260 - - - - Plei Krong 120 - - - - Ban Mai 350 - - - - A Vuong 145 - - - - An Khe 350 - - - - Dong Nai 8,3/4 340 8.00 0.40 125.00 13.00 Son La 3,600 75.00 30.00 450.00 35.00 a Total >83.00 >30.40 >575.00 >48.00 a - No estimate is available because the environmental impact assessment is incomplete or has not commenced. a. Excludes China. Costs in China are estimated to be an additional $350 million in investment and $30 million a year in recurrent expenditures. - 118- Annex 3.5 Incremental investments in thermal plants required to meet environmental standards (millions of US. dollars) Capacity Baseline Environmental Environmental Plant (megawatts) plan alternative plan alternative + plan PhaLai2.1/2 600 72 111 201 Quang Ninh 1-4 1 200 144 222 402 New coal plants 2 200 264 407 737 Totals Base case scenario 1,800 216 333 603 High-growth scenario 4,000 480 740 1,340 Note: The baseline plan covers minimum investments, including particulate control and water treatment or recycling. The environmental alternative plan includes particulate control, water treatment or recycling, and nitrogen oxide controls. The environmental alternative + plan includes particulate control, water treatment or recycling, nitrogen oxide controls, and sulfur emission controls. Incremental control costs are estimated to be $120 per kilowatt for particulate and water controls, $65 per kilowatt for nitrogen oxide controls, and $150 per kilowatt for sulfur controls. Under the base case scenario Pha Lai 2.1/2 is commissioned in 2000-01 and Quang Ninh 1-4 is commissioned in 2000-06. The high-growth scenario is the same but also includes new coal plants-including PC2. P. Thiet and three other units - by 2010. Annex 3.6 Environmental costs under the base case scenario (millions of U.S. dollars) Sector Baseline plan Environmental alternative plan Natural gas 0 0 Petroleum 0 5-10% of supply costs Coal 0 7 a year Hydroelectricity 86, 750 + 40 a year + 72 a year Thermal electricity 216 333 Total 302, 1,083 + 40 a year + 79 a year - 119- Annex 4 ANNEX 4. INVESTMENT PRIORITIES AND FINANCING STRATEGIES 4.1. Energy sector financing requirements- 1998-2002 ............... ........................ 121 4.2. The need for government guarantees ....................................... 122 - 120 - Annex 4.1 Page 1 of 1 Energy financing requirements, 1998-2002 (millions of U.S. dollars) Financing sources Cash disbursements Finance Financing required Public Export credits Private Sectorlproject Size period through 2002 sector and ODA investment 199S 1999 2000 2001 2002 Gas Nam Con Son field development 3 BCM/yr. 1998-2002 375 375 25 180 140 30 Offshore gas pipeline 400 km 1998-2000 490 490 270 150 70 Subtotal gas 865 0 0 865 Power Yaly hydropower 720 MW 1994-2000 220 220 120 80 20 Ham Thuan Da Mi 472 MW 1996-2002 332 82 250 90 108 84 50 Song Hing 70 MW 1995-2000 84 84 50 26 8 DaiNinh 1997-2003 416 200 216 7 19 40 200 150 Sezan, Plei Krong, Dong Nai, Son La Misc. 2000-Ox 678 378 300 200 200 278 Hydro plants 1,730 964 766 0 BaRiaCCGT 156Mw 100 100 27 21 52 Phu-My 1-1 CCGT 213 MW 1998-99 140 40 100 40 90 10 Ba Ria Diesel 120 MW 1999-2000 70 70 70 Phu-My 2-2 Gas Tutbine 288 MW 1999-2000 120 120 40 80 Phu-My 1-2, 1-3 CCGT 426 MW 1999-2001 280 80 200 100 140 40 PhaLai2Thermal(2x300) 600MW 1999-2001 600 600 70 150 210 170 Phu-My 2-1 Convertto CC 144MW 2000-01 94 94 10 40 44 Phu-My 2-2 Convert to CC 144 MW 2000-01 94 94 10 40 44 Phu-My 3 New 600 MW 2000-02 400 400 50 200 150 Quang Ninh Thermal 300 MW 2000-03 200 200 50 150 Thermalplants 2,098 214 1,100 684 Transmission and distribution, north 1998-2002 450 225 225 90 90 90 90 90 Transmission and distribution, south 1998-2002 500 250 250 100 100 100 100 100 Transmission and distribution, central 1998-2002 350 175 175 70 70 70 70 70 Rural electrification 1998-2002 700 350 350 140 140 140 140 140 Transmission and distribution 2,000 1,000 1,000 0 Subtotalpower 5,828 2,178 2,866 684 804 1,124 1,374 1,398 1,128 Coal Upgrading coal transport facilities 1999-2001 70 35 35 20 30 20 Investing in open cast mines 1999-2002 140 70 70 30 50 30 30 Subtotal coal 210 105 105 50 80 50 30 Total energy investments 6,903 2,283 2,971 1,549 829 1,624 1,744 1,548 1,158 - 121 - Annex 4.2 Page 1 of 5 Financing Private Projects in Developing countries The need for government guarantees. Introduction This note examines the various forms of project financing techniques that are in use for power projects around the world and the financial constraints that face developing countries. It explains the need for government support and guarantees for BOT projects and the experience of other developing countries who have been successful in attracting foreign private investments in the power sector. It also underlines the importance of specifying the degree of government support provided a specific project in the request for proposals. Projectfinancing Private sector infrastructure projects are primarily financed in two ways: (1) through balance sheet financing; and (ii) through non-recourse project financing, which is off-balance sheet for the sponsoring company. The latter method of financing, with modifications, is often utilized in build, own, operate (BOO) or build, operate, transfer (BOOT) schemes, and is sometimes referred to as limited recourse financing. In balance sheet financing, lenders provide loans to a corporate entity to finance a project and in return the corporation has a general obligation to repay the loans. That is, it has an obligation to repay the loans regardless of the performance of the specific project it financed, so that the lenders assume the credit risk of the larger corporate entity (which would normally have an acceptable credit rating) which has many assets, and are therefore not limited to relying only on the performance of a specific project. The loan is on-balance sheet for the corporate borrower. The borrower in this case also has the ability to utilize internally generated cash flow to finance new investments and thereby lessen the degree to which it must secure financing outside the form such as loans and new equity issues. Traditional Public sector Projects are also financed through the balance sheet method. In these cases the government assumes the liability of loans for the projects, generally from multilateral or bilateral sources. These are utilized by the public entity to fund goods and services required to construct the project. Even though the implementing agency has the primary responsibility for the repayment of the loan, the government invariably guarantees these loans with an assurance to the lenders that these loans will be repaid independent of the performance of the project. For traditional public sector project this could amount to more than 80% of the project cost with the remaining coming from internal resources of the entity. In contrast, under non-recourse project financing, lenders provide loans to special purpose companies whose only asset is the project being financed. Normally, the sponsoring party (usually a company with experience in the specific sector) will provide a portion of the financing as part of the equity for the project and lenders provide the remainder of the required financing (70-80%) in debt. The major difference in the financing methods is that under non-recourse financing, lenders have no recourse to the corporate sponsor for repayment of their loans, and therefore must rely on the ability of the specific project they have financed to repay the loan. If the project fails, the sponsor is only liable to the extent of its equity contribution (the 20-30% of project costs that it has financed) which are at risk. If the project is a new, greenfield investment, lenders generally must rely for repayment on a set of contracts (see Security Package) which provide for the project's cash flow. - 122 - Annex 4.2 Page 2 of 5 In recent years there has been increasing interest on the part of infrastructure firms' from many countries to invest equity in development countries as opportunities in their home markets slackened or as part of global diversification strategies. Most of these potential investors are interested in non-recourse financing arrangements, as discussed above, where they provide only 20- 30% of the financing and raise debt financing for the balance.2 For lenders to participate in these kinds of projects, however, several conditions must be met: (i) they must possess the capabilities to assess project risks and mitigation measures to determine whether they have a high probability of being repaid from the specific project they are asked to finance: this requires specialized "project finance" analysis skills, which are available in only a limited number of international banking institutions which have the size and experience to staff experts in this area; (ii) they must be willing to commit funding to countries which are considered high risk by the banking community and their regulatory agencies, and rating agencies; and (iii) they must be willing to provide long-term financing, which is generally required to make the economics of infrastructure projects acceptable; this generally requires loan maturities of not less than 8-10 years. Financing Constraints in Developing countries Notwithstanding myriad potential investment opportunities, lenders have been very reluctant to provide this kind of financing in developing countries without some form of support to alleviate country-specific risks which they feel they cannot assume. This reluctance stems from several factors: Country creditworthiness: Commercial banks look to a country's creditworthiness, often as reflected in the rating of the sovereign government's debt securities by an international rating agency like Moody's Investor Services or Standard & Poor's to assess it overall attractiveness. Financing becomes more difficult for countries with ratings below investment grade3 or those countries without a rating, since it is difficult for the banks to assess the creditworthiness. Y Past Experience.' Banks are also reluctant to lend to countries with histories of non-payment to them and/or for which they have accumulated outstanding arrears on debt repayments. Once a country has rescheduled their external debt, the impact of this constraint would be lessened. * Regulatory Treatment of Bank Lending: Banks are obliged by their regulators to set aside funds ("provisioning") when making loans to many developing countries to protect against the risk of non-payment. This is very costly to the banks and hence discourages lending to these countries. The poorer the credit of the project the shorter the maturity and higher the interest rate for the financing. For some of the poorer credits lenders are not able to provide financing because of these regulatory requirements. IMainly electric and water utilities through subsidiaries, private development firms specializing in particular sectors, oil and gas firms, construction and engineering firms, and equipment supplier. 2Although these investors may only provide 20-30% of the total investment cost of a project in equity, they would own 100% of the stock in the project companies, if they provide all of the equity (i.e. all of the 20-30% required). 3Investment grade is signified by a rating of BBB-or better by Standard & Poor's rating agency and Baa3 for Moody's Investor Services. - 123 - Annex 4.2 Page 3 of 5 Sector Regulatory Arrangements: Even if banks were satisfied that the macroeconomic conditions were stable and the overall country creditworthiness was adequate, for infrastructure projects, they would also scrutinize the payment ability of the power purchaser, ability of government and other public entities to fulfill their obligations, track record or regulatory arrangements of the particular sectors in which the projects they are financing will operate. In recently reformed sectors, this track record has yet to be established this limiting the ability of the banks to analyze whether it is a good risk to make a loan to a project which will rely on the stability of these arrangements for its profitability. As domestic capital markets in the developing countries are unable to provide long term financing, most of this invariably comes from offshore sources. In cases where foreign lenders have recently provided financing for private infrastructure projects in developing countries, they sought to minimize these risks by seeking guarantees (from host governments and third parties) against the risks associated with sector regulatory arrangements or broader political and "country" risks, such as expropriation, and foreign exchange inconvertibility. When the purchaser of the service and/or the provider of an input is a government-owned entity, the banks have also often sought and usually received a government guarantee of the purchasing entity's payment obligations. This is on account of two reasons: (i) under government ownership the government has the right to change the decisions of the public entity in areas such as tariff fixation etc.; and (ii) the credit of the company may not be acceptable to the lenders. In some cases, projects have been able to raise a portion of the required debt from the domestic financial markets, but in general these alternatives are constrained by the small size of the domestic market, very limited experience in domestic institutions with non- recourse project financing, and the lack of a long-term debt market. Government support and Guarantees The Lenders generally need guarantees which address Performance Risk and Credit Risks associated with the project. The former is to ensure that the parties to the contract are able to fulfill their obligations under the contracts and in case the operation of the entity is controlled by the government its must also give guarantee that the entity can fulfill its obligations. This would involve guarantees of the obligations of the government owned entities such as the power purchaser, fuel supplier and other entities contractually required to provide inputs to the project. Similarly if the credit of the counter parties to the agreement is not acceptable, it needs to be enhanced by guarantees by the government. For projects where the output is sold in local currency and the foreign currency markets are controlled by the government, the governments need to guarantee the lenders that the project would be able to obtain and transfer foreign currency if they tender the local currency. Wherever governments are in control of these activities and the currency markets are volatile, the governments would invariably be required to guarantee these obligations. The principal reasons for seeking normal and binding government support, in addition to those listed above are: * it negates any future attempts by the government or successors governments to honor the support agreed at the initial stage; * it establishes in clear and comprehensive terms and contractual rights, duties and obligations of the government and, any conditions which need be satisfied by the sponsors for the agreement to become effective. - 124 - Annex 4.2 Page 4 of 5 Security Package. An important aspect of project financing is the need for clear allocation of the risks and obligations of each parties involved in the transaction. The responsibility and obligations are set out in various legal agreements for the project. For instance, lenders to a private power generation project would rely on, most importantly, a power sale agreement, which would have to provide sufficient cash flow to pay for operating expenses, plus debt service to lenders and dividends to equity investors. Other important contracts would typically include a construction contract, a fuel supply agreement, and operation and maintenance agreement. Each of these would feature penalty provisions sufficient to sustain the project in the event of a contractor's default. Taken together, these must amount to an acceptable credit risk to the lender for it to make a loan to this kind of project. Because of this, lenders focus their attention on the specific provisions of these contracts to identify all the risks of non-payment and ensure that they are mitigated satisfactorily. These generally fall into categories: Project agreement and Financing agreements. All the project documents put together are loosely refereed to as the security package. As the lenders and the investors depend upon these agreements to repayments of their financing, returns and equity, they from a critical part of project financing. Typically this would include: Power Purchase Agreement Government Support Agreement / Implementation Agreement Fuel Supply Agreement Operation and Maintenance Agreement Credit agreements. Shareholders Agreement Security documents Intercreditor Agreement Construction contract Out of the above, the first three invariably form a part of the RFP specially as these define the role of responsibilities of the government and the private sector in the transaction. The clearer the governments thinking in these areas the more responsive and competitive would be the bids. The only way the bidders can address the uncertainty and lack of clarity, is by including price cushions in their bids. As the judgment and the motives of bidders may vary, lack of clarity can lead to bids which are not fully comparable. Moreover, if the level of comfort / governnent support is not known the financial advisers are likely to advice the bidder to submit their bids based on higher financing costs which reflects the higher risk of the transaction i.e. without government support. Experience in other countries It is important to compare the experience of initial projects in countries with similar credit and where the purchasing utilities have similar financial standing, as lenders and investors attach considerable weightage to consistency of policies and are likely to require reduced support. The table below gives the level of the government support of either the early project in some of the countries. All the projects are thermal although in some cases, they may be coal and fuel oil - 125 - Annex 4.2 Page S of 5 based. In most of these the credit rating of the countries was higher than Vietnam. This aspect needs to be kept in view while deciding the level of support proposed to be provided. Proje. Utility Performance & [ uForeign Exchange: Project | Payment Obligations Fuel Supply convertibility & availability China: Shajiao-C MGS MGS MGS Philippines: Pagbilao MGS MGS MGS Pakistan: HUB MGS MGS MGS Jamaica: Rockfort MGS MGS MGS Pakistan: UCH MGS MGS MGS Mexico: Samalyuca LGS MGS MGS Philippines: Sual MGS MGS MGS Indonesia: PTJawa PGS PGS PGS The above table uses the following terminology to indicate the level of government guarantee/support: MGS - Major government support akin to guarantees. PGS - Partial government support. LGS - Low government support. This terminology is used as the actual mechanism of government support has varied in different countries e.g. energy conversion arrangements where the utility supplied the fuel and paid for the electricity in foreign exchange to arrangements where there were commercial arrangements between the project countries e.g. energy conversion arrangements between the project company and various public entities but were backed by government guarantees. In addition to the above area, governments have in one form of the other provided comfort to the lenders and investors against currency devaluation, political force majeure and changes in law which could materially and adversely affect the project and its operations. Conclusions In conclusion, while each project is unique, based on the experience in other countries and the lenders minimum requirements, it is clear that government of developing countries would need to provide some basic undertakings to the private developers of infrastructure projects. Eliminating these would lead to reduced competition, increased complexity in evaluation, an uneven playing field as some bidders may not price every item, while hoping to negotiate the missing elements with the purchaser and the government. It also reduces the benefits of competition and invariably increases the cost of the project. - 126 - Annex 5 ANNEX 5. INSTITUTIONAL DEVELOPMENT AND REGULATION 5.1. Vietnam Energy sector organization ........................................ 128 5.2. EVN Organization ........................................ 129 5.3. Petrovietnarn organization ........................................ 130 5.4. Vinacoal organization ........................................ 131 5.5. Power Sector Policy Statement ........................................ 132 5.6. Action Plan for Institutional Reform of the Power Sector ........................................ 136 - 127 - VIETNAM ENERGY SECTOR - _ I I_ _ Prime Minsiter's Of fice Council of Ministers Office of the Govermnment Commtittees to Council Oil and Gas Dept. Electricity Dept. State Petroleum Management Authority (SPMA) Petrovietnam National Energy Policy to be implemented Operating Depts.: PVGC (Bach Ho Gas pipelines) PVTC,PVCC Office Policy, Rights management, Regulation for upstream Non-Operating Depts,PVSC,PVEP about 10,000 employees Proposed Oil & gas, pipelines Vietsopetro Private Sector | Operation of Bach Ho e.g. Dai Hung (BHP)| 50/50 JV with Russian __l companyI State Committee for Pricing (SCP) Recommend & monitor max prices for electricity, pet - products also steel, cement, telecom, dom air fares and recommended natural gas prices l MPI Ministry of Industry Ministry of Finance Ministry of Trade Gas Steering Committee Coal & Power Investigation & Design Cos, Construction Cos Taxation strategies in each sub-sector Electric Law Stteering Committee Domestic and Foreign Borrowing EVN VINACOAL | Energy Institute Coalimex Hanoi PC, PCI Coal Companies Central PC3 CamPha, Uong Bi, § -, HoChiMinh City PC, Hong Gai etc. I South PC2 ORGANIZATION CHART OF ELECTRICITY OF VIETNAM S~lpefvison Dept.Management Board General director | Vice General Director Vice General Director Vice General Director Vice General Director Vice General Director (PRODUCTION) (BUSINESS) (CONSTRUCTION) (ACCOUNTING & FINANCE) (NESMENT & Dev.) ; Generation Dept. | > Administration Dept. | _2 Personal Dept. l _ CoConstruction Finacial & International Management Dept. Accounting Dept. Cooperation Dept. GridDept. l | BusinessDept. l _ InspectionDept. | Economic Estimation Planning Dept. Appraisal Dept. | lectricity Safely Rural Eclectricity Material, Import- Pre-Investme n Dept., l + Dept. 1 Export Dept. _PNational Load | ProjeDt Management _ Dispatching Center | Boards _ ; ~~~~~~~~~~~~~~~~~~~~~Dependent Accounting Units Independent Eeg ~kc Accounting Units -t| Electricity Telecom | tjb Co.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ , PETROVIETNAM ORGANIZATION CHART | BOARD OF DIRECTOR I |PRESIDENT & CEO AND MANAGEMENT BOARD| Exploitation & production Vietsopetro Joint Venture Oil&gas processing ' . ADF Vietnam Joint Venture Petrovietnam Processing & Petrovietnam Exploration & Vietnam Petroleum Institute [pDistribution Company Production Compnay (VPI) distib. (PVPDC) (PVEP) I distib. ________ _______ ________ J [ ___ ________ _______ ______ _ ________ _______ _P etro-TPotro-T w er iJoin VV entur R&D Center for Petroleum Petrovietnanm Gas Company Petrovietnam PSC Processing (RDCPP) - Science,tech.&environ. (PVGC) 1 Supervising Company LPG Vietnam Joint Venture ______________ .____ (PVSC) LPG Victnam JointIVe Planning Petrovietnam Engineering & R&D Center for Petroleum Construction Company | Petrovietnam Training & Safety & Environment Tuyen Quang DMC barite (PVECC) Manpower Supply Center (RDCPSE) Joint Venture o | Commerce ______________ _ ] [ (PVTMSC) Petroleum Technical Service Thang Long LPG Joint Finance l l Company (PTSC) l Petroleum Information Venture Finance Co pnCPT Center_________________________ Drilling Mud Company | | Best Food Catering Joint Accounting (DMC) Venture Internation Cooperation Petrovietnam Trading Petrovietnam Golden Company (PETECHIM) Processing |Organizing & personnel| Petrovietnam Tourist Shell Codamo Lub. Oil Joint Service Company (PVTSC) Venture Training P Tourist E~~~~~~~~~~~~~~ ~ ~~~~~~~~~~~~~~~~~~~~~~~~~ Helivifra JointVnue| p > Petrovietnam Insurance H Inspection l l Company (PVIC) - CD Vietubes Joint VentureX Administration ORGANIZATION CHART OF VINACOAL BOARD OF SUPERVISION MANAGEMENT COMMITTEE GENER-AL DIRECTOR DTY. GEN DIR. DTY. GEN DIR. DTY. GEN. DTY. G . DIR. Investment, Production Equipment & Material; DTY. GEN. DIR. Military forces DTY. GEN. DIR. construction & technology & Human resources & salary; Coal Processing & cum General Economic CHIEF development of non- Environment Training; Health Care Sale DIRECTOR Affairs ACCOUNTANT coal sector ..North East Company CORPORATION INDEPENDENT ACCOUNTING MEMBER UNITS D ENDE COUNTING NON-PROFIT UNIT JOINT VENTURE OFFICE_MEMBER UNITS UNITS 1. Hon Gai Coal Co. 13. Mao Khe Mining Co. 5. Mao Khe Mech. Fac. I. Coal Trading & Port Co. 1. Mining Scien. & Tech. 11. Hanoi Heritage J-V i histitute - Infor. & Tech. Serv. otel Mine Construction Co. 14. Vang Danh Mining Co. 26. Aoto Mech. Fac. . Hon Gai Coal Prep, Ent. Cen. - ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~. Ha Long Heritg - Uong Bi Coal Co. 1 a Lam Mining Co. | 7 North Coal Proc Co. . Worker Transport Ent. . Mining Tech. College ota J Interior Coal Co. 16. Thong Nhat Mining Co. 8. Central Coal Proc. Co. _ . Coal Invest, Conslt. Cen. tL -------- +I I.Economic High School -. Hai Long Cement J-V S. Quang Ninh Coal Co. 7.MnDugMingC.9. South Coal ProcCo. 5. Mining Recu~-e _Cente_r_ ] Co *Camn Pha Mining Tann School North East Co. | ll. Khe Cham Mining Co. 0. In-Ex & Int'l Coop. Co. . Elec. Adjsst. & Experimental Center | IS,cTha VICCOA Beer 4o. r. Hon Gai Mining Training ~ ~~~~~~~~~~~~VEFnt. coc San Mining Co | 19 Geology & Mining expl Co. 1 Trans. & Loading Co. 7. VN Coal Trasaction Center 5. Hon Gai Mining Training 4 IS, - - F~~~~~~~~~~~~~~~~~~~~~~~~~~~. Quansg Ninh Universal Deo Nai Mining Co. 0 MinngIndt.&Cons.Consulting.Co. 2.MiningChemicalCo. I llamasResourcesDevelopment.Cede .Friendship Mning Training ement - iSchool Cao Son Mining Co. 21. Cua Ong Coal Prep. Ent. 3. General Service & Trading Co. . Vietnam Coal Journall I r. I 17Mining Training & 10. Ha Ta Mining Co. | 2. Ca Pha Mechanical Fac. 4. Vinacoal Tourist Co.onstruction School SMech. &Construction_ P;t iI. Nui Beo Mining Co. I23. Ion Gai Mechanical Fac. |i35.SBeer&Beverage Co. . MeSchool . & C 12. Duong Huy Mininig Co. 24. Uong Bi Elec. Mechanical Fac. 36. Infor, Tech. & Env. Co. . Elect. Mcch. Training School o 437. Product Control Center Annex 5.5 Page 1 of 4 Socialist Republic of Vietnam Power Sector Policy Statement August 12, 1997 This paper sets out the main elements of the Government of Vietnam's (GOV) power sector policy. It outlines the objectives and strategy of the Government and the Ministry of Industry for the development of the power sector of Vietnam. This paper is an update of the Power Sector Policy statement issued by the Ministry of Industry on December 1st, 1995. This policy paper is supported by a Reform Implementation Plan (Attachment I). A. Policy Objectives The Government's power sector policy aims to achieve the following objectives: (a) Provide electricity access to the national economy and the entire population of Vietnam. (b) Increase the operating/technical efficiency of the electricity sector to optimize the use of scarce investment resources. (c) Ensure reliable electricity supply of good quality (d) Resolve the mismatch between market-based production costs and State administered prices (e) Clearly delineate and separate State management functions and business management functions (f) Enable Vietnam to raise the necessary financing for power sector expansion to meet economic growth targets. B. An Overview of the Power Sector In January 1995, GOV issued Decree No. 14/CP to establish Electricity of Vietnam (EVN) as a State Corporation for the different power sector entities engaged in generation, transmission, distribution and associated service functions. These entities are grouped under two accounting systems: (I) independent accounting units; and, (ii) dependent accounting units. The business units fall into three categories: Those engaged in generation and transmission are subject to dependent accounting, and consolidation of accounts takes place at the level of EVN as a whole (general EVN). There are 17 business units involved in these activities- 13 for generation, 4 for transmission and 1 for the National Load Dispatch Center. Those engaged in distribution and supply are independent accounting enterprises (i.e. State Enterprises as defined in State Enterprise Law). There are five distribution units: Hanoi, HCMC, PCI, PC2, and PC3. Those involved in the provision of services (including finance, design and construction, and planning) have either independent or dependent accounting status. - 132- Annex 5.5 Page 2 of 4 Figure 1. Electricity of Viet Nam (EVN) Generation Business Unit (12 Power Plants) Transmission Business Unit (NLDC & 4 Transmission Cos) -BTPI BTP2 BTP3 BTP4 BTP5 Hani Pwe HCM Cit Poe oe Consumers BTP Bulk Transfer Price NLDC National Load Dispatch Center EVN has the legal status of a state corporation under the State Enterprise Law. Independent accounting entities have the status of state enterprises that are members of the state corporation (i.e. EVN). Within EVN, the Board of Management (BoM) has the highest authority and exercises functions established under the State Enterprise Law. The Ministry of Industry is responsible for policy and oversight of the power sector. From a sector structure perspective, the core functions of generation and transmission are currently integrated and under direct management of the EVN headquarters. The generation-transmission core sells electricity in bulk to the five independent distribution companies (Figure 1). Retail prices to final consumers are established by the Government and are currently uniform across the country. The mechanism for setting the BTP allows the distribution companies to make a target profit - the profit level is determined by EVN. Given uniform retail pricing and differing distribution system costs for each distribution company, the bulk transfer price is different for each distribution company. Vietnam is currently experiencing high growth in electricity demand. Vietnam's power development plan envisages the addition of 3,000 MW by the turn of the century and about 6,000 MW by the year 2005o To meet this ambitious expansion program, a combination of goverment budgetary resources, official development assistance (ODA) funds, resources from multilateral financial institutions and diversified finance will be utilized. - 133 - Annex 5.5 Page 3 of 4 C. Reform Strategy The Government reform strategy addresses the following key aspects of power sector reform. A reform implementation plan is attached. (a) Structural Reform and Commercialization of Sector Enterprises GOV will facilitate the transformation of the power sector enterprises into efficient commercially run entities which are financially strong and creditworthy, and have management autonomy in operations. The Government strategy includes: Introducing cost accounting practices in the transmission network operations and facilitating the transition of the transmission business into a profit center. Subsequently, it is expected that a separate transmission company would be established as an independent legal entity (i.e. as a independent accounting member unit of EVN). Developing efficient pricing and contractual relationships between the transmission network business unit and the generation stations on the system. These contracts will facilitate the efficient production of electricity and optimize resource utilization on the system. Transforming the distribution entities which are currently independent accounting state enterprises into entities that have management and financial autonomy from the EVN State Corporation. This transition will include the development of more efficient performance incentives for the distribution entities based on market based costs. Commercial management practices will be developed in these entities to prepare for separation from the EVN State Corporation structure. (b) Legal and Regulatory Framework The GOV is preparing legislation for the power sector. It is expected that the primary Electricity Law will be supported by secondary legislation covering the aspects of tariff regulation, service regulation and licensing of activities in the power sector. This body of legislation would form a consistent legal basis to facilitate commercial sector operations and objective government oversight of the sector. The following steps are envisaged: promulgation of a primary Electricity Law - development of supporting secondary legislation to the Electricity Law, to inter alia address: (a) scope and structure of regulatory agency; (b) procedures for tariff setting and regulation; (c) administrative regulations and standards. - preparation of a Grid Code that would address issues related to interconnection and operating standards between generation entities and the transmission entity. (c) Electricity Pricing It is recognized that cost-based retail prices and internal transfer prices are essential to a commercial power sector that is expected to raise the required capital for its needs. Retail prices based on these principles will ensure that resources are allocated efficiently in the economy and that consumers face the appropriate price signal to utilize electricity efficiently. Efficient internal prices will provide incentives to the distribution companies to operate efficiently and establish an objective basis to evaluate the cost of purchasing power from BOT/JV power generation schemes. The government plans to: - 134 - Annex 5.5 Page 4 of 4 Progressively raise average retail tariff to about USc 7.0/kwh by 1999 and take all measures necessary to realize a self financing ratio of not less than 30% for the electricity sector as a whole. introduce a cost-based bulk transfer price for bulk power sales to the distribution companies. (d) Diversified Participation in Vietnam's Power Sector The objectives for promoting diversified sector participation are to: (i) mobilize additional financial resources in the form of debt and equity financing; (ii) supplement public sector investments; (iii) access the diversified sector's proven skills in project design, finance, implementation and operation; and, (iv) create an environment that fosters competition. It is expected to achieve: (i) balanced portfolio mix: power projects financed from diversified sources will be consistent with Vietnam's least-cost power plan in terms of size and technology, and with the system's operational needs; (ii) competitiveness: project sponsors will be selected through a competitive bidding process measured in terms of lowest price of electricity delivered; and, (iii) limited recourse project financing: foreign investors will secure financing on a limited recourse basis where project sponsors and lenders will assume commercial and project risks. Diversified participation will be sought in both thermal and hydro generation schemes. A variety of financing structures may be utilized to involve diversified capital in generation. Diversified financing approaches will also be evaluated for distribution operations. (e) Rural Electrification Only 65% of the Vietnamese population has access to electricity. Access to electricity is much lower in rural than in urban areas. In order to increase rural access to electricity the Government will develop a Rural Electrification Master Plan. This master plan will define: (I) criteria for expanding the electricity network to rural areas; (ii) appropriate regulatory, institutional and financing frameworks; (iii) methodologies for forecasting and economic evaluation of altemative supply locations and options; (iv) technical standards for design, construction and operation. (f) Electricity Conservation To facilitate the efficient utilization of electricity and encourage electricity conservation practices and technologies, the Govemment will implement measures and systems for electricity demand-side management (DSM) and load management in Vietnam. Signed Ministry of Industry Attachment 1: Reform Implementation Plan - 135 - Objectives Strategy [Implementation Steps & Timetable I Achieve financial viability and sustainability of 1.1 Progressive increase of average retail tariff to 1.1.1 Self Financing Ratio (SFR) targets: overall power sector operations about USc 7.0/kwh by 1999 and taking all - 1997 SFR 30% measures necessary to ensure a self financing ratio of not less than 30% in any year. - 1998 SFR 30% - 1999 SFR 30% 1.2 Increase average retail tariff to financially 1.2.1 Average retail tariff increases: sustainable levels - average for 1997 6.2 USc/kwh - average for 1998 6.6 USc/kwh - average for 1999 7.0 USc/kwh 1.3 Implement a cost-based bulk supply tariff (BST)l. 1.3.1 EVN to prepare annual audited accounts This is distinct from existing internal bulk supply identifying full costs of generation and tariff that does not reflect actual G&T costs and is transmission (G&T). These audited statements based on PCs ability to pay to achieve a target will be prepared beginning from January 1998 - profit. which is the start of the new fiscal year. EVN will ensure that the difference between cost- 1.3.2 Implementation of full cost-based bulk supply reflective bulk supply tariff (BST) to PCs and tariff to PCs may be phased, if necessary. retail tariff by year 2000, which results in an - 1998 70% of actual G&T cost operating loss to PCs is compensated transparently - 1999 85% of actual G&T cost i.e. not through the bulk supply tariff. - 2000 100% of actual G&Tcost >t. 'The term bulk supply tariff (BST) refers to the price at which electricity is sold from EVN generation and transmission operations (G&T) to the distribution companies. Objectives { Strategy [Implementation Steps & Timetable 2. Commercialize, corporatize and diversify ownership 2.1 Strengthen EVN HQ management procedures and 2.1.1 Strengthen the HQ function of distribution of independent accounting distribution units (i.e. systems to oversee PC operations efficiently. management: PCs) a. Distinct function for distribution management at level of EVN Deputy Director Generals (DDG) will be defined. Evidence of this assignment of functions at DDG level will be provided by January 1998. c. EVN HQ to issue: - accounting procedures for implementing phased increase in cost-based bulk supply tariff by January 1998. (refer 1.3.2) - Information system standards for all PCs. (January 1999). 2.2 Increase management and financial autonomy of 2.2.1 Issue separate Charters for all Pcs by mid-1998, PCs. providing increased financial and management autonomy. 2.2.2 Annual accounting audit by independent auditors for all PCs from January 1998 onwards. 2.3 Strengthen the internal organization and operations 2.3.1 Implementation of a finance and commercial of the PCs. organization structure within each PC as shown in attachment 1. - PC Hanoi and HCMC - January 1998 - PCI, PC2, and PC3 - January 1999 2.3.2 Begin work on strengthening the Meter Reading, Billing and Collection Systems2 Terms of Reference - Attachment 2. (Initialfocus for pilot implementation could be in Vung Tau and Halong). 2.4 Equitization of distribution operations. 2.4.1 Pilot equitization of one or more distribution operations based on results of PHRD study. Target date to commence equitization program: 0 o 4S 2 Reference 4.3.1I, Report on Improvement of Financial and Accounting System, Draft Final Report by Price Waterhouse, March 1997. Objectives Strategy Implementation Steps & Timetable 3.(A)Consolidate transmission operations as a profit 3.1 Identification and separate accounting of 3.1.1 Formation of transmission operations as a cost center and eventually as a wholly-EVN owned transmission costs center, based on completion of EVN accounting independent accounting unit. audit. - Transmission cost center operating accounts prepared annually beginning in January 1998. 3.2 Preparatory work for transition of transmission 3.2.1 PHRD-study to be completed by mid-1 998. operations to independent accounting member unit Recommendations will be reviewed with EVN of EVN and implementation will commence. Target dates: - Transmission formed as profit center - December 1999. - Transmission formed as independent accounting member unit of EVN - after 2000. 3.(B) Strengthen EVN transmission planning 3 .(B). I EVN to develop planning capacity to optimize capabilities. transmission network expansion with generation -eexpansion plans. 00 - EVN to identify appropriate least cost planning software that incorporates transmission network optimization together with generation expansion. (September 1997) - EVN to obtain the package and training for its utilization. (January 1998) - EVN to prepare system expansion plan with optimization of transmission and generation. (December 1998). 0 o4~ Objectives Strategy Implementation Steps & Timetable 4. Create a system of government regulatory oversight 4.1 Implementation of an Electricity Law that defines 4.1.1 Timetable for preparation and presentation of that allows the power sector to be financially viable the functions of government in the areas of policy draft Electricity Law to the National Assembly: and efficient, and also protects the interest of the and regulation. Draft regulations will be prepared - Preliminary review - October 1997 consumer for reliable and least-cost supply. that define the basic regulatory framework and initial institutional mechanism to perform the - For promulgation - March 1998 regulatory functions. (The above work is partially supported by ESMAP Grant and IDF Grant) 4.2 Preparation of secondary regulations, staff training 4.2.1 Process and timeframe: and institutional capacity building for the - Preparation of secondary legislation. Expected establishment of the regulatory function. promulgation of secondary legislation within 12-18 months of approval of Electricity Law by National Assembly. - Preparatory work for establishing a separate so unit to perform regulatory functions TA to be initiated around April 1998. Implementation of TA - March 1998 to mid- 1999. 4.3 Government to establish a separate regulatory unit 4.3.1 Target date for the forTnation of unit to perfor to perform regulatory functions. regulatory functions - January 1999. o4~A Annex 6 ANNEX 6. AN AGENDA FOR ACTION 6.1. Energy Sector Policy Reform Agenda .141 - 140- Annex 6.1 Page 1 of 1 THE ENERGY SECTOR POLICY REFORM AGENDA The policy matrix below spells out the short and medium term agenda for reform for 1999-2005: Reform Objectives Strategy for the period 1999- 2005 Creating an economic Completing competitively bid projects like Phu My 2.2 and efficient commercial Developing gas supply infrastructure from Nam con basin energy delivery system Increasing energy efficiency and DSM programs Improving overall energy system efficiency including reducing transmission and distribution losses Promoting exploration through appropriate fiscal incentives and systems Improving efficiency of the coal distribution systems Preparing a National Hydropower Master plan Developing a financing Implementing tariff reform in the energy sector strategy for energy Increasing average retail power tariffs to 7 cents/kwh by March 2001 and sector ensuring self financing ratio of not less than 30 % in any year Implement a cost-based bulk supply tariff (BST) in the power sector Co-ordination of external borrowing strategy Promoting private participation in energy sector Pilot equitization in electricity and gas Opening up distribution of downstream petroleum markets in competitively possible markets Ensuring energy Extending modern energy use to rural area through grid extension expansion is equitable Promoting renewable energy development for remote communes and environmentally Energy system planning to incorporate environmental costs sustainable Strengthening pollution monitoring Revising environmental standards Phasing out lead in gasoline Improving corporate Redefining governments role as owner govemance and creating Commercialise, corporatize and diversify ownership of independent creditworthy institutions accounting units (e.g. . PCs in EVN) Streamline investment approval processes Increase management and financial autonomy of PCs. Consolidate transmission operations as a profit centre and eventually as a wholly-EVN owned independent accounting unit. Rationalising sector Creating a National Energy Policy Council and a National Energy Policy governance Office Implementing arms length regulation and creating a regulatory agency for electricity and gas State Petroleum Management authority to be energised Issuing a Natural Gas Policy statement Issuing a national energy policy Passage of Electricity Law and secondary legislation - 141 -