fueling vietnam's development- new challenges for the energy...
TRANSCRIPT
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 UnitVietnam Country DepartmentEast Asia and Pacific
Document of the World Bank
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Currency Equivalents
Currency Unit = Dong (D)US$1.00 = D12,990 (July 98)
Fiscal YearJanuary I - December 31
Date of last Sector ReportJune 18, 1993
Weights and Measures
bbl - barrelbm3 - billion cubic meterbcf - billion cubic feetbcm - billion cubic meterbpd - barrel per daydwt - deadweight tonGWh - GigaWatt - hour (I million kiliwatt - hours)ha - Hectarekcal - kilocalorie (3.97 British thermal units)km - kilometer (0.62 miles)kV - kilovolt (1,000 volts)kW - kilowattkWh - kilowatt - hourm - meterm3 - cubic metermm - millimetermmb - million barrelsmmcf - million cubic feetmt - million tonsMW - mega wattppm - parts per milliont - tontcf - trillion cubic feettoe - 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 SeverinoDirector Andrew SteerSector Manager Yoshihiko SumiTask Manager Anil Malhotra
Abbreviations and Acronyms
ADB - Asian Development BankAFTA - ASEAN Free Trade AreaASEAN - Association of South East Asia NationsBOT - Build - Operate - TransferBP - British PetroleumBTP - Bulk Transfer PriceCC - Combined CycleCIEM - The Central Institute of Economic ManagementCOALIMEX - Coal Import-Export and Material Supply CorporationDoi Moi - Vietnam's economic renewal program launched in 1986EDI - Economic Development InstituteEHV - Extra High Voltage Transmission LineEl - Energy Institute of VietnamEIA - Environmental Impact AssessmentENPEP - Energy and Power Evaluation ProgramESAF - Enhanced Structural Adjustment FacilityESMAP - Energy Sector Management Assistance ProgramEVN - Electricity of VietnamFDI - Foreign Direct InvestmentGDP - Gross Domestic ProductGEF - Global Environment FacilityGSA - Gas Supply AgreementGT - Gas TurbineHCMC - Ho Chi Minh CityHVAC - High Voltage Alternative.CurrentHVDC - High Voltage Direct CurrentIDF - Institutional Development FundIMF - International Monetary FundIUCN - International Union for the Conservation of NatureLPG - Liquified Petroleum GasLRMC - Long Run marginal CostMIS - Management Information SystemMOI - Ministry of IndustryMPI - Ministry of Planning and InvestmentNEAP - National Environment Action PlanNGO - Non-Governmental OrganizationNPESD - National Plan for Environment and Sustainable DevelopmentODA - Official Development AssistanceOECD - Organization for Economic Cooperation and DevelopmentOECF - Overseas Economic Cooperation FundPCI - Power Company IPC2 - Power Company 2PC3 - Power Company 3PCI - Pulverized Coal InjectionPETECHIM - Petroleum Equipment Import CorporationPETROLIMEX - Importer and Exporter of Petroleum ProductsPVN - PetroVietnam
PHRD - Population Human Resource DevelopmentPIDC I - Power Investigation and Design Company 1PIDC2 - Power Investigation and Design Company 2PSC - Production Sharing ContractsRAP - Resettlement Action PlanRoW - Right of WaySAC - Structural Adjustment CreditSCP - State Committee on PricingSIDA - Swedish International Development AgencySOE - State Owned EnterprisesSUC - Standard Unit CostsT&D - Transmission & DistributionTA - Technical AssistanceTR - Transferable RublesUNDP - United Nations Development ProgramUNEP - United Nations Environment ProgramVITTEP - Vietnam Institute of Tropical Technology and Environmental protectionVOC - Volatile Organic CompoundsWASP - Wein Automatic System Planning PackageWB - 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 ........................................................ I1.2. Population and Estimated GDP by Sector (1980-1995) .......................................................21.3. Consumption of Modern Energy (1980-1995) ........................................................ 31.4. Supplies of Modern Energy (1980-1995) ........................................................ 41.5. Consumption of Main Petroleum Products (1980-1995) .......................................................51.6. Production and Consumption of Natural Gas and
Crude Oil (1980-1995) .................................. 61.7. Consumption of Coal (1980-1995) .................................. 71.8. Electricity Consumption (1980-1995) .................................. 81.9 Energy Balance and Commodity accounts 1995 .................................. 9
Graphs:
1.10. Consumptionofmodernenergy- 1980-95 .10
ENERGY DEMAND FORECASTS
1.11. Forecast Population of Viet Nam ........................................................ 11.12. Macroeconomic Forecast for Base Case ....................................................... 121.12. Macroeconomic comparison with Thailand, Malaysia, Philippines, and Korea .................. 131.13. Base Year Prices of Key Energy Products ....................................................... 141.14. Forecast of Opportunity Value Energy Prices ....................................................... 151.15. Electricity Demand Forecasts for Three Scenarios ....................................................... 161.16. Electricity Demand Forecast under Efficiency Measures .................................................... 171.17. Energy Balance and commodity accounts 2005 ....................................................... 18
Demandforecasts for Base case scenario
1.18. Summary of Electricity Demand for Viet Nam ....................................................... 191.19. Northern Region Electricity Demand ....................................................... 201.20. Hanoi Electricity Demand ....................................................... 211.21. Rural North Electricity Demand ....................................................... 221.22. Central Region Electricity Demand ....................................................... 231.23. Southern Region Electricity Demand ....................................................... 241.24. Ho Chi Minh City Electricity Demand ....................................................... 251.25. Rural South Electricity Demand ....................................................... 261.26. Petroleum Product Demand Forecast ....................................................... 271.27. Coal Demand Forecast ....................................................... 28
1.28. Gas Consumption Forecast .......................................... 291.29. Summary of Modem Energy Consumption Forecast .30
Graphs
1.30. Population ........................................ 311.31. Regional share of GDP ........................................ 321.32. Sectoral share of GDP ........................................ 331.33. Electricity demand forecast for scenarios ........................................ 341.34. Electricity demand under efficiency measures ........................................ 351.35. Base case electricity demand - by sector ........................................ 361.36. Petroleum Product demand ........................................ 371.37. Coal Demand ........................................ 381.38. Natural Gas Demand Forecast ........................................ 391.39. Diesel Conservation ........................................ 401.40. Primary Modem Energy Forecast ........................................ 411.41. Shares of Prim a ry En ergy Forecast ........................................ 421.42. Modern Energy per US$000 GDP ........................................ 431.43. Typical Composition of Energy Prices in Engergy sector ........................................ 44
ANNEX 2.1. THE POWER SECTOR
2.1.1. Vietnam Electric Power System - Historical Data ........................................ 462.1.2. Existing Power System in 1998 ........................................ 472.1.3. Electricity Generation Balance in 1996 (TWh, estimated) ........................................ 482.1.4. Trends in Electricity Generation and Consumption ........................................ 482.1.5. Electricity Generation Demand Forecasts ........................................ 492.1.6.a Electricity Tariffs (at May 1997) ........................................ 502.1.6.b Electricity Tariffs (at Dec 1998) ........................................ 502.1.7. Estimated Seasonal Plant Load Factors ........................................ 502.1.8. Hydro Plant Investment Options ........................................ 512.1.9. Thermal Plant Investment Options ......................................... 522.1.10. Comparative cost assumptions .532.1.11. Comparative cost estimates, c/kWh .542.1.12. Cases Examined in Power System Analysis .552.1.13. Comparison of Investment Plans for 5 Cases, to 2010 .562.1.14. Evaluation and Ranking of Cases (Indicators) .582.1.15. Fuel Consumption Forecasts in Power Generation .592.1.16. Son La Hydro Plant: NPV Analysis .592.1.17. Power system losses .602.1.18. DSM and energy efficiency .602.1.19. Comparison of Investment Plans .612.1.20. Summary of Generation costs .62
Graphs:
2.1.21. Regional Character of Viet Nam's Power System .632.1.22. Increasing Electricity Intensity per unit of GNP, 1974-1993 .632.1.23. Monthly Generation Mix for the Year 2000 (Base case) .642.1.24. Typical Daily Load Curves (PC2, 1995) .652.1.25. Annual Variation in Demand (1995) .652.1.26. Comparative Generation Costs-New Plant .662.1.27. Breakeven Fuel Prices (Netback Values) .662.1.28. Gas Demand in Power Generation .672.1.29. Monthly Gas Swing (Base case) .672.1.30.a Fuel Use Forecast - Fuel Consumption in Power Generation - Gas Demand .. 682.1.30.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 .722.2.2. Exploration History and Discovered Reserves Potential .732.2.3. Expected Oil and Associated Gas Production .742.2.4. Production Prospects from Speculative Gas Reserves (bcm)
- Nam Con Son Basin .752.2.5. Production Prospects from Speculative Gas Reserves (bcm)
- Son Hong Basin .762.2.6. Estimates of Development Cost of Associated Gas .772.2.7. Development Cost Estimates of Non Associated gas
- Lan Tay, Lan Do & Hai Thach .782.2.8. Development Cost and Associated Gas Economic cost
- Cuu Long Basin .792.2.9. Hydrocarbon Production and Supply Cost of Gas .802.2.10. Cost of Exploration and Development for Speculative Reserves ........................................ 81
Graphs:
2.2.11. Potential Oil Production from discovered reserves- Cuu Long Basin ................................. 822.2.12. 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 ....................................................... 852.3.2. Organization of PVGC ....................................................... 96
ANNEXES 2.4: THE COAL SECTOR
2.4.1. Coal Reserves in Coalfield under exploitation .1092.4.2. Coal Demand .1102.4.3. Vinacoal Production Capacity .Ill2.4.4. Mine head Production costs .1122.4.5. Elements in Production Costs .1132.4.6. Port Facilities .1132.4.7. Anthracite Production and Trade .114
ANNEX 3: ENERGY AND ENVIRONMENT
3.1. Ambient Air Quality standards .1163.2. Emission Standards from Stationary Sources .1173.3. Coal mining disturbed area and production .1183.4. Hydroelectric Plant incremental investments .1183.5. Thermal plant incremental investments .1193.6. Environmental costs under the base case scenario . 119
ANNEX 4: INVESTMENT PRIORITIES AND FINANCING STRATEGIES
4.1. Energy sector financing requirements- 1998-2002 .......................................... 1214.2. The need for government guarantees .122
ANNEX 5: INSTITUTIONAL DEVELOPMENT AND REGULATION
5.1. Vietnam Energy sector organization ........................................ 1285.2. EVN Organization ........................................ 1295.3. Petrovietnam organization ........................................ 1305.4. Vinacoal organization ........................................ 1315.5. Power Sector Policy Statement ........................................ 1325.6: 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 ........................................................ 11.2. Population and Estimated GDP by Sector (1980-1995) ........................................................21.3. Consumption of Modem Energy (1980-1995) ........................................................ 31.4. Supplies of Modem Energy (1980-1995) ........................................................ 41.5. Consumption of Main Petroleum Products (1980-1995) .......................................................51.6. Production and Consumption of Natural Gas and
Crude Oil (1980-1995) ................................. 61.7. Consumption of Coal (1980-1995) ................................. 71.8. Electricity Consumption (1980-1995) ................................. 81.9 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 ....................................................... 111.12. Macroeconomic Forecast for Base Case ....................................................... 121.12. Macroeconomic comparison with Thailand, Malaysia, Philippines, and Korea .................. 131.13. Base Year Prices of Key Energy Products ....................................................... 141.14. Forecast of Opportunity Value Energy Prices ....................................................... 151.15. Electricity Demand Forecasts for Three Scenarios ....................................................... 161.16. Electricity Demand Forecast under Efficiency Measures .................................................... 171.17. Energy Balance and commodity accounts 2005 ....................................................... 18
Demand forecastsfor Base case scenario
1.18. Summary of Electricity Demand for Viet Nam ....................................................... 191.19. Northern Region Electricity Demand ....................................................... 201.20. Hanoi Electricity Demand ....................................................... 211.21. Rural North Electricity Demand ....................................................... 221.22. Central Region Electricity Demand ....................................................... 231.23. Southern Region Electricity Demand ....................................................... 241.24. Ho Chi Minh City Electricity Demand ....................................................... 251.25. Rural South Electricity Demand ....................................................... 261.26. Petroleum Product Demand Forecast ....................................................... 271.27. Coal Demand Forecast ........................................................ 281.28. Gas Consumption Forecast ....................................................... 291.29. Summary of Modem Energy Consumption Forecast ....................................................... 30
Graphs
1.30. Population ....................................................... 311.31. Regional share of GDP ....................................................... 321.32. Sectoral share of GDP ....................................................... 331.33. Electricity demand forecast for scenarios ....................................................... 341.34. Electricity demand under efficiency measures ....................................................... 351.35. Base case electricity demand - by sector ....................................................... 361.36. Petroleum Product demand ....................................................... 371.37. Coal Demand ....................................................... 381.38. Natural Gas Demand Forecast ........................................................ 391.39. Diesel Conservation ....................................................... 401.40. Primary Modern Energy Forecast ....................................................... 411.41. Shares of Primary Energy Forecast ....................................................... 421.42. Modem Energy per US$000 GDP ....................................................... 431.43. Typical Composition of Energy Prices in Engergy sector ................................................... 44
Annex 1.1Page 1 of I
ENERGY AND THE ECONOMY
1990 1991 1992 1993 1994 1995 1996 1997
EXPORTS in US $ millionTOTAL 1731 2042 2475 2985 4054 5198 7330 8955ENERGY 428 629 803 914 941 1105 1461 1530Crude oil 390 581 756 844 866 1024 1346 1419Coal- 38 48 47 70 75 81 115 111
Energy/exports as % 25 31 32 31 23 21 20 17
IMPORTSTOTAL 1772 2105 2535 3532 5245 7543 10481 10313ENERGY 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)
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Annex 1.2Page I of I
POPULATION ANDESTIMATED GDP BY SECTOR IN VIET NAM (Trillion 89 Dong)
1980 to 1995
Gross National ApproxProduct
Industry Annual Population Us$/CapitaYear Agriculture (incI Constr) Other WB Adjust Total Change millions (199OUS$)
1980 6.672 3.407 2.993 4.705 17.776 53.722 1481981 6.896 3.441 3.215 4.879 18.431 3.7% 54.927 1501982 7.621 3.721 3.248 5.253 19.844 7.7% 56.170 1581983 8.218 4.199 3.488 5.725 21.629 9.0% 57.376 1691984 8.685 4.484 3.733 6.084 22.986 6.3% 58.770 1751985 9.077 5.039 3.744 6.432 24.292 5.7% 59.872 1821986 9.207 5.268 3.983 6.650 25.108 3.4% 61.109 1841987 8.892 5.866 4.168 6.813 25.740 2.5% 62.452 1851988 9.197 6.095 4.495 7.216 27.002 4.9% 62.910 1921989 11.470 6.792 9.831 0 28.093 4.0% 63.367 1991990 11.642 6.990 10.894 0 29.526 5.1% 66.200 2001991 11.894 7.598 11.794 0 31.286 6.0% 67.800 2071992 12.751 8.623 12.617 0 33.991 8.6% 69.400 2201993 13.235 9.723 13.778 0 36.736 8.1% 71.026 2321994 13.751 11.049 15.182 0 39.982 8.8% 72.510 2471995 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 andservices .
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
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Annex 1.3Page 1 of 1
CONSUMPTION OF MODERN ENERGY IN VIETNAM1980 to 1995
TotalMODERN*
Pet Products Nat Gas Coal Electricity ENERGY
mill barrels bill cf 000tons GWh 000 TOE
1980 13.000 0.000 4052 2800 48121981 13.250 0.000 4509 2818 51791982 13.750 0.000 4983 2973 55961983 14.000 0.000 5015 3108 56331984 14.002 0.000 5010 3597 56531985 14.461 0.000 5083 3860 57611986 16.173 1.236 5500 4151 63251987 18.454 1.201 6139 4597 70971988 19.140 1.059 5808 5048 69651989 18.356 1.059 3801 5666 55071990 21.742 1.165 4039 6185 62241991 18.726 0.706 4602 6573 62831992 24.384 0.706 4445 6941 69771993 31.329 0.530 4473 7833 79731994 35.897 2.437 4757 9284 89421995 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 hydrocomponent of electricity to avoid double counting; gas products such as methanol are included ingas. Electricity is amount consumed.
Source: Compiled by Mission
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SUPPLIES OF MODERN ENERGY IN VIET NAM1980 to 1995
PETROLEUM COAL Total Self-Crude NATURAL GAS Total Electricity MODERN Supply
Offshore Offshore Offshore Onshore Domestic Exports Generation ENERGY RatioProduction 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 conversionlosses in oil gas and coal, but only hydro component of electricity to avoid double counting; Petroleum product consumption in period 1980 to 1983 isestimated. Flared gas in 1986 and 1987 estimated. ,
Source: Compiled by Mission CD
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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 sectorSource: Energy Institute, and Petrolimex, and Mission estimates
Annex 1.6Page 1 of I
PRODUCTION AND CONSUMPTION OFNATURAL GAS AND CRUDE OIL IN VIETNAM
1980 TO 1995
Natural Gas Crude Oil
Offshore Offshore RefinYear 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 Gasmill 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 0.001981 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.001982 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.001983 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.001984 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.001985 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.001986 250.0 247.5 2.5 0.0 0.0 1,236.0 0.30 0.391987 1,500.0 1,485.0 15.0 0.0 0.0 1,200.7 2.07 0.391988 4,125.0 4,083.8 41.3 0.0 0.0 1,059.4 5.11 0.391989 10,524.0 10,418.8 105.2 0.0 0.0 1,059.4 11.23 0.391990 19,070.0 18,879.3 190.7 0.0 0.0 1,165.4 19.98 0.391991 28,500.0 28,215.0 285.0 0.0 0.0 706.3 29.01 0.391992 41,300.0 40,887.0 413.0 0.0 0.0 706.3 40.70 0.391993 44,500.0 44,055.0 445.0 0.0 0.0 529.7 46.69 0.391994 49,100.0 45,783.8 491.0 565.0 2,260.1 176.6 51.06 0.391995 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
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CONSUMPTION OF COAL IN VIET NAM (O0Otons/year, of clean coal)1980 to 1995
TOTALS
CONSUMPTION BY INDUSTRIAL ACTIVITYConsumption 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 -xo
Annex 1.8Page I of I
ELECTRICITY CONSUMPTION IN VIET NAM (GWhlyr Sales)1980 to 1995
Year Industry Residential Agricultural Other TOTAL
1980 2,800 estimated1981 1,516 691 316 295 2,8181982 1,658 717 246 352 2,9731983 1,754 763 237 354 3,1081984 2,031 843 308 415 3,5971985 2,108 985 303 464 3,8601986 2,204 1,094 331 522 4,1511987 2,383 1,243 387 584 4,5971988 2,579 1,332 449 688 5,0481989 2,617 1,880 470 699 5,6661990 2,845 2,035 587 718 6,1851991 3,069 2,052 809 643 6,5731992 3,197 2,163 975 606 6,9411993 3,476 2,520 1,144 693 7,8331994 3,944 3,130 1,360 849 9,2841995 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, 1995Coal 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 GeneratioaUs.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 -292Om 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 0Imports 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 0PrmaryEnergy 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 4.4R=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 1.5Rur 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 7.5Rurl 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 (etknaltedHe 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 1.12Page 1 of 2
ECONOMIC GROWTH FORECAST VIET NAM Case B
NORTHERN REGION - HANOI + RURAL
GDP Growth Rates1991-95 1996-1997 1998-2000 2001-2015 ForecstAvge Percent of Regional EconomyActual 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 18.60Constr 25.99% 13.87%b 6.88% 9.88% 9.2% 3.49 7.86 9.20 13.35Industry 10.70% 11.00% 6.78% 9.00% 8.5% 16.88 19.93 22.10 28.39Trade/other 6.38% 7.65% 6.35% 7.65% 7.3% 37.29 36.10 37.20 39.65
Percent of Viet Nam EconomyNORTH 7.08% 7.5% 5.4% 7.2% 6.7% 38.21 36.55 34.81 33.40GOP
HANOI GDP Growth Rates1991-95 19956-1997 1998-2000 200t-2015 Forecst Avge Percent of Local EconomyActual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015
Agriculture 4.56% 4.00% 3.00% 3.50% 7.22 5.86 4.93 2.54Constr 11.46% 13.00% 6.00% 9.00% 5.19 5.80 6.28 7.02Industry 10.82% 11.00% 6.00% 9.00% 23.84 25.87 27.02 30.24Tradelother 8.58% 8.00% 6.00% 8.00% 63.75 62.47 61.77 60.20
Percent of Viet Nam EconomyHanoi GDP 9.02% 8.9% 5.8% 8.2% 7.6% 6.01 6.29 6.22 6.85
RURAL GDP Growth RatesNORTH
1991-95 1996-1997 1998-2000 2001;-201 Forcat Avgs Percent of Local EconomyActual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015
Agriculture 3.69% 3.90% 3.00% 3.50% 48.90 42.39 37.27 22.75Constr 29.33% 14.00% 7.00% 10.00% 3.17 8.29 9.84 14.98Industry 10.66% 11.00% 7.00% 9.00% 15.58 18.70 21.03 27.92Trade/other 5.53% 7.50% 6.50% 7.50% 32.35 30.62 31.86 34.35
Percent of Viet Nam EconomyRural North 6.70% 7.2% 5.3% 7.0% 6.5% 32.20 30.26 28.59 26.54
CENTRAL REGION
GDP Growth Rates1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Regional EconomyActual 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 20.97Constr 15.80% 10.00% 8.00% 9.00% 8.8% 3.80 6.12 7.00 10.50Industry 7.62% 7.00% 7.00% 7.00% 7.0% 19.39 21.66 22.79 25.89Trade/other 8.40% 8.00% 7.00% 7.00% 7.0% 30.23 35.00 37.52 42.64
Percent of Viet Nam EconomyCENTRAL 5.27% 6.3% 5.7% 6.1% 5.9% 11.06 9.72 9.12 7.49GDP
SOUTHERN REGION - HCMC + RURAL
GDP Growth Rates1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Regional EconomyActual 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 11.05Constr 18.84% 16.00% 8.00% 8.79% 8.6% 2.21 3.36 3.85 4.37Industry 15.95% 14.50% 7.69% 8.83% 8.6% 26.92 36.20 39.99 45.69Trade/other 10.05% 12.00% 7.00% 8.52% 8.2% 33.11 34.29 35.56 38.89
Percent of Viet Nam EconomySOUTH 9.28% 10.9% 6.4% 7.9% 7 5% 50.73 53.73 56.07 59.11GDP
HO CHI GDP Growth RatesMIN
1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Local EconomyActual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015
Agriculture 1.16% *3.00% 3.00% 3.00% 3.85 2.38 1.76 0.84Constr 22.58% 16.00% 8.00% 9.00% 3.71 6.00 6.50 7.25Industry 12.90% 14.50% 7.10% 8.50% 35.98 38.57 39.68 41.32Trade/other 9.96% 12.00% 7.00% 8.00% 56.46 53.04 52.06 50.59
Percent of Viet Nam EconomyHCMC GDP 11.34% 13.0% 7.0% 8.2% 7.9% 14.87 17.29 19.06 21.06
RURAL GDP Growth RatesSOUTH
1991-95 1996-1997 1998-20W0 2001-2015 ForecstAvge Percent of Local EconomyActual Actual Forecast Forecast 1998-2010 1990 1995 2000 2015
Agriculture 1.54% 3.40% 3.00% 3.50% 51.82 37.42 30.31 16.70Constr 14.72% 16.00% 8.00% 8.50% 1.59 2.11 2.48 2.78Industry 17.75% 14.50% 8.00% 9.00% 23.16 35.07 40.16 48.11Trade/other 10.13% 12.00% 7.00% 9.00% 23.43 25.39 27.05 32.41
Percent of Viet Nam EconomyRural South 8.37% 9.9°h 6.1% 7.7% 7.2% 35.86 36.43 37.00 38.06
- 12-
Annex 1.12Page 2 of 2
TOTAL ECONOMY VIETNAM Case 1
Vietnam GDP Growth Rates1991-95 1996-1997 1998-2000 2001-2015 Forecst Avge Percent of Viet Nam EconomyActual 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 14.32Constr 22.0% 14.2% 7.4% 9.4% 8.9% 2.87 5.28 6.00 7.83Industry 13.8% 13.1% 7.4% 8.8% 8.5% 22.25 28.84 32.20 38.43Trade/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% 100.00 100.00 100.00 100.00Approx 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 in2015Pop in 1990 66.7 million 66.7 checkPop in 1995 73.9 millionPop in 2015 is about 103.73
GDP Growth RatesThailand 1965-80 1970-1980 1980-1991 Percent of Thai Economy
Historical Historical 1965 1970 1980 1991Agriculture 4.6% 4.4% 3.8% 32.00 26.00 23.00 12.00Constr (in Ind)Industry 9.5% 9.5% 9.6% 23.00 25.00 29.00 39.00Trade/other 7.4% 7.2% 8.0% 45.00 49.00 48.00 49.00
TOTAL ECON 7.30% 7.10% 7.90% 100.00 100.00 100.00 100.00GNP per capita (US$/person) 1,570
Source: WB World Development Report
GDP Growth RatesMalaysia 1965-80 1970-1980 1980-1991 Percent of Malaysian Economy
Historical Historical 1965 1970 1980 1991Agriculture na 4.9% 3.7% 28.00 29.00 22.00 17.30Constr (in Ind)Industry na 9.6% 7.7% 25.00 25.00 38.00 43.80Trade/other na 8.3% 4.7% 47.00 46.00 40.00 38.90
TOTAL ECON 7.40% 7.90% 5.70% 100.00 100.00 100.00 100.00GNP per capita (US$/person) 2,520
Source: WB World Development Report, and ADB Asian Development Outlook
GDP Growth RatesPhilippines 1965-80 1970-1980 1980-1991 Percent of Philippines Economy
Historical Historical 1965 1970 1980 1991Agriculture 3.9% 4.0% 1.1% 26.00 29.00 25.00 21.00Constr (in Ind)Industry 7.7% 8.2% -0.5% 27.00 32.00 39.00 35.00Tradelother 5.0% 5.1% 2.8% 47.00 39.00 36.00 44.00
TOTAL ECON 5.70% 6.00% 1.10% 100.00 100.00 100.00 100.00GNP per capita (US$/person) 730
Source: WB World Development Report, and ADB Asian Development Outlook
GDP Growth RatesKorea 1965-80 1970-1980 1980-1991 Percent of Korean Economy
Historical Historical 1965 1970 1980 1991Agriculture 3.0% 2.7% 2.1% 38.00 26.00 15.00 8.00Constr (in Ind)Industry 16.4% 15.2% 12.1% 25.00 29.00 40.00 45.00Trade/other 9.6% 8.8% 9.3% 37.00 45.00 45.00 47.00
TOTAL ECON 9.90% 9.60% 9.60% 100.00 100.00 100.00 100.00GNP per capita (US$/person) 6,330
Source: WB World Development Report, and ADB Asian Development Outlook
- 13 -
Annex 1.13Page 1 of 1
VIET NAM Case BBASE YEAR PRICES OF KEY ENERGY PRODUCTS
1996 DOLLARSINTERNATIONAL CIF PRICES OR SUPPLY PRICES 1995
mill cal/ Cents/Price unit mill kcal
Crude Oil US$/B 25.00 1,512 1,653Diesel US$/B 31.00 1,463 2,119Heavy Fuel Oil US$/B 23.00 1,532 1,501Nat Gas (cost) US$/mcf 1.90 252 754LNG US$/mcf 3.45 252 1,369Int Coal US$/ton 46.00 6,000 767Dom Coal (north) US$1ton 25.00 5,500 455Dom Coal (south) US$/ton 39.00 5,500 709
PARAMETERS AND CONVERSION FACTORS(Parameters with * are "driving" parameters)
crude 1512 mill cal/BDiesel 1463 mill cal/BHeavy Fuel Oil 1532 mill cal/BMCF gas 252 mill cal/MCFMCF equiv 0.167 B crude oilInt Coal 6000 mill cal/tonVietnam Coal 5500 mill cal/ton
INTERNATIONAL FOB PRICES OR SUPPLY PRICES 1995
FOB Price Linkage Ratios * Deliv Costs*
Crude Oil * 20.00 US$/B 5 /BDiesel 26.00US$/B Diesl/crude 1.3000 5 /BHeavy Fuel Oil 18.00 US$/B HFO/Crude 0.9000 5 /BNat Gas Cost * 1.90 US$/mcf % growth/yr 2.00% /mcfLNG (delivered) 3.45 US$/mcf LNG/HFO 0.1500 /mcfInt Steam Coal 36.00 US$/ton Coal/HFO 2.0000 10 /tonCoal Costs north * 23.00 US$/ton % growth/yr 2.00% 2 /tonCoal Costs south * 23.00 US$/ton % growth/yr 2.00% 16 /ton
OTHER ASSUMPTIONS (PARAMETERS)
Effective Exchange Rate * 11000 d/US$Escalation in Oil Price 1.00% per yr
- 14 -
VIET NAM Case B VIET NAM Case BFORECAST OPPORTUNITY VALUE PRICES FOR ENERGY PRODUCTS FORECAST OPPORTUNITY VALUE PRICES FOR VIETNAM ENERGY
______________________________ __ PRODUCTS
Crude Oil Diesel Fuel Natural LNG Int Domestic Coal in US Cents per Million Kilo Calories (1996 Dollars)
Oil Gas Coal north southCost
Fob Cif Cif Cif at Ba Cif Cif Cif Cif Crude Diesel Fuel Natural LNG Int Domestic Coal
RiaEnd (1996 Dollars --without inflation) End Oil Oil Gas Coal north south
Year US$/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 5Page 1 of I
Cases B, A and C Electricity Forecasts, 1997 to 2010
Base Low High Case BCase Case Case with
Case B Case A Case C prices upto LRMC
Year Demand Demand Demand DemandMW MW MW MW
1990 1,546 1,546 1,546 1,5461991 1,638 1,638 1,638 1,6381992 1,744 1,744 1,744 1,7441993 1,934 1,934 1,934 1,9341994 2,260 2,260 2,260 2,2601995 2,714 2,714 2,714 2,7141996 3,161 3,161 3,161 3,1611997 3,585 3,585 3,585 3,5851998 3,942 3,807 4,012 3,9421999 4,363 4,067 4,521 4,3502000 4,779 4,298 5,039 4,734
2001 5,343 4,718 5,719 5,2442002 5,939 5,152 6,455 5,7572003 6,617 5,638 7,303 6,3352004 7,340 6,143 8,226 6,9412005 8,195 6,739 9,325 7,655
2006 9,114 7,363 10,536 8,4082007 10,163 8,069 11,932 9,2612008 11,358 8,863 13,547 10,2222009 12,690 9,735 15,372 11,2812010 14,123 10,650 17,389 12,401
- 16-
Annex 1.1 6Page 1 of I
Case B Electricity Forecast and variations, 1997 to 2010
No Loss Loss Reduction Program, andReduction Base with Prices LRMC
Case non-price up to PricesDSM LRMC and
by 2002 DSM
Year Demand Demand Demand Demand DemandMW MW MW MW MW
1990 1,546 1,546 1,546 1,546 1,5461991 1,638 1,638 1,638 1,638 1,6381992 1,744 1,744 1,744 1,744 1,7441993 1,934 1,934 1,934 1,934 1,9341994 2,260 2,260 2,260 2,260 2,2601995 2,714 2,714 2,714 2,714 2,7141996 3,161 3,161 3,161 3,161 3,1611997 3,585 3,585 3,585 3,585 3,585
1998 3,942 3,942 3,942 3,942 3,9421999 4,377 4,363 4,358 4,350 4,3482000 4,838 4,779 4,762 4,734 4,727
2001 5,425 5,343 5,304 5,244 5,2292002 6,058 5,939 5,867 5,757 5,7312003 6,802 6,617 6,506 6,335 6,2972004 7,568 7,340 7,182 6,941 6,8882005 8,499 8,195 7,981 7,655 7,583
2006 9,496 9,114 8,833 8,408 8,3162007 10,667 10,163 9,803 9,261 9,1452008 11,921 11,358 10,902 10,222 10,0772009 13,396 12,690 12,123 11,281 11,1032010 14,974 14,123 13,427 12,401 12,186
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VIET NAM Case B SUMMARY OF ELECTRICITY DEMAND FORECASTS -ALL REGIONSGENERATION 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 REGIONANNUAL 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 FrorecalinoLo[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/ Useper yr in 1899 Growth In Use per Consumer
25000 3.0% 3.0% 3.0% 3.0%
GENERATIONREQUIREMENTS
LOSS LOAD INFACTO,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 ForecastLong-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 9.0Constr 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 2.50Resulting 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 Usemr Yr In 1 9J0 Growth In UWe per Consumer
1.5w0 3.0% 3.0% 3.0% 3.0%
GENERATION REQUIREMENITSLOSS 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% ResulotGEGd48y 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 UNeo 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 ForecastingLong-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 %RuralAcduals 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 0.5Rural 1.4% 1.3% 1.2% 0.1%Total 2.1% 2.0% 2.0% 1.8%
Rcs MvWW UseoervyrnI0n 2 Gnwth In Use per Consumer
2.000 2.0% 2.5% 2.5% 2.5%
GENERATION REQUIREMENTSLQkiL9jMENRG LQAWJIN 00GQA
ANNUAL SALE NON-TECH TECH Requked TRANSFER GENERATION Deramrd PEAKELECTRICITY 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% 830.091997 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% 1209.22001 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% 1933.02000 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% -4160.32012 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 ForecassRnhLong-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 % RurlActuals 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 UseDOe vr in 1990 Growth in Use per Consumer
2.000 2.0% 2.5% 2.5% 2.5%
GENERATION REQUIREMENTSLOSS 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 -R9 i
VIET NAM Case B PETROLEUM PRODUCT DEMAND FORECAST
Parameters for ForecastingLong-,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 FoRecasingLofg-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 60.2bcm
JCD CD
x
VIET NAM Case BSUMMARY OF MODERN ENERGY CONSUMPTION FORECAST (Primary Energy, in TOE)
Petroleum Natural Coal Hydro Total Petroleum Natural Coal Hydro TotalProducts 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 ForecastVIET NAM, 1990 TO 2010
46.0
40.0
30.0
2S.020.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 201020,000
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 LRMC2,000 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 201016,000
1 2 ,0 0 0 - -- -- -- --. -------------------------------- .--.--.--.--.--.--..-..-..-..-..-..-.. .. .. -- - --- - - -- - -- - -- -- -- -- -- - --- - -- -- -- -- - -
I o , o o o - -- - - - - - .. ,. .. . . .. .... . ... -- - - - - - - - - -- - - - - - -- -- -- - - - - - - - -- - - - - - - - ...... ... .. . .... . . .
6 ,0 0 - -- -- -- - -- - -- --- --- -- -- -- -- .... . .... :.... .I- -- -- -- -- -- -- -- -- --- -- --- -- -- --- -- --- -- -- --- -- --
14,000-n . .... A Case B, no Loss Red-tion4,000~~ ~ ~ ~ ------------------ ----- + 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-xo _
Forecast of Electricity Demand, Sales by Sectorin Viet Nam, 1997 to 2010
Case B30,000 -
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 B50,000
45,000 - Diesel
40,000 - Petrol,
35,000-h-4-- er
00 30,-- Fuel Oil0
* mn 25,000
20,000
15,000
10,000
01990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Yearo-
_%
Forecast of Coal Demand,in Viet Nam, 1995 to 2010
Case B6,000
5,000 Power
Industry4,000..
Residential
3,000 i=
. 2,000/ _ -
1,00 k
'~~~~~~~~~~~~~ -
019901991 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
-xo -
00,
Estimate of Diesel Conservation,wth higher diesel taxes
in Viet Nam, 1998 to 2010sax - 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
Yewo- !
Forecast of Primary Modern Energy,in Viet Nam 1995 to 2010
Case B
1,000 Petroleum Products18,000
16,000 -a-Natural Gas14,000 -l- Coa
12,000
10,000
I- 0 8,000
6,000
4,000
2,000' --Sw-
01990 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 Energyin Viet Nam 1995 to 2010
Case B60.0%-
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 B7m0
MO ------------------------------------------------------------------------------------------------------------------------------------
00 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 DISTRIBUTIONDEVELOPMENT
"'Increase least cost vLower cost of VEfficient and reliable /Least cost distributionresource exploration / convertion transmission /Expansion of coveragedevelopment
Composition of Prices in the Energy Sector(Cents/kwh)
Wellhead Gas Capacity O&M Bus bar Transmission Distribution Retail CTransport 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 ......................................... 462.1.2. Existing Power System in 1998 ......................................... 472.1.3. Electricity Generation Balance in 1996 (TWh, estimated) ......................................... 482.1.4. Trends in Electricity Generation and Consumption ......................................... 482.1.5. Electricity Generation Demand Forecasts ......................................... 492.1.6.a Electricity Tariffs (at May 1997) ......................................... 502.1.6.b Electricity Tariffs (at Dec 1998) ......................................... 502.1.7. Estimated Seasonal Plant Load Factors ......................................... 502.1.8. Hydro Plant Investment Options ......................................... 512.1.9. Thermal Plant Investment Options ......................................... 522.1.10. Comparative cost assumptions .532.1.11. Comparative cost estimates, c/kWh .542.1.12. Cases Examined in Power System Analysis .552.1.13. Comparison of Investment Plans for 5 Cases, to 2010 .562.1.14. Evaluation and Ranking of Cases (Indicators) .582.1.15. Fuel Consumption Forecasts in Power Generation .592.1.16. Son La Hydro Plant: NPV Analysis .592.1.17. Power system losses .602.1.18. DSM and energy efficiency .602.1.19. Comparison of Investment Plans .612.1.20. Summary of Generation costs .62
Graphs:
2.1.21. Regional Character of Viet Nam's Power System .632.1.22. Increasing Electricity Intensity per unit of GNP, 1974-1993 .632.1.23. Monthly Generation Mix for the Year 2000 (Base case) .642.1.24. Typical Daily Load Curves (PC2, 1995) .652.1.25. Annual Variation in Demand (1995) .652.1.26. Comparative Generation Costs-New Plant .662.1.27. Breakeven Fuel Prices (Netback Values) .662.1.28. Gas Demand in Power Generation .672.1.29. Monthly Gas Swing (Base case) .672.1.30.a Fuel Use Forecast - Fuel Consumption in Power Generation - Gas Demand .. 682.1.30.b Fuel Use Forecast - Fuel Consumption in Power Generation Domestic Coal Demand.. 692.1.31. Generation Forecast for the year 2005 .70
- 45 -
Viet Nam Electric Power System -- Historical Data1 1976 1877 1975 1979 1950 1591 1952 15532 1954 1999 M95 1997 19e 199 199 1991 10922 199 1? 4 1999
Viet NamGeneration 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
PCIGemertion 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 2451.9dAgarecfu 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 3Gn+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 2.1.2Page 1 of 1
Existing Capacities in Power System of Vietnam
Existing Plants Installed MW Available MW
A. Northern Power System 2731.9 2652.9Hydro: - 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 1657.7Hydro: - 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 65Grant 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 11.8generation
Thermal 2.4 0.2 2.5 5.1generation
Net regional -2.9 0.9 1.9 0imports
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 2.1.5Page 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 DemandPeakGWh 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 GDPgrowth growth growth growth growth growth growth growthrate % 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 9.52000
2001- 9.9 6.0 11.8 7.5 13.7 9.5 11.3 9.02010
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$. The lowest residential tariff is USc4.3/kWh - a kind of "life-line
Source: Tariff Schedule.
Annex 2.1.6.b
Summary of Electricity Tariff, as at December 15, 1998
Typical Price Max. Price
US cents/kWh US cents/kWh
Residential 151 to 250 kWh/month 5.9 351 kWh and up 8.2
Commercial >6 kV, Normal Times 7.8 >6 kV, Peak Times 12.3
Induatrial >20kV <II0 4.8 >2OkV<110 11.4
Notes: assumes 13,900 VND to US$. The lowest residential tariff is Usc3.3/KkWh. This tariff ispre-VAT tariff. 10% of VAT will be added.
Annex 2.1.7
Estimated Seasonal Plant Load Factors
average plant load Annual average Wetseason Dry seasonfactors, %
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 2.1.8Page I of I
Hydro Plant Investment Options
Earliest Northern C Central and SouthernCommissioning Region Capacit M Region Capacit MWYear
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 500hydro
Source: Institute of Energy
-51 -
Annex 2.1.9Page I of I
Thermal Plant Investment Options in WASP Model
Earliest Capacity CapacityCommissioning 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 300CCGT (2.2, 3, 4)
2003 Quang Ninh (coal) 300
2007 Coal (domestic or 500imported)
2008 New coal 500
Source: Institute of Energy
- 52 -
Annex 2.1 .1 0Page 1 of I
Comparative cost assumptions
Var. Fixed
Plant type Capital l Ei c cost, ye O&M cost O&Mcost $/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 0.72North>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 bearound 3.7c/kWh and the generation cost would be 5.03c/kWh.
- 53 -
Annex 2.1.11Page 1 of I
Comparative cost estimates, c/kWh
yCapital Var Fixed TotalPlant type cot Fuel cost O& & pot TotalFuelcos 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 3.68North>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 2.1.12Page 1 of 1
Main Cases Examined in Power System Analysis
Demand Case Description, purposescenario
BASE 50 BT Base case demand scenario
(scenario B) With minimum Take-or-pay contract assumed forgas supply; new gas plant assumed to run for aminimum of 5000 hrs pa (approximately 56% loadfactor).
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 2.1.13Page 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 newcapacity 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 2.1.13Page 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 CCGTby addition of ST unit, Phu My new = new CC units at Phu My (in WASP we have not identified alternative gasprojects separately)
Source: WASP analysis
- 57 -
Annex 2.1 14Page 1 of I
Financial Evaluation of Cases
Case 60 LT 50 BT 80 HT
Criterion: (ow) (base) (high)
Efficiency (minimumcost)
- 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 arecalculated in the PSDP spreadsheet model and vary slightly from those calculated in WASP due to a slightlydifferent calculation method (in particular, average fuel costs have been used over the whole period, rather thanspecific costs for each year, and the cost of energy not served has been omitted), but the ranking of cases by cost isthe same.
2 The present worth of costs to 2010 divided by the present worth of demand, to give an indicator of cost per unitelectricity generated.
- 58 -
Annex 2.1.15
Fuel Consumption Forecasts in Power Generation
B1 Base+nil B2 Base + maxCASE B Base A Low demand C High demand transfers exports
Gas Coal Gas CoaT Gas Coal Gas Coal Gas coalYear 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 1.51997 0.8 2.2 0.8 2.1 0.8 2.2 0.8 2.2 0.8 2.21998 1.4 2.4 1.4 2.4 1.4 2.5 1.4 2.4 1.4 2.41999 2.0 2.1 1.9 2.0 2.1 2.1 2.0 2.1 2.0 2.12000 1.7 2.8 1.9 2.0 1.9 2.9 2.1 2.0 2.5 1.02001 1.8 3.8 T2. -TO 3.9 2.3 3.0 3.0 1.22002 2.0 4.7 2.0 3.9 2.2 4.9 2.4 3.9 3.2 2.02003 2.3 4.9 2.2 3.9 2.6 4.9 2.7 4.1 3.5 2.22004 2.5 5.8 2.3 4.9 2.9 5.8 3.2 4.0 3.6 3.02005 3.3 5.9 3.0 4.9 3.5 5.9 4.1 4.0 4.5 3.02006 3.4 6.8 2.9 5.8 4.0 6.9 4.6 4.0 5.0 3.02007 3.9 6.8 3.2 5.8 4.5 6.9 5.1 4.0 5.6 3.02008 4.5 6.6 3.7 5.5 4.8 6.6 5.7 3.6 6.0 2.72009 4.8 6.6 3.9 5.6 5.3 6.6 5.6 3.7 5.8 2.72010 5.3 6.6 4.2 5.5 5.6 6.6 6.0 3.6 6.0 3.62011 6.4 6.6 5.47 7 . 3.7 7. 72012 7.2 6.7 6.6 5.6 7.8 6.9 7.9 4.0 7.9 4.02013 8.0 6.9 6.8 6.7 8.4 7.1 8.2 5.1 8.2 5.12014 8.5 7.2 7.6 6.8 8.8 7.3 8.5 7.2 8.5 7.22015 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, $M, Base Case Demand Low Demandevaluated up to year:
2010 -41 -128
2015 261 161
2017 333 303
2020 463 n/a
Source: WaspRuns
- 59 -
Annex 2.1.17
Statistics and Projection of Power Production and Losses
1985 1990 1991 1992 1993 1994 1995 2000 2005 2010planned planned planned
Sale Power 3,866 6,185 6,575 6,941 7,833 9,284 11,185GwhGrowth Rate 9.2 6.4 5.3 13.0 18.5 20.0 18.0 15.0 12.0
Self-services 1,201 2,493 2,569 2,723 2,823 3,000 3,451 5,474 8,187 10,330and lossGwh __
Self-service 23.7 28.7 28.1 28.2 26.6 24.4 23.6 18 15 12and losses %Total 5,608 8,673 9,152 9,652 10,665 12,284 14,636 30,100 53,600 87,816ProductionGwh
Source: Vietnam DSM Assessment - Phase 1, Hagler Bailly Consulting, Inc.
Annex 2.1.18
DSM Program Demand Impact
Year 2000 Gwh Saving Benefit/Cost NPVProgram MW Gwh Ratio US$ mil.
Load Management 535 1,968 13.2 396Com'l Appl. Stands & Bldg. Codes 166 1,633 2.1 82Residential Lighting Standards 92 277 6.8 114Residential Refrigerators 39 268 4.0 25Motor Standards 34 301 29.0 36Industrial Audits 28 244 18.0 42Large Project Energy Effic. Review 22 191 185.5 32Industrial Lighting Efficiency 8 65 2.0 6JV Internation Interim Bldg. Stands. 4 39 50.7 18Public Lighting 2 145 3.5 23Total Package Analyzed 930 5131 5.9 774
Source: Vietnam DSM Assessment - Phase 1, Hagler Bailly Consulting, Inc.
- 60-
Annex 2.1.19Page I of 1
COMPARISON OF INVESTMENT PLANS 1998-2010
Low Demand Case Base Demand Case High Demand Case
Total New Capacity in MW1998 288 288 2881999 1025 1025 10252000 1691 2117 21172001 2417 3777 37772002 300 4077 46772003 3605 4977 55772004 3905 5577 64272005 4805 6697 78472006 5325 7807 93072007 6175 8912 112472008 7375 10602 134472009 8835 12063 161632010 9640 14263 17763
Comparison of I nvesment Plans 1998-201020000
S18000
:~16000
aL 14000 *~DTad~
U 1200010000 uBase Demand Case
13000 ~~~~~~~~~~~~~~~~High Deanad Case
0
Nc Nq 169 °° IV l - -le ° °
- 61 -
Annex 2.1.20Page 1 of I
Summary of Generation Costs
Case (Bow demand) (base demand) (high demand)
Minimum generation costs to meetdemand of each case
- PV costs of Investments & Operating, to 3,614 4,678 5,2612005 (PV $mill) '
- PV costs of Investments & Operating, to 5,814 8,001 9,8432010 (PV$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 arecalculated in the PSDP spreadsheet model and vary slightly from those calculated in WASP due to a slightlydifferent calculation method (in particular, average fuel costs have been used over the whole period, rather thanspecific costs for each year, and the cost of energy not served has been omitted), but the ranking of cases by unit costis the same.
2 The present value of incremental generation costs to 2015 divided by the present value of incremental energygenerated, 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 sameperiod, un-discounted.
- 62 -
Annex 2.1.21
Figure 1: Regional Character of Viet Nam's Power System
NorthernRegion
CentralRegion
SouthernRegion
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 2.1.23Page I of 1
Figure 3: Monthly Generation Mix for the Year 2000 (Base case 50)
2500
2000 _ - -_
15000
500s~~~~~~~~~~~~~r a s E]Ohrtema
0J F M A M J J A S 0 N D
M onths
5000
4500~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
4000 .
3 5 0 0 J O ;
3500
30000E 2500
0
J F M A M J J A S 0 N DM 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
10.4E ........Wnter -....Summe00.2
01 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
0.2z
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 Fixedw . ; bIe O&M6-0
nor68.0 .. . EFuel
on . Capitalco 5.
ck 4,0 ',Wh
3.0
2.0
10
0.0CCGT: 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 .003250 0i i
20 25 30 35 40 45 50 55Coal 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' Gasborn
0.0~ ~ 0 C~'J 0 ej IT
0)0 0) 00 0 - -0)0) 0 0 00
Source: WaspRunsAnnex 2.1.29
Figure 9: Monthly Gas Swing (Base case)
0.45
0.40
0.35
0 0.30
0. 0.25E
0.2
0
0.05 -21
0.00J 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 2.1.31Page 1 of I
Generation Forecast for the year 2005
0.50
0.45
0 400
0.35
CL 0.30E10 0.25
0.20
E 0.150 ~ ~ 20
0.0
0.00J 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 ......................................... 722.2.2. Exploration History and Discovered Reserves Potential ......................................... 732.2.3. Expected Oil and Associated Gas Production ......................................... 742.2.4. Production Prospects from Speculative Gas Reserves (bcm)
- Nam Con Son Basin ......................................... 752.2.5. Production Prospects from Speculative Gas Reserves (bcm)
- Son Hong Basin ......................................... 762.2.6. Estimates of Development Cost of Associated Gas ......................................... 772.2.7. Development Cost Estimates of Non Associated gas
- Lan Tay, Lan Do & Hai Thach ......................................... 782.2.8. Development Cost and Associated Gas Economic cost
- Cuu Long Basin ......................................... 792.2.9. Hydrocarbon Production and Supply Cost of Gas .............. ........................... 802.2.10. Cost of Exploration and Development for Speculative Reserves .81
Graphs:
2.2.11. Potential Oil Production from discovered reserves- Cuu Long Basin .822.2.12. Potential Gas production from discovered reserves
- Cuu Long and Nam Con Son (Blocks 6.1 and 5.2) .83
- 71 -
Annex 2.2.1Page 1 of 1
Exploration Activities in Vietnam
ward Block Basin Operator Wellse DiscoveriesAwarded _ _ Drilled
1969 Red River Petrovietnam Gas (Tien Hai, 1975)1974 12, 04 N Con Son Pecton 4 Oil1975 09, 05 C Long S, N C Son Mobil 1, 1 Bach Ho, Dia Hung1978 28, 29 N C Son Bow Valley 2 Dry
15 C Long Deminex 41979 04, 12 N C Son Agip 6 Gas in 121981 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 Relinquished106 S Hong Total 3 Relinquished
1989 117,118,119 S Hong British Petroleum Gas (C02 >70%)115 S Hong IPL22 N C Son Cairn17,21 C Long, N C Son Enterprise 5 21 Relinquished46,50,51 Malay Thu Chu Petrofina111 S Hong Sceptre03,12W,20 N C Son Petro-Canada
1991 120,121 S Hong BHP01,02 C Long Petronas Oil (Ruby&Emerald 1994)
1992 10 N Con Son Shell 3 Relinquished 199611-02 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, Statoil05-2,06,12E N C Son BP, S Statoil, 5 Wet Gas (Hai Thach,1995)
ONGC11-1 N C Son Total 3 Oil & Gas (Ca Cho 1995)102 Red River Idemitsu04-2, 04-1 N C Son Lasmo - Cieco15-2 C Long JVPC 5 Oil (Rang Dong, 1994)04-1 N C Son British Gas04-3 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 Conoco1996 B-52, B-54 Malay Thu Chu Unocol
- 72 -
Annex 2.2.2Page 1 of I
Exploration History and Discovered Reserves Potential
Wells Potential Reserves Total ReservesYear Drilled Discoveries Oil AG NAG Accretion Company
_____ ____________ MMbIs Bcm Bcm MMboe MMboe
1970 6 Tai Hai 2.83 18 6 18 Petrovienam1971 2 0.00 8 181972 0.00 8 181973 0.00 8 181974 5 Bach Ho 300 5.10 0.00 332 13 350 Mobil1975 1 0.00 14 3501976 2 0.00 16 3501977 0.00 16 3501978 1 0.00 17 3501979 8 0.00 25 3501980 2 0.00 27 3501981 Bach Ho 650 14.16 0.00 739 27 1089 Vietsovpetro1982 0.00 27 10891983 0.00 27 10891984 3 0.00 30 10891985 0.00 30 10891986 0.00 30 10891987 1 Dia Hung 150 3.97 0.00 175 31 1264 MobilNVSP1988 0.00 31 12641989 1 0.00 32 12641990 9 0.00 41 12641991 9 0.00 50 12641992 4 Lan Do 11.90 75 54 1339 BP1993 16 Lan Tay, Moc Tinh, 110 2.83 95.18 726 70 2065 BP
R Doi1994 21 R Dong, Ruby, 680 25.50 840 91 2905 JVPC, Mobil
Emerald1995 17 H Thach, ANZ 90 28.33 268 108 3173 BP, ANZOIL1996 18 Bunga:Kekwa,Orkid 70 9.92 19.83 126 3173
,Raya1997 8 134 3173
TOTAL 126 2050 61 158 3173
Reserves Discovered v.s Exploration Drilling400035003000
8 2500200015001000 . * *500
0 t I I I
0 20 40 60 80 100 120 140Number 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
-oCD 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 199Reserves Bcm
On Stream
200120022003 0.57 0.62004 1.13 1.20 2.32005 1.13 2.41 1.20 4.72006 1.13 2.41 2.41 0.0 5.92007 1.13 2.41 2.41 0.0 0.0 5.92008 1.13 2.41 2.41 0.0 0.0 0.0 5.92009 1.13 2.41 2.41 0.0 0.0 0.0 0.0 5.92010 1.13 2.41 2.41 0.0 0.0 0.0 0.0 0.60 6.62011 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 7.22012 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 0.60 7.82013 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.50 8.92014 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.30 9.62015 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 10.02016 1.13 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 10.02017 1.08 2.41 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 9.92018 0.97 2.18 2.41 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 9.62019 0.83 1.86 2.29 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 9.02020 0.67 1.50 2.05 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 8.22021 0.52 1.18 1.71 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 7.42022 0.40 0.91 1.35 0.0 0.0 0.0 0.0 1.20 0.0 1.20 0.99 0.60 6.72023 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 157Reserves Bcm___
On Stream2001200220032004 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 2.2.6Page 1 of 1
Estimates of Development Cost of Associated GasMillion 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 20Utilities 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
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Annex 2.2.7Page 1 of I
Lan Tay, Lan Do and Hai Thach Development Cost EstimatesOil and gas Most likely Scenario
Million US $ 1996Lan Tay and Lan Do
Year 1 MM [ 1 2 3 4 5
Total
Exploration and Delineation 60 60Feasibility & Front Engineering 2 2Drilling& Completion of Wells 98 32 66Flowlines 24 8 16Offshore Structures (Water :125 m) & Facilities 76 11 15 23 27Process Facilities (Oil and Gas), onshore 125 19 25 38 44Floating Storage & Off-loading 0 0 0Offshore Pipelines (24",380 km)Line pipes, valves and fittings 140 70 70Transport 14 7 7Coating and Laying 173 26 69 78Phase I Compression 18 3 7 8EPC and Management 84 8 8 25 25 17
8 8 7 10 11Contingencies 113 2 6 26 42 38Total Cost (Excluding Exploration Cost) 866 12 44 197 321 293
Facilities 12 44 54 127 187Pipelines 0 0 142 194 106
Cost / Well MM$Platform wells Wells 8 6Sub-sea Wells 2 25Flowlines: km/well 4
Hai Thach Field
Year MM S 1 2 3 4 -
TotalExploration and Delineation 80 80Feasibility & Front Engineering 10 10Drilling& Completion of Wells 120 40 80Flowlines 24 8 16Offshore Structures 120 18 24 36 42Topside Facilities (Oil and Gas) 175 26 35 53 61Floating Storage & Off-loading 60 24 36Offshore Pipelines (20", 40 km)Line pipes, valves and fittings 12 6 6Transport 3 2 2Coating and Laying 18 3 7 8Phase I Compression 0 0 0 0EPC and Management 80 8 8 24 24 16
8 8 20 22 15Contingencis 92 3 8 14 30 39Total Cost (Excluding Exploration Cost) 714 21 60 107 228 299
Facilities 21 60 91 209 289Pipelines 0 0 16 19 10
Cost / well MM $Platform wells Wells 10 12Sub-sea Wells 0 25Flowlines: km/well 4
- 78 -
Development Cost and Associated Gas Economic CostCuu Long Basin
Associated Gas Bcm LPG Capital Cost MM$ 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 TodaBk6.1 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 MyValue
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 Facilities
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
ASSUMPTIONSSuccess Ratio 1/4 -1/8 Drilling MM $
Cost/WellDrilling Ratios Exploration well 12 Facilities $/ boe 3
Delineation/deve 1/4 Exploration well 10
lopmentInfilV 1/2 Development / 6
Development Infill
Source: World Bank Mission, October 1997
° s-
Potential Oil Production From DiscoveredReserves
Cuu Long Basin
120 -I,~
. . . .. ... .
100 22080....
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 FromCuu 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 .......................... 852.3.2. Organization of PVGC .......................... 96
- 84 -
Annex 2.3.1Page 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 countriesespecially because gas is a commodity that requires significant infrastructure in the form of afixed transmission and distribution system. It has also been called a "continental" energy productbecause only a small fraction of natural gas is traded overseas. This differentiates the problem ofnatural gas pricing from oil pricing because oil prices are established through integrated marketsworldwide. It also means that the balance of natural gas supply and demand within a countrytends 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 formore complicated and longer term contracting for gas than for oil. In almost all countries, naturalgas development has lagged many years behind oil development, but since the energy crisis of the1970's its day has come.
2. Some of the debates about natural gas pricing involve vicious circles: it is sometimescontended that gas prices must be determined before upstream fiscal terms may be set -- but theupstream fiscal terms play a part in determining the private supply cost of gas which has abearing on the prices that are acceptable to producers. So, some analysts argue that fiscal termsand prices should be set together as a package. This argument assumes that prices and fiscalterms are necessarily rigid and not responsive to market or investor conditions. A viablearrangement both for prices and fiscal terms must assure that 1) gas prices are responsive tomarket 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 gassuppliers. Gas prices, specified in supplier-purchaser contracts, are typically kept responsive tomarket conditions through indexing gas prices to the prices of alternative fuels, usually to theprices of heavy fuel oil and/or gasoil. Fiscal terms are made responsive to supplier economics byupstream fiscal systems that focus the government's royalties, or share of revenues, on therealized profits of suppliers, or proxies for profits. If either of these conditions are not met, itbecomes extremely unlikely that a gas industry can be developed and sustained over the longterm.
3. An effective strategy for developing the gas industry is therefore to separately pursue theseobjectives: 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. Thefiscal terms for development and production of Block 6.1 in the Nam Con Son basin have beennegotiated 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 behelpful first to establish a fiscal regime that is progressive, and satisfactory to government andindustry over a range of gas prices and costs. Where production is more profitable, thegovernment should get a larger share of revenues and the reverse. This may be done on acontract by contract basis, prescribed or by negotiation. It may be bid by contractors, subject tothe guidance of a model contract, or it may be established as a generic regime for all projects.
- 85 -
Annex 2.3.1Page 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 (allowingfor investment and operating cost differences etc) that could be used for the same purpose. Fromthe supplier's perspective the price must be sufficiently high to cover all the costs of supply andprovide 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 Benefitsfrom Offshore Gas Development in Viet Nam
Value of Non-Cash Total State SharePrc Besh Benefits to Benefits of TotalPrice Benefits Gas to State Project Implications
to PVN & Consumers Benefitsper mcf G(NPV) (NPV) (NPV) (NPV)
Too Low nil nil nil nil no project in short tern &also discourage otherexploration & developmenti in long term
Low 40% 60% 100% 90% develops market in short termbut exploration &development slows downeffecting longer term supplyprospects
Middle 50% 50% 100% 85% benefits balanced betweenupstream and downstream
High 60% 40% 100% 80% more benefits upstrearn andprivate sector gets higherROR, accelerates short termsupply but slows marketdevelopment
Too High 100% nil or 100% 70% Consumers of gas do notnegative 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 ofeconomic benefits can be estimated along the lines illustrated above. The sharing of benefitsfrom a successful project involves three considerations: 1) the balance between government andthe private sector, 2) the balance between upstream and downstream participants, and 3) thebalance between short term and longer term benefits to Viet Nam.
- 86 -
Annex 2.3.1Page 3 of 11
1) Higher gas prices tend to shift benefits towards the upstream, and shift the share of benefits infavour of the private sector producers. However, the government's share remains high, in the order of70% 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/orelectricity consumers, and shift benefits away from the private sector producers. Gas prices mustbe high enough to encourage more exploration and development of gas, otherwise the gasindustry will not develop and Viet Narn will become short of gas, even though the first projectmay be started. Another risk with lower gas prices is that gas may not be used efficiently and thedownstream benefits would be dissipated within the gas consuming entities. Lower gas pricescall for lower US dollar obligations through the gas chain.
3) Gas prices should balance the benefits between government interests, upstream anddownstream, 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 ofsupply. Otherwise the gas industry could not be sustained for lack of supplies. It may be arguedthat, having discovered gas, the gas price should cover only the half cycle costs to develop andproduce 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 fora continuing gas industry, all the gas that is produced must be replaced through finding newsupplies, and clearly, for an expanding industry which is the objective in Viet Nam, more newgas 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 basinhave 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 PhuDevel and Pipelines Production levels My
US$mill bcm/yrWithout Taxes With Taxes& Royalties & RoyaltiesUS$/millBtu US$/millBtu
Block 6.1 500 2.6 1.70 - 2.20 2.30 - 2.80Block 5.2 660 2.1 1.30 - 1.80 naPipelines 500
Notes: Assumes discount rate of 15% real for production, and 12% for pipelines. The range of supply costs isdetermined by production rates, cost contingencies, level of liquids production, etc. The private supply cost forBlock 5.2 will depend on as yet unknown fiscal terms (Exploration amounts are also estimated). Total production of50.3 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 2.3.1Page 4 of 11
9. The maximum market price for gas, is determined by the price that consumers would Just bewilling to pay rather than to use an alternative fuel. The maximum value in the power sector isestimated to be in the range of US$3.60/mill Btu to US$4.00/mill Btu, which would givegeneration costs in a CCGT plant of between 4.50 cents per kWh to 4.75 cents per kWh . Theestimated maximum or economic value of gas is summarized below:
Maximum Value of Natural Gas in Various UsesUS$ 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 iflow cost gas is discovered, and the maximum price will increase if for example the price ofalternative fuels increases. Therefore it is unlikely that a fixed gas price will be suitable over along period of time. For this reason, given that gas contracts are typically long term, the majorityof contracts worldwide contain gas prices that are indexed to the fuel oil price. The contractstypically include a "base" price and an indexation of the base price linked to fuel oil, andsometimes to gasoil. The result is a long term contract -- and a long term commitment to buy andsell gas -- but with some short term flexibility of price. Many contracts also have a clause inthem that provides for periodic renegotiation of at least some of the pricing terms, for example ofthe design of the price index. The gas buyer looks for an indexation that ensures competitivenessof the gas price, against other fuels, at the burner tip. For example, a power generator will linkthe gas price to prices of alternative fuels for power generation such as oil products andsometimes coal. Some principles of gas price indexing are summarized below:
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Principles of Gas Price Indexing
Principles Comments
The gas consumer: as buyer of gas, wants an Example: Power companies all over theindex that ensures competitiveness of the gas world link gas price to alternative fuelsprice 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 themuncertainty into the price but should shift the and use averages over a number of monthsprice gradually so that the gas price keeps in line or years, to smooth out randomwith 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 inflationor bias in the price but rather to be fair to both the would be biassed upwards and unfair toseller 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 thein the region where the gas is delivered. In the gas price to domestic coal prices becausecase of EVN, the alternatives are fuel oil and coal. coal prices to EVN are capped by MPI andThe components are sometimes weighted in the SCP. An international coal price indexindex, in the ratio that the alternative fuels might could be used. But a suitably designedbe 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 notshould be the same as the index used for pricing the same, PVGC could be squeezed in thethe 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 indexescontain a ceiling and a floor so that gas prices would not spurt up or collapse if the internationaloil market is upset.
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Example Gas Price Indexes
Components of IndexThailand: Proposed Gas price to annual average crude price imported into Japan, asPrivate Sector Power Plants reported in Japan Exports and Imports Monthly.
annual average coal price of Australian coal sold underone year contracts to Japanese buyers, for 6,700 kcal/kgcoal as reported in The Tex Report.
average price of other gas from the "Thai Gas Pool". Theprice 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 independentpower plant in year 1999 is There is also an adjustment for inflation but only up to theUS$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, butthere are also small components related to petroleumequipment costs and US inflation. This was introducedbecause the field fiscal terms did not properly take intoaccount 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, pluspower plant (15 year contract)
average spot gas prices last month
the index is of form that majority have:Gas price in year t =Base gasprice* (A* HFOt/HFOb+B* SPOTgast/SPOTgasb)
Canadian: Gas export to US monthly average of LFO and HFOpower plant (15 year contract)
average other gas prices in same regionform of index as above
end of every 3 years the price index may be renegotiatedat request of one party and acceptance by other.
Japan, Brazil, Colombia and West some West European countries have a base gas price plusEuropean 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 tto coal Base gas price + A*(energy price per mill Btu of FOt).
The A factor is called a "pass through factor" and isPakistan, Egypt and Bolivia: gas reported to be in the range around 0.8prices are fixed as a percentage offuel oil or crude oil (e.g. 75% of The fixed percentage form of indexes isthe 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*0.75also had this arrangement.
The Thai ceiling prices are in this index form
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12. Most of the gas contracts in North America index gas prices to fuel oil prices and to othernatural gas prices, for example to spot gas prices in neighbouring markets. The use of other gasprices 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 maybe useful. A few contracts in Europe and the Thai contracts include an inflation index, with asmall weighting, as one of the factors in the gas price index, but none of them to our knowledgeindex the gas price solely to US inflation. Such an inflation index is obviously biassed upwardsand therefore one sided in favour of the seller. Gas contracts in North America in the 1950s and1960s often included a simple escalation clause such as a price increase of a few cents per mcfper year, or a small percentage increase, but as soon as oil prices became erratic and higher in the1970s these contracts were unsustainable and were either broken or re-negotiated. The idea ofsimple escalation has recently been revived, probably because of the past decade or so ofrelatively stable oil prices and inflation rates, but it is liable to the same upsets as occurred in the1970s 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 governmentsto reference the wellhead price to the costs of field appraisal and development, with explorationcosts treated as sunk. While this practice may lead initially to low prices for consumers -- ifindeed the project proceeds, it has not proved sustainable in the longer term. The problem is thatproducers will not have incentive to explore for more gas and within a few years gas supplies willbe short. An example of this has been the experience of Indonesia. It has recently had to abandonthis pricing policy because it was counter-productive in developing its extensive gas reserves. Aninfamous natural gas shortage occurred, for the same reasons, in the United States during the1970's. At that time gas prices for gas shipped between the individual States were controlled bythe US Federal Power Commission, on the basis of their estimates of supply costs. As inCanada, 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 controlledprices and consumers wanted more gas. There was a huge government created excess demand forgas. Legislation had to be changed and the gas price had to increase, more in line withalternative fuels, to balance supplies and demand.
14. Price indexing brings to a long term contract the advantages of some price flexibility so thatthe risk of the gas price becoming unacceptable either to the sellers or the buyers is muchreduced. The potential foreign exchange advantages should also be mentioned because a suitableindex related to oil products, say fuel oil, will tend to hedge Viet Nam's foreign exchangeexposure. This is because Viet Nam is a net exported of petroleum products. For example, if theinternational oil price increases, the natural gas price would increase although less depending onthe index weighting and government "take" from profit sharing will increase. The result is thatnet 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 oilprice and to a degree the gas price, would track US inflation. The long term trend of real dollaroil prices has been about constant over the past 50 years.
15. Natural gas prices in the industrialized countries are generally much higher than in lessdeveloped countries. They are typically close to the maximum market values of gas whencompared to other fuels at the "bumer tip". This reflects competitive markets and developedpipeline systems, and gas prices are essentially "market determined". The gas price is determinedat 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.
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Approximate Range of Natural Gas Pricesaround the World, in 1997
Region US$ per mill Btu Comments
Western Europe Competitive marketsWholesale 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, CompetitiveWholesale 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 3.20Burner tip 3.50 to 4.00
South Asia Pakistan was 2.50 wholesale, but hasWholesale 2.50 to 3.00 been revised upwards because of lackBurner 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 sectorBurner tip 3.50 to 4.00 Thailand 3.00 + to EGAT
Yadana at Thai border 3.00Japan
Wholesale 4.00 to 4.50Bumer 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 purchasegas on their own account and deliver a "bundled" commodity, without distinguishing the cost ofthe gas itself from its transmission cost. This is no longer the case and although gas prices aredetermined 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 importantstep towards more efficient gas markets in these countries. Viet Nam should follow this trend byassuring that gas prices are negotiated and established with suitable indexing, separately fromtransmission tariffs. The gas price between PVGC and the producer-shippers could beestablished alternatively at the platform or at the onshore delivery point, of Phu My. It isassumed that the producers would remain the shippers in either event. Some advantages anddisadvantages are summarized below:
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Advantages and Disadvantages of Pricing Gas Purchased by PVGC,at the Point of Onshore Delivery rather than at the Offshore Platform
Advantages Disadvantages CommentsGas would be priced closest to the market place, Perhaps more Today, Most gaswhich best keeps it correctly aligned to complicated to fix sales in Northalternative fuels. the initial price for America and Europe,
the first project (but in competitiveThe pipeline tariff becomes a deduction from easier to negotiate markets, are pricedthe wholesale buyer's price so that the the initial tariff). at the market, andproducers get a netback at the field. The not at the field.producers as shippers on the NCS pipeline, But, approach mightwould have an incentive to reduce the pipeline be preferred by Thailand hastariff so that the net-back would be higher. private sector and discussed pricing
therefore negotiation their gas at theNew producers would expect to get the same might be easier. market in Bangkok,downstream market price but may have a for many years, anddifferent net-back because they might have The fiscal terms for the Thai Nationaldifferent transportation costs. They would be producers must take Energy Policy Officeencouraged to look for gas closest to the market. account of the cost is again reviewing it.
differences in fieldThe NCS negotiations on the pipeline tariff development & North Americawould be simplified because the producers have production (which practice is for thean 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 priceto EVN) would not go up or down depending onthe pipeline tariff.
The precedent would be set for one gas price forPVGC, as the wholesale buyer, which is thecompetitive market solution to pricing. Thiswould encourage exploration and developmentfor new gas.
Gas Transmission Tariff
18. Main line transmission of gas, like electricity transmission, is typically a monopoly, withsignificant economies of scale. There is therefore a strong case for government to intervene inorder for main transmission pipelines to be installed for the benefit of all producers who mightmake discoveries in a region. This means that access to the pipeline should be available to newproducers, on fair terms, without discrimination. Lacking any regulatory arrangements to ensurethese objectives, the principles should be reflected in the contracts that underpin the pipelineconstruction and operation.
19. The estimated transmission tariff from the Nam Con Son basin to Phu My has beenestimated to be in the range of US$0.80 to US$1.00 per millBtu. The transmission tariff shouldbe based on the following elements negotiated between the parties:
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* 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 thepipeline and for cost savings. The benefits from greater capacity utilization should beshared between users and owners, by re-establishing the level of the capacity charge inthe tariff.
20. The seasonal swing in the power sector's demand for gas varies from a minimum of 100million cm per month to 270 million per month in 2000, and frbm 270 million per month to 400million 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 initialannual requirement for gas by the power sector is 2.4 bcm. This suggests that there should bescope for developing an interruptible market in the off-peak months.
21. The foregoing factors bearing on gas supply costs, gas market value and price indexingdetermine the boundaries for price negotiations. A range for the possible outcome is indicatedbelow. The gas sales price to the power sector should certainly be higher than the full cycleprivate sector costs of supply (after fiscal terms) and should be lower than the maximum marketvalue.
Range for Non-Associated Natural Gas Price,at Phu My, $/milBtu, in 1997
Min Price Max PricePrice of Gas at Phu My Cost Based, Market
full cycle Based
To Power Sector 2.3 - 2.8, 2.75-7.0after fiscal terms
To Fertilizer 1.50 - 2.30, 2.20 - 2.60before fiscal terms
Note: Gas price to fertilizer based on a fertilizer price of US$ 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 areasonable 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 permillBtu lower than in power generation. The Gas Master Plan referred to benefits from buildingand operating a fertilizer plant, such as foreign exchange savings from lower imports, localemployment and transfer of technology. While there would be direct foreign exchange savingsfrom lower imports, they would be at the expense of an inefficient allocation of gas and thepossible earnings of foreign exchange from higher value uses of gas. If transfer of technology isthe 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.
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investing in the sub-optimal production of urea. The self-sufficiency argument is also weakbecause there are many potential sources of fertilizer for import to Viet Nam. Hence, the risk ofsupply interruption is low. The highest net benefits are obtained when gas is sold into the highestvalue 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 $ 400million 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 asignificant excess supply of gas, much larger than the present discovered reserves. However, ifthe government is determined to subsidize fertilizer production, the gas price to the fertilizer plantshould at least cover the full cycle social supply cost of delivering it, which is estimated above tobe in the range of US$1.50 to $2.30 per mill Btu. The use of associated gas for fertilizer has beenproposed as a way to avoid subsidizing the ptice of gas used for fertilizer. The economic benefitto Viet Nam, however would be higher if gas is used in power generation.
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A NoTE
ON
PVGC ORGANIZATIONAL STRUCTURE3
A. INTRODUCTION
1. The strategic direction for PVGC is defined by its mandate from GOV, what is involved indeveloping 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 andmanagement capacity in each of the distinct business segments: E & P, Gas Transmission, GasDistribution 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 ofPVGC commercialization and organizational structure needs to be reviewed in the context of thechallenges 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 withtwo operating centers (for Bach Ho pipeline operations and for construction services) and two LPGjoint ventures generating cash flow. The priority of Petrovietnam (PVN) and PVGC management isclearly project development, specifically the Nam Con Son gas pipeline (NCS Gas Pipeline) projectand the Bach Ho gas processing project and related condensate / LPG storage terminal and transportinfrastructure (Bach Ho GPP). The NCS Gas Pipeline project is the building cornerstone todevelopment of Vietnam's gas industry. Gas purchase, transport and sales contracts associated withthe NCS Gas Pipeline project will also set important precedents concerning how PVN will exerciseits gas monopoly trader mandate. The Bach Ho GPP project is the building cornerstone todevelopment of Vietnam's LPG industry. Both projects will make important contributions toeconomic 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 restructuringto change PVGC into a commercial state gas company focused on its core business areas. Theinterface of PVGC with PVN headquarters (PVN-HQ) is of course central to both issues. This inturn will be influenced by the course of the Government (GOV) enterprise reform and therestructuring PVN into a commercialized holding company.
4. The scale of development that is envisaged, however, needs to be put in context. Within fiveto seven years, we foresee five PVGC strategic business units/subsidiaries (SBUs) being establishedto manage PVGC operated enterprises and PVGC JV interests, aligned by industry function inaccordance with international gas industry practice: Transmission, Distribution, Gas MonopolyTrader, LPG/Condensate and Construction Services. Each PVGC SBU will be several-fold the sizeof PVGC today in terms of revenue generated and operating profits. The PVGC group in total willlikely by 2005 be larger than PVN today, not in terms of numbers of employees but with respect toassets deployed and revenues generated
3This note is a draft report prepared under the ESMAP project: "Institutional Reform and Restructuring of thePetrovietnam Gas company"
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B. THE EVOLVING GAS INDUSTRY STRUCTURE
5. In determining the organization and structure of PVGC, it is necessary to analyze the scaleand scope of gas sector development that is in prospect and how the Vietnamese gas industrystructure might naturally evolve. Annexe 1 discusses this in some detail the enabling policy andregulatory initiatives that will be required to mobilize international energy company (IEC) capitaland expertise, to facilitate restructuring / productivity in state enterprises and to encourage thetransition to competitive markets
6. Table 1 sets out a course for evolution of the gas industry structure through the three gasmarket 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 frameworkOne producing PSC PSC fiscal regimeBach Ho pipeline Gas pricing policyNCS pipeline JV Regulatory principlesBa Ria/Phu My distribution re. access and tariffs
Market Development/ Gas Monopoly Trader (assisted National Energy Policy OfficeFirst Years by Int. Oil Companies?) State Management Petroleum
producing PSCs Authority Gas Master Plan forpipeline JVs downstream marketBach Ho pipeline developmentBa Ria/Phu My distributionPhu My/HCMC distrib. JVs
Market Development! Gas Monopoly Trader (Liberalization ofLatter Years Clearinghouse bulk gas market?)
Several producing PSCs Regulatory CommissionPVGC pipeline networkpipeline JVsPVGC Distributiondistribution JVs
Mature Market PVGC Holding CompanyCompetitive upstreamRegulated T&D industries
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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 allthe attributes of a 'Holding Company'. The corporate shell given to PVN is a good first step, buta commercialization would confer true autonomy of PVN. Functional departments in PVNsupervise 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, theoperations center, project development center and safety division have a staff of around 180 and theJVs 35 people.
8. PVN has the right to expand or restrain the business scope of PVGC in line with the commonstrategy of PVN's development and to approve plans of the company. PVN appoints the Director ofPVGC and authorizes the director to manage and operate its business according to its charter. As tothe PVN - PVGC interface, PVN is not involved in day-to-day management of operations but itdoes exercise complete control over subsidiary operations and capital investments. The PVN GasDepartment decides the yearly operating and investment budgets of PVGC and it makes thedecision on what portion of revenues generated from PVGC operations stays with PVGC. ThePVN Gas Department also takes the lead in project development and financing, and in the case of ajoint venture, in the choice of the strategic partner and negotiation of terms. It takes the lead also inproject implementation, supervising the bidding and procurement process and the work of thesubsidiary's project management boards.
9. PVGC has a self-operating and self-financing right fully responsible to PVN for itsobligations and interests. However, the financial autonomy of PVGC is minimal, which is partlydue to the fact that investments are decided by PVN headquarters and approved by MPI. At onepoint in time, 100 percent of PVN revenues went directly to the State. But step-by-step PVN hasbeen allowed to use portions of revenues it generates to cover operations and to establish modestcapital funds.
D. OPTIONS FOR PVGC ORGANIZATION
10. Table 1 has set out a course for development of the Vietnamese gas sector. Specific referenceis made to the possible timing of when a number of PVGC transmission and distribution companiesand joint ventures might be established, and also the likely evolution of the PVGC monopoly traderrole. The demands that this will place on PVGC as an organization will need to be recognized. It isnot simply a matter of adding staff and expanding the scope of professional and industrycompetencies to meet the challenge ahead. PVGC will soon have investment interests andoperating responsibilities in five distinct business areas: gas transmission, gas distribution, gastrading, LPG/condensate supply/processing/distribution and construction services. How to bestorganize PVGC in order to develop and manage these operations and investment interests has beena principal focus of the study.
11. In the international gas business, a common practice is to establish subsidiaries by corebusiness segment, recognizing fundamental differences as to how revenues are earned, the different
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technical and commercial competencies required for success and investor attitudes to risk. Thesedifferences are illustrated in Table 2 which presents an overview of the principal business activitiesof the different PVGC SBU's that are expected to be in place by 2005 and how they will begenerating revenues. It is to be noted that most international energy companies would not have aLPG/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 GPPproject, is large and this SBU is strategically-important to PVGC development over the next yearsas it could produce sufficient equity capital that will be required to fund development of PVGC'stransmission system and distribution ventures.
12. The options for organizing PVGC core business activities that were examined are set outbelow:
Option 1: Organize by core business segment as shown in Table 2, i.e., in five separate corebusinesses.
Option 2: Initially combine PVGC gas transmission and distribution activities in one SBU, andestablish SBUs for gas trading, LPG/condensate, and construction services;
Option 3: Initially combine gas transmission, distribution and trading activities in one SBU, andestablish SBUs for LPG/condensate, and construction services; and
Option 4: Initially combine gas transmission and distribution activities in one SBU, establishSBUs for construction services and LPG/condensate, and retain gas trading within PVGCheadquarters.
Table 2: PVGC Core Business Groups
Core Business Activities SBU HQ: functionaldepartments
Gas Transmission Systems planning/design Admin./personnelSystems operation/dispatch Finance/account.Systems maintenance/safety Systems planningMarketing transport services Technical support
[Revenue Source: provision of transportation services; profit is based on allowed rate ofreturn and size of asset/equity base plus operating effectiveness and throughput utilizationincentives.]
Gas DistributionSystems planning/design Admin./personnelSystems operation/dispatch Finance/account.Systems maintenance/safety Systems planningSupply contracting market Technical supportdevelopment systems CustomersCustomer connections Market researchCustomer services CommercialSales
[Revenue Source: volumes sold and margin between gas purchase costs and consumer prices,and transportation service fees.]
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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./personnelExport bulk sales Finance/account.Condensate processing JV interestsStorage terminals Technical supportProduct transport CommercialLPG bottling distribution Market research/planning
[Revenue sources: product sales, product upgrading, fees from storage, terminal andtransportation services and JV income.]
Construction Services PVN Group projects Admin./personnelPVGC 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 gasventures might proceed and whether they are likely to be PVGC operating companies or jointventures, in order to determine at what point in time the scale of operations is likely to be ofsufficient size to justify establishing a SBU. Also taken into consideration is that PVGC will needto build management capacity and develop certain areas of professional expertise important to thegas industry.
14. While the Option 1 organizational structure is considered the best longer-term solution forPVGC, for the reasons listed in paragraph 12, it would not be an efficient solution at this point intime. In the first stages of gas development the gas distribution business is likely to be limited tothe Ba Ria/Phu My region and it is not likely to reach a significant scale until the onshore gastransmission 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 numberof purchase, transport and sales contracts that are in prospect over the shorter horizon. There is alsothe 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 NCSpipeline/treatment plant joint venture, the Bach Ho gas plant (JV?) and an onshore gas transmissionpipeline to HCMC. In addition to responsibility for system operations and dispatch, it will also beresponsible for longer term network development planning and system design. The latter isextremely important given the economies of scale in pipeline construction and system operation andshould be given immediate priority.
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16. A placement of the Ba Ria/Phu My distribution project with the gas transmission SBU is apractical solution for an interim period. The project is presently being developed in an integratedmanner with the NCS Gas Pipeline project and from a systems design/ operations/ dispatchperspective can be readily managed by the transmission SBU. Moreover, this project is directed atsupplying larger industrial clients and the Gas Monopoly Trader will be responsible for gas salescontracting. Once more traditional gas distribution ventures are initiated, directed at supplyinghundreds of medium and small industrial and commercial clients, consideration should then begiven 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 scaleof gas trading reaches a scale that could justify establishing a separate SBU, the choices examinedwere placing it with the gas transmission SBU or placing it at PVGC HQ. Placing it with the gastransmission company is not favored. The international experience is that the gas trading groupwould quickly become subordinate to the technical operating/ system planning groups, exactly atthe 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 beingestablished at PVGC HQ, supported by a strong market research/ planning department and acommercial department with a greatly strengthened market development capacity. It should bepossible to create a positive environment for the Gas Monopoly Trader within the HQ structure andits 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 toprepare 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 and90,000(?) metric tons of condensate to market and/or process into blended gasoline andpetrochemical 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 exceedprojected total domestic demand by a considerable margin. PVGC also has plans to construct aLPG / condensate storage terminal associated with the BACH HO GPP project and also a LPGstorage terminal project at Haiphong. Consideration is also being given to entering the LPGtransportation field supplying LPG to companies in the fast-growing LPG bottling distribution retailbusiness, including the two PVGC LPG bottling/distribution joint ventures. These diverseoperations and commercial activities would have to be managed and this is best done by forming astand-alone SBU with a full range of corporate services, particularly as it is likely that onceestablished 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 establishinga LPG/ condensate SBU. Management functions such as overseeing joint venture interests, this ismore 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 adistraction to management at a time when it will be pressed to manage development of the otherSBUs. A better placement within the PVN Holding Company would be with the PetrovietnamEngineering Construction Company (PVECC). This enterprise does have the advantage of being
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profitable through construction contracts outside the PVN group of companies. It is recommendedthat 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 tomobilize International Oil Companies (IOC)/ IEC capital and expertise to assist in marketdevelopment and in development and operation of gas transmission and distribution infrastructure.It is further concluded that attracting IOC/IEC investment raising international project financingwill be facilitated an orderly transition from a centrally-controlled, state monopolized gas sector to amarket-based gas industry in which competition is encouraged and the natural monopolies areregulated.
22. The recommended option for organizing the PVGC core business activities should bringabout a shift in the management approach of PVGC from operations management to corporatestrategy and finance, earnings performance of the gas group and the core business SBU's, and todevelopment of major investment ventures. Management at the SBU level will focus as before onoperations but with an important shift in priorities, from asset and operations management to profitmaximization and enhancement of the company value. The recommended Option 4, implies aninitial combination of gas transmission and distribution activities in one SBU, establish SBUs forconstruction 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 instand-alone gas subsidiaries of an international gas company involved in this range of businessactivities. Although in Option 4 transmission and distribution activities are combined for the GasTransmission 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 adistribution operations group, we do not recommend that the market research, commercial, andcontracting competencies shown for the gas distribution SBU be added. The Gas Monopoly Tradergroup at PVGC-HQ will handle the commercial aspects of Ba Ria/Phu My distribution until adistribution SBU is established.
24. With the proposed commercialization of PVGC, there would be a need to strengthen thecapacity and expand the scope of expertise of the Finance/ Accounting Department. PVGC willhave 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 timedevelop the expertise to take the lead in corporate and project financing of PVGC expansion (post2005).
25. With the proposed commercialization of PVGC, there would be a need to strengthen thecapacity and expand the scope of expertise of a restructured Corporate Planning Department. Thisgroup will take the lead in developing both corporate and SBU development strategy and relatedbusiness plans and coordinate the PVGC group and SBU capital investment and operating budgetprocess. It will become a much more important departmnent than today and be the principalinterlocutor on PVGC development strategy with PVN HQ Gas Department. It will need to developover time the expertise and capacity to take over the lead from PVN-HQ in development of gasprojects and negotiation ofjoint ventures (post 2005).
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Annex 2.3.2Page 8 of 12
26. At the time when the Gas Monopoly Trader function is transferred to PVGC, there will be aneed to establish in PVGC-HQ a strong gas marketing group responsible for the Gas MonopolyTrader function supported by Gas Monopoly Trader-dedicated contracting and market researchdepartnents. The Gas Monopoly Trader group should be headed by a Deputy Director reportingdirectly to the Managing Director.
27. With the proposed transfer of responsibility for project implementation to PVGC, includingfor international contracting and procurement, a PVGC HQ Project Management Department willneed to be established. Forming ad hoc project management boards is a practical approach andshould 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 theproject feasibility stage, the Project Development Department of PVGC HQ should be absorbed bythe restructured Corporate Planning Department.
29. As to the role of the Gas Engineering/Technology Department, it will need to change but howdepends largely on whether it has a contribution to make to supporting the LPG/Condensate andConstruction Service SBUs. It clearly has a contribution to make to the Project ManagementDepartment. The systems planning/ technical support competencies for gas transmission anddistribution are, however, best placed with the SBU. Also the practice of technical evaluations ofSBU 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-alonebasis in preparation for its separation from the group, with any work for the gas group done undercontract.
31. If PVGC is going to enter the LPG/condensate supply distribution business as operator then itwill need the full range of corporate and technical services listed in Table 2. This is best establishedon a stand-alone basis. It is a business that is very different from gas and the PVGC-HQ functionaldepartments have not have specific knowledge on this issue. Any LPG commercial expertiseresiding 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 hirerequired expertise; (ii) develop JVs to advance development of gas transmission and distributionexpertise; and (iii) develop BOT projects to put in place required transmission infrastructure andoperating expertise. BOT projects are recommended JV terms are not satisfactory or it is desirableto put the responsibility for the project outside PVGC. PVN is advised to develop alliances and nottrying to develop the gas sector itself, relying on hired expertise. This would be very costly fromthe national perspective, unduly retarding development of the industry and thereby reducing thebenefit flow (most notably with respect to upstream fiscal revenues). Moreover, PVN does not havethe financial or management capacity at this time.
33. PVN is advised to take a more balanced approach with greater weight given to the JV Optionin the first years, at least through the first stage of the Market Development Phase. A combinationof the first two options would meet the corporate development objectives of PVGC as well as itsresponsibilities to the state. Promoting JVs has proved an effective strategy of mobilizingInternational Oil Companies/IEC capital and expertise and for achieving the desired transfer of
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Annex 2.3.2Page 9 of 12
technology and PVN staff development. It might well prove necessary, however, to rely to someextent on the BOT option to alleviate pressure on PVGC' financial and management resourcecapacity.
34. PVGC Pipelines will continue to operate the Bach Ho pipeline. It will need to take the lead inplanning, developing and operating integrated regional gas systems, possibly with the assistance ofa twinning technical assistance program with an IEC. PVGC would take the lead in gas marketdevelopment. At a later stage after the Monopoly Gas Trader function has been transferred to PVGCand the gas market has developed significantly there will be a need to develop and operate a GasClearinghouse to manage this function in an efficient manner. As to Gas Distribution, given thenature of the business with the importance of market development expertise, it is advised that thejoint venture route for the first utilities. As to PV-E & P, this has important ramifications for gasindustry structure and promotion of upstream competition. Most immediate is that PVN has theright to capture and market all associated gas that is not required in oil field operations. This willshortly 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 implicationson 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 companylevel focuses on the issues of corporate strategy and finance, earnings performance of the group andthe individual core business SBU's and major investment decisions. Management at the SBU levelfocuses on SBU operations and asset management, maximizing profits and increasing the value ofthe company. The process of management control takes on added importance in a holding companyframework, involving a comprehensive process of approval of annual SBU business plans andbudgets for operations and capital investment, setting SBU performance targets, a fixed schedule forreporting SBU operating and financial results and analysis of business results vis-a-vis businessplan and performance targets. A company-wide system of business planning, accounting andperformance reporting is invariably imposed. The exercise of these planning and control functionsin turn requires appropriate technical expertise and specialization to support the management of theholding company. State oil companies which have successfully made the transition to profitable,competitive energy companies have invariably followed this course. And it is recommended thatPVN 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 threeorganizational functions:
* Business line functions: to provide overall strategic direction to core business entities whileensuring appropriate control through: (I) direction of SBU corporate development; (ii)review and approval of SBU capital and operating budgets; and (iii) monitoring SBUoperating 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 commercialaffairs, public relations, corporate planning and development, and organizational development.
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Annex 2.3.2Page 10 of 12
The corporate planning and development function has prominence, responsible for managing theannual planning and budgeting cycle and for provision of general planning guidelines to thebusiness line departments. The finance function also has prominence, responsible forestablishing 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 servicesto business line and corporate staff functions within PVN-HQ.
I1. For PVN, such a system would mean that PVN headquarters (PVN-HQ) would not directlymanage core business subsidiaries, but focus on (i) setting strategic and financial direction for thePVN group of core business subsidiaries and on (ii) management control of the SBUs throughapproval 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, thestructuring of investment proposals and financing, and the setting up of strategic partnerships inbusiness ventures.
2. Consistent with the above PVN holding company concept, the PVN-HQ Gas Business LineDepartment 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 theannual 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.
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Annex 2.3.2Page 11 of 12
1. It is recommended that within this framework of corporate strategic direction set by the PVNgroup-wide system of SBU approval and control centered on business plans and capital andoperating budgets and PVN-HQ, that PVGC management be given full discretion and authoritiesover PVGC group operations and asset management. PVGC group annual budgets for operationsand capital investment budgets once approved by PVN-HQ would provide the reference point forPVGC operations and development, and also the basis for evaluating PVGC performance andensuring accountability.2. It is also proposed that revenues generated by PVGC be managed by PVGC, subject toagreement with PVN-HQ on revenue allocation. Specifically, PVGC would retain revenuesrequired to cover agreed operating budgets, agreed capital investment project expenditures, all debtservicing 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 demandsthat will make on both PVN and PVGC organizations, as discussed in the main section it is clearthat the present management system is not sustainable and would need to develop with thechallenges. 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 byavailability of both equity and debt capital. PVN and PVGC do not has assured access to revenuesgenerated from operations, thus are not in a position to accumulate equity investment capital orprovide required assurances to financial institutions that they can service debt obligations. PVN andPVGC presently rely to a large extent on capital allocations from GOV to fund investments. Thereis, however, a general shortage of investment funds available to state enterprises and in any eventthe capital investment requirements of the oil and gas sector are considerable larger than what islikely to be available from state development funds.
2. Commercialization of PVN and PVGC is the key to this constraint. If the companies wereassured the revenue (or an agreed share of the revenue) they generate, subject to shareholderagreement on annual dividend payments management would have more authority and discretionover how they develop and operate their business, within a framework of shareholder approval of
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Annex 2.3.2Page 12 of 12
annual business plans and capital and operating budgets, monitoring of financial and operatingperformance and annual performance review. Until this happens, gas sector development andPVGC corporate development will continue to be constrained and there will be a bias towards jointventure development because they are allowed to operate under more favorable conditions than thestate enterprises.
G. CONCLUSIONS AND RECCOMMENDATIONS
3. From the above analysis, it is reccommended that the management of PVN and PVGC takethe 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 andJV's.
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- 801 -
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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 2.4.2Page 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.
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Annex 2.4.3Page 1 of 1
Vinacoal Production Capacity(million tons per year)
1997 2000 2005Company
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.
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Annex 2.4.4Page 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.
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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/tonSource: 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 dwt50,000 dwt at
anchorage
Loading rate (tons per day)*
Sized 2,000 1,500
Fines 6,000 4,000
* Sundays and holidays exceptedSource: Vinacoal, May 1997.
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Annex 2.4.7Page 1 of I
Anthracite Production and Trade(million tons)
Year World Export WorldProduction Quality Trade Production
1985 354 62.2 5.3 5.0 0.61986 362 62.6 5.9 5.5 0.61987 391 61.1 6.3 6.1 0.21988 401 61.1 6.0 5.7 0.31989 407 60.5 5.1 4.6 0.51990 377 60.0 5.1 4.8 0.71991 370 58.1 5.2 4.2 0.91992 374 57.8 9.2 4.5 3.0 1.61993 354 56.4 8.9 5.2 3.8 1.41994 346 56.1 9.6 5.6 3.8 1.81995 376* 55.0 9.6 7.8 5.0 2.71996 na na na 8.5 4.8 3.6
* Major producers - China (69.1%), N. Korea (10.6), FormerUSSR (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 Instituteand others.
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Annex 3
ANNEX 3. ENERGY AND ENVIRONMENT
3.1. Ambient Air Quality standards .................................. 1163.2. Emission Standards from Stationary Sources .................................. 1173.3. Coal mining disturbed area and production .................................. 1183.4. Hydroelectric Plant incremental investments .................................. 1183.5. Thermal plant incremental investments .................................. 1193.6. Environmental costs under the base case scenario .................................. 119
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Annex 3.1Page 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 yearSulfur dioxideWorld Health Organization 350 125 40-60United States 365 80World Bank 80Korea, Rep. of 650 365 80Philippines 180 80Thailand 780Vietnam 500 Ncm 300 NcmParticulatesWorld Health Organization 150-230 60-90(TSP)United States (PM1 0) 150 50World Bank 200 (PM10); 300 (TSP) 50 (PMIO); 80 (TSP)Korea, Rep. of 150 (PMIO); 300 (TSP) 80 (PMI0); 150 (TSP)Philippines (TSP) 150-230 60-90Thailand 120 (PM1O); 330 (TSP) 50 (PM1O); 100 (TSP)Vietnam 300 200Nitrogen oxideWorld Health Organization 400 150United States 100Korea, Rep. of 280 150 100Philippines 150Thailand 320Vietnam 400 100LeadWorld 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 5.0Carbon monoxideWorld Health Organization 30 mgUnited 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 mgOzoneWorld Health Organization 100-200 60 (8 hour)United States 235 235World Bank 250Korea, Rep. of 200 120 (8 hour)Philippines 140 60 (8 hour)Thailand 200Vietnam 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 AbatementHandbook (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.
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Annex 3.2Page 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 oxideUnited States 920-1,240 (oil and coal post-1971)Japan 644 223European 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
ParticulatesUnited States Site-specificJapan 50-800European 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 oxideUnited 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)CommunityIndonesia 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 1,000Carbon monoxidePhilippines 500 500Vietnaml 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 draftguideline was prepared that would apply only to thermal power plants. Under this guideline emission limits for new plants would be 50milligrams per normal cubic meter for particulates, 400-1,500 for sulfur oxide (depending on fuel and size), and 650 for nitrogen oxide (for solidfuels). These standards are not being enforced and have never been fornally passed, however.
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Annex 3.3
Disturbed area and production of coal mines
Disturbed area Annual production Average productionMine (hectares) (thousands of tons) (tons per hectare per year)
Cao Son a 405 715 1.77Coc6 a 305 1,511 4.95Deo Nai a 335 500 1.49Hatu a 615 924 1.50Hon Gai - 116Khanh Hoa 61 85 1.39NaDuong 115 125 1.09Nong Son a 25 25 1.00Nui Beo a 105 175 1.67Nui Hong 50 110 2.20Total 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 Environmentalalternative
Capacity Resettlement Compensation Investment RecurrentPlant (megawatts) (per year) (per year)Short-term projects (through 2002)Song Hinh 70 0.50 2.75 15.00 1.00Yaly 1 and 2 720 3.00 5.00 120.00 10.00Ham Thuan 236 0.00 2.50 20.00 1.75Da Mi 236 0.00 0.25 20.00 1.75Total 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 13.00Son La 3,600 75.00 30.00 450.00 35.00 aTotal >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 ayear in recurrent expenditures.
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Annex 3.5
Incremental investments in thermal plants required to meet environmental standards(millions of US. dollars)
Capacity Baseline Environmental EnvironmentalPlant (megawatts) plan alternative plan alternative + planPhaLai2.1/2 600 72 111 201Quang Ninh 1-4 1 200 144 222 402New coal plants 2 200 264 407 737
TotalsBase case scenario 1,800 216 333 603High-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 oxidecontrols. The environmental alternative + plan includes particulate control, water treatment or recycling, nitrogenoxide controls, and sulfur emission controls. Incremental control costs are estimated to be $120 per kilowatt forparticulate 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 in2000-06. The high-growth scenario is the same but also includes new coal plants-including PC2. P. Thiet and threeother 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
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Annex 4
ANNEX 4. INVESTMENT PRIORITIES AND FINANCING STRATEGIES
4.1. Energy sector financing requirements- 1998-2002 ............... ........................ 1214.2. The need for government guarantees ....................................... 122
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Annex 4.1Page 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
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Annex 4.2Page 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 forpower projects around the world and the financial constraints that face developing countries. Itexplains the need for government support and guarantees for BOT projects and the experience ofother developing countries who have been successful in attracting foreign private investments inthe power sector. It also underlines the importance of specifying the degree of governmentsupport provided a specific project in the request for proposals.
Projectfinancing
Private sector infrastructure projects are primarily financed in two ways: (1) throughbalance sheet financing; and (ii) through non-recourse project financing, which is off-balancesheet for the sponsoring company. The latter method of financing, with modifications, is oftenutilized in build, own, operate (BOO) or build, operate, transfer (BOOT) schemes, and issometimes referred to as limited recourse financing.
In balance sheet financing, lenders provide loans to a corporate entity to finance a project and inreturn the corporation has a general obligation to repay the loans. That is, it has an obligation to repay theloans regardless of the performance of the specific project it financed, so that the lenders assume thecredit risk of the larger corporate entity (which would normally have an acceptable credit rating) whichhas 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 toutilize internally generated cash flow to finance new investments and thereby lessen the degree to whichit must secure financing outside the form such as loans and new equity issues. Traditional Public sectorProjects are also financed through the balance sheet method. In these cases the government assumes theliability of loans for the projects, generally from multilateral or bilateral sources. These are utilized by thepublic entity to fund goods and services required to construct the project. Even though the implementingagency has the primary responsibility for the repayment of the loan, the government invariablyguarantees these loans with an assurance to the lenders that these loans will be repaid independent of theperformance of the project. For traditional public sector project this could amount to more than 80% ofthe project cost with the remaining coming from internal resources of the entity.
In contrast, under non-recourse project financing, lenders provide loans to special purposecompanies whose only asset is the project being financed. Normally, the sponsoring party (usually acompany with experience in the specific sector) will provide a portion of the financing as part of theequity 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 norecourse to the corporate sponsor for repayment of their loans, and therefore must rely on the ability ofthe specific project they have financed to repay the loan. If the project fails, the sponsor is only liableto the extent of its equity contribution (the 20-30% of project costs that it has financed) which are atrisk. If the project is a new, greenfield investment, lenders generally must rely for repayment on a setof contracts (see Security Package) which provide for the project's cash flow.
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Annex 4.2Page 2 of 5
In recent years there has been increasing interest on the part of infrastructure firms' frommany countries to invest equity in development countries as opportunities in their home marketsslackened or as part of global diversification strategies. Most of these potential investors areinterested 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 thesekinds of projects, however, several conditions must be met: (i) they must possess the capabilities toassess project risks and mitigation measures to determine whether they have a high probability ofbeing repaid from the specific project they are asked to finance: this requires specialized "projectfinance" analysis skills, which are available in only a limited number of international bankinginstitutions which have the size and experience to staff experts in this area; (ii) they must be willingto commit funding to countries which are considered high risk by the banking community and theirregulatory agencies, and rating agencies; and (iii) they must be willing to provide long-termfinancing, 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 toprovide this kind of financing in developing countries without some form of support to alleviatecountry-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 asreflected in the rating of the sovereign government's debt securities by an international ratingagency like Moody's Investor Services or Standard & Poor's to assess it overallattractiveness. Financing becomes more difficult for countries with ratings below investmentgrade3 or those countries without a rating, since it is difficult for the banks to assess thecreditworthiness.
Y Past Experience.' Banks are also reluctant to lend to countries with histories of non-paymentto 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 belessened.
* Regulatory Treatment of Bank Lending: Banks are obliged by their regulators to set asidefunds ("provisioning") when making loans to many developing countries to protect againstthe risk of non-payment. This is very costly to the banks and hence discourages lending tothese countries. The poorer the credit of the project the shorter the maturity and higher theinterest rate for the financing. For some of the poorer credits lenders are not able to providefinancing 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 wouldown 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 forMoody's Investor Services.
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Annex 4.2Page 3 of 5
Sector Regulatory Arrangements: Even if banks were satisfied that the macroeconomicconditions were stable and the overall country creditworthiness was adequate, forinfrastructure 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 orregulatory arrangements of the particular sectors in which the projects they are financing willoperate. In recently reformed sectors, this track record has yet to be established this limitingthe ability of the banks to analyze whether it is a good risk to make a loan to a project whichwill rely on the stability of these arrangements for its profitability.
As domestic capital markets in the developing countries are unable to provide long termfinancing, most of this invariably comes from offshore sources. In cases where foreign lenders haverecently provided financing for private infrastructure projects in developing countries, they soughtto minimize these risks by seeking guarantees (from host governments and third parties) against therisks associated with sector regulatory arrangements or broader political and "country" risks, such asexpropriation, and foreign exchange inconvertibility. When the purchaser of the service and/or theprovider of an input is a government-owned entity, the banks have also often sought and usuallyreceived a government guarantee of the purchasing entity's payment obligations. This is on accountof two reasons: (i) under government ownership the government has the right to change thedecisions of the public entity in areas such as tariff fixation etc.; and (ii) the credit of the companymay not be acceptable to the lenders. In some cases, projects have been able to raise a portion of therequired debt from the domestic financial markets, but in general these alternatives are constrainedby 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 Risksassociated with the project. The former is to ensure that the parties to the contract are able tofulfill their obligations under the contracts and in case the operation of the entity is controlled bythe government its must also give guarantee that the entity can fulfill its obligations. This wouldinvolve guarantees of the obligations of the government owned entities such as the powerpurchaser, 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 beenhanced by guarantees by the government. For projects where the output is sold in localcurrency and the foreign currency markets are controlled by the government, the governmentsneed to guarantee the lenders that the project would be able to obtain and transfer foreigncurrency if they tender the local currency. Wherever governments are in control of these activitiesand the currency markets are volatile, the governments would invariably be required to guaranteethese obligations. The principal reasons for seeking normal and binding government support, inaddition to those listed above are:
* it negates any future attempts by the government or successors governments to honor thesupport agreed at the initial stage;
* it establishes in clear and comprehensive terms and contractual rights, duties and obligationsof the government and, any conditions which need be satisfied by the sponsors for theagreement to become effective.
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Annex 4.2Page 4 of 5
Security Package.
An important aspect of project financing is the need for clear allocation of the risks andobligations of each parties involved in the transaction. The responsibility and obligations are setout in various legal agreements for the project. For instance, lenders to a private power generationproject would rely on, most importantly, a power sale agreement, which would have to providesufficient cash flow to pay for operating expenses, plus debt service to lenders and dividends toequity investors. Other important contracts would typically include a construction contract, a fuelsupply agreement, and operation and maintenance agreement. Each of these would featurepenalty provisions sufficient to sustain the project in the event of a contractor's default. Takentogether, these must amount to an acceptable credit risk to the lender for it to make a loan to thiskind of project. Because of this, lenders focus their attention on the specific provisions of thesecontracts 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 projectdocuments put together are loosely refereed to as the security package. As the lenders and theinvestors depend upon these agreements to repayments of their financing, returns and equity, theyfrom a critical part of project financing. Typically this would include:
Power Purchase AgreementGovernment Support Agreement / Implementation AgreementFuel Supply AgreementOperation and Maintenance AgreementCredit agreements.Shareholders AgreementSecurity documentsIntercreditor AgreementConstruction contract
Out of the above, the first three invariably form a part of the RFP specially as these definethe role of responsibilities of the government and the private sector in the transaction. The clearerthe 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 pricecushions in their bids. As the judgment and the motives of bidders may vary, lack of clarity canlead to bids which are not fully comparable. Moreover, if the level of comfort / governnentsupport is not known the financial advisers are likely to advice the bidder to submit their bidsbased on higher financing costs which reflects the higher risk of the transaction i.e. withoutgovernment support.
Experience in other countries
It is important to compare the experience of initial projects in countries with similar creditand where the purchasing utilities have similar financial standing, as lenders and investors attachconsiderable weightage to consistency of policies and are likely to require reduced support. Thetable below gives the level of the government support of either the early project in some of thecountries. All the projects are thermal although in some cases, they may be coal and fuel oil
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Annex 4.2Page S of 5
based. In most of these the credit rating of the countries was higher than Vietnam. This aspectneeds 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 MGSPhilippines: Pagbilao MGS MGS MGSPakistan: HUB MGS MGS MGSJamaica: Rockfort MGS MGS MGSPakistan: UCH MGS MGS MGSMexico: Samalyuca LGS MGS MGSPhilippines: Sual MGS MGS MGSIndonesia: PTJawa PGS PGS PGS
The above table uses the following terminology to indicate the level of governmentguarantee/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 indifferent countries e.g. energy conversion arrangements where the utility supplied the fuel andpaid for the electricity in foreign exchange to arrangements where there were commercialarrangements between the project countries e.g. energy conversion arrangements between theproject 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 comfortto the lenders and investors against currency devaluation, political force majeure and changes inlaw 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 andthe lenders minimum requirements, it is clear that government of developing countries wouldneed to provide some basic undertakings to the private developers of infrastructure projects.Eliminating these would lead to reduced competition, increased complexity in evaluation, anuneven playing field as some bidders may not price every item, while hoping to negotiate themissing elements with the purchaser and the government. It also reduces the benefits ofcompetition and invariably increases the cost of the project.
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Annex 5
ANNEX 5. INSTITUTIONAL DEVELOPMENT AND REGULATION
5.1. Vietnam Energy sector organization ........................................ 1285.2. EVN Organization ........................................ 1295.3. Petrovietnarn organization ........................................ 1305.4. Vinacoal organization ........................................ 1315.5. Power Sector Policy Statement ........................................ 1325.6. Action Plan for Institutional Reform of the Power Sector ........................................ 136
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VIETNAM ENERGY SECTOR
- _ I I_ _Prime Minsiter's Of fice Council of Ministers
Office of the Govermnment Commtittees to CouncilOil and Gas Dept.Electricity Dept.
State Petroleum Management Authority (SPMA) Petrovietnam National Energy Policyto 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 ProposedOil & 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 andrecommended natural gas prices
lMPI Ministry of Industry Ministry of Finance Ministry of Trade
Gas Steering Committee Coal & Power Investigation & Design Cos, Construction Cos Taxation strategies in each sub-sectorElectric Law Stteering Committee Domestic and Foreign Borrowing
EVN VINACOAL |Energy Institute Coalimex
Hanoi PC, PCI Coal CompaniesCentral PC3 CamPha, Uong Bi, § -,
HoChiMinh City PC, Hong Gai etc. ISouth 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 & InternationalManagement 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
_ ; ~~~~~~~~~~~~~~~~~~~~~DependentAccounting Units
Independent Eeg ~kcAccounting 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 VenturePetrovietnam Processing & Petrovietnam Exploration & Vietnam Petroleum Institute[pDistribution Company Production Compnay (VPI)
distib. (PVPDC) (PVEP) Idistib. ________ _______ ________ J [ ___ ________ _______ ______ _ ________ _______ _P etro-TPotro-T w er iJoin VV entur
R&D Center for PetroleumPetrovietnanm 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 PetroleumConstruction Company | Petrovietnam Training & Safety & Environment Tuyen Quang DMC barite
(PVECC) Manpower Supply Center (RDCPSE) Joint Ventureo | Commerce ______________ _ ] [ (PVTMSC)
Petroleum Technical Service Thang Long LPG JointFinance l l Company (PTSC) l Petroleum Information Venture
Finance Co pnCPT Center_________________________
Drilling Mud Company | | Best Food Catering JointAccounting (DMC) Venture
Internation Cooperation Petrovietnam Trading Petrovietnam Golden
Company (PETECHIM) Processing
|Organizing & personnel|Petrovietnam Tourist Shell Codamo Lub. Oil Joint
Service Company (PVTSC) VentureTraining P TouristE~~~~~~~~~~~~~~ ~ ~~~~~~~~~~~~~~~~~~~~~~~~~ Helivifra JointVnue| p >
Petrovietnam Insurance HInspection l l Company (PVIC) - CD
Vietubes Joint VentureX
Administration
ORGANIZATION CHART OF VINACOAL
BOARD OF SUPERVISIONMANAGEMENT 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 CHIEFdevelopment 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 VENTUREOFFICE_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-Vi 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
SchoolNorth East Co. | ll. Khe Cham Mining Co. 0. In-Ex & Int'l Coop. Co. . Elec. Adjsst. & Experimental Center | IS,cTha VICCOA Beer4o. 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 UniversalDeo 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 JournallI 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 5.5Page 1 of 4
Socialist Republic of VietnamPower 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 developmentof the power sector of Vietnam. This paper is an update of the Power Sector Policy statement issued bythe Ministry of Industry on December 1st, 1995. This policy paper is supported by a ReformImplementation 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 ofscarce investment resources.
(c) Ensure reliable electricity supply of good quality
(d) Resolve the mismatch between market-based production costs and State administeredprices
(e) Clearly delineate and separate State management functions and business managementfunctions
(f) Enable Vietnam to raise the necessary financing for power sector expansion to meeteconomic 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 aState Corporation for the different power sector entities engaged in generation, transmission, distributionand 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 threecategories:
Those engaged in generation and transmission are subject to dependent accounting, andconsolidation of accounts takes place at the level of EVN as a whole (general EVN). There are 17business units involved in these activities- 13 for generation, 4 for transmission and 1 for theNational Load Dispatch Center.
Those engaged in distribution and supply are independent accounting enterprises (i.e. StateEnterprises 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, andplanning) have either independent or dependent accounting status.
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Annex 5.5Page 2 of 4
Figure 1.
Electricity of Viet Nam (EVN)
GenerationBusiness Unit
(12 Power Plants)
TransmissionBusiness Unit
(NLDC & 4 Transmission Cos)
-BTPI BTP2 BTP3 BTP4 BTP5
Hani Pwe HCM Cit Poe oe
Consumers
BTP Bulk Transfer PriceNLDC National Load Dispatch Center
EVN has the legal status of a state corporation under the State Enterprise Law. Independentaccounting 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 functionsestablished under the State Enterprise Law. The Ministry of Industry is responsible for policy andoversight of the power sector.
From a sector structure perspective, the core functions of generation and transmission are currentlyintegrated and under direct management of the EVN headquarters. The generation-transmission core sellselectricity in bulk to the five independent distribution companies (Figure 1). Retail prices to finalconsumers are established by the Government and are currently uniform across the country. Themechanism for setting the BTP allows the distribution companies to make a target profit - the profit levelis determined by EVN. Given uniform retail pricing and differing distribution system costs for eachdistribution company, the bulk transfer price is different for each distribution company.
Vietnam is currently experiencing high growth in electricity demand. Vietnam's powerdevelopment plan envisages the addition of 3,000 MW by the turn of the century and about 6,000 MW bythe year 2005o To meet this ambitious expansion program, a combination of goverment budgetaryresources, official development assistance (ODA) funds, resources from multilateral financial institutionsand diversified finance will be utilized.
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Annex 5.5Page 3 of 4
C. Reform Strategy
The Government reform strategy addresses the following key aspects of power sector reform. Areform implementation plan is attached.
(a) Structural Reform and Commercialization of Sector EnterprisesGOV 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 andfacilitating the transition of the transmission business into a profit center. Subsequently,it is expected that a separate transmission company would be established as anindependent legal entity (i.e. as a independent accounting member unit of EVN).
Developing efficient pricing and contractual relationships between the transmissionnetwork business unit and the generation stations on the system. These contracts willfacilitate the efficient production of electricity and optimize resource utilization on thesystem.
Transforming the distribution entities which are currently independent accounting stateenterprises into entities that have management and financial autonomy from the EVNState Corporation. This transition will include the development of more efficientperformance incentives for the distribution entities based on market based costs.Commercial management practices will be developed in these entities to prepare forseparation from the EVN State Corporation structure.
(b) Legal and Regulatory FrameworkThe GOV is preparing legislation for the power sector. It is expected that the primary Electricity Lawwill be supported by secondary legislation covering the aspects of tariff regulation, service regulation andlicensing of activities in the power sector. This body of legislation would form a consistent legal basis tofacilitate commercial sector operations and objective government oversight of the sector. The followingsteps are envisaged:
promulgation of a primary Electricity Law
- development of supporting secondary legislation to the Electricity Law, to inter aliaaddress: (a) scope and structure of regulatory agency; (b) procedures for tariff setting andregulation; (c) administrative regulations and standards.
- preparation of a Grid Code that would address issues related to interconnection andoperating standards between generation entities and the transmission entity.
(c) Electricity PricingIt is recognized that cost-based retail prices and internal transfer prices are essential to a commercialpower sector that is expected to raise the required capital for its needs. Retail prices based on theseprinciples will ensure that resources are allocated efficiently in the economy and that consumers face theappropriate price signal to utilize electricity efficiently. Efficient internal prices will provide incentives tothe distribution companies to operate efficiently and establish an objective basis to evaluate the cost ofpurchasing power from BOT/JV power generation schemes. The government plans to:
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Annex 5.5Page 4 of 4
Progressively raise average retail tariff to about USc 7.0/kwh by 1999 and take allmeasures necessary to realize a self financing ratio of not less than 30% for the electricitysector as a whole.
introduce a cost-based bulk transfer price for bulk power sales to the distributioncompanies.
(d) Diversified Participation in Vietnam's Power SectorThe 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) accessthe 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 planin terms of size and technology, and with the system's operational needs; (ii) competitiveness: projectsponsors will be selected through a competitive bidding process measured in terms of lowest price ofelectricity delivered; and, (iii) limited recourse project financing: foreign investors will secure financingon 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 offinancing structures may be utilized to involve diversified capital in generation. Diversified financingapproaches will also be evaluated for distribution operations.
(e) Rural ElectrificationOnly 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 willdevelop a Rural Electrification Master Plan. This master plan will define: (I) criteria for expanding theelectricity 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 ConservationTo facilitate the efficient utilization of electricity and encourage electricity conservation practices
and technologies, the Govemment will implement measures and systems for electricity demand-sidemanagement (DSM) and load management in Vietnam.
Signed
Ministry of Industry
Attachment 1: Reform Implementation Plan
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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 ratioof 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 accountsThis is distinct from existing internal bulk supply identifying full costs of generation andtariff that does not reflect actual G&T costs and is transmission (G&T). These audited statementsbased 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 supplyreflective 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 costoperating loss to PCs is compensated transparently - 1999 85% of actual G&T costi.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 distributionof 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 thisassignment of functions at DDG level will beprovided by January 1998.
c. EVN HQ to issue:
- accounting procedures for implementingphased increase in cost-based bulk supplytariff 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 auditorsfor all PCs from January 1998 onwards.
2.3 Strengthen the internal organization and operations 2.3.1 Implementation of a finance and commercialof 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 ofReference -Attachment 2.
(Initialfocus for pilot implementation could be inVung Tau and Halong).
2.4 Equitization of distribution operations. 2.4.1 Pilot equitization of one or more distributionoperations based on results of PHRD study.Target date to commence equitization program:
0o 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 accountsprepared 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 EVNof EVN and implementation will commence.
Target dates:- Transmission formed as profit center -
December 1999.
- Transmission formed as independentaccounting 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 incorporatestransmission network optimization togetherwith generation expansion. (September 1997)
- EVN to obtain the package and training for itsutilization. (January 1998)
- EVN to prepare system expansion plan withoptimization of transmission and generation.(December 1998).
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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 1997consumer for reliable and least-cost supply. that define the basic regulatory framework and
initial institutional mechanism to perform the - For promulgation - March 1998regulatory functions.
(The above work is partially supported by ESMAPGrant 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. Expectedestablishment of the regulatory function. promulgation of secondary legislation within
12-18 months of approval of Electricity Lawby National Assembly.
- Preparatory work for establishing a separateso 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 perforto perform regulatory functions. regulatory functions - January 1999.
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Annex 6
ANNEX 6. AN AGENDA FOR ACTION
6.1. Energy Sector Policy Reform Agenda .141
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Annex 6.1Page 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 2.2and 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 reducingtransmission 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 sectorstrategy for energy Increasing average retail power tariffs to 7 cents/kwh by March 2001 andsector 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 incompetitively possible markets
Ensuring energy Extending modern energy use to rural area through grid extensionexpansion is equitable Promoting renewable energy development for remote communesand environmentally Energy system planning to incorporate environmental costssustainable
Strengthening pollution monitoring
Revising environmental standards
Phasing out lead in gasoline
Improving corporate Redefining governments role as ownergovemance and creating Commercialise, corporatize and diversify ownership of independentcreditworthy 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 asa wholly-EVN owned independent accounting unit.
Rationalising sector Creating a National Energy Policy Council and a National Energy Policygovernance Office
Implementing arms length regulation and creating a regulatory agency forelectricity 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
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