Basis for formulation of a Bolivian National Energy Plan

@ ~~~~~~~~~~~~~~/' 'n Joint UNDP/World Bank Energy Sector Management Assistance Program BASIS FOR FORMULATION OF A BOLIVIAN NATIONAL ENERGY PLAN A REPORT BY CONSULTANTS LA PAZ, BOLIVIA NOVEMBER 1987 Energy Strategy, Management & Assessment Division Industry & Energy Department The World Bank Washington, D.C. 20433  BASIS FOR FORMULATION OF A BOLIVIAN NATIONAL ENERGY PLAN A Report by Consultants La Paz, Bolivia NOVEMBER 1987 The work underlying this report was undertaken at the request of the Bolivian Government. It was designed to assist the Government in formulating a strategy for the energy sector which would be appropriate in the context of the overall Bolivian economy. The work was carried out between November 1986 and June 1987; financed by the United Nations Development Program. The World Bank was the executing agency of which the supervision was carried out by Gabriel Sanchez-Sierra and Ignacio Rodriguez. The team consisted of Gustavo Rodriguez (Resident Project Director), Angel Zannier (Advisor to the RPD), Manuel Ignacio Dussan (Electric Power), Marc Heittet (Natural Gas), and Robert Gould (Rural Energy). In addition to Mr. Zannier, the following local consultants were used: Franz Lino (Hydrocarbons), Ricardo Quiroga (Macroeconomy), Eddy Iporre (Electric Power), Marcelo Valenzuela (Finance). The National Petroleum Company (YPFB) provided Max Perez, Guido Soliz, and Freddy Escobar. The National Electric Power Company (ENDE) provided Enrique Gomez. The Corporation for the Promotion of Rural Energy (COFER) provided Lucio Saal and Jorge Sarate. Secretarial support was provided by Yamila de Mattos.  ACRONYMS ANICARVE Asociacion Nacional de Industriales de Carbon Vegetal (National Association of Charcoal Industries) CAF Corporacion Andina de Fomento (Andean Development Fund) CDF Centro de Desarollo Forestal (Center for Forest Development) CESSA Cooperativa de Electrificaci6n Sucre S.A. (Electrification Cooperative of Sucre S.A.) CNECA Comision Nacional de Estudio de la Cana y del Azucar (National Commission of the Study of Sugarcane and Sugar) COBEE Compania Boliviana de Energia Electrica (Bolivian Power Company) CODETAR Corporacion de Desarollo Regional de Tarija (Regional Development Corporation of Tarija) COFER Corporacion de Fomento Energetico Rural (Corporation for the Promotion of Rural Energy) COMIBOL Corporaci6n Minera de Bolivia (Bolivian Mining Corporation) CONNAL Consultura Nacional (National Consultants) CORDEBENI Corporacion de Desarrollo Regional de Beni (Regional Development CorporatLon of Beni) CORDECH Corporacion de Desarrollo Regional de Chuquisaca (Regional Development Corporation of Chuquisaca) CORDECO Corporacion de Desarrollo Regional de Cochabamba (Regional Development Corporation of Cochabamba) CORDECRUZ Corporacion de Desarrollo Regional de Santa Cruz (Regional Development Corporation of Santa Cruz) CORDEOR Corporacion de Desarrol.lo Regional de Oruro (Regional Development Corporation of Oruro) CORDEPANDO Corporacion de Desarrollo Regional de Pando (Regional Development Corporation of Pando)  CORDEPAZ Corporacion de Desarrollo Regional de La Paz (Regional Development Corporation of La Paz) CORDEPO Corporacion de Desarrollo Regional de Potosi (Regional Development Corporation of Potosi) COSELEREC Cooperativa Servicios Eiectricos Trinidad (Cooperative of Electric Services Trinidad) COSELCA Cooperativa Servicios Electricos Camiri (Cooperative of Electric Services Camiri) CRE Cooperativa Rural de Electrificaci6n (Rural Electrification Cooperative) DGH Direcci6n General de Hidrocarburos (General Hydrocarbons Directorate) DINE Direcci6n Nacional de Electricidad (National Electricity Directorate) ELFEC Empresa de Luz y Fuerza Electrica de Cochabamba (Electric Power Company of Cochabamua) ELFEO Empresa de Luz y Fuerza de Oruro (Electric Power Company of Oruro) ENAF Empresa Nacional de Fundicion (National Metal Smelting Company) ENDE Empresa Nacional de Electricidad (National Electric Power Company) FAO Food and Agriculture Organization IMF International Monetary Fund INE Instituto Nacional de Estadistica (National Statistical Institute) INER Instituto Nacional de Electrificacion Rural (National Institute for Rural Electrification) INFOL Instituto de Fomento Lanero (Institute for the Development of the Wool Industry) INI Instituto Nacional de Inversiones (National Institute of Investments) JUNAC Junta del Acuerdo de Cartagena (Cartagena Compact)  MACA Ministerio de Asuntos Campesinos y Agropecuarios (Ministry of Rural and Agricultural Affairs) MEH Ministerio de Energia e Hidrocarburos (Ministry of Energy and Hydrocarbons) NEP National Energy Plan OLADE Organizacion Latinoamericana de Energia (Latin American Energy Organization) PERTT Programa Ejecutivo de Rehabilitacion de Terrenos de Tarija (Executive Program for the Rehabilitation of Land in Tarija) SEPSA Servicios Electricos Potosi S.A. (Electric Service of Potosi S.A.) SETAR Servicios Electricos de Tarija S.A. (Electric Service of Tarija S.A.) TGN Tesoro General de la Naci6n (General Treasury of the Nation) UDAPE Unidad de Politicas Economica (Economic Policies Unit) USAID United States Agency for International Development YABOG Yacibol Bogoc Transportadores, a subsidiary of YPFB involved in gas exports to Argentina and gas distribution in Eastern Bolivia YPFB Yacimientos Petroliferos Fiscales Bolivianos (Bolivian National Oil Company)  ABBREVIATIONS bbl Barrel bd Barrel per day BTU British thermal unit m3 Cubic Meter CFD Cubic feet per day MM Million GWh Gigawatt hour ha Hectare MT Metric Ton kcal Kilocalorie MW Megawatt kgoe Kilograms of oil equivalent MWh Megawatt hour ktoe Kilo tons of oil equivalent toe Tons of oil km Kilometer equivalent kW Kilowatt TPD Ton per day kWh Kilowatt hour GDP Gross Domestic Product bcf billion cubic feet PPF Project Preparation bbl barrel of oil (159 liters) Facility c.i.f. cost, insurance, freight CNG compressed natural gas f.o.b. free on board LPG liquefied petroleum gas MCF thousand cubic feet MMCF million cubic feet MMCFD million cubic feet per day MMBTU million British Thermal unit Conversion Factors - Calorific Product Density Cal.Equiv. (kcal/kg) LPG 0.55 11,834 Kerosene 0.798 11,128 Diesel 0.800 10,972 Fuel Oil 0.850 11,050 Crude Oil 0.745 11,507 Ton of Oil Equivalent - 10,000 Natural Gas (MCF) 263,356 kcal 1 kWh (generation) 2,867 kcal 1 kWh (consumption) 860 kcal  Conversion Factors - Natural Gas Product (ton) Number of MCF LPG 44.94 Kerosene 42.25 Diesel 41.66 Fuel Oil 41.96 Crude Oil 43.69 Ton of Oil Equivalent 37.97 Biomass Fuelwood 300 toe = 1,000 ton Charcoal 650 toe = 1,000 ton Bagasse 209 toe = 1,000 ton Electricity 86 toe/GWh Currency Equivalents Currency Unit: Bolivian Peso (Bs) Exchange Rate: Bs2.10/US$  TABLE OF CONTENITS Page EXECUTIVE SUMMARY ................... i I. THE ECONOMY AND ENERGY*****,.**......................... 1 Recent Economic Developments.................... ........ 1 Exports & Foreign Debt..*.*. ......................... 1 The Agricultural Sector.*,,,,*, ....................... . 3 The Industrial and Manufacturing Sector...***......... 4 The Mining Setr.............................4 Non-Factor Services o..o.. ....o.o.o..o.o............. 4 Impact of the Energy Sector.oo......oo.. ooo..o.......... 5 Energy Supply and ................. ... 90 9*0&4&G6. **0 6 Hydrocarbons .... o9.. .. ..............................0.. 6 Electric Power ............. 9 7 Biomasso.e.... o.9e* *oo.o.*... ooo.o..*........................ 8 Energy Demand Projections .............................. 9 Hydrocarbons .... 9 Electric Poe ......o11 Biomass ............o........00.... .................... 12 II. MACRO-ECONOMIC PROSPECTS AND THE ENERGY SECTOR......... . 13 Economic Development Alternatives . .. ..... 13 General Assumptions.. ............ .... ..... ... o 14 Hydrocarbons Subsector Investment and Production Scenarios .o.... ... .o..oo*o.....o... 9o............. ............. 15 Macro-Economic Analysis 99999999999999999999 17 Impact on GDP..o..o.... ......... ...... ,.......... 17 Hydrocarbon's Participation in GDP.. .................. 20 Final Demand Evolution.....9. e e 20 Impact on Exports..................................... 21 Impact on Balance of Payments.oo.ooo.o..o.... ........ 23 Conclusions. *ooo ..o.o..... .. O.. 26 III. ENERGY DEMAND MANAGEMENT ....................... .o.o.....o..o 27 Energy Pricing ..... ...-.........9.99.9..999999 27 Hydrocarbons.. .o ..................9999999999n 27 Electricity Tariffs................... 31 Marginal Cost Ana'ysiso o............. .9..... 31 Tariff Structure and Levelso.oo.oo................... 33 Pricing Strategyo... ........... 36 Petroleum Products .... . . ...........999.. 36 Natural Gasl... 999999999999999999999999999999999999999. 37 Electric Power ......... 0 .... .............. 37 Interfuel Substitution and Conservation................. 37 The Structure of Energy Demand .......................... 37 The Household/Commercial SecLor .............00 9990..... 38 Urban Areas .... o ................... . 38 Rural Areas.* ...o... ......o....... 0006-.0.................... 38  The Industrial/Mining Sector.......................... 42 The Transport Sector...... . . . . ............ *.... 43 Natural Gas Substitution Potentiai............$oo..... 45 Interruel Substitution and Conservation Strategy........ 47 IV. INVESTMENT AND TECHNICAL ASSISTANCE PRIORITIES*............ 49 Investment Pirte ......... *49 Petroleumn ..................... ........ ..e.. ............e 49 Natural Case*.***.*............................... 54 Electric Power........ .................... .......... . 56 Technical Assistance Priorities ......................... 5 V. INSTITUTIONAL AND FINANCIAL ISSUES ................ o ....... 60 Organization Structure............... ...... ... o.. o..... 60 Institutional Problems.... ...............e.... .....e....* 60 Hydrocarbonse................. .........................o 60 Electric Power ......... ... 63 Rural Energy ......... 67 Financial Situation ....... ..... ..*.. ......... ... o ..... 68 Hydrocarbons ................................ 68 Electric Power ................ 0.*** *0.*.. . ...... ... ... 70 Rural Energy.. . ... ....... ... *......o ...... .... 71 Institutional Strategy....99*.*.*..o99**..9**....... . 72 Natural Gs........................................... 72 Electric Power ...... ............ 73 Rural Energy ..9 . . 9 999. 73 TABLES 1.1 Hydrocarbons and the Trade Balance........................ 6 2.1 YPFB's Proposed Investment Levels as a Share of Total Public Investment Forecastso..... .... o eoo 19 2.2 Real GDP Growth Rates ..................................... 19 2.3 Hydrocarbon's Participation in GDP*........................ 20 2.4 Average Annual Real Growth Rates for Final Aggregate Demand Variables During the 1987-1995 Period ......... 21 2.5 Government Deficit as a Percentage of GDP. ................ 21 2.6 Exports of LPG and Crude Oil ............................... 22 2.7 LPG and Crude Oil Exports as a Percentage of Total Hydrocarbon's Exports.*,,** ......................... 22 2.8 Hydrocarbons Exports as a Percentage of Total Exports..... 23 2.9 Bolivia's Total Goods and Services Exports..............o.. 23 2.10 Trade Balance** .... oeo................................. oo......... ..... 23 2.11 Debt Service as Percentage of Exports..................... 24 2.12 Current Account Deficit as a Percentage of CDP............ 24 2.13 Capital Account Balance Surplus .................. ....... 25 2.14 Balance of Payments Exceptional Financing Requirements.... 25 2.15 Outstanding Foreign Debt Evolution Through December of Each Year .o ......... o.......e ...... o........... . . . 25  3.1 Domestic Prices of Oil Products and Opportunity Costs..... 28 3.2 Marginal Cost Estimates for 1990-1995..................... 31 3.3 ELFEC Distribution Marginal Cost Structure................ 32 3.4 ELFEC Retail Marginal Cost Structure for Average ................. ......... . ........ ..... .... ... ........... 33 3.5 Range of Retail Tariffs in Mills/kWh...................... 34 3ef Power Companies Tariffs and Rates of Return....,.......... 34 3.7 Relativity of ELFEC's Retail Tar,.ffs...................... 35 3.8 Comparison of Tariff Structure and HV Marginal Costs...... 36 3.9 Altiplano Economic Comparison of Household Cooking Fuels.. 39 3.10 Valleys Economic Comparison of Household Cooking Fuels.... 41 3.11 Tropics Economic Comparison of Household Cooking Fuels.... 41 3.12 Cost of Fuel per kcal..................................... 46 3.13 Impact of Price Difference between LPG and Natural Gas on Payback Period for Commercial and Domestic Consumers... 47 4.1 YPFB Current Fields Development Investment Program........ 50 4.2 Additional Reserves Required ...... ........e............. 54 4.3 Investment Requirements for 1987-1991,.09....... .0...... 56 4.4 Generation Expansion Program**..**.****..* .............. 57 5.1 ENDE's Forecasted Financial Performance..*................ 71 FIGURES 1. Supply/Demand Balance v.. Liquid Hydrocarbon............... 10 2. Balance Between Liquid Hydrocarbons Supply and Demand..... 18 ANNEXS I. PETROLEIJM ..o .............................. oeo............ 74 Struct:ure of Petroleum Demand ........................... 74 76 Exploration o*oo..oo.**ooeooo o.o..o.o.... .......................... 76 Rr....... e 77 Tables and Graphs .......... ......... O ........... * . 78 II* NATURAL GAS .............................................. 127 Overview .*.9,o... .0.0.0 ............. . .... ...... 127 Gas Domestic Market Regional Analysis................... 127 La Paz, rr ...................... 127 Cochabamba and Beni Pendo............................. 128 Santa Cruz-Camiri ..... .......................... ..... 129 Sucre-Potosio ...... ..... .... 0.0............... 129 Bermejo-Tarijo-Villamontes-Yacuiba.................... 129 Market Development Strategy........ -.. ............ g.... 130 Average Incremental Cost of Supply ..... 130 Priorities in Gas Usee..*o ............. 133 YPFB 5-Year Gas Substitution Program .................... 134 Long-Term Gas Demand Forecast ............. .......... 135 Tables and Graphs .......................... ........ * ... 138  III. ELECTRIC POWER ............................................ 150 Electric Demand Projections.. ............................ 150 The Central East Interconnection........................ 153 Background...... .e....... ..... ...................*o 153 .conomic Justification ........................ ...... 154 NeLback of Gas for Power Generation...................... 157 Marginal Electricity Costs.............................. 159 Power Generation........ ...... 999999999.9 ......... 9 99 159 Average Incremental Costs...o oo .....................o 161 Marginal Energy Costso.... o .........ee..oo 161 Marginal Capacity Costso ............................. 162 Transmission and Sub-transmission. .............o...oo.. 162 Distribution ................. ..... 163 Tables and Graphso..... 999999999999999999999999..999999 166 IV. RURAL ENERGYo..o ..... ..........o........o..... 196 Geographical Divisions ................. 196 Altiplano .... 999999999999999999999999999 . .... 197 197 Fuels for Cooking and Rural Industry .................. 198 Househ:ld Lighting ...................... 205 Ir9ig99........9 206 Other Uses.*** ....................... o9999 209 Regional Institutional Issues. ........................ 212 Recommendations o.o....oo.......e.............. 214 V 215 215 Overview .....9999999999999999999999.... 215 Fuels for Cooking and Rural Industry. ................. 215 Irrigation................. .........................* 221 Other Uses....o.. .... ......... 999999999999999999999 221 Regional Institutional Issues ......................... 223 Recommendations ....................................... 224 225 O..... 225 Fuels for Cooking and Rural Industry.................. 225 Irrigation ................... 9999999999 227 Other Uss....................228 Regional Institutional Issues .................... 228 Recommendations......*... .......................... 228 Tables and Graphs............ 230  EXECUTIVE SUMMARY 1. Bolivia is a net energy exporter and has a large energy resource base relative to its Rresent internal needs. Proven natural gas reserves are about 4.1 x 10u CF, equivalent to over 40 years at the current production level. However, liquid hydrocarbon proven reserves are limited by comparison, and reach approximately 124 million bbl plus 54 million bbl of probable reserve, with a possible imbalance between production and domestic demand in the next decade. Although Bolivia has an abundant economically exploitable hydropotential of nearly 18,000 KW, only a small fraction of less than 300 MW have already being exploited. Fuelwood resources are considerable with forests covering about half of the country, but mainly in the scarcely populated tropical lowlands, while the Altiplano inhabitants suffer from a century old shortage of fuel-wood, which has contributed to the area's total deforestation and substantial degradation of its soil. Bolivia has also some minor coal and peat resources (which are limited to local markets). 2. Bolivia's short-to medium-term growth prospects will depend critically upon hydrocarbons exports. While mineral exports dropped from US$641 million (63% of total exports) to US$263.8 million (38% of total exports) in the period 1980-1986 as a consequence of the international. tin prices crisis and internal administrative inefficiency plus sociaL instability, hydrocarbons exports increased from US$245 million (24% of total exports) to US$371 million (60% of total exports) in the same period. Just about all of these hydrocarbons exports in 1986 are natural gas sales to Argentina. Hydrocarbons have become the main source of hard currency, contributing over 50% to the Government's treasury income in 1986. In 1987, the Government assigned about US$170 million for invest- ments planned in the energy sector, which is almost 30% of the planned total public investment, in a period where the country is facing its worst economic crisis in the century. The public investment program is likely to be reduced by almost one-third, with energy, however, being the most resistant in the reduction. Per-capita GDP which is one of the lowest in Latin America, has fallen by about one-third since 1979 to US$560 in 1986. Inflation in the first half of 1985 was averaging 60% a month (equivalent to 28,000% a year), although in the last 18 months the current administration has taken strong measures to incentiva.e the economy and control successfully the inflation. In addition, Bolivia faces a difficult situation with its international debt, amounting to US$3.9 billion, over 5 times its exports of goods and services. Bolivian authorities have recently renegotiated its debt, and is paying about 60% of the service of the debt, or 35% of current total exports. 3. The major energy issues in Bolivia revolve around investment priorities, energy demand management and institutional problems. Although the country has a plentiful energy resource base, it has limited financial resources which must be allocated efficiently according to priorities. A list of technical assistance priorities is listed at the end of this summary.  Investment Priorities Petroleum 4. Field Development. Field development is the key short term investment priority in Bolivia's energy sector. While the oil and condensates production peaked in 1973 at 47,400 bd, it declined steadily to 17,600 bd in 1986 as a result of the depletion of various fields and because no new fields came on stream due to a lack of investments -reflecting the impact of foreign exchange shortages and insufficient exploration caused in particular by apparent lack of interest by the international petroleum industry. Liquid hydrocarbons exports, which reached 32,500 bd in 1973, were reduced to spot sales of naphtha and gasoline in 1980 and ceased altogether soon thereafter. Until now, Bolivia has been able to maintain an equilibrium in its internal supply/demand balance for petroleum products. 5. If the proposed field development investment program for the national petroleum company YPFB is carried out totalling US$245 million in a seven year period, Bolivia couid be self-sufficient with respect to its domestic supply/demand balance until 1995 according to the current YPFB data and will have a surplus of liquids which could be exported providing an additional needed revenue of about US$32 million p.a. on average, 1/ excluding LPG exports estimated at another US$20 million p.a. However, because of the great inconsistencies that exist in YPFB data, an in-depth revision is warranted. 6. Exploration. At the same time that oilfield developments will be carried out, exploration needs to be accelerated to maintain an adequate reserve/demand ratio. An additional 120 million bbls are estimated to be required for the period 1989-1997 assuming the projected demand and production for the period, and a 15 year reserve/demand ratio. By way of illustration, if exploration costs were in the order of US$7.50/bbl for liquid hydrocarbons as calculated by a consultant in a hypothetical case to preserve self-sufficiency, the magnitude of exploration investments f3r the period 1987-1997.required is estimated in the order of US$900 million. 7. A World Bank private exploration promotion Project Preparation Facility (PPF) has recently been initiated to evaluate the hydrocarbons potential. Following the results obtained, YPFB exploration activities should focus on low risk areas, while the high risk areas should be offered to private investors. For the short term, the following measures should be implemented: the opening of new areas to private sector companies for exploration contracts on reasonable terms requiring (i) extension of the 1972 hydrocarbon Law to authorize joint ventures; 1/ At a crude oil price of US$20/bbl.  - iii - and (ii) agreement on payments due to private contractors (Occidental and Tesoro). 8. In the short term, exploration contracts with the private sector could reduce the investment outlays otherwise required by YPFB in exploration. Such savings could be used to increase the production activities. 9. YPFB's 1987 planned exploration program amounts to US$45 mil- lion. IDB has a strong participation in exploration activities in Bolivia, financing US$80 million for the period 1987-1989. An additional, IDB loan of US$31 million is being negotiated. However, the magnitude of the exploration program required and the critical economic situation in Bolivia, emphasizes the strong need of private participation in exploration activities. Natural Gas 10. Natural gas is by far the most abundant energy resource in Bolivia and is a top priority in replacing the more scarce liquid hydrocarbons. YPFB has prepared a 5 year natural gas substitution plan (1987-1991) which aims for the replacement of 80% of the industrial consumption of liquid fuels in the main urban centers and a start in the conversion of commercial and residential consumers. The economics involved are discussed later in paras. 31-33. 11. For the time being, the only investment necessary concerns the development and expansion of natural gas transmission to major consuming areas estimated at US$16.8 million (US$6.4 million YPFB) for the period 1987-1991. 2/ To this one has to add the cost of converting to gas industrial consumers (about US$5 million for the three smelters plus US$2.5 million for the other industries), the cost of connections of industrial consumers (about US$2.5 million) and that of converting commercial and domestic users (about US$2 million). To attract private participation in natural gas distribution investments, a technical, financial, and economic evaluation is needed for each proposal, in addition to defining a plan for potential bidders. Contractual arrange- ments between YPFB and private firms also needs to be examined. Electric Power 12. A tentative five-year investment program for the power subsector was prepared, for a long-term power expansion plan is not available. The total investment required is US$181 million for the period 1987-1991. 2/ If exports to Brazil do materialize, then major investments will be required for that purpose.  - iv - 13. The required power generation investment amounts to US$76 mil- licn on the least cost expansion program prepared by the National Power Company (ENDE). The program is based on the addition of gas turbines in Santa Cruz. At a cost of gas of US$1/MCF at the plant, very few hydroelectric alternatives could compete with gas turbines. The most attractive hydroeleccric alternative is the proposed expansion of the Zongo River plant. The power generation system should be expanded using plants for peak load operations. In this regard, the rehabilitation of small hydro-stations now on use may be attractive, and the large hydroelectric projects now under consideration can be improved by lowering their designed plant factor. 14. Regarding transmission investments (US$29 million), the only major project considered by ENDE is the Central-Eastern interconnec- tion. It is important to commission the project by 1990 to reduce the need for expanding generation capacity and to allow the use of hydro- electric surplus, if any, in the Central-North-South interconnected system. The main benefits of the interconnection in the medium term would be to facilitate the development of additional thermal generation in the Santa Cruz area, where their performance is better, and avoid transporting natural gas to the Central Regions for power generation purposes. 15. Regarding substransmission, specific projects have been included to meet future demand with a total investment requirement of about US$8 million. An aggregate investment requirement for distribution was calculated at US$50 million for the 1987-1991 period taking into account the average cost per incremental peak demand at US$450/kW. Rural Energy 16. LPG was found to be the most economic household cooking fuel which, however, requires an improvement in its marketing arrangements. The Ministry of Energy and Hydrocarbons (MEH) with the rural cooperatives and corporations, need to design a distribution network wbich will allow the transport of LPG to rural areas at the fixed national price as recommended in paras. 21-22. 17. Investments into fuelwood plantations can not be recommended at this time due to the very high economic costs. The very high cost of reforestation in the Altiplano is attributed to poor growth of currently identifiable species, attributable to the relatively poor-quality of soil and dry climate found at an altitude of about 4,000 m. above sea level. For the Valleys, only if about 10% of the reforestation costs would be assigned for fuelwood purposes, then it could be economically competitive with LPG and kerosene. 18. Investment in rural electrification is recommended only where there is a productive use for electricity. In addition, small hydro- electric plants are recommended only in areas where there is an advantage over diesel.  19. Unconventional technologies, such as biogas, windpower, and solar energy, are expensive relative to the income of the rural household based on subsistence farming, and requires a social and technical environment that can only be brought through continuous technical support. The energy problem of the rural areas should be treated as a part of integral rural development programs considering the resource endowments of the region in question. Energy Demand Management Energy Pricing 20. Petroleum Products. Except for LPG (domestic use) and diesel oil (for power generation) which are subsidized mainly for social reasons, petroleum product prices are either considerably above opportunity cost or close to it. On the whole, there is no subsidy of oil products, with a weighted price of the composite barrel to the consumer equivalent to about 160% of the opportunity cost. 21. With respect to LPG, the opportunity cost, including distribution, is of the order of US$17/bbl against a price of LPG for domestic use of US$12.5/bbl. This is critical because LPG represents about 25% of the petroleum products sold in Bolivia, and it is the only product whose consumption is rising rapidly. The price of LPG should therefore be increased at least to its opportunity cost (about 30%). Government policy has been to subsidize LPG for the low income rural population which may not ha%a any other fuel alternative but animal dung or fuelwood. With that in mind, however, the rural population has actually been paying two or three times the price of LPG in the urban areas, due to high transport costs and an inefficient distribution system. A fixed national retail price at its economic cost should therefore be set, which would permit to subsidize the transport costs to the low income rural areas. The end result should be that the low income rural population will not be affected by the price increase. 22. By achieving a fixed national LPG retail price at its economic cost, the other domestic LPG prices for industrial purposes and vehicles should be eliminated. The existence of three simultaneous prices encourages fraud. Furthermore, in volume terms, more than 90% of LPG sold is for domestic use. . I 23. Regarding the subsidization of diecel oil used for power generation, this product represents only O.,% of products sales in Bolivia. The number of beneficiaries is small so that they are well identified. The subsidization could be rationalized by the fact that the bulk of power generation in Bolivia is hydro and gas-based so that diesel oil is used in remote areas, without any other power alternative.  - vi - 24. An important distortion exists regarding diesel and gasoline. While their retail prices are identical, the opportunity cost of diesel is about 35% higher than that of gasoline. Taking into account that about 60% of the diesel is used for transportation, measures should be considered to encourage, whenever feasible, the substitution of gasoline for diesel oil, including imposing special taxes and custom duties on diesel powered vehicles, trucks, and tractors (at present custom duties are identical at 20%). Increasing the price of diesel could have a negative effect for most of the food products are brought by road at already a high cost. 25. Natural Gas. The average incremental cost of gas (AIC) is considered low because most of the infrastructure for gas production and transport to the main markets already exists, and gas reserves are plentiful. The AIC is estimated in the order of US$0.65/MCF including exploration, operating costs, and minimal transport costs because most of the additional investments are required in more than 10 years' time. 3/ This is below the two current official prices for natural gas, for the power sector at US$0.88/MCF and one for the other consumers at US$1.76/MCF. 26. Oil and Gas Pricing Financial Viability. Oil and gas prices should also be sufficiently high to enable YPFB to recover costs. How- ever, in financial terms, oil and gas prices are barely sufficient for YPFB to recover its costs. Following the fiscal measures taken in 1986, a 65% tax on petroleum products is collected from YPFB (in addition to an 11% royalty) which has resulted in a tight cash flow situation for the entity (paras. 43-44). 27. Although the current policy to maintain natural gas prices relatively low to encourage further use of this abundant resource is commendable, retail prices per kcal are well below other alternatives and need to cover all financial costs (paras. 31-32). The AIC, including the finan- lal cost of gas by taking into account past investments, is estit d at US$1.50/MCF at city gate. In addition one would have to add a dli..ibution cost estimated at US$0.22/MCF for industrial consumers, and US$3.55/MCF for residential and commercial consumers. The tariff to be introduced depends on the density of consumers and the mix of industrial, commercial, and residential users. 28. Electric 'ower. The level and structure of electricity tariffs in Bolivia does rat reflect the real cost of this public service. The current bulk electricit rates for sales from ENDE to the distribution companies are well below their marginal costs (e.g., bulk tariffs to ELFEC have a demand charge of US$2.5/kW per month and 12 mill/kWh of 3/ If exports to Brazil materialize in addition to ALxgentina, the AIC may reach US$1.15/MCF, because of production costs due to greater demand and additional transport costs.  - vii - energy charge, while the marginal costs were estimated at US$8.9/kW per month and 14 mills/kWh respectively). On the other hand the current bulk electricity rates for mining and industrial consumers are well above their marginal cost (e.g., bulk tariffs to COMIBOL--La Palca are US$13.5/kW per month as demand charge and 40 mills/kWh as energy charge, with the same marginal cost previously mentioned. In addition, with respect to the retail tariff structure, it is also inverted, since those consumers with higher marginal costs (residential) are paying much less than consumers with lower marginal costs (industrial). ELFEC, Cochabamba's distribution company, average residential tariff is about 20-25 mills/kWh while the average marginal cost is about 69 mills/kWh. 29. The follor-'ng actions need to be taken in establishing an adequate power tariff structure: (i) first, carry out a reevaluation of assets for all the distribution and generatisn companies, in order to establish the real tariff base in each company; (ii) execute a detailed tariff study based on and consistent with the rate of return, cash flow, and marginal cost approaches for all generation and distribution companies; and (iii) implement the tariff structure based on actual marginal costs and taking into account the financial viability of the power companies. Interfuel Substitution and Conservation 30. Natural Gas. The single most important measure oriented to substitute liquid fuels in Bolivia is the utilization of natural gas. However, under all circumstances and considering the structure of demand, the potential for substitution by natural gas remains small. YPFB's five year substitution plan (1987-1991) aims at substituting by the end of the decade 1,200 bd of liquid fuels and 112 tons of LPG through the conver- sion of 250 industries, 750 commercial and 15,000 residential users. Consumption of gas would thus increase from 22.6 MMCFD in 1986 to 38.6 MMCFD in 1990, an average annual growth rate of 15%. Should the smelter resume their operations, the market would be higher by about 9 MMCFD. 31. The conversion of industrial and commercial consumers appears highly economic whereas the use of natural gas in the residential sector needs to be evaluated in more detail before the viability of this option can be established. Private participation should ensure economic viability of projects. 32. For industrial and commercial consumers, the payback period ranges from 19 to 436 days 4/ justifying the conversion to natural gas. However, for the residential consumers, even with the recommended increase in the price of LPG, the high cost of supply does not justify their conversion. Nevertheless, on some circumstances with a cross- subsidy from industrial consumers, a tariff could be elaborated taking into consideration the anticipated mix of consumers. 4/ Assuming current prices.  - viii - 33. Substitution of compressed natural gas (CNG) for gasoline and diesel oil is an interesting alternative. However, this is still in the study stage and would require many years to reach an impact at the national level. 34. Kerosene. In an economic comparison of household cooking fuels, kerosene was found to be an interesting alternative to LPG because of the lower former's transport and distribution costs to the rural areas. Currently, kerosene is almost only used for lighting purposes since the kerosene supply is restricted. However, kerosene seems to offer an interesting alternative which should be investigated further along with the program to improve the distribution of LPG in the rural areas. 35. Conservation. An audit of YPFB's internal consumption (10% of national petroleum product consumption) should be carried out. In the refineries alone, internal use and losses average 8% of the feedstock, notwithstanding the fact that they use increasing quantities of natural gas as fuel. A study to improve bagasse utilization should also be carried out, since the sugar mills require hydrocarbons for about 15% of their energy needs. Institutional Problems 36. The Ministry of Energy and Hydrocarbons (MEH) is responsible for formulating energy policies and for regulating the activities of the sector, except forestry which is under the responsibility of Ministry of Agriculture. These functions are carried out by two main departments within the Ministry, one responsible for hydrocarbons (DGH), the other for electric power (DINE). Overall sector planning is limited within the Energy Planning Unit (DEP) of the MEH. The Rural Energy Corporation (COFER), funded through the MEH, is responsible for rural energy and alternative forms of energy. Power tariffs and petroleum product prices are set by the MEH. 37. MEH is insufficiently equipped to exercise its functions and to coordinate the efforts necessary to successfully meet Bolivia's future energy needs. The creation of the DEP was a first step but it must be strengthened. This unit must be staffed with highly qualified personnel, equipped with analytical tools, and advised by outside experts during its initial years. Free flow of information to and from the energy companies and with the other ministries of economy and planning must be established. DEP, working together with strengthened DGH and DINE, would be in charge of proposing and evaluating energy strategies, scheduling programs and monitoring those that are implemented. It would also make sure that a proper link is establishad between economic objectives and energy, and would coordinate with the Ministries of Planning, and Agriculture and Rural Affairs.  - ix - 38. The current structure of DGH, DINE, COFER and DEP needs to be examined in detail. Most of these units are receiving enough funds to maintain basic office functions and nothing else. In the case of DINE, a political and legal solution should be worked out to give back DINE the responsibility for setting tariff rates. 39e Hydrocarbons. The national petroleum company YPFB is responsible for all phases of the hydrocarbons industry from exploration to drilling, production, refining, and marketing. YPFB has been engaging in operations contracts with foreign oil companies (Occidental and Tesoro). 40. YPFB's current situation is characterized by: (i) a high degree of centralization, featuring excessive concentration of decision- making authority to the top levels of management; (ii) overstaffing and duplication of functions; (iii) extremely slow and cumbersome administrative decision-making procedures; (iv) inadequate development and use of management information and other systems; and (v) poor coordinating and conflict resolution mechanisms between functions. 41. YPFB needs to be restructured to work under economic efficiency criteria. Five operational divisions (exploration and production; drilling and oilfields services; refinery; transport and marketing; and a new gas division (para. 42) should be set up along with four other general divisions (contracts, procurement, construction, and administration). 42. With respect to natural gas, there are three gas divisions: Yabog located at Santa Cruz (exports to Argentina, and transport and distribution in the eastern part of Bolivia), the Industrial Division located at Cochabamba (transport and distribution in the western part of Bolivia) and the Gas Division in Sucre (planning, tariffs, policy). There should be an attempt to unify those three divisions into one department in YPFB, to consolidate the functions presently fulfilled by the three groups at different locations. 43. The new tax structure (para. 26) appears to have had disastrous consequences for YPFB. The loss for 1986 was estimated at US$39 million, the investment program for that year was reduced to about US$50 million and it failed to comply with over US$18 million in debt service obligations. In addition, the accounting system is totally inadequate. YPFB's financial requirements need to be taken into consideration in the context of the ongoing review of the overall tax system. 44. An agreement between the Government and YPFB is urgent on realistic operating and capital budgets together with their corresponding financing plans. A reduction in YPFB's investment program will have adverse consequences. Development and enhanced oil recovery projects should ensure self sufficiency in petroleum products in the coming years and could provide a surplus for expsrts which is essential for Bolivia's economic recovery.  - K - 45. Electric Power. At the generation and transmission level, there are two companies responsible for the development and operation of generation and transmission projects. The National Electric Power Company (ENDE) is responsible for the programming, development, and transmission projects at the national level and for supplying energy to all distribution companies and some large mining and industrial consumers. The foreign owned private Bolivian Power Company (COBEE) is responsible for supplying energy to La Paz and Oruro markets, and for the operation of generation plants in that area, and is authorized to develop new generation projects at the Zongo River Basin. 46. In general, ENDE and COBEE are well organized and efficient. The deterioration of the financial situation and of their performance was due to external factors and not to inefficiencies in their operations. However, the lack of definition for the responsibility in the development of power generation projects at the national level has created problems for sector planning. The programming process needs to be strengthened and ENDE is the institution best qualified for directing this process and should be responsible for preparing the Power Development Program. Since COBEE's concession expires in 1990, a decision should be taken as soon as possible. The Government should evaluate carefully the alternatives before a decision is taken on not to extend the contract. Nevertheless, if the contract is not extended, COBEE's generation and transmission system should be transferred to ENDE. Regarding dist ibution, it should all be transferred to distribution companies. There is no need to burden ENDE with the sponsibility of developing part of their distribution system. 47. Rural Energy. There is virtually no coordination either on the national level or on the level of the regional development corporations with non-governmental organizations involved in rural development or with rural cooperatives. This lack of central government coordination has resulted in often sub-optimal investment decisions. 48. Inadequacies in the existing raral financing system for energy purposes should be investigated, and changes should be made to provide financing for small rural energy development projects, in line with priorities. Financing must be improved in the poorer regional areas which in fact may be in a much more critical fuel shortage situation. Technical Assistance Priorities 49. The following technical assistance activities should be given high priority so that critical problems in the energy sector can be tackled.  - xi - Within the MEH: 5/ (a) evaluate options to strengthen the policy and institutional framework and market arrangements for LPG in the rural areas, and carry out an energy demand analysis focussing en the use of LPG (paras. 3.2-3.3 and 3.41, 3.47, and 3.50); (b) establish an energy information system and develop and implement anaLytical tools to carry out energy planning, in particular, strengthen DINE's organization, methodologies and procedures regarding the setting of electricity rates and the development of data bases for power sector statistics (paras. 5.1-5.3 and 5.18); (c) review the current electricity tariff structure both at bulk and retail level, and prepare specific proposals for setting electricity rates for 1987-1990 (paras. 3.21-3.28); (d) carry out a study to improve bagasse utilization in the sugar mills (para. 3.56); and (e) determine efficiency of current wood and dung stoves in the Altiplano, and carry out an analysis of the economics of its substitution by hydrocarbons including kerosene (paras. 1.42- 1.43). Within YPFB: (a) develop and implement a petroleum supply management information system (MIS) optimizing the use of refineries and evaluating least cost supply options (para. 5.9); (b) develop and introduce in YPFB modern integrated accounting, budgeting and control systems (paras. 5.33-5.38); and (b) carry out an energy audit on YPFB's consumption of liquid fuels (para. 3.54). Within ENDE: (a) carry out a power system analysis of the interconnected system, including a stability analysis (paras. 4.32); (b) Review electricity demand projections for the industrial, mining and residential sectors for the period 1987-1995 (paras. 1.39-1.41); and 5/ All of these activities could be carried out under the proposed technical assistance in strengthening energy planning at the MEH.  I - xii - (c) Review procedures, methodologies, and organization in ENDE for project analysis (paras. 5.14-5.20).  I. THE ECONOMY AND ENERGY Recent Economic Developments Background 1.1 In the 1980's, Bolivia has been facing its worst economic crisis during the century, although in the last 18 months, the GOB has taken strong measures to reactivate the economy. Per capita GDP had fallen by one-third since 1979 reaching only about US$560 in 1986, which is one of the lowest in Latin America. GDP declined by 18% between 1980- 1986. Inflation in the first half of 1985 was averaging 60% a month (equivalent to 28,000% a year), and the deficit of the consolidated non- financial public sector had reached 24% of GDP in 1984. As a result of recent measures by the current administration, inflation has been controlled to about 20% for 1986. The economy had appeared to have done well in the 1970s when GDP growth averaged 5.4% until 1978. However, this growth was based in large part of foreign borrowing, and debt built up rapidly from a level of US$500 million in 1970 to US$2,400 million by 1980. This borrowing was not, on the whole, used productively, and when external creditors reduced lending in 1979-1980 the economy did not have the resources to service this debt. With foreign debt greater than GDP (1.04 ratio in 1985) the debt service rose from US$ 208.5 million to US$349.5 million between 1980 and 1985, representing 56% of total exports in 1985. The economy embarked on a downward spiral of falling investment, savings, exports, consumption and GDP. Inflation grew to unprecedented levels in Latin America, and the public sector deficit widened. The exchange rate appreciated in real terms as the Government made futile atteupts to maintain a fixed nominal rate system. Extreme price distortions opened up. Exports & Foreign Debt 1.2 Bolivia faces two particularly important structural difficulties for its external accounts; one is the size of its current external debt obligations, and the other is the structure of its exports. Bolivia's total external debt at the end of 1985 was US$3.9 billion,over 5 times its exports of goods and servic!s. These are among the highest such ratios for any country in Latin America, yet B^livia is one of the poorest. The interest on this debt was accruing at almost 9% of GDP in 1985, although most of this interest was not paid. The current account balance in 1985 was in deficit at a level of 9.2% of GDP even though the trade balance (in goods and non-factor services) was in surplus of 1.3% of GDP. 1.3 In 1986, Bolivian authorities negotiated the reschedule of multilateral and some of the bilateral external debt. After the negotiation, Bolivia drawed on from the IMF a Compensatory Financing Facility of SDR 64 million on a Structural Adjustment Facility to be  -2- received in three installments. Bilateral creditors (including suppliers' credits, which are mostly from official sources) are assumed to continue to reschedule through the Paris Club. Presently, Bolivia is paying its debt service to multilateral organizations and to some bilateral sources. However, Bolivia has not paid interest nor principal to commercial banks since March 1984. Currently, Bolivia is paying 60X of its debt service which consists of 35X of total export earnings. 1.4 Bolivia's ability to service its debt depends on its exports performance, but exports prospects are currently poor. The structure of Bolivia's exports is highly concentrated in natural gas and minerals, which are vulnerable to exogenous factors. On the other hand, estimates of the value of exports as a result of the informal economy, range up to the equivalent of Bolivia's total legal exports or well above, when valued in terms of revenues brought back into the economy. 1.5 Considering gas and tin, both of these goods face problems brought on by external events over the recent past. First, the international market for tin collapsed in October 1985. Trading ceased on the London Metal Exchange after the International Tin Council, which had kept prices stable in the 1980s, announced it had run out of funds to cover purchases it had contracted for on margin. Effective tin prices as of August 1986 were less than half of what they had been a year earlier. Second, the reduction in the international price of petroleum from an average of US$28 per barrel in 1985 to a range of US$8-16 per barrel for most of 1986, reduced the value of Bolivia's natural gas exports to Argentina. 1.6 Bolivia's natural gas exports are exclusively to Argentina through a pipeline completed in 1972 and under terms of a 20-year contract covering the period to May 1992. The price for the gas has come to be negotiated on an annual or semi-annual basis, and these negotiations have become increasingly difficult for Bolivia. In addition to the problems created by the collapse in oil prices, Argentina has also in recent years developed its own supplies of gas and no longer has a global requirement for the Bolivian gas. Although it continues to import the volume of gas as specified under the terms of the 1972 contract, 1/ the level of imports likely from 1992 onwards is quite uncertain. Continuation of the purchases, and on what terms, will be based on more than purely economic considerations. In the short term, the price issue is likely to dominate. At the April 1986 negotiations, the price of the gas was reduced by 12X from its 1985 levels, with effect from January 1. The new price of US$4.22 per thousand cubic feet 2/ is, however, still equivalent to about US$22-US$23 per barrel of oil on 1/ As subsequently amended in the late 1970s, when the volume was increased. 2/ Includes dry gas and condensates.  -3- energy equivalent terms. Partially offsetting the fact the current gas price is higher than the world price because of the recent decline in international prices, is the requirement that part of the gas in the order of 60% be paid by Argentina not in freely convertible foreign exchange, but in terms of Argentine goods on a counter-trade basis. Until Bolivia decides which Argentine goods to purchas), the gas receipts which must be dedicated to counter-trade accumulate without interest in a special account at the Argentine Central Bank. Because of these counter- trade restrictions, it cannot be said that Bolivia, in fact, receives a full US$1 of value for US$1 of recorded gas exports. The appropriate discount is not clear. However, even with this taken into account, it is likely Argentina will con,.inue to push for lower gas prices. Given Bolivia's dependence on gas exports, with 60% of its merchandise exports being this one commodity to this one customer, Bolivia can ill afford a major reduction. Argentinean authorities are currently negotiating new volumes and gas prices. 1.7 Polivia's exports suffered a third major shock in 1986 when a Government-sponsored effort led to the closure of some of Bolivia's clandestine cocaine processing laboratories. The long-term effectiveness of these interdictions is not yet clear, although the current government clearly intends to do whatever is possible to ensure their success. The extent of the illegal trade is also not clear, but estimates of its scale range to amounts of several times Bolivia's total legal exports. The Agricultural Sector 1.8 Although contributing only in the order of 20% of Bolivia's GDP, and about '2% of the country's exports, the agricultural sector is of fundamental economic and social significance to the country. The 1976 census has demonstrated that about 55% of the councry's total population live in rural areas and that 63% of the labor force are employed in the agricultural sector. The agriculture sector suffered a decline at the early 1980s which was worsened as consequence of the 1983 drought. In 1983, the agriculture sector output dropped by 26%. 1.9 With prospects of declining output in the mining sector and with not very clear potential external markets for hydrocarbons, the government is re-examining the role which agriculture may play in the country's foreign trade. In particular soybeans projects are in consideration as potential substitutes and complements to mineral and hydrocarbons export projects, in order to increase the foreign exchange. 1.10 The performance of the agricultural sector, however, is limited by a number of serious constraints and imbalances which are difficult to correct. The most serious of these are: (i) a concentration of population in areas of lowest productive potential; (ii) limited scale of national market; and (iii) high exporting costs.  -4- The Industrial and Manufacturing Sector 1.11 The industrial and manufacturing sector had also a negative growth during the 1980-1985 period as reflected by an average decline rate of almost 10%. This sector in Bolivia has ne er being very important in GDP formation as reflected by its percent shares reaching the highest levels in the 1970s and early 1980s in the order of 15% of GDP, and 9% in 1985. 1.12 The industrial sector in Bolivia has a series of adverse factors among which the most important are: (i) reduced internal markets; (ii) technological dependence from abroad; (iii) high composition of imported inputs; (iv) high production costs which in turn makes the output uncompetitive with imported products; and (v) after the new economic policy implementation, all the industrial policy incentives have been abolished by uniform and reduced tariffs to imported products and with the abolishment of tax redemption on exported products. The Mining Sector 1.13 During thA; 1980-1985 period, the mining industry has been affected not only by tC e international tin prices crisis but also by an inefficient administration, an artificially nigh local currency value plus social instabiLity. During the 1980-1986 period, and as a consequence of the previously mentioned adver . situations, the mining sEctor's participation on GDP has been on average 8%. Mineral exports dr3pped from US$641.2 million (63% of total exports) in 1980 to US$263.8 million (38% of total exports) in 1986. 1.14 After the 1985 liternational tin prices collapse, several mines have turned to be margii.al and uneconomic. As a result many mines have closeed leaving a number of some 30,000 workers unemployed over a total mining force of about 70,000 workers. Government has created an Emergency Social Fund which will finance projects of high social content which should help to reduce unemployment. Non-Factor Services 1.15 If growth was negative for the principal sectors of the economy, on the contrary, the non-factor services, commerce and financial sectors have incremented their share in GDP during the period. Whereas the tradeable sector of the economy (mining, hydrocarbons and industry) has declined its GDP share from 30% to 22%, the non-tradeable sector has incremented its participation from 70% to 78%.  -5- Impact of the Energy Sector 1.16 The possible economic outcomes due to alternative energy development strategies depend on interactions between the sector and the rest of the economy. The relative importance and the impacts of the energy sector in the Bolivian economy have been estimated at two different levels: (i) fiscaL policy; and (ii) foreign trade. 1.17 Fiscal Policy. As hydrocarbons became the main source of hard currency in a context of an overall production crisis, the sector has contributed to the Government's Treasury (TGN) with more than 50% of TGN's income in 1986. On the other hand regional governments, in oil producing regions, have received more than 90% of their income from royalties on hydrocarbons. 1.18 Until 1985, the National Petroleum Company (YPFB) was subject to the following system of taxes: (a) For domestic sales: (i) a 19% production tax for oil and gas; (ii) a 15% tax on the sale of transportation fuels (that is gasoline, avgas, and diesel); and (iii) a 12% tax on gasoline and diesel sales. (b) For exports: (i) a 15% export tax; and (ii) a 19% tax on production. In addition to the tax system above mentioned, YPFB pays an 11% royalty fee to regional governments of oil producing areas. 1.19 The above mentioned tax system to the hydrocarbons subsector, has been replaced on a temporary basis, by a 59% tax on exports and a 65% tax on domestic sales, in order to increase substantially the national fiscal income. This tax system has represented some US$365 million against US$165 million that would have been collected with the previous system (a net increment in taxes of more than 120%). On top of that, YPFB has paid some US$56 million to regional governments as royalties. Although those amounts have helped in a decisive manner in the economic stabilization program, they have also constrained the investment capability of the subsector. 1.20 Foreign Trade. The growing importance of the hydrocarbons subsector in the Bolivian economy may be reflected by pointing out that its participation in total exports has involved from 5.9% in 1970 to  -6- about 60% in 1986. Table 1.1 shows the increasing importance of natural gas in the total export market and the critical decline of oil production. Table 1.1: HYDROCARBONS AND THE TRADE BALANCE (USS million) 1975 1980 1985 - Petroleum Prod. Exports 111.4 24.2 1.9 - Natural Gas Exports 47.5 220.9 372.6 - Total Exports of Gcoods and NFS 505.0 1,023.6 712.9 - Total Imports of Goods and NFS 1/ 641.0 795.4 664.4 - Hydrocarbons as % of total exports 31.5% 23.9% 52.5% - Hydrocarbons as % of total imports 24.8% 30.8% 56.4% I/ NFS-Non Factor Services. Source: World Bank CEM of November 1986, and NEP estimates. 1.21 The hydrocarbons exports increased from US$158.9 million in 1975 to US$374.5 million in 1985. During the 1980-1985 period, YPFB generated almost 40% of the total foreign currency inflow to the country. In 1985, the current account balance deficit reached 9.2% of GDP, but excluding natural gas exports it would have reached 13.9% of GDP. 1.22 After the 1985 international tin prices crisis, the Bolivian trade balance is dramatically dependant on one product (natural gas) and on the willingness of one costumer (Argentina), which reveals the fundamental importance of the energy sector in the Bolivian economy. 1.23 The prospects for hydrocarbons exports are not so clear. Bolivia's export contract to Argentina will end in 1992 and it is expected that sales may not continue beyond that date. Although negotiations with Brazil are under way, prospects are not very clear and the failure to find a market for surplus gas may represent a major set- back. Energy Supply and Demand Hydrocarbons 1.24 Bolivia is more gas than oil-prone, and the largest liquids producer is a gas condensate field (Rio Grande). At present, about 62% of total liquids are produced from condensate, mostly by stripping gas of  - 7 - its liquid content at surface. The hydrocarbon developed rapidly in the 1960s and oil and condensates output continued to rise until it peaked in 1973 at 47,400 bd. and declined steadily to 17,700 bd in 1986 as a result of the depletion of various fields, and because no new fields came on stream due a lack of investments reflecting the impact of the foreign exchange shortage, and insufficient exploration caused in particular by apparent lack of interest by international oil industry. Oil exports, which reached 32,500 bd. in 1973, were reduced to spot sales of naphtha and gasoline in 1980, and have remained minimal thereafter. 1.25 Domestic demand for petroleum products in 1986 was about 21,300 bd. Demand grew during 1974-1978 at an average 11% p.a., grew at only 3.5% p.a. in 1979-1980, and declined by 9.4% p.a. in 1980-1986. Only LPG demand continues to grow at an average of 10% p.a. in 1980-1986, substituting for kerosene, electricity and to a minor extent fuelwood and dung. Gasoline (including avgas) now accounts for about 40% of total domestic consumption, diesel 20%, LPG 25%, fuel oil 4%, kerosene 4%, and jet fuel 7%. 1.26 The Bolivian market for petroleum products exhibits the following: (i) three products, gasoline, LPG and diesel oil account for more than 80% of products sales; (ii) the share of LPC--25Z is probably one of the highest in the world; and (iii) the transportation sector (gasoline and 60% of the diesel) accounts for in excess of 50% of products sales. The overall decline in petroleum product consumption reflects the severe recession which has affected the economy since 1980. 1.27 Until now, Bolivia has been able to maintain an equilibrium in its domestic supply/demand balance for petroleum products. This can be attributed partly to the decline in the economy. Had the tin smelters continued to operate, a shortage of fuel oil would have been almost unavoidable. Electric Power 1.28 In 1986, the installed generation capacity was about 553 MW, of which about 50% hydro and 50% thermal. The thermal capacity is composed of 134 MW (51%) in gas turbines, and 129 MW in diesel plants installed in small isolated systems and in self-producer plants. In terms of electricity production, in 1986, 75% was generated by hydro plants and 25% by thermal plants, of which, 91% in gas-fired thermal plants. 1.29 Regionally, the market comprises four major load centers: the Northern system (La Paz), the Central system (Cochabamba and Oruro), the Southern system (Potosi and Sucre) and the Eastern system (Santa Cruz); and several small isolated systems (Trinidad, Tarija, Villamontes, etc). The Northern, Central and Southern systems are interconnected and represented in 1986 about 66% of total electricity consumption in the country; the Eastern system, with 20% of total consumption, would be interconnected in the late 1980s; the small isolated systems, with 14%,  -8- are far away from the interconnected system, and their interconnection would not be justifiable in the short to medium term. 1.30 Regionally, the Central-North-South (C-N-S) interconnected system has an installed capacity of 342 1I of which only 50 MW in thermal plants; the Eastern system, 118 MW all in gas turbines; and about 3 other isolated systems, and microsystems (small communities with diesel engines) have and installed capacity of 112 MW, mostly in small diesel plants. 1.31 In 1987, the C-N-S system can meet its demand with hydro- electric generation, using only the gas turbines in emergency situation. The Central-South system is in a balanced situation, and the transmission line which link La Paz with the rest of the interconnected system serves as a reserve support for the Northern system. On the other hand, the Eastern, Trinidad, and Tarija isolated systems are operating with a very small capacity reserve and require further expansion of their generation capacity. Biomass 1.32 Biomass consumption in 1985 totalled 921t000 toe (45X of total national energy consumption), which is an increase from 838,000 toe (10%) from 1980. Most of the biomass in Bolivia is consumed in the rural areas, where introduction of commercial fuels has been restricted because of the subsistence family income levels, poor road system, and scattered nature of communities. 1.33 For the purpose of the National Energy Plan, Bolivia was divided into three climatological and geographical regions--Altiplano, Valleys, Tropics. Most of the dung consumed in Bolivia (160,000 toe) originates in the Altiplano, because of the lack of fuelwood and prohibitive costs of reforestation as a consequence of the poor terrain and climate at an altitude of about 4,000 m. For the Valleys, deforestation problems exist only in Tarija and the Province of Yamparaez, and for those specific areas, as in the Altiplano, the most cost-efficient policy choice for the short term would be to improve the delivery of LPG to those areas. In the Tropics, there is an abundance of fuelwood, although care should be taken with the expansion of the agricultural frontier and large amount of wood waste. 1.34 The Altiplano is the only region in Bolivia, where there is an overall critical imbalance between fuel supply and demand. In the Altiplano, the major household cooking fuels are dung and fuelwood with the supply of fuelwood decreasing. Approximately 210,808 toe of fuel- wood 3/ and 152,058 toe of dried animal dung were consumed as household 3/ No breakdown of fuelwood resources betweer trees and shrubs was possible.  -9- cooking fuels in 1985. Both are consumed in the two-pot "kery" stove (9- 14% thermal efficiency), unique to the Altiplano. These estimations were based -n an average fuelwood equivalent daily consumption per inhabitant in rural households of 2.05 kgs/person/day and the total rural population in the region. 4/ Much of the fuelwood used in the Altiplano is the shrub-thola, which burns very quickly and is slow growing although it is a hardy species which has grown relatively well in the Altiplano. However, because of the great demand, its supply in many parts is inadequate. Energy Demand Projections Hydrocarbons 1.35 Oil. Forecasting the supply/demand balance for petroleum products becomes a difficult task because of the lack of refining model and the blending of heavier cuts with gasoline. With the recently discovered oil fields Santa Cruz and Villamontes, Bolivia may be self- sufficient with respect to the internal demand of petroleum products until 1995 if the proposed YPFB investment program (paras. 4.2-4.4) is carried out. Table 1.2 below shows YPFB and the private contractors (Tesoro and Occidental) projected production curve in relation to the estimated domestic demand. Caution must be taken with these estimates, however, since large inconsistencies in data still exist in YPFB. Since negotiations are still underway between YPFB and the private contractors on payments due to the private contractors, it is assumed that the production of the latter will eventually phase out because of the end of the life of the reservoir. For 1987 and 1988, the Penia and Rio Grande oil fields, followed by Villamontes and Santa Cruz, will provide about 56% of the national production. The production curve shown has two peaks, in 1989 at 11 MMbbl and in 1993 at 10.5 MMbbl. Annex 1 shows the projected production by field. 1.36 Projected increases in domestic petroleum consumption would largely depend on the strength of the economic recovery in Bolivia following several years of severe recession. It is anticipated that a modest economic recovery will take place beginning in 1987, and petroleum product domestic prices will be maintained in real terms reducing unauthorized exports of hydrocarbons and encouraging energy conservation. in addition, by increasing the supply of gas and improving the infrastructure for its transportation, the substitution of petroleum products should keep increasing by 1,200 bd by 1990. Under these 4/ Approximately 45% of the rural population in the Altiplano was assumed to consume primarily fuelwood (tree species and shrubs) for cooking, 35% dried dung, and 20% hydrocarbons (mostly LPG). Consumption estimates include fuelwood equivalent of all fuels.  - 10 - assumptions, projected domestic demand for petroleum products by around 1990 would be about 24,000 bd, representing an annual growth of about 3.6Z. By 1997, petroleum product consumption is estimated at about 32,000 bd, following the same assumptions. 1.37 Natural Gas. A 20 year YPFB gas demand forecast prepared on a sectoral basis indicates that by 2005, the main uses of gas would be for power generation (about 45%), industry (about 30%) and YPFB (about 15%). The share of the commercial and domestic sectors would therefore remain small. Overall consumption is estimated at 265 MMCFD. Figure 1: SUPPLY/DEMAND BALANCE OF LIQUID HYDROCARBON 10 - 7 1987 1908 1909 t990 1991 1092 1993 1994 1998 1996 1997 0 1 + 2 O 3 A 4 1/ Diomestic petroleum product demand without YPFB's 5 year gas substitution plan. 2/ Domestic petroleum product demand considering YPFB's 5 year gas substitution plan. 3/ YPFB's production according to the investment program, and including transfer of Escond;do field from Tesoro to YPFi. 4/ YPFB's production without Escondido. 5/ Total production including Tesoro and Occidental. 6/ Because of large Inconsistencies in YPFB data, a further in-depth review of data is needed. Source: YPFB and NEP estimates.  - 11 - 1.38 Over 1986-2005, one can anticipate the cumulated domestic demand for gas to be of the order of 0.9-1.3 TCF depending on develop- ments in the economy. This represents about 25% of Bolivia's proven reserves of 4 TCF. Should Bolivia continue to export about 215 MMCFD (to Argentina and/or Brazil) during the same period, that consumption would represent about 1.6 TCF. Thus it would use about 75% of its proven reserves in the next 20 years. It is only if potential exports beyond 1991 exceed 300 MMCFD that there would be grounds for concern regarding Bolivia's reserves. But since Bolivia's gas reserves are thought by all to exceed 4 TCF by a considerable margin, higher exports would only entail an effort to confirm probable reserves, and possibly undertake more exploration in gas prone areas. Electric Power 1.39 There are major uncertainties related to the projection of electricity demand, mainly the future of the mining sector and the impact of gas substitution and electricity rate increases on industrial and residential consumption. ENDE is now projecting a rate of growth of 5.8% p.a. for total electricity consumption for tbe period 1985-1991 based on the assumption of a 9.5% annual rate of growth for the residential sector and a drop in the consumption of the mining sector. The rate of growth projected for the Eastern system is about 12.5% p.a. The projected rates of growth are considered reasonable and adequate for planning the expansion of the power system at this time. However, further studies are necessary to analyze the case of the mining sector and the potential impact on residential and industrial demand of substitution of natural gas for electricity, and the impact on residential demand of the projected increases in electricity rates. The rate of growth for total consumption projected by ENDE is estimated at 6.3% for 1990-1995. 1.40 There are three factors related to electricity demand that should be analyzed further and monitored closely in the future. First, electricity demand in the mining sector should be studied based on the end use of electricity in this sector and on specific plans for the operation of existing mines. This is important, for a major portion of electricity consumption in this sector is related to support services (camps, etc). Second, substitution of natural gas for electricity at smelters (ENAF) and residential (water heating and cooking) should be assessed. Third, the rate of growth of demand in the Eastern system, now projected at 13% p.a. for 1986-1990, should be studied further based on realistic plans for connection of new consumers, an analysis of annual consumption for new consumers, an assessment of the price elasticity of demand in light of projected electricity rate increases, and an analysis of saturation of demand in existing high-income residential consumers demand. Furthermore, it would be important to analyze the economic potential for load management programs in order to shave the peak load. 1.41 As long as the opportunity cost of gas keeps around US$1/MCF, the power sector would have a lot of flexibility to adjust power supply to changes in demand at a reasonable cost, and the demand projection  - 12 - would not be so critical to take generation expansion decisions. In effect, under these conditions, the least cost solution would be gas turbines, which require a short lead-time (one to two years), have a low capital cost, and can be developed in modules adapted perfectly to demand growth. Furthermore, in case of emergency, jet type turbines could be installed in short notice. This does not imply that medium and long term growth of demand would not affect major strategic decisions like the expansion of gas transport capacity, the strengthening of the transmission system, or the sizing of new generating units. Biomass 1.42 In general, the Altiplano is the only critical region in fuel supply and demand. Only specific cases in the Valleys exists (paras. 3.44-3.46). Estimates of fuelwood supply in the Altiplano show that given projections of fuelwood consumption and estimated growth rates, there will be roughly a 6% decrease in 1992 from the estimated total supply of fuelwood in 1987. 5/ Dung supply is assumed to grow with projected demand, although shortfalls in fuelwood supply could put pressure on the portion of dung used as fertilizer. Fuelwood supply is most critical in the department of Oruro. Some areas of Oruro near Lake Poopo use dung alone as household cooking fuel, and there is some evidence that cultivated land is being deprived of natural fertilizer as a result. 1.43 Projections for dung consumption in the Altiplano through 1992, based on expected population growth, showed a demand in 1992 of 169,640 toe, an increase of almost 8% over the expected demand for 1987. There have been no studies in the Altiplano relating the consumption for dung as cooking fuel to nutrient (fertilizer) deprivation of farmland. Such deprivation could result in restrains on additional production of agricultural products, or, if fuelwood supplies are very low, insufficient fertilizer for present production. For the purposes of the current study, it has been assumed that the supply of dung exactly meets demands for cooking and fertilizer, and that projected increases in dung demand will be met by increases in animal stock. This must be confirmed through further study. If there are deficits in fuelwood supply, the subsequent need for additional cooking fuel could come from dung currently used for fertilizer in the Altiplano. This relationship requires further evaluation before definitive conclusions can be reached on the impacts of fuelwood shortages in the Altiplano. There is reason to believe, however, that in areas where there is a deficit of fuelwood, and where dung is used as a substitute cooking fuel, agricultural productivity will eventually suffer from deficits in supplies of natural fertilizer. 5/ Using an average growth rate for tree species in the Altiplano assuming thola supply constant.  - 13 - II. MACRO-ECONOMIC PROSPECTS AND THE ENERGY SECTOR Economic Development Alternatives 2.1 One of the most important bottlenecks for economic development in Bolivia is its ability to generate hard currency in order to import capital and intermediate goods necessary to pursue economic growth. In this respect, it is important to allocate resources to those sectors that will expand the country's export horizon. 2.2 The hydrocarbons subsector is one with good possibilities in helping Bolivia's economy in a decisive manner through exports of crude oil, LPG, and natural gas. Therefore, well planned actions should be conceived in order to exploit this subsector in the best possible way, taking into account both external and internal constraints. 2.3 It is highly probable that economic development in Bolivia will be, at least in part, based in hydrocarbons into the 1990s. Means of transferring economic surpluses from this sector to allow other sectors' development should be planned in such a careful way that the hydrocarbons development itself may be assured. Other important sectors in future exports performance may be agriculture and mining. 2.4 Considering Bolivia's future in the present decade, the agri- culture sector may probably play an important role. It is expected that agricultural products such as soybeans, tea, coffee, nuts, and wood will grow rapidly, generating export surpluses. In terms of hard currency generation, however, these products may have limited possibilities as compared with those of present natural gas exports. 2.5 With respect to the mining industry, which has been the traditional hard currency generator in Bolivia's economy, its future role may not be as important as in the past, due to external factors. This fact is reflected by the change .n its relative importance in foreign trade as compared with the hydrocarbons subsector in the recent past. Its future export possibilities are presently limited and major changes, both externally and internally, must occur before the mining industry recovers a prominent role in Bolivia's economy. 2.6 Predicting future economic performance in a context in which several unpredictable non-economic variables (as in the case of possible natural gas export agreements), or some economic non-quantifiable variables (as the case of the presumably large Bolivian informal economy), may take place, makes it extremely difficult. 2.7 Nevertheless, a macro-economic model developed by the Unidad de Analisis de Politicas Economicas (UDAPE) has been utilized. Using various energy investments, production, export, and import levels, if any, the model is capable of demonstrating the impact of the energy  - 14 - sector in the Bolivian economy. Although the model does not include the effects of the informal economy, the obtained results may indicate what strategies should be encouraged within the energy sector in order to obtain the best possible macro-economic outcomes. General Assumptions 2.8 The main assumption of the macro-economic model, for sectors other than energy, are those of the IMF's Structural Adjustments Facilities (SAF) document prepared for Bolivia. A major assumption is a slowly but steady recovery of international mineral prices, i.e., for tin concentrates, an evolution from US$2.55/pound in 1987 to US$4.77/pound in 1992, has been considered, while export volumes change from 3,352 MT to 4,072 MT during the same period. 2.9 The energy sector is considered in the macro-economic model through hydrocarbons investment and production scenarios, and through planned electric power investment levels which are those necessary to implement the power expansion program discussed in Chapter V. The investment figures do consider expansions on the generation, trans- mission, subtransmission, and distribution systems, sufficient to match the forecasted demand with adequate reliability levels. Although an in- depth revision of the power expansion program will be carried out in the near future, the investment requirements probably will not differ sub- stantially with those considered in the present analysis, which are summarized in Annex 1. With respect to electric power production levels, they are not considered explicitly in the macro-economic model, although they could be assumed as those sufficient to match the forecasted demand estimated elsewhere in the present document. Energy for the rural areas is considered implicitly within the model. Therefore, no investment levels, nor production patterns, are needed as assumptions for the analysis. 2.10 General assumptions for the hydrocarbons subsector, which are common for the four scenarios considered below, are as follows: (a) Hydrocarbons Internal Demand. The demand for internal petro- leum products has been considered as that with no natural gas substitution. The effect of an aggressive natural gas substitution program will lead to lower petroleum demand levels, but the effect of a possible economic reactivation performance in the Bolivian economy will probably compensate that demand reduction and, therefore, no further adjustments have been done for the present analysis. (b) Hydrocarbons Foreign Trade. Concerning export markets for hydrocarbon surpluses, only natural gas, LPG, and crude have been considered. Although negotiations regarding natural gas volumes and 'export prices to Argentina are already in progress, some assumptions have been made. Those estimates should not be considered as the recommended levels, nor as the most likely  - 15 - outcomes of the negotiations between Bolivian and Argentinean authorities, and were taken only for analysis purposes. The main assumption concerning natural gas exports to Argentina is that the combined effect of volumes and prices will represent to the Bolivian economy a stream of foreign currency inflows of US$244 million p.a. between 1988 and 1991, decreasing to US$128 million p.a. in 1992, to be continued by a constant level of US$73 million p.a. from 1993 to 1995. No natural gas exports to Brazil have been included in the model. 2.11 LPC marginal surpluses, until 1989, are assumed to be exported to the Brazilian border as normally happens. After the commission of the Vuelta Grande recycling plant project in 1989, and after new LPG production and transport facilities are completed, net surpluses are also assumed to be exported to Brazil. In all cases, the considered border price has taken to be of US$21.9/barrel, which is the present price for Bolivian exports. Although the Santos c.i.f. price of LPG is in the order of US$13/barrel due to high transportation costs to the Mato Grosso area, it is worthwhile for the Brazilian economy to buy Bolivian LPG at the above-mentioned price. Crude surpluses have been considered to be exported at a border price of US$20/barrel. If crude imports would take place, the border import price assumed for those cases is of US$30/barrel. Hydrocarbons Subsector Investment and Production Scenarios 2.12 Four different scenarios have been considered for the present analysis. The two first cases may be seen as production targets which, if feasible, will allow the country exportable crude oil surpluses. In both cases, a high private participation is anticipated. A third case is considered, in which no private participation occurs and where no investment for exploration activities take place. In the fourth case, investments in developing existing fields are curtailed because of financial constraints. 2.13 The aim of considering those cases is to analyze the macro- economic impacts of different investment and production patterns in the oil subsector. There is no intention to point out any of the considered cases as the most likely, nor as the recommended one. (a) Case 1. A public investment level of US$1.35 million is considered for the period 1987-1995, while private participa- tion during the period is assumed to be of US$983 million. This includes an exploration program (around US$900 million) to be shared in equal terms by YPFB and private companies, which would allow a constant reserves to demand ratio of 15 years. Investment on field development in YPFB is divided in US$274 million for existing fields plus US$334 million for developing new fields. For private companies, investment in field development is set at US$334 million.  - 16 - The expected production level estimated for YPFB amounts to 92.2 million bbl for the period 1987-1995, which is divided in 73.1 million bbl correspending to the production of already existing fields while the balance corresponds to new discoveries. This YPFB production forecast has its peak at 13 million bbl in 1993. Private companies are assumed to reach a peak of 5 million bbl in 1994, and a total production of 29 million bbl for the 1987-1995 period. The production estimates, both for YPFB as well as for private companies, have been calculated taking into account known technical characteristics of existing fields, and considering a high probability of finding oil fields with low associated natural gas. Due to the gas prone nature of Bolivian oil fields, this production forecasts may be considered as an upper bound. (b) Case 2. This scenario considers the same investment pattern of the previous case 1, but assumes a different production level. The production estimates, both for YPFB as well as for private companies, have been calculated taking into account known technical characteristics of existing fields, and considering that new discoveries may have high associated natural gas contents which may not allow an optimum oil production program due to limited natural gas markets. The estimated production level for YPFB amounts to 84.4 mil- lion bbl for the period 1987-1995, which is divided in 73.1 million bbl corresponding to the production of already existing fields while the balance corresponds to new discoveries. This YPFB production forecast has its peak at 11.8 million barrels in 1993. Private companies are assumed to reach 3.6 million bbl in 1994, and a cumulative production of some 22.6 million bbl during the 1987-1995 period. (c) Case 3. A reduced public investment level of US$465 million is used for the period 1987-1995, while new private participation during the period is considered to be non-existent. In this case, no exploration activities are assumed while investment for field development at YPFB (US$274 million) are exclusively for already existing fields. The estimated production level for YPFB amounts to 73.1 million bbl for the period 1987-1995. Private companies are assumed to reach a peak in 1987 with 1.7 million bbl, and will have a total production of 5.4 million bbl in the 1987- 1995 period.  - 17 - The production estimates, both for YPFB as well is for private companies, have been calculated taking into account known technical characteristics of existing fields. No new discoveries have been considered. (d) Case 4. A further reduced public investment level of US$256 million is considered for the period 1987-1995, while new private participation during the period is considered to be non-existent. In this case, no exploration activities are considered while investment for field development at YPFB (US$161 million) is not sufficient to exploit even already existing fields. The expected production levels estimated for YPFB amounting to 62.9 million bbl for the per.od 1987-1995. Private companies are assumed to have a production level that will reach a peak of 1.7 million bbl in 1987, and a total production of some 5.4 million bbl in the 1987-1995 period. The production estimates, both for YPFB as well as for private companies have been calculated taking into account the invest- ment curtailments considered. 2.14 Figure 2 below summarizes the liquid hydrocarbons production patterns for the four scenarios. Macro-Economic Analysis 2.15 A comparative analysis of the macro-economic implications that result from the four scenarios is presented in order to help decision- makers find the best energy sector alternatives, towards obtaining the best poqsible national economic performance. 2.16 The macro-economic impacts of energy sector growth alternatives have been measured using the following indicators: impact on CDP, final demand evolution, impact on exports, and impact on balance of payments. Impact on GDP 2.17 The hydrocarbons sector may have an important effect on the economy through public and private investment depending upon the success of these investments in reaching significant levels of production.  - 18 - Figure 2: BALANCE BETWEEN LIQUID HCU SUPPLY AND DEMAND 6/ 17 - 1 5 14 - 13 - 12 10 7 0 I1907 1960 1909 1990 1991 1992 199.R 1994 1995 Ui I + 2 * 3 A 4 a 1/ Domestic Demand. 5/ Case 1 - Production. 3/ Case 2 - Production. 4/ Case 3 - Production. 5/ Case 4 - Production. 6i/ Because of large inconsistencies in YPFB data, a further in-depth review of data is needed. Source: YPFB and NEP estimates.  - 19 - 2.18 It is important to note that YPFB investment is fixed within the public investment ceiling specified in SAF's forecast. According to it, Bolivia's public investment would grow from US$259 million in 1987 to US$440 million in 1995. In cases 1 and 2, in which YPFB is assumed to invest US$150 million per year in real terms, hydrocarbons would be the sector with the highest priority within the national public investment plan given its investment share. On the other hand, if YPFB investments are those of cases 3 and 4, then hydrocarbons would rank below agri- culture, mining, and transportation in the national investment plan. Table 2.1: YPFB'S PROPOSED INVESTMENT LEVELS AS A SHARE OF TOTAL PUBLIC INVESTMENTS FORECASTS 1987 1989 1991 1993 1995 Total Public Investment (in USS million) 259 308 362 399 440 YPFB Share case 1 58% 48% 41% 38% 34% YPFB Share case 2 58% 48% 41% 38% 34% YPFB Share case 3 58% 23% 6% 6% 5% YPFB Share case 4 58% 11% 2% 0% 0% Source: NEP estimates. 2.19 In cases 1 and 2, high public and private investments in hydro- carbons, associated with high production levels, lead to higher economic growth rates than in cases 3 and 4, in which YPFB's investments are set to a minimum level and no private investments are required. Table 2.2: REAL GDP GROWTH RATES (%) 1987 1988 1989 1990 1991 1992 1993 1994 1995 Case 1 3.3 3.6 5.8 4.0 5.0 4.5 5.5 3.9 2.4 Case 2 3.3 3.6 5.8 3.8 4.4 3.9 4.9 3.9 2.2 Case 3 3.3 3.6 4,9 3.5 3.6 3.2 3.9 2.9 3.1 Case 4 3.3 3.3 4.9 3.6 3.5 2.7 2.6 3.2 3.2 Source: NEP estimates.  - 20 - 2.20 Real GDP grows faster between 1990-1993 in case 1, as compared with the other three cases, showing the impact of higher investment levels on production. These growth rates are significant, given that they respond to changes in only one sector of the economy. However, even with the expected GDP's high growth rates of case 1, the living standard of the country's population is not expected to improve significantly, as measured by GDP per capita, which grows from US$520 in 1987 to US$652 in 1995. Hydrocarbon's Participation in GDP 2.21 The results reflect the expected differences on hydrocarbons economic importance, dua to different sectoral investment strategies. Those cases in which reduced oil subsector investment are considered not only may lead to minor participation in GDP's formation, but also may burden national finances through the need of importing crude and condensates, which in some cases may represent amounts as high as US$100 million per year. Table 2.3: HYDROCARBON'S PARTICIPATION IN GDP (%) 1987 1989 1991 1993 1995 Case 1 6.97 8.79 9.37 11.52 10.05 Case 2 6.97 8.79 8.66 9.90 8.26 Case 3 6.97 8.03 7.06 6.78 4.91 Case 4 6.97 7.77 6.79 4.88 3.71 Source: NEP estimates. Final Demand Evolution 2.22 As explained before, the assumptions of national public and private investments are considered constant according to SAF's fore- casts. Investments in the energy sector were modified within the overall public investment target. Also, public consumption forecast is not modified from SAF's results. Three important components of the final aggregate demand are changed in every case, as a result of the scenarios presented: real exports, imports, and private consumption.  - 21 - Table 2.f AVERAGE ANNUAL REAL GROWTH RATES FOR FINAL AGGREGATE DEMAND VARIABLES DURING THE 1987-1995 PERIOD (%) Case 1 Case 2 Case 3 Case 4 Public Consumption 3.5 3.5 3.5 3.5 Private Consumption 4.2 3.7 2.8 2.8 Public Investment 6.8 6.8 6.8 6.8 Private Investment 7.2 7.2 7.2 7.2 Exports 4.3 4.2 4.0 3.8 Imports 6.0 5.5 4.7 4.5 Source: NEP estimates. 2.23 Estimated economic growth for the considered cases, as measured by their GDP growth rates, imply that, on average, import annual growth rates may have to be greater in cases 1 and 2 than in cases 3 and 4. In turn, that implies that private consumpcion for the first two cases is higher than for the last two, taking also into account that aggregate investments and savings are greater for cases 1 and 2 than for cases 3 and 4. Also, real exports growth rates are greater for those cases with higher investment levels in hydrocarbons (private and public) than for the other two with small investment. On the other hand, better GDP growth rates and export performance for cases 1 and 2 may lead to smaller fiscal deficits in those cases, as compared to scenarios 3 and 4. Table 2.5: GOVERNMENT DEFICIT AS A PERCENTAGE OF GOP 1987 1989 1991 1993 1995 Case 1 3.52 2.96 1.56 0.74 1.11 Case 2 3.52 2.96 1.72 1.12 1.53 Case 3 3.52 2.99 2.10 1.84 2.31 Case 4 3.52 2.99 2.16 2.26 2.60 Source: NEP estimates. Impact on Exports 2.24 Different investment scenarios have important effects on crude and condensates production levels, thus on export possibilities of this product during the following years as can be seen in Table 2.6.  - 22 - Table 2.6: EXPORTS OF LPG AND CRUDE OIL (In Current USS Millions) 1987 1989 1991 1993 1995 Case 1 14 116 138 1W0 135 Case 2 11 113 115 142 80 Case 3 11 96 71 66 (21)* Case 4 7 79 51 (13)* (100)* * Imports. Source: NEP estimates. 2.25 Case 1 presents important export revenues for the country, as compared to the other three cases. In cases 3 and 4, in which no private investment is assumed, imports of crude oil may begin in 1995. The contribution of exports revenues in cases 1 and 2 is important, parti- cularly in the context of decreasing natural gas exports as it was assumed earlier. The expected shares of LPG and crude oil in total hydrocarbon's exports are presented in Table 2.7. Table 2.7: LPG AND CRUDE OIL EXPORTS AS A PERCENTAGE OF TOTAL HYDROCARBON'S EXPORTS 1987 1989 1991 1993 1995 Case 1 6 34 38 72 75 Case 2 4 34 34 66 52 Case 3 4 30 24 47 0 Case 4 3 26 18 0 0 Source: NEP estimates. 2.26 As expected, the negative effect of decreasing natural gas exports is reduced in cases 1 and 2 because of the export surpluses of LPG and crude oil generated by higher production levels. Nevertheless, hydrocarbon's share in total Bolivian exports after 1992 would, in any case, considerably be reduced. That means that even under the most optimistic crude export scenario, not finding new natural gas export markets may represent a major setback to the Bolivian foreign trade. 2.27 Hydrocarbons total exports decrease in every case, starting in the early 1990s, and lose relative importance against non-traditional and mineral exports.  - 23 - Table 2.8: HYDROCARBONS EXPORTS AS A PERCENTAGE OF TOTAL EXPORTS 1987 1989 1991 1993 1995 Case 1 43 45 39 25 17 Case 2 43 44 38 21 14 Case 3 43 43 35 15 5 Case 4 42 42 33 7 0 Source: NEP estimates. Table 2.9: BOLIVIA'S TOTAL GOODS AND SERVICES EXPORTS (USS million--c.i.f values) 1987 1989 1991 1993 1995 Case 1 583 760 928 1,058 1,229 Case 2 580 756 901 1,003 1,116 Case 3 580 740 851 917 1,051 Case 4 576 723 828 826 960 Source: NEP estimates. Impact on Balance of Payments 2.28 The Trade Balance and Current Account Situation. The trade balance situation is clearly more favorable for cases 1 and 2 than for the other two cases. This is the result of a less depressed export performance in the first two cases, even though these two cases have greater import growth rates, which are in accordance with their GDP growth rates. Table 2.10: TRADE BALANCE (US$ millions f.o.b.) 1987 1989 1991 1993 1995 Case 1 (146) (57) (45) (136) (158) Case 2 (148) (61) (57) (152) (174) Case 3 (148) (67) (75) (169) (203) Case 4 (153) (80) (91) (217) (258) Source: NEP estimates.  - 24 - 2.29 The most favorable export situation of cases 1 and 2, in relation to the last two cases, contributes to improve the current balance situation in spite of growing debt services obligations in every case. Debt service to exports ratio for all cases is as follows in Table 2.11. Table 2.11: DEBT SERVICE AS PERCENTAGE OF EXPORTS 1987 1989 1991 1993 1995 Case 1 44.95 42.50 60.05 71.39 68.49 Case 2 50.15 42.71 61.82 75.84 72.22 Case 3 50.15 43.65 65.47 83.02 80.14 Case 4 50.54 44.68 67.27 92.13 87.69 Source: NEP estimates. 2.30 The current account balance as percentage of GDP is an important indicator to evaluate the balance of payments performance. In the obtained results, the deficit in the current account is lower for those cases wit higher private and public investment (case 1 and 2) than for the other two, as may be expected, giveii the better exports and better debt service situation in the first two cases. Table 2.12: CURRENT ACCOUNT DEFICIT AS A PERCENTAGE OF GOP 1987 1989 1991 1993 1995 Case 1 9.17 8.51 8.34 8.90 8.29 Case 2 9.23 8.59 8.65 9.34 8.09 Case 3 9.23 8.75 9.19 9.98 9.49 Case 4 9.34 9.05 9.57 11.09 10.55 Source: NEP estimates. 2.31 Capital Account. The direct impact of foreign investment is reflected in the capital account balance. Thus, case 1 and 2, for which private investment of foreign companies have been specified, present a far better position than cases 3 and 4, in which no private foreign investment is assumed. The assumption of foreign lending does not change, in any scenario and are those of SAF's forecast.  - 25 - Table 2.13: CAPITAL ACCOUNT BALANCE SURPLUS (Deficit--USS Million) 1987 1989 1991 1993 1995 Cases 1 and 2 272 581 336 142 79 Cases 3 and 4 215 491 203 9 (55) Source: NEP estimates. 2.32 The lower capital account balance for cases 3 and 4 make the balance of payment situation critical, making it necessary to resort to exceptional financing, which includes exceptional borrowing and/or non- paying the debt service. From 1991 to 1995, exceptional financing for cases 3 and 4 exceeds the first two cases by approximately US$200 million annually. Of course, this situation will induce the country's foreign debt to grow annually and to be capitalized at the model's assumed interest rates. Table 2.14: BALANCE OF PAYMENTS EXCEPTIONAL FINANCING REQUIREMENTS (USS Million) 1987 1989* 1991 1993 1995 Case 1 88 (178) 131 436 528 Case 2 88 (175) 144 452 543 Case 3 147 (81) 297 603 708 Case 4 151 (68) 315 656 770 * During 1989, there is no need of exceptional financing in any of the cases due to improved export situation. Source: NEP estimates. Table 2.15: OUTSTANDING FOREIGN DEBT EVOLUTION THROUGH DECEMBER OF EACH YEAR (USS Million) 1987 1989 1991 1993 1995 Case 1 4,589 5,239 5,933 6,810 7,741 Case 2 4,585 5,248 5,959 6,867 7,831 Case 3 4,644 5,468 6,553 7,655 8,935 Case 4 4,648 5,498 6,512 7,792 9,199 Source: NEP estimates.  - 26 - Conclusions 2.33 Investments in the development of already existing fields should be considered as a high priority. In fact, the economic analysis carried out on a field-by-field basis (Chapter IV) has demonstrated the convenience of pursuing those investments. These results are reinforced from a macro-economic point of view as demonstrated in the present comparative analysis. Investing in developing YPFB's existing fields will lead to a production pattern that could allow not only self- sufficiency in crude and condensates, but may also lead to exportable surpluses that can help the already constrained Bolivian economy. 6/ 2.34 Although not considered in the present analysis, it is obvious that efforts should be placed in finding natural gas export markets. That would help the economy in two ways. The first obvious one is that of providing significant amounts of revenues from natural gas sales, which could be the main source of foreign trade as presently happens. The second is that the existence of new natural gas markets will allow the oil sector mn optimum exploitation, reaching to production. patterns that will allow important crude and condensates exportable surpluses. This, on the other hand, may represent the best economic growth feasible alternatives, as demonstrated in cases 1 and 2. 2.35 Exploration investments should be encouraged. Although the internal demand could be met by YPFB's existing fields development in the short term, the possibility of having a constant 15 year reserves to demand ratio, may enable the Bolivian oil sector to export surpluses. Given the amounts needed for a successful exploration program, efforts should be shared between YPFB and private initiatives. 2.36 Success in public investment within the hydrocarbons subsector should be closely monitored. As demonstrated on the analysis, public investments in the oil subsector may be bigger than in any other sector, and therefore its use should be absolutely Justified. 6/ An in-depth review of YPFB data is warranted.  - 27 - 111. ENERGY DEMAND MANAGEMENT Energy Pricing Hydrocarbons 3.1 Petroleum Products. Except for LPG (domestic use) and diesel oil (for power generation) which are subsidized mainly for social reasons, oil products prices are either considerably above opportunity costs or close to it. On the whole, there is no subsidy of oil products with a weighted price of the composite barrel to the consumer equivalent to about 160% of the opportunity cost. In Bolivia's case, transport to and from the international markets could make a considerable difference as the cost of shipping to and from Santos, Brazil, the nearest inter- national port 7/ 5s estimated at US$85/ton of which US$50/ton is within Bolivia and the balance in Brazil. 8/ The prices of products as of February 1987 and the estimated opportunity costs appear below in Table 3.1. 3.2 A major issue arises with LPG prices where the real opportunity cost, including distribution, is of the order US$17/bbl against a price of LPG for domestic use of US$12.5/bbl (volume-wise, more than 90% of the LPG sold is for domestic use). This is particularly serious since LPG represents about 25% of the products sold in Bolivia, and it is the only product whose consumption is rising rapidly. The existence of three simultaneous prices for the one product is likely to encourage fraud-- YPFB is not in position to ensure that for each bottle purchased, the end-use corresponds to the price paid by the consumer especially since 71 Arica, a Chilean port, is connected to Bolivia by a crude oil pipe- line which was designed for Bolivia'q crude exports in the 1970's. Importing from Africa would be prohibitively expensive because of the altitude difference. The crude line to Argentinean ports is presently used to meet Argentina's internal requirements, and could not be used, according to specialists, to import products. 8/ For the evaluation to be fully valid, a provision for domestic transport and distribution has to be added. In the case of liquid fuels, the provision is relatively small US$1-3/bbl. In the case of LPG, however, it is much higher, approximately US$45/ton or US$4/bbl.  - 28 - LPG distribution is in private hands. 9/ If such pricing policies are maintained, considerable damage could be made to thie natural gas distribution program with respect to both commercial and domestic customers. The price of LPG should therefore be increased by about 30y, to its opportunity cost. Table 3.1: DOMESTIC PRICES OF OIL PRODUCTS AND OPPORTUNITY COSTS d/ % of Domestic Opportunity Opportunity Cost ------(US$/bbl)------- Opportunity Cost Special Gasoline a/ 37.9 16.9 224 Premium Gasoline a/ 43,9 16.9 260 Avgas b/ 68.0 26.4 258 Avgas (Meat) b/ 54.0 26.4 205 LPG - Domestic use a/ 12.5 13.1 95 LPG - Industrial use a/ 17.9 13.1 137 LPG - Vehicles a/ 37.9 13.1 289 Kerosene b/ 31.8 28.2 113 Jet Fuel b/ 48.0 28.2 170 Diesel Oil b/ 37.9 26.1 145 Diesel Oil - Power b/ 18.9 26.1 72 Fuel Oil b/ 32.6 22.0 148 Weighted Average 32.0 19.5 164 a/ Estimated at CIF Santos Brazil due to close balance between domestic supply and demand. b/ Product anticipated to be imported at the margin, estimated at CIF Santos plus transport to Santa Cruz Bolivia. c/ Exchange Rate: Bs2.10 = US$1,00. d/ February 1987. Source: NEP estimates. 3.3 Government policy has been to subsidize LPG for the low income rural population which may not have any other fuel alternative but animal dung or fuelwood. With that in mind, however, the rural population has actually been paying two or three times the prices of LPG in the urban 9/ To emphasize this point further, YPFB's Commercial Department records the industrial consumption of LPC in La Paz in 1985 to be about 30,000 bbl. The Gas Division, on the basis of market surveys estimates it to exceed 50,000 bbl.  - 29 - areas, due to high transport costs and an inefficient distribution system. A fixed national retail price covering its opportunity cost should therefore be set, which would subsidize the transport costs to the low income rural areas. The end result should be that the low income rural population will not be affected by the price increase. 3.4 By achieving a fixed national LPG retail price at its economic cost, the LPG prices for industrial purposes and vehicles should be eliminated. The existence of three simultaneous prices encourages fraud. Furthermore, in volume terms, more than 90% of LPG sold is for domestic use. 3.5 Regarding the subsidization of diesel oil used for power generation, this product represents only 0.5% of products sales in Bolivia. The number of beneficiaries is small so that they are well identified. The subsidization could be rationalized by the fact that the bulk of power generation in Bolivia is hydro and gas-based so that this diesel oil is used in remote areas, without any other power alternative. 3.6 An important distortion exists regarding diesel and gasoline (para. 3.60). While their prices are identical, the opportunity cost of diesel is about 35% higher than that of gasoline. Taking into account that about 60% of the diesel is used for transportation, measures should be considered to encourage, whenever feasible, the replacement of diesel by gasoline imposing special taxes and custom duties on diesel-powered vehicles, trucks and tractors (at present customs duties are identical at 20%). Increasing the price of diesel could have a negative effect for most of the food products are brought by road at already high costs. 3.7 Natural Gas. The average incremental cost (AIC) of gas is estimated in the order of US$0.65/MCF including exploration, operating, and a minimal transport cost because most of additional investments are required in more than 10 years time. 10/ This is below the two current official prices for natural gas, for the power sector at US$0.88/MCF and one for the one other consumers at US$ 1.76/MCF. 3.8 The AIC is considered low because most of the infrastructure for gas production and transport to the main markets already exists. Furthermore, reserves should suffice to meet the demand in the next 20 years, even under the most optimistic scenarios. 3.9 Oil and Gas Pricing Financial Viability. Oil and gas prices should also be sufficiently high to enable YPFB to recover costs. The present fiscal regime for hydrocarbons is a provisional introduced in 1986. YPFB is subject essentially to a flat tax of 65% on all products. Furthermore, YPFB pays on 11% royalty. Taking into 10/ If exports to Brazil materialize in addition to Argentina, the AIC may reach US$1.15/MCF.  - 30 - consideration the fiscal deficit, YPFB's tax structure needs to be reviewed to ensure a sound financial position for YPFB. 3.10 Regarding oil, with an average selling price of the barrel of the order of US$32/bbl, YPFB is left with less than US$10/bbl to cover its exploration, production, transport, refining, distribution, depreciation and dabt service obligations. 3.11 On natural gas, the AIC has to take into consideration past investments, resulting in a financial cost of gas estimated at US$1.50/MCF at city gate. In addition one would have to add a distribution cost estimated at US$0.22/MCF for industrial consumers, and US$3.35/MCF for domestic and commercial consumers. Instead, because also of the present fiscal regime, YPFB collects on average less than US$0.30/MCF, i.e. less than 15% of its financial cost. In addition, the industrial park of Santa Cruz is only charged 36% of the official price. Although the current policy to maintain natural gas prices relatively low to encourage further use of this abundant resource is commendable, retail prices per kcal are well below other alternatives (para. 3.67) and need to cover all financial costs. 3.12 It is intended to award citywide concession to private distributors in early 1988. Subject to a detailed financial analysis of YPFB's domestic gas operations, YPFB's bulk gas tariff should be of the order of US$1.90-2.50/MCF (net of taxes); this would cause financial losses in the early years because of low pipeline utilization to be made up in subsequent years as consumption rises. But this level is close to YPFB's financial cost of supply. 3.13 Regarding the different concessions, the tariff to be introduced in each will depend inter alia on the density of consumers and the mix of industrial, commercial and domestic users. The first priority will be to complete the conversion of fuel oil and then diesel consumers. Subject to detailed financial analyses, the concessionaires could charge industrial users US$2.50-3.00/MCF, and commercial users US$3.00-4.00/MCF; this would still be well below the price of diesel (US$7.2/MCF), kerosene (US$5.93/MCF) and fuel oil (US$4.88/MCF). Regarding LPG replacement, as explained above if (i) the domestic LPG price (US$3.2/MCF) is increased by some 30% to reach its opportunity cost level; and (ii) the price of gas is increased to reach the cost of supply, conversion to natural gas would be still unattractive. For large commercial users presently using LPG, conversion to natural gas would remain an attractive proposition. Obviously, should the present tax regime continue to apply to gas, the prices above would have to be adjusted accordingly. 3.14 Regarding the power subsector (63% of domestic gas sales in 1986), from which YPFB collects net of taxes US$0.21/MCF, even the IJS$0.88/MCF price of natural gas is very low in relation to any other energy source: fuel oil is priced at about US$5.75/MCF and diesel oil for power generation at about US$3.60/MCF. The netback of natural gas against hydroelectric projects is about US$1.70/MCF. There is therefore little rationale for such a low price for the power sector.  - 31 - Electricity Tariffs 3.15 The level and structure of electricity tariffs in Bolivia do not reflect the real cost of this public service. The current bulk electricity rates for sales from ENDE to the distribution companies are well below their marginal costs (e.g. bulk tariffs to ELFEO have a demand charge of US$2.5/kW per month and 12 mill/kWh of energy charge, while the marginal costs were estimated at US$8.9/kW per month and 14 mills/kWh respectively). On the other hand the current bulk electricity rates for mining and industrial consumers are well above their marginal cost (e.g. bulk tariffs to COMIBOL-La Palca are US$13.5/kW-month as demand charge and 40 mills/kWh as energy charge, with the same marginal costs previously mentioned). In addition, with respect to the retail tariff structure at the distribution level, it is also inverted, since those consumers with higher marginal costs (residential) are paying much less than consumers with lower marginal costs (industrial). ELFEC's average residential tariff is about 20-25 mills/kWh while the average marginal cost is about 69 mills/kWh. Marginal Cost Analysis 3.16 Generation and Transmission. The marginal capacity and energy costs for generation and transmission in the interconnected system were analyzed on the basis of tentative generation and transmission expansion programs for the period 1980-1995. Table 3.2. summarizes the marginal costs estimation: Table 3.2: MARGINAL COST ESTIMATES FOR 1990-1995 Generation Transmission Energy Cost (mills/kwh) 13.5 13.9 Capacity Cost (US$/kw-m) 5.8 9.1 Source: NEP estimates. 3.17 The value for the marginal capacity and energy costs was determined, by and large, by the capital and production costs of a gas turbine, which is the marginal unit. The energy cost in this case depends directly on the cost of gas at the plant (assumed at US$1/MCF) and any change in this cost would affect directly this estimate. The capacity cost for the transmission system was estimated on the basis of the average incremental cost of the proposed transmission expansion, mainly the Central-East interconnection. The seasonal variations (wet and dry periods) of marginal costs were not significant, and therefore, were not considered. For the period 1987-1989, before the intercon-  - 32 - nection is commissioned, the marginal cost for the Central and Northern systems would be nil for they have hydro surpluses. 3.18 Based on this results, one can estimate the marginal cost of supplying a consumer connected at the transmission level. This is the case of the bulk supply by ENDE to the distribution companies and the large industrial consumers like COMIBOL and ENAF. However, the capacity costs estimated above refer to the coincidental peak demand; to determine the costs for these consumers one should take into account the peak demand diversity, which is estimated, in this case at 2.5%. The marginal costs for these consumers would be at an energy cost of US$13.9 mills/kWh and a capacity cost of US$8.9/kW/month. 3.19 Distribution. For the distribution system, the case of ELFEC which is the distribution company in Cochabamba, has been selected taking into account that it had the required information for this analysis. The analysis and its results can only be applied to this company. In the future, when the other distribution companies prepare complete investment programs and collect additional data, the analysis can be extended to them. The cost calculation for the distribution system was based on the average incremental costs related to the proposed 1987-1995 expansion program for ELFEC's distribution system. The results are summarized below in Table 3.3. Table 3.3: ELFEC DISTRIBUTION MARGINAL COST STRUCTURE Voltage Level Medium - lOkV Low - 380-220 V Energy cost (mills/kWh) 14,2 15.0 Capacity costs (US$/kW-m) 12.6 19.8 Source: NEP estimates. 3.20 The calculation of the marginal cost for different consumers is much more complex than for the HV consumers. It requires an evaluation of the load curves for individual consumers and of the coincidence factors. Unfortunately, this detailed information was not available, and "typical" values and aggregate demand by feeders have been utilized, as shown in Table 3.4.  - 33.- Table 3.4: ELFEC RETAIL MARGINAL COST STRUCTURE FOR AVERAGE CONSUMERS Industrial Commercial Residential Average Cost (mills/kWh) a/ 41 55 69 a/ Calculated on the basis of the capacity and energy costs, and a typical toad factor for the consumer. These results are tentative, they are based on non-supported assumptions about coincidence and load factors. Source: NEP estimates. Tariff Structure and Levels 3.21 Legal Framework. The National Electricity Code of 1968 established that electricity rates should be set at a level sufficient to achieve an average rate of return of 9% on the rate base, composed of net revalued asset, and a provision for working capital. Until the late 1970s the power utilities reached this rate of return; however, during the period 1981-1985 of economic recession and hyperinflation, the rates did not keep pace with inflation. In fact, from 1981 to 1984 the average rates dropped about 80% in real terms, to levels of less than 10 mills/kWh. In 1985, the new administration made substantial tariff increases and changed also the ground rules to set electricity rates. Decree 21060 established that bulk and retail tariffs should be negotiated between the concerned parties and set a ceiling of 45 mills/kWh for sales to mining and industrial consumers (later increased to 75 mills/kWh by Decree 21072) without any consideration of marginal cost levels. Recently, the Government has approved a Decree which would allow the distributors monthly tariff increases of 1.5% until tariffs would average 50 mills/kWh. Distributors at such rate increased would reach this tariff level in 4 years time. 3.22 Average Retail Tariffs. The current average electricity retail rates charged by the power companies to specific consumer categories are, in general, consistent within each other. The major exceptions are the isolated systems and the subsidiaries of the Bolivian Power Company (COBEE and ELFEC) as shown below in Table 3.5. The first, with a higher average rate and the latter with a lower average rate. This fact reflects basically differences in the "accounting" cost of service for these systems. The average rates for 1986 are summarized in Table 3.5.  - 34 - Table 3.5: RANGE OF RETAIL TARIFFS IN MILLS/KWH Average Residential Industrial COBEE and ELFEC 29-34 20-25 25-29 Small Isolated (diesel) 62-96 40-64 70-150 Other distribution 42-46 21-29 50- 62 ENDE's bulk to distribution Companies 23-25 - - Source: NEP estimates. 3.23 Tne average rates are not sufficient, in most cases, to achieve a 9% return on the rate base. In fact, the projected rate of return in 1987 for the largest generation and distribution companies (with the exception of COBEE) are below 4%. The results of the rate of return calculation are summarized below in Table 3.6, while a detailed firm financial description is provided in Chapter V. Table 3.6: POWER COMPANIES TARIFFS AND RATES OF RETURN (mills/kWh) Actual Average Tariff Required Rate of Tariff for 9% of Return ENDE 36 62 1.3% ENDE S.Cruz 23 35 - 3.2% ENDE Tarija 41 116 - 28.6% ENDE Trinidad 53 132 - 34.2% ELFEC 49 54 3.4% CRE 46 54 1.8% COBEE 27 27 9.1% Source: NEP estimates. 3.24 From the Table 3.6, the following can be concluded: (a) The distribution companies require a margin of about 30 mills/kWh to achieve a 9% rate of return (difference between the required tariff and the actual bulk energy purchase tariff). (b) The distribution companies are in a better shape than the generation company and apparently would require a mcdest tariff increase to obtain a 9% return. However, this is deceiving, as their operating expenses would increase as a result of the increases in bulk energy purchase price necessary to meet the generation company's requirements.  - 35 - (c) ENDE is operating at a loss in all the isolated systems. The case is specially dramatic in the Tarija and Trinidad thermal systems where in spite of a subsidized diesel oil price, sales revenues cover just 50% of fuel costs. 3.25 The retail tariff structures for the major distribution companies are similar regarding the application of demand and energy charges to large commercial and industrial consumers, and differential energy charges according to the consumption level to residential and small commercial consumers. In most of the distribution companies, in contradiction with the cost of service, the average tariff for a residential consumer is substantially lower (about 50%) than for an industrial consumer. The only exception are the COBEE companies where the average residential rate is only 15% lower. 3.26 This distortion in average rates for industrial, commercial and residential consumers can be explained by comparing ELFEC's current structure in terms of relativity with the marginal costs estimated previously for this company. In broad terms, the current ELFEC retail tariff structure as shown in Table 3.7 is inverted. Table 3.7: RELATIVITY OF ELFEC'S RETAIL TARIFFS a/ Marginal Retail tariffs Cost Structure Residential i 1 Small commercial 2.8 .8 Medium industrial 1.8 .6 a/ Taking the residential rates to be 1. Source: NEP estimates. 3.27 HV Level Tariff Structure. The bulk tariff structure includes bulk sales to distribution companies and large mining and industrial consumers. Table 3.8. summarizes the tariff structures and compares them with the HV marginal costs obtained above.  - 36 - Table 3.8: COMPARISON OF TARIFF STRUCTURE AND HV MARGINAL COSTS Demand Charge Energy Charge (USS/kW/month) (mills/kWh) Marginal Cost 8.9 14 Bulk sale to CRE and ELFEC 3.5 17 Bulk sale to ELFEC 2.5 12 COMIBOL/Central 13.5 a/ 40 COMIBOL/La Palca 10.9 48 Private Mining 6.7 44 Matilde Mine 6.1 50 COBEE Interconnection 13.5 10 a/ Refers to contracted peak demand. Additional at US$7.6/kW per month. Source: NEP estimates. 3.28 The following conclusions are evident: (a) The tariffs for the distribution companies are well below marginal costs, for the energy charge is abou: the same, and the demand charge is less than half. For example in the case of the distribution companies (CRE or ELFEC), typically with a load factor of about 50%, the average rates would be: Actual: 27 mills/kWh Marginal: 38.3 mills/kWh (b) The energy charge for the mining industry is well above the marginal energy costs, while the capacity charge is in the same range of the marginal capacity costs. Pricing Strategy Petroleum Products (a) Increase the price of LPG about 30% to its economic cost, but consider this to be the only national retail price for all LPG, which would already consider transport costs to the rural areas.  - 37 - Natural Gas (a) Charge a natural gas retail price to consumers which is sufficient to cover its average incremental cost plus whatever financial costs that may occur. (b) Natural gas conversion for the residential/commercial sector should only be encouraged where the gas l1ne passes and covers a minimal consumption level. (c) All taxes should be removed from domestic gas sales in order to encourage substitution. The revenue loss to the State would be small (less than US$8 million per annum). Electric Power (a) Carry out a reevaluation of assets for all the distribution and generation companies, in order to establish the real tariff base in each company. (b) After completing the previous recommendation, carry out a detailed tariff study based on and consistent with the rate of return, cash flow and marginal cost approaches for all generation and distribution companies. (c) At the bulk level, attempt to reduce the gap between actual electricity rates and marginal costs for large industrial and mining consumers supplied at the transmission level. (d) Implement the tariff structure based on actual marginal cost and taking into account the financial viability of the power companies. Interfuel Substitution and Conservation The Structure of Energy Demand 3.29 In 1985, Bolivia consumed 2.011 million toe of energy. Per capita energy consumption was 313 kgoe, compared with a world average of 1,500 kgoe and an average for LatTn America of 1,000 kgoe. Petroleum products met 48% of total demand, electricity 7%, natural gas 3%, and biomass 11/ the remaining 42%. 3.30 Commercial energy consumption amounted to 1.167 million toe in 1985, represented by: gasoline 30%, other petroleum products 53%, electricity 11%, and natural gas 6%. The transport sector is the most 11/ Fuelwood, animal dung, bagasse, and charcoal.  - 38 - important consumer of commercial energy 51%, followed by household/ commercial 25%, industry 21%, and agriculture 3%. 3.31 Biomass energy consumption in Bolivia totaled 0.847 million toe in 1985, represented by fuelwood 67% (including a minimal amount of charcoal), animal dung 19%, and bagasse 14%. Fuelwood accounted for 56% of the energy consumption in the household sector, animal dung accounted for 34% of the household energy consumption in the rural Altiplano, and bagasse supplied 34% of the energy consumption in the industrial sector. The Household/Commercial Sector 3.32 The household/commercial sector consumes 25% of all the energy consumed in Bolivia in 1985, LPG is an important source of energy, increasing by 25% between 1980 and 1985. For all practical purposes, the sector is not using natural gas. For analytical purposes and to point out the most critical issues in the sector, it has been divided into urban and rural areas. Urban Areas 3.33 The urban areas have to a great extent switched over to modern fuels; LPG *is the most common urban household cooking fuel although supply shortages have occurred recently which may lead to increasing use of fuelwood or dung if available. Fuelwood and dung is not common in the urban areas except for the very low income population that may have access to those fuels. For lighting purposes, electricity is well spread in the urban areas although the marginal income areas continue to use kerosene. Rural Areas 3.34 For the purpose of the National Energy Plan, the rural areas of Bolivia were divided into three physical areas that share climatological and geographical attributes--the Altiplano, the Valleys, and the Tropics. 3.35 Altiplano. With over half of the total rural population and at an altitude of about 4,000 m, the cumulative effects of deforestation and high levels of current consumption have forced much of the population to rely on dung and small shrubs for household cooking and heating needs. The inadequacies of the present transportation networks and scattered nature of communities is a major impediment to development and distri- bution of commercial energy. 3.36 Unconventional technologies, such as biogas, windpower and solar energy, are expensive relative to the income of the rural household based on subsistence farming and require a social and technical environ- ment that can only be brought about through continuous technical support. The energy problem of the Altiplano should be treated as a part of integral rural development programs considering the resource endowments of the region in question.  - 39 - 3.37 With the short supply of fuelwood in many parts of the Altiplano, driea dung is commonly used as the primary cooking fuel. In fuelwood-poor areas in Oruro, there are indications that the need for dung as a cooking fuel is restricting its use as natural fertilizer, although no such tendency for the Altiplano as a whole is quantifiable. 3.38 The supply of LPG, the principal supplement to biomass as a cooking fuel is poor. Where it is available, the price is more than double the price at YPFB distribution centers, depending on the distance from those centers. Kerosene is delivered to rural areas and its use for household cooking should be investigated. Currently it is only used for household lighting. 3.39 Charcoal is not consumed as a cooking fuel in rural households in the Altiplano. No biogas plants have succeeded in the Altiplano, nor have pilot programs been coordinated on a national level. A pilot program might be justified in rural areas where other fuels have higher opportunity costs than biogas. The high capital cost would be a barrier to implementation on small farms. 3.40 Economic Comparison of Energy Alternatives. According to the opportunity cost analysis shown below, LPG is the best short-term alternative for household cooking in the rural Altiplano. Oruro should be a priority for improving the distribution of LPG because of the severe shortage of fuelwood and subsequent increasing ese of dung. Relative costs of actual and potential cooking fuels for the Altiplano were estimated and are summarized below in Table 3.9. Table 3.9: ALTIPLANO ECONOMIC COMPARISON OF HOUSEHOLD COOKING FUELS (Cost of Useful Energy) Opportunity Cost Average Relative Efficiency Fuel Market Price Opportunity Cost to LPG Used a/ (mills/'OO0 kcal) (mil s/5/000 kcal) LPG 30-43 35-49 1.0-1.4 59% Kerosene 48 35 1.0 56% Fuelwood 349 930 26.6 9-14% a/ Although some of these efficiencies may be considered high, they are the result of a JUNAC study and are commonly used in Bolivia. Source: NEP estimates.  - 40 - 3.41 LPG and kerosene are clearly the most economic fuels for cooking in rural areas in terms of useful energy. LPG has the disadvantage that under the current distribution system, its costs rise substantially in rural areas (para. 3.2-3.3). 3.42 Kerosene would seem to be the ideal household cooking fuel for rural areas in the Altiplano. Its price does not seem to vary with distance from YPFB distribution centers, but its delivery under the current distribution system in Bolivia is expected to decrease in the early 1990s and is restricted. Nevertheless its use for household cooking purposes in the Altiplano should be investigated. 3.43 The marginal costs of rural electricity was estimated between 120 and 370 mills/kWh. However, for most homes in rural areas, electricity is simply not available, and for the few rural areas where there is a power line, connection costs are prohibitive. The opportunity cost of electricity for rural households indicates that it may be more costly than kerosene. Furthermore, expansion of electric grids to rural areas, or installation of local diesel electric generators or hydro- electric plants, is not recommended if there are no productive end uses for the power. Household illumination is not considered sufficient reason for the introduction of electric power. 3.44 Valleys. Only two areas in the Valleys have shortage of fuelwood supplies--the historically deforested and eroded Valley of Tarija and the province of Yamparaez in the Department of Chuquisaca. The Valleys have a greater resource basis than the Altiplano, due to the more temperate climate. 3.45 Most households in rural areas in the Valleys use three-stone stoves to burn fuelwood for cooking. A negligible quantity of dung is used for fuel in the Valleys. An estimated 199, 464 TOE of fuelwood (35% of national fuelwood consumption), was consumed in 1985 in rural house- holds for cooking purposes. 3.46 The UNDP is financing a joint Bolivian-Brazilian program to improve the efficiency of wood-burning household stoves and foster the development of fuelwood plantations. The project is a demonstration program for both stove improvement and fuelwood plantations. In the town of Lavadero, in the province of Yamparaez 132 families have been chosen for installation of efficient stoves developed in Brazil, and to be constructed entirely from local material. 3.47 Economic Comparison of Energy Alternatives. Economic costs indicate that for Yamparaez and Tarija, the most cost-efficient policy choice would be also to improve the delivery of LPG to those areas. For other areas in the Valleys, there appears to be sufficient fuelwood supplies to warrant its continued use. Therefore, investment in reforestation in most areas in the Valleys cannot be recomnended. Table 3.10 below shows the economic comparison of household cooking fuels in the Valleys.  - 41 - Table 3.10: VALLEYS ECONOMIC COMPARISON OF HOUSEHOLD COOKING FUELS (Cost of Useful Energy) Average market Opportunity Cost Thermal Fuel Price Opportunity Cost Relative to LPG Efficiency a/ (mills/1O0O kcal) (mills/1OO0 kcal) (%) LPG 27-34 28-35 1.0-1.2 59 Kerosene 38-42 34-37 1.2-1.3 56 Fuelwood b/ 172-196 270-349 9.6-12.5 9-14 a/ JUNAC study. b/ Fuelwood deficit area, total reforestation cost. Source: NEP estimates. 3.48 If only 10% of reforestation costs are assigned for energy purposes in Tarija, the economic cost of fuelwood would be comparable to LPG. However, in general, the above data favors LPG as a fuel supply for the Valleys. As in the Altiplano, the distribution of LPG is poor to areas just outside of the city of Tarija with prices similarly dependent on distances from distribution centers. The use of kerosene which has been restricted for lighting purposes should be examined toward cooking purposes. In relation to lighting purposes, the same conditions as in the Altiplano hold for the Valleys making rural electrification viable only if it is marketed to productive end uses. 3.49 Tropics. The tropics with 17% of the country's population, occupies 69% of the total land mass. The tropics have by far the greatest per capita supply of fuelwood in Bolivia. Rough estimates indicate 40 to 50% losses in cutting, and 40 to 60% losses in processing by the forest industry, all of which could be used as fuelwood. Table 3.11: TROPICS ECONOMIC COMPARISON OF HOUSEHOLD COOKING FUELS (Cost of Useful Energy) Average Opportunity Cost Fuel Market Price Opportunity Cost Relative to LPG Thermal Efficiency a/ (mills/1OOO kcal) (mills/OOO kcal) (M) LPG 30-41 35-50 1.0-1.4 59 Kerosene 48 35 1.0 56 Fuelwood b/ 53-71 233 6.7 6 a/ JUNAC study. b/ ,Fuelwood deficit area. Source: NEP estimates.  - 42 - 3.50 The above table indicates a close alignment of economic costs of fuelwood energy for cooking fuel, reflecting the relative abundance of fuelwood. LPG and fuelwood in the surplus areas have the lowest opportunity cost for cooking fuels. In the fuelwood deficit areas, the cost of fuelwood is higher. Although LPG is the primary cooking fuel in the city of Trinidad, LPG is apparently used very little outside of a 100 kilometer radius from trinidad, probably due to higher costs and poor delivery. In the short term, continued use of fuelwood is the best option. 12/ However, efforts should be made to control and slow down the rate of deforestation, if not maintain sustainable yields. Rural electrification in the Tropics holds the same constraints as in the Valleys and Tropics, indicating a viable option only if it is has productive end uses. The Industrial/Mining Sector 3.51 The Bolivian industrial sector is concentrated in the cities of Cochabamba, Santa Cruz, and La Paz. Moreoever, the mineral industries have their major installations in the cities of Oruro and Potosi. The mines are mainly disseminated along the Andean Range. 3.52 Energy Consumption. In 1985, the industrial mining sector was the third largest consumer of energy in Bolivia, after the transport and household/commercial sectors, accounting for 50% of the total electric power demand and 12% of oil consumption. Major consumers of energy are the agroindustries and the mineral industries. 3.53 Because of the collapse of the economy, the share of petroleum products in industry decreased from 154,000 toe in 1983, to 100,000 toe in 1985. 13/ Paralleling this evolution, the share of non-commercial energy in industry remained fairly constant at 120,000 toe in the same period. 3.54 YPFB's internal consumption of oil products represents, at 2,000 bd, about 10% of the national consumption in Bolivia. In the refineries alone, internal use and loss average 8% of the feedstock, notwithstanding the fact that they use increasing quantities of natural gas as fuel. An energy audit focussing on YPFB's consumption of liquid fuels should be carried out. 3.55 The industrial sector, for gas market analysis purposes, comprises a diversified range of users which individually use in excess of US$0.50 MCF/hr at peak. The main representative industries are 12/ The region of the Tropics is diverse, and further study is warranted on an area-by-area basis to ascertain comparative costs of cooking fuels for implementation of the appropriate energy strategy. 13/ Excluding YPFB's internal consumption.  - 43 - breweries, ceramics, detergents, edible oils and other food related industries, glass, sawmills and textile; they are mostly located at Cochabamba, La Paz and Santa Cruz. In the first two cities, gas became available in 1984, and the conversion effort is under way. On the other hand, in Santa Cruz, the more important users have already coaverted to natural gas, particularly those located in an industrial park sponsored by the regional development corporation (CORDECRUZ). On the whole, the industrial market will include both growth and conversion. A market analysis of the gas potential for industrial purposes is presented in Annex 2. 3.56 Bagasse, most of which is produced by the sugar industry in the department of Santa Cruz, is approximately 32% of the total quantity of sugarcane processed. The average bagasse production is 3.32 MT per ton of sugar product. All of the bagasse is consumed internally (that is, in the production of sugar). The bagasse contributes approximately 84% of the total calorific requirements of sugar processing. Of the rest, 14% is provided by hydrocarbons, and about 1% by fuelwood. Because of the relatively high hydrocarbon consumption, an improved bagasse utilization study should be carried out. 3.57 For the Valleys, agricultural product drying is one of the major agro-industrial needs, particularly for the aji. Because of the time required for drying in the sun, large losses (30 to 40%) often occur. During humid weather, losses can reach 70%. Based on the very limited data available, pilot studies could be initiated for small-scale solar drier which has been used with some success in Peru, and the continued use of LPG driers for larger-scales operations. The Transport Sector 3.58 The transport sector is the single most important user of energy in Bolivia over half all the energy consumed in Bolivia, and 60% of the diesel. Bolivia's internal transportation needs are largely met by road vehicles which carry about 93% of the freight (mostly agri- cultural products) and 96% of the passengers. Most of the freight and passengers move along a main transportation axis linking the Altiplano cities of La Paz and Oruro, with the Valley of Cochabamba and the lowland city of Santa Cruz. Foreign trade depends more on the railroads, which carry largely mineral products exports and 81% of the imports. The principal flows are from the mines in the Altiplano towards Chilean and Peruvian ports along the Pacific. In terms of energy, road vehicles consumed 80% of the total, railroads 3% and airplanes 17%. Of additional importance in the qualitative balance is the fact about 85% of all diesel sale are to the transport sector. Both the high energy consumption of the sector and its exclusive reliance on liquid fuels suggest that transport should have a high priority for improving energy efficiency and interfuel substitution, especially among road vehicles. 3.59 Substitution of Gasoline for Diesel Oil. Since the opportunity cost of diesel is about 35% higher than that of gasoline while their  - 44 - retail prices are identical (para. 3.6) measures should be considered to encourage, whenever feasible the substitution of gasoline for diesel. Substitution could be brought about by imposing special taxes and custom duties on diesel-powered vehicles. 3.60 Substitution of CNG for Gasoline and Diesel Oil. Compressed natural gas could pay a small but important role in gasoline and diesel oil conservation in Bolivia in the future. Consultants are currently in the field to examine interfuel substitution possibilities. Substitution by CNG appears economical, but it would take many years to have an impact at the national level. 3.61 Energy Efficiency in Transport. An important way in which fuel savings can be achieved is through improving traffic flow in urban areas. The most immediate results could probably be achieved by introducing and enforcing parking and stopping regulations along the main urban arteries, staggering work hours to spread out the commuter rush over a longer period and reduce average commuting time. In the longer run, priority lanes for bus services could be introduced in high density routes and some underpasses built in main intersections. Considering that these measures involve new investments in traffic control and road improvement, more information is needed before a decision can be made. Thus, it is recommended that the Government undertake an urban transportation study, including a review of energy saving possibilities, particularly for La Paz. 3.62 Recent studies indicate that changes in the driving behavior of vehicle operators can reduce fuel consumption per vehicle by about 10- lSZ. These savings have been achieved through training drivers in fuel saving techniques and motivating them to use those techniques. The achievement of those savings do not require any capital expenditure, and basically require the vehicle operators to reduce idling time, maintain proper tire pressure, accelerate more gently, perform periodic maintenance, etc. These techniques are timed-tested and generally known, but the problem is to motivate the drivers. It is recommended that the Government establish a driver training and motivation program that would enable Bolivia to take advantage of these very economical energy saving opportunities. 3.63 Another source of energy savings can be a sustained effort to rehabilitate the existing road infrastructure and improve road maintenance. Much of the network is in poor condition as a result of light construction and deferred maintenance, and the fact that about a third of the trucks exceed the legal axle load limit. A truck consumes about 5Z more fuel on a gravelled road than on a paved road and that a similar savings occurs between paved roads in poor and in good conditions. Thus, while fuel savings constitute only a fraction of the major (50X-80%) savings in transport costs that can be obtained through road rehabilitation Rnd improvement, these savings are nonetheless important when considering the large volume of fuel consumed in road transport.  - 45 - Natural Gas Substitution Potential 3.64 Because of the relatively large domestic supply of natural gas available, substitution of gas for other products is a top priority. However, under all circumstances, considering the structure of demand, the potential for substitution by natural gas remains small. The combined consumption of fuel oil and diesel oil (other than transportation) accounted for only 12% of the consumption of petroleum products in 1986. This market, on a calorific equivalent basis represents about 14 MMCFD of gas (or twice the present gas market other than power generation). However, all this demand cannot be connected economically, so that the above estimate represents an upper ceiling for the replacement of fuel oil and diesel oil (other than transportation). Regarding kerosene and LPG replacement, even in areas close to the gas network, connecting potential consumers would not be economical most of the time, unless the specific consumption is relatively high. In conclusion, the potential for substitution by natural gas, in a five year perspective, is small and cannot be anticipated to cause a significant shift in consumption patterns. On the other hand, gas will have a major impact on the development of the power sector, where it represents the most attractive energy source; furthermore, once the economy picks up, sectors which are already gas users such as the cement industry would represent a growth market. Lastly, the tin smelters could become, once they reopen, important consumers. 14/ 3.65 During 1986, the average consumption of gas amounted to 22.6 MMCFD, equivalent to nearly 200 thousands of ton of fuel oil on an annual basis, which represents, in turn, approximately 20% of Bolivia's consumption of liquid fuels. 3.66 YPFB's Gas Division has prepared a 5-year liquid fuels substitution program (dated April 1986) as well as a 20-year gas demand forecast (February 1987). The 5-year program aims in particular for the replacement of 80% of the industrial consumption of liquid fuels in the main urban centers and a start in the conversion of commercial and domestic consumers. The program qims at substituting by the end of the decade 1,200 bd of liquid fuels 15/ and 112 tons/day of LPG through the conversion of 250 industries, 770 commercial and 15,000 domestic users. Consumption of gas would thus increase from 22.6 MMCFD in 1986 to 38.6 MMCFD in 1990, an average annual growth rate of 15%. Should the smelter resume their operations, the market would be higher by abgut 9 MMCFD. A detailed regional analysis of gas market is provided in Annex 2. 14/ They are already connected to the gas network, but have yet to make the investment in conversion. 15/ 1,200 bd represents approximately 45% of the consumption of liquid fuels by the industrial sector nationwide in 1986.  - 46 - 3.67 Since virtually all the gas in Bolivia is used as fuel, as opposed to feedstock, the price of gas in relation to other fuels can be evaluated on a calorific equivalent basis as shown below in Table 3.12. Table 3.12: COST OF FUEL PER KCAL Price per Unit Unit bS uSS kcal/unit US$/MM kcal Domestic LPG liter 0.17 0.08 6,509 12 Kerosene liter 0.42 0.20 8,880 23 Diesel Oil liter 0.50 0.24 8,778 27 Fuel Oil liter 0.43 0.20 9,393 22 kWh (ind.) kWh 0.10 0.05 860 58 kWh (dom.) kWh 0.05 0.03 860 29 Natural Gas (ind) MCF 3.70 1.76 263,356 7 Natural Gas (elec) MCF 1.85 0.88 263,356 3 Source: NEP estimates. 3.68 On a purely calorific equivalent basis, the present price of gas is considerably lower than that of other energy sources. However, this is somehow theoretical because few consumers have a choice to make between the different fuels at any point in time. The real option is often between a liquid fuel, and conversion to natural gas, where the consumer has to pay the connection, metering and conversion cost (industrial consumers) or for the conversion cost only (residential and commercial consumers). 3.69 For industrial commercial corsumers, the payback period ranges from 19 to 436 days. Unquestionably, with the present prices, conversion to natural gas for such consumers pays off. On the other hand, for residential consumers, the difference between the official price of LPG (US$3.2/MCF) and that of gas (US$1.8/MCF) is not sufficiently attractive so cover the estimated conversion cost (US$100) for an household using 40 k& of LPG (1.8 MCF of gas equivalent) per month. The impact of the price difference on the payback period is shown in Table 3.13.  - 47 - Table 3.13: IMPACT OF PRICE DIFFERENCE BETWEEN LPG AND NATURAL GAS ON PAYBACK PERIOD FOR COMMERCIAL AND DOMESTIC CONSUMERS Price of LPG Price Difference Payback (USS/MCF) (USS/MCF) (months) 3.0 1.2 46 4.0 2.2 25 5.0 3.2 17 6.0 4.2 13 Source: NEP estimates. 3.70 Thus to reduce the payback period to two years (which can be taken to be the maximum period acceptable to domestic households), the price of LPG would have to be increased by 25% over its present level. However, the approach followed so far does not take into account the cost of supply; as will be seen, the present price of gas for domestic consumers does not cover the cost of supply, so that conversion of such consumers does not represent an economically attractive proposition. With a cost of supply of the order of US$4.85/MCF. the price of LPG would have to be increased to a minimum of about US$6.85/MCF or in excess of 200% in order t- make it attractive for them to convert to natural gas. Taking into account the additional benefits associated with the substitution of liquid fuels and electricity, on some circumstances, with a cross subsidy from industrial consumers, a tariff could be elaborated which would take into account the cost of supply in each system and the present anticipated mix of consumers. However, the conclusions depend on the specific circumstances in each case. 3.71 Technical, financial, and economic evaluation for each proposal should be carried out, along with a well-defined plan for bidders to attract private investors. The contractual arrangements between YPFB and private investors need to be examined in detail. The economic viability and financial incentives may attract private investors in the distribution phase. Interfuel Substitution and Conservation Strategy (a) Improve LPG distribution in the rural areas, particularly in the Altiplano. (b) Incentivate natural gas substitution in industry where economic and analyze in detail case-by-case the conversion of household/ commercial consumers. Private participation in gei distri- bution is encouraged.  - 48 - (c) Carry out an energy audit of YPFB's consumption of liquid fuels. (d) As a medium term strategy, control the growth of the diesel fleet taking into account the yield of the refinery. (e) Investigate the use of kerosene in rural areas, particularly in the Altiplano. (f) Investigate possibilities for improving traffic flow in urban areas, particularly in La Paz. (g) Rural electrification needs to be examined in detail for its viable only if it is marketed for productive end uses. (h) Investigate, on a site-specific basis, the needs for irrigations and the economics involved. (i) Carry out an analysis of the trade-off between dung burning and its substitution by hydrocarbons. (j) Determine efficiency of current wood and dung stoves in the Altiplano, and analyze the possibility for an efficient woodstove program. (k) Carry out an improved bagasse utilization study. (1) Initiate pilot studies for small-scale solar drier which have been used with some success in Peru, and the continued use of LPG driers for larger-scale operations. (m) Examine biogas, windpower, small hydro, and solar energy in detail on a case by case basis only taking into account the conditions of each location. The energy problem needs to be treated as a part of integral rural development programs.  - 49 - IV. INVESTMENT AND TECHNICAL ASSISTANCE PRIORITIES Investment Priorities Petroleum 4.1 There is an urgent priority in identifying ways of increasing Bolivia's oil supply without increasing the country's overall budget deficit. Several types of measures seems appropriate and possible to .be implemented in the short term, particularly the following: (a) The reorientation of YPFB's short run investment program from exploration to production, to defer the decline in production. In the short and medium term exploration contracts with the private sector would reduce the investment outlays otherwise required by YPFB in exploration. (b) The opening of new areas to private sector companies for exploration contracts on reasonable terms. This would require: (i) extension of the 1972 hydrocarbon law to authorize joint ventures; (ii) agreement on payments due to the private contractors; and (iii) revision of the current fiscal regime to attract private risk capital while ensuring a reasonable profit share for YPFB. The feasibility study for private exploration promotion funded under the World Bank Project Preparation Facility (PPF) was recently initiated. 4.2 Field Development. The critical financial situation of YPFB makes it particularly necessary to focus on a well defined investment program oriented to: (i) invest in currently producing oil fields, (ii) assure an adequate period in supplying its internal demand; (iii) prioritize investment opportunities in field development for those fields that have an ERR greater than 20X. 4.3 Under that criteria, except for Sirari and Naranjillos, there are eight fields (Cascabel, Escondido, HSR-Yapacani, La Pefia, San Roque, Santa Cruz, Villamontes, and Vuelta Grande) wich should proceed with their scheduled program and the other two (Camiri and Monteagudo) require reservoir injection studies before any investment is undertaken. Table 4.1 below shows YPFB's investment program. 16/ 16/ Because of great inconsistencies in YPFB data, an in-depth examination is warranted.  - 50 - Table 4.1: YPFB CURRENT FIELDS DEVELOPMENT INVESTMENT PROGRAM a/ Fields 1987 1988 1989 1990 1991 1992 1993 South District Camiri 3.5 3.0 1.0 Monteagudo 3.0 2.0 San Roque 12.00 25.0 9.5 Vuelta Grande 16.25 15.85 Escondido 13.5 8.5 Villamontes 7.10 12.00 Subtotal 23.35 39.85 41.5 23.5 3.0 1.0 0 Central District HSR/Yapacani 15.0 9.0 Santa Cruz 17.5 NaranJillos 0.6 6.0 Sirari 5.5 15.5 13.0 Cascabel 6.6 9.6 5.3 Subtotal 33.1 15.0 6.6 9.6 10.8 15.5 13.0 Santa Cruz Division La pena 8.0 Subtotal 8.0 TOTAL 64.45 54.85 48.1 33.1 13.8 16.5 13.0 a/ Pending results of World Bank PPF, confirmation of data, and completion of studies mentioned below. Source: YPFB. 4.4 For the period after 1993, no further investment opportunities in currently producing oil fields is foreseen, emphasizing the need to accelerate exploration immediately. Based on the production forecast, the economic evaluation of each field is as follows, choosing a 12% discount rate and a base price of US$15/bbl, and taking into account the year in which investments should start considering the "future investment criteria': INVESTMENT PROGRAM STARTING IN 1987 4.5 Vuelta Grande. This is one of the largest retrograde gas condensate fields in Bolivia. The proposed investment program consists in the drilling of remaining wells and installation of a gas processing plant to recycle gas at 90 MMCFD. This project is partially financed by the World Bank, and the development program is based on sound reservoir engineering studies. The pilot plant which has been in operation since  - 51 - June 1983 is recycling gas at about 20 MMCFD and recovering over 1,000 bd of condensates. The actual production data indicates that the reservoir is behaving as it was predicted by the simulation study. When the project is fully completed early in 1989, a substantial amount of liquids (average of 6,289 bd in 1989) would result. The ERR is estimated at more than 100%. 4.6 La Pefia. This field, discovered in 1965, has an investment program that consists in drilling 10 in-fill wells to optimize field production and to prove the additional recoverable reserves, estimated at 1.1 million barrels. The actual proven reserves as of December 1986 are calculated at 8.3 million barrels. The cumulative production from 1987 to 1997 is estimated at 9.3 million barrels. This field development project is financed by the IDB (US$33.6 million) and is expected to be completed in 1987 with the perforation of 8 shallow wells. La Penla will become the main oil producer field for the next two years. The ERR is estimated at more than 100%. 4.7 Villamontes. Field discovered by YPFB in April 1987. Its preliminary proven reserves are estimated at 7.5 million bbl, adding 3.0 million as probable reserves. According to the development program, between 1987 and 1988, the total perforation of 8 wells is expected, including two structure probatory wells, which together with other investments for production infrastructure, will require a total of US$19 million. The economic evaluation of this field, in view of the preliminary existing data, renders the highest ERR well above 100%. 4.8 Santa Cruz. The development of this field constitutes a technical and economical priority. It has two producing horizons: Chorro and Tupambi. The final investment required for its development will be made in 1987, US$17.5 million, covering two producing wells, four injection wells, plus recycling and duct injection systems. By December 1986, US$24 million were invested. The ERR is estimated at more than 100%, which reflects the projects earning power. Besides, it's a fieid located along the limits of the city of Santa Cruz, which minimizes its production costs with regards to other fields. 4.9 HSR-Yapacani. Due to the physical and chemical characteristics of HSR crude (paraffinic), it should be mixed with the condensates of the Yapacani field for its transportation. The ERR is about the lowest among those development projects analyzed, around 24%. However taking into consideration the project has already ensured international financing (IDB) for US$27.8 million and that the HSR crude is 35 degrees API, the continuation of its development is recommended. These fields are expected to enter into production by 1989. 4.10 Naranjillos. A predominantly gas producing field. Its development is p.:ngrammed so as to assure the supply of dry gas to the industrial sector of Santa Cruz, which is now consuming wet gas from Caranda and Colpa fields, at highly subsidized prices. This project should be seen from the gas supply strategy point of view, and should be  - 52 - evaluated only from the perspective as a marginal condensates producer. This field is included in the production investment program but should nevertheless be asnalyzed in detail for it may have negative repercussions on liquid production associated with gas. Its ERR is very low, between 11-21%, compared to other projects. INVESTMENT PROGRAM STARTING IN 1988 4.11 San Roque. Taking into consideration the last YPFB revision carried out in may 1987, this field enters the development program in 1988 with the perforation of 6 wells and the extension of gas processing plant plus the necessary infrastructure. YPFB has secured financing for the gas plant (US$8.7 million) from the Corporaci6n Andina de Fomento. As the Santa Cruz field, this is also a retrograde gas condensate reservoir, with a yield of 2.7 tons of LPG and 7.5 bbl of natural gasolines per million processed cubic feet of gas. By 1991, it would reach a peak condensate production of 3,000 bd. Its estimated recycling life is 6 years with a probable additional reserve of 2.8 million barrels. The maximum recycling flow will be of 87 MMCFD. Its ERR is more than 50%. INVESTMENT PROGRAM STARTING IN 1989 4.12 Escondido. Originally a property of Tesoro, it is legally in a position to be reverted to YPFB (as occurred with Villamontes). Still there is no decision in this regard since it is a fundamental aspect of the Government-Tesoro negotiations, and could become, if Bolivian legislation foresees, the first "joint venture" field between YPFB and a private company. It is an ideal field for a recycling project (Vuelta Grande type), since it is a gas field rich in liquids, and although it is not as large (its reserves are estimated at 10 million bbl), it is a highly productive field, specially if it is possible to optimize invest- ments by taking advantage of Occidental's Tita Camp recycling plant, which is being passed on to YPFB's hands, upon this years closure of the camp. It is estimated that with about a US$22 million investment, the perforation of five wells (three producers and two injectors) could be covered, along with the purchase and installation of recollection and injection systems, the pipelines (gas and oil) and the overhaul of the Tita Plant. Its ERR is estimated at 53% and the initiation of production is scheduled for 1991, helping substantially the supply/demand balance. 4.13 Cascabel. Field discovered in 1985, with a primary gas dome reservoir and 35 degree API oil. Recent data indicates proven reserves at 1 MMbbl and 3.4 MMbbl as probable. At least perforation of two new wells is required to define the field more precisely. According to the priorities given by the forecast production, its development may be deferred until 1989. A total investment in the order of US$21.5 million is required for the perforation of nine wells, recollection and injection systems, separation battery and pipeline to connect with the HSR- Yapacani. The oil production peak is estimated at 3,000 bd, producing 4.4 million bbl in 11 years. The ERR is estimated at 32%. Nevertheless,  - 53 - this scheme should be confirmed by the feasibility study to be financed by the World Bank, under PPF-1. 4.14 Monteagudo. Together with Camiri, Monteagudo is one of the two water injection programmes which YPFB has scheduled. This project was originally financed by IDA under Cr. S-25-BO. The investment should be deferred until a more detailed study is carried out, including an evaluation of the reservoir to define its water injection behavior and reserves, proven as well as probable. If the studies suggested are carried through, the field could peak with a secondary production by 1993 of some 4,400 bd. The estimated ERR is over 100%. INVESTMENT PROGRAM STARTING IN 1990 4.15 Camiri. Field discovered in 1927, its primary reserves are practically depleted. According to a recent YPFB revision, the field contains probable reserves of about 7.5 million bbl, which could be recovered by means of water injection. Water injection is foreseen for Sararenda, although pilot trials would not be very reliable due to the variability of physical properties. The Sararenda formation reached a primary recovery at above 45% and an additional recovery around 24% is expected. The water injection project requires a more detailed study of the reservoir injection behavior, so as to define an optimum design of the project. Upon the revised data, the estimated ERR for the project is over 100%, although concrete evidence that the water injection would be effective still needs to be confirmed. POTENTIAL INVESTMENT PROGRAM STARTING IN 1991 4.16 Sirari. Field which should be put into production only if the export of gas to Brazil is realized or, if there is a critical shortfall in future supply of liquid hydrocarbons. In any case, due to the fact that no step welLs were drilled after the discovery well to define the reservoir limits and hydrocarbon potential, investment in this field seems unrealistic. Its ERR is estimated at about 10%. This picture could change once the World Bank's PPF-1 is completed. Exploration 4.17 According to the production schedule, and to keep a reserve/ demand ratio of 15 years, there will be a need to replenish cumulative reserves by 120 million bbl by 1997. By way of illustration, if explor- ation costs were in the order of US$7.50/bbl as calculated by the consultant for liquid hydrocarbons in a hypothetical case to preserve self-sufficiency, the magnitude of exploration investments for the period 1987-1998 required is calculated in the order of US$900 million. The size of the investment program required and the critical economic situation in Bolivia highlights the need of private participation in exploration activities. Table 4.2. shows the required annual increment of reserves, maintaining a 15 years reserve/demand ratio.  - 54 - Table 4.2: ADDITIONAL RESERVES REQUIRED (15 year reserve/demand ratio) ('000 bbi) Year Proven Reserves Additional Reserves Total Additional Reserves 1987 116,386 0 0 1988 107,260 0 0 1989 109,984 13,444 1,344 1990 113,361 13,406 26,850 1991 117,549 14,105 40,955 1992 121,003 13,717 54,673 1993 125,146 14,689 69,363 1994 130,081 14,086 83,449 1995 135,172 12,993 96,443 1996 140,649 12,445 108,889 1997 146,124 11,120 120,009 Source: NEP estimates. 4.18 Following the results obtained from the PPF for private exploration promotion, YPFB exploration activities should focus on low risk areas while the high risk areas should be offered to private investors. Nevertheless, the 1987 YPFB exploration investment program consist of US$45 million which will cover activ.:ies (exploration and drilling) in traditional areas and new stratigraph:c traps zone. IDB is financing US$80 million in exploration activities for the next three years and is considering a new project to finance up to US$30 million for exploration activities (including 4 exploratory wells) in the Altiplano. 4.19 The Altiplano and the Northwest (including the North Sub-Andean and part of the Llanuras Benianas) present favorable geological conditions according to preliminary studies carried out by YPFB and private companies. However, further prospecting is needed before the liquid hydrocarbon potential could be determined. Natural Gas 4.20 For the purpose of the NEP, the YPFB five year natural gas substitution plan, has been taken as an indicative one. In general, the development and expansion of natural gas transmission to major consuming areas for industrial purposes is an economic option, however, for the residential/commercial sector, a more detailed analysis needs to be carried out. To attract private participation in gas distribution investments, a technical, financial, and economic valuation is needed for each proposal in addition to defining a plan for bidders. Contractual arrangements between YPFB and private firms also need to be examined. The plan aims for the replacement of 80% of the industrial consumption of  - 55 - liquid fuels in the main urban centers and a start in the conversion of commercial and domestic consumers (paras. 3.64-3.70). If exports to Brazil materialize, then further investments will be necessary. 4.21 The investment necessary for the development and expansion is US$16.8 million of which US$6.4 million is YPFB and the remainder is private. To this, one has to add the cost of converting to gas industrial customers (about US$5 million for the three smelters plus US$2.5 million for the other industries), the cost of connections of industrial consumers (about US$2.5 million) and that of converting commercial and domestic users (about US$2 million). 4.22 Nearly 30% of the investments would be in the La Paz area, where the potential for industrial substitution of liquid fuels is the highest. By end-1988, some 50 industries would be converted, representing altogether nearly 450 bd of liquid fuels and 20 tons/day of LPG. If the program at the industrial level is successfully implemented, in the last two years of the plan, small industries, commercial and domestic consumers could be connected. A similar approach is proposed for Cochabamba (20% of the proposed investments) where about 40 industries could be connected by end-1987 representing about 320 bd of liquid fuels and 18 tons/day of LPG. In subsequent years, the small industries, commercial and domestic users would be connected. 4.23 In Santa Cruz (24% of the proposed investments), unlike the first two cities, emphasis is to be given already now to the conversion of small industries, commercial and domestic users, essentially because the larger industrial consumers are virtually all connected. 4.24 In Sucre and Tarija (altogether 24% of proposed investments) major and medium industries are to be connected in the early years of the program, followed by commercial and domestic users. In Oruro and Potosi (altogether 2% of the proposed investments), as long as the smelters remain closed, implementation of the gas network will be slowed down in view of the major impact of the smelters on the local economy. 4.25 Financing. The lack of credit could be an impediment for certain industries to convert to gas despite the financial benefits. Therefore, consideration ought to be given to setting up credit lines for such conversions. A detailed market survey should be made to evaluate the potential demand for such credits. 4.26 The cost of gas equipment (pipe, valves, meters) is said to be considerably higher than in other countries in Latin America. At the minimum, a feasibility study ought to be carried out to assess the merits of creating a domestic gas equipment industry including in particular polyethylene pipes and the assembly of meters.  - 56 - Electric Power 4.27 Currently there is not available a long term (10 years) investment program for the power subsector. The Ministry of Energy and Hydrocarbons has collected a list of specific projects in the power subsector for future financing, but their timing and justification is yet to be determined. The only investment programs, that were based on an expansion plan, were the programs for ENDE and ELFEC. Therefore a tentative five-year investment program for the subsector based on this information, has been prepared, in order to estimate a preliminary figure for the required investment. 4.28 The tentative investment program for the electric power subsector is summarized as follows in Table 4.3. Table 4.3: INVESTMENT REQUIREMENTS FOR 1987-1991 Type US$million Generation 76 Transmission & Subtransmission 37 SubstGtions 8 Distribution 60 TOTAL 181 Source: NEP estimates. 4.29 Generation. The required generation investment amount considers an expansion program prepared by ENDE which is based in the least cost criteria. The program considers that the construction of the 6th and 7th gas turbines at Santa Cruz, is necessary to meet projected increases in electricity demand at the Eastern system. By 1990, and assuming that the Central-East interconnection system will be commissioned, the best alternative would be to continue expanding the gas turbine plant at Santa Cruz and such expansion should be carried out with gas turbines rather than combined cycle plants. This can be explained by the fact that the improvement in efficiency does not compensate the high investment associated with a combined cycle plant. At a cost of gas at the plant of US$1/MCF, very few hydroelectric alternatives could compete with gas turbines. At this moment, the most attractive hydroelectric alternative is the proposed expansion of the Zongo River plant. The power generation system should be expanded, at least in the period 1990- 1995, using plants suitable for peak load operation. In this regard, the rehabilitation of small hydro-stations now on use may be attractive, and the large hydroelectric projects now under consideration can be improved by lowering their designed plant factor.  - 57 - 4.30 The generation expansion program, for the interconnected system is as shown in Table 4.4. Table 4.4: GENERATION EXPANSION PROGRAM Year Project Capacity (MW) 1987 6th Turbine at Santa Cruz 22 1988 7th Turbine at Santa Cruz 22 1990 8th Turbine at Santa Cruz 22 1991 9th Turbine at Santa Cruz 22 1992 10th Turbine at Santa Cruz 22 1993 Zongo River Expansion 61 1994 11th Turbine at Santa Cruz 22 1995 12th Turbine at Santa Cruz 22 Source: NEP estimates. 4.31 Although the above generation expansion program may be subject to further changes during the power system expansion revision to be carried out by ENDE during this year, it has been considered as adequate for estimating investment requirements in generation. 4.32 Transmission. Regarding transmission investment, the only major project considered by ENDE is the Central-Eastern interconnection project. It has been found that it is important to commission this project by 1990, in order to reduce the need for expanding generation capacity and to allow the use of hydroelectric surplus, if any, in the C- N-S interconnected system. The interconnection will perform a role in the system completely different to that envisaged when it was planned in the late 70's due to major changes in the cost of gas, in the demand of the Eastern system and the availability of hydro surplus. Initially it was intended for the use of hydroelectric resources which were the least cost alternative; now, gas turbines are the most attractive development and there may not be significant hydro surpluses in the C-N-S system when the interconnection is commissioned. The main benefits of the interconnection in the medium term would be, therefore, to facilitate the development of additional thermal generation in the Santa Cruz area, where their performance is better, and to facilitate the need of gas transport to the central regions. 4.33 Subtransmission and Distribution. Regarding subtransmission and substation investment, specific projects suitable to meet future demand in Santa Cruz, Cochabamba and La Paz systems have been included (i.e. subtransmission lines to Chapare, Yacuiba and Trinidad) with a total investment required of about US$8 million.  - 58 - 4.34 Due to the absence of detailed information at the national level on distribution, an aggregate investment requirement has been estimated taking into account the average cost per incremental peak demand (US$450/kW derived from ELFEC's records) and the increase in peak demand for the whole system. Using this assumption an estimated investment of about US$50 million is required for the 1987-l991 period. 4.35 Impact of Reduced Investment Levels. Although the estimated investment in the power sector represents only a small fraction (about 5%) of the public sector investment, it is important to analyze the impact of a reduction in this investment program caused by financial constraints. A reduction in generation would affect in the short term the electricity supply to Santa Cruz; if total investment in generation is reduced in, say 10%, this would be equivalent to cancel the 7th turbine in Santa Cruz. In this case, the margin Or generation in 1989 would be 4.3 MW which is completely inadequate. This margin means that whenever one of the generation units at Santa Cruz is taken out of service for maintenance or there is a forced outage, it would be necessary to ration about 15 MW, equivalent to 12% of the peak demand in Santa Cruz. Expressing it in probabilistic terms, it means that there would be about 330 hours per year with power rationing at peak. 4.36 A reduction in transmission investment in 1987 or 1988 would mean a postponement of the construction of the Central-East inter- connection. A postponement of one year would result in: (i) need to install two additional turbines in 1990 (investment of US$17 million) in order to meet the projected demand in the C-N-S and the Eastern systems operating in isolation; and (ii) an increase in fuel costs in 1990 of about US$1.3 million. 4.37 Investment in distribution is not as lumpy as investment in generation and transmission, and, therefore, gives more flexibility to reduce it gradually. The implications of a reduction in this investment are much more difficult to analyze for it depends on the distribution company and the component that is affected by the reduction. It is not worthwhile to analyze these implications, for a reduction of 20% in the investment estimated for aistribution represents only about US$2 million per year. Technical Assistance Priorities 4.38 The following technical assistance activities should be given high priority so that critical problems in the energy sector can be tacked. Within the MEH: (a) Evaluate options to strengthen the policy and institutional framework, and market arrangements for LPG in the rural areas and carry out an energy demand analysis focussing on the use of LPG (paras. 3.2-3.3 and 3.41, 3.47, and 3.50).  - 59 - (b) Establish an energy information system and develop and implement analytical tools to carry out energy planning, in particular, strengthen DINE's organization, methodologies, and procedures regarding the setting of electricity rates and the development of data bases for power sector statistics (paras. 5.1-5.3 and 5.18). (c) Review the current electricity tariff structure both at bulk and retail level, and preoare specific proposals for setting electricity rates for 1987-1990 (paras. 3.21-3.28). (d) Carry out a study to improve bagasse utilization in the sugar mills (para. 3.5). (e) Determine the efficiency of current wood and dung stoves in the Altiplano, and analyze the economics of dung burning and its substitution by hydrocarbons, including kerosene (paras. 3.37- 3.38). (f) Evaluate the current organizational striucture of the rural energy sector(paras. 5.30-5.32 and 5.42-5.44). Within YPFB: (a) Develop and implement a petroleum supply management information system (MIS) optimizing the use of refineries and evaluating least cost supply options (para. 5.9). (b) Develop and introduce in YPFB modern integrated acco nting, budgeting and control systems (paras. 5.33-5.38). (c) Carry out an energy audit on YPFB's consumption of liquid fuels (para. 3.54). Within ENDE: (a) Carry out a power system analysis of the interconnected system, including a stability analysis (paras. 4.32). (b) Review electricity demand projections for the industrial, mining and residential sectors for the period 1987-1995 (paras. 1.39-1.41). (c) Review procedures, methodologies, and organization in ENDE for project analysis (paras. 5.14-5.20).  - 60 - V. INSTITUTIONAL AND FINANCIAL ISSUES Organization Structure Institutional Problems 5.1 The Ministry of Energy and Hydrocarbons (MEH) is responsible for formuliting energy policies and for regulating the activities of the sector, excert forestry which is under the responsibility of the Ministry of Agriculture. These functions are carried out by two main departments within the Ministry, one responsible for hydrocarbons (DGH), and the other for electric power (DINE). Overall sector planning is limited within the Energy Planning Unit (DEP) of the MEH. The Rural Energy Corporation (COFER), funded through the MEH, is responsible for rural energy and alternative forms of energy. Power tariffs and petroleum product prices are set by the MEH. 5.2 MEH is insufficiently equipped to exercise its functions and to coordinate the efforts necessary to successfully meet Bolivia's future energy needs. The recent creati3n of the DEP was a f;-st step but it must be strengthened. This unit must be staffea with highly qualified personnel, equipped with analytical tools, and advised by outside experts during Its initial years. Free flow of information to and from the energy companies and with the other ministries must be established. DEP, working together with strengthened DGH and DINE, would Le in charge of proposing and evaluating energy strategies, scheduling programs and monitoring those that are implemented. It would also make sure that a prop.r link is established between economic objectives and energy, and would coordinate with the Ministries of Agriculture and Rural Affairs, and Planning. 5.3 The current structure of DGH, DINE, COFER and DEP needs to be examined in dctail. Most of these units are receiving enough funds to maintain basic office functions and nothing else. In the case of DINE, a political and legal solution should be worked out to give back DINE the responsibility for setting rates at all levels. Hydrocarbons 5.4 Petroleum. YPFB was incorporated in December 1936 as a state oil company to take over the nationalized Bolivian assets of Standard Oil of Uew Jersey, Inc. (now Exxon). On September 1969, the Bolivian subsidiary of Gulf Oil Co. was T itionalized and YPFB assumed the administration, production, transpLetation, pipeline construction and operation, -efining and distribution as well as imports and exports. YPFB has been engaging in operations contract with foreign oil companies. YPFB is experienced in all phases of the oiL industty from exploration to drilling, production, refining, and marketing.  - 61 - 5.5 A previous diagnosis of YPFB's operations carried out by independent consultants in December 1985 is still true today, and includes the following: (a) A high degree of centralization, featuring excessive concen- tration of decision-making authority to the top levels of management. (b) Duplication of functions, overstaffing. (c) Extremely slow and cumbersome administrative decision-making procedures. (d) Inadequate development and use of management information and other systems. (e) Poor coordinating and conflict resolution mechanisms between functions. (f) Excessive specialization; no cross-functional career paths. (g) Excessive centralization of administrative staff functions in La Paz. 5.6 In line with the above issues, YPFB's organizational structure should include corporate restructuring to gear YPFB to work under economic efficiency criteria. At present investment decisions are based on physical targets of production and supply with little economic priority consideration. The present organizational structure and accounting system of YPFB does not permit a realistic evaluation of economic performance since revenues and costs cannot be attributed to the underlying lines of activity and transfer prices used among the company's operating unit do not have a solid economic foundation. 5.7 Since the role of YPFB is an integral part of the Government policies for the oil and gas subsector, it is important to assess the competitiveness of its operations and activities on the basis of international standards. This would determine which of its operations and activities are economically justified, which are not, and what opportunities exist for increasing their efficiency. One w. to do so would be toe reorganize YPFB into a set of independent, commercially oriented divisions--each specializ.og in a particular field of activities--and by using proper transfer priLes between them. 5.8 The operational divisions could be responsible, re.spectively, for exploration and production; drilling and oil-field services; refining; transport and marketing. In addition, the restructuring should start with (i) defining clear objectives commensurate with the human, technical and -inancial resources of the division, integrated in a long- term investment strategy for the sector; (ii) establishing control mechanism over operations without interfering with managerial  - 62 - responsibilities and the financial autonomy of the company; (iii) making the divisions cost-conscious, and self reliant; (iv) holding managers accountable for results by means of performance evaluation and introducing managerial incentives linked to result; and (v) opening up the industry to outside competitors toward maximizing the efficiency of operations, encourage entrepreneurship and innovations and bring in latest technologies and knowhow. This will help optimize the potential of each division and ease their adjustment to an increasingly competitive environment. 5.9 With respect to refinery operations, a computerized refinery model should be set up to take into account the specific circumstances of the Bolivian environment. Bolivia's three refineries (Cochabamba, Santa Cruz, Sucre) represent twice the demand and operate considerably below capacity. A petroleum supply management information system should Le set up optimizing the use of refineries and evaluating least cost supply options. 5.10 As a result of a current situation where salaries are very low and the lack of a career development perspective, the morale in YPFB is very low. With the government freeze on salaries, the ratio of the private oil companies salaries to YPFB is substantially different. This is critical, for YPFB best staff is leaving in a period where the oil sector is the backbone of the Bolivian economy. A revision of YPFB's salary structure is urgent. 5.11 The regional difficulties should also be resolved. A constraint on drilling activities is that the three petroleum producing provinces jealously watch over exploration and production activities and have been able to stop the movement of rigs and other equipments out of their respective provinces. For example, about one third of the time the rigs are in waiting; costing YPFB about US$ 12 million per year. 5.12 Natural Gas. At present, responsibility for natural gas is under Yabog located at Santa Cruz (exports to Argentina, and transport and distribution in eastern part of Bolivia), the Industrial Division located at Cochabamba (transport and distribution in western part of Bolivia) and the Gas Division located at Sucre (planning, tariffs, policy). In addition, YPFB centralized services (personnel, accounts, commercial, etc.) provide support to the different groups involved with natural gas. It is intended that gas distribution in the main towns be awarded to concessionaires in early 1988 who will get the concession at no cost, but will be required to invest part of their income in the expansion of the network, and the connection of new consumers. YPFB would supervise the concessionaires, and ensure that they comply with their obligations, including the one to invest. The Gas Division is presently preparing bid documents that will serve for the selection of concessionaires. The selection is expected during the second half of 1987.  - 63 - 5.13 While the gas activity of YPFB is small, it is likely to play an increasingly important role in the future; the problems of gas are very specific (load management, transport, distribution, metering, safety etc.) and demand in general a different expertise than that of oil. That is why many countries have opted for separate gas companies which essentially buy the gas from the producers in the producing areas, and are responsible for transport and sometimes distribution. In the case of Bolivia, some consideration ought to be given to consolidate the functions presencly fulfilled by the three groups at different locations 17/ 5.14 The concessionaire system for gas appears prima facie reasonable under the Bolivian circumstances, in particular the wide geographical dispersion of the consumption centers, and the need to raise private capital for the distribution systems. However, these concessionaires will have virtually no past records in the operation of gas networks. It is therefore intended that they be closely monitored by the present Gas Division. In addition, and taking in particular into account the safety aspects, consideration ought to be given to securing the service of experts from an operating gas utility to ensure that the systems being introduced are up to standards. This could avoid costly mistakes, and spare the need for introducing modifications at a later stage, after expenditures have already been incurred. Electric Power 5.15 ENDE's responsibilities on planning of the expansion system at the national level (generation and transmission) should continue, while the coordination of operational activities should be strengthened. Construction of new plants, included in the least cost expansion program prepared by ENDE, could be developed by ENDE or private or regional entities, as long as the operation will be closely coordinated with ENDE. At the distribution level the responsibility of construction of new facilities should be transferred to the distributors companies. 5.16 At the regulatory level the Ministry of Energy and Hydrocarbons is responsible for formulating the policies for the sector and regulating power sector operations. Its regulatory function is carried out by DINE in accordance with the National Electric Code (NEC) of 1986. 5.17 At the generation and transmission level, there are two companies responsible for the development and operation. On the one hand, ENDE is responsible for the planning, development, and operation of generation and transmission projects at the national level, and for supplying energy to all distribution companies and some large mining and industrial consumers. On the other hand, the private Bolivian Power 17/ An immediate benefit will be that a true costing system for gas would be rapid'Ly developed.  - 64 - Company (COBEE) is responsible for supplying energy to La Paz and Oruro markets, and for the operation of generation plants in that area, and is authorized to develop new generation projects at the Zongo River Basin. Additionally, there are several regional development coorporations (CORDECRUZ, CORDECH, etc) which pursue the development and operation of multi-purpose projects (irrigation and power). The organization at the generation and transmission level raises some queries and creates some problems for sector planning discussed below. 5.18 In the early sixties, with the support of the international financing institutions, the Government introduced major reforms in the regulation and organization of the power subsector that contributed to its rapid development in the 1960s and 1970s. The most important actions in this period were: (i) in 1962, the creation of ENDE, as responsible for the planning, construction and operation of generation and transmission systems, for the interconnection of isolated systems, and for assisting in the creation and development of distribution companies; (ii) in 1962, the creation of the Direccion Nacional de Electricidad (DINE) responsible for the regulation and coordination of the power sub- sector; and (iii) the enactment by the Government in 1968 of the National Electricity Code (NEC) which regulates the operations of power electric utilities and establishes technical criteria to set electricity rates. In the 1980s, however, the regulatory action weakened, mainly as a result of the economic crisis and new legislation enacted by the Government. 5.19 First, the provisions of the NEC for setting electricity rates based on a 9Z rate of return were not applied during the economic recession and electricity rates deteriorated rapidly. SeconL, DINE's technical capability weakened as its budget was reduced and salaries were kept too low. And third, the Decrees 21060 and 21072, and the Law of Municipalities enacted in 1985 weakened the application of the NEC and role of DINE in regulating the power subsector. Other problems, like lack of definition of responsibilities in developing new generation projects and the expiration of the concession in 1990 of the largest distribution company (COBEE), contributed to create institutional problems in the power subsector. 5.20 Generation. The lack of definition for the responsibility in the development of power generation projects at the national level has created problems for sector planning. On the one hand, COBEE is pursuing the development of very attractive generation projects in the Zongo River with little coordination with ENDE, which is responsible for the preparation of national power development plans. On the other hand, the regional development corporations are promoting vigorously multipurpose projects with substantial electric power components. To alleviate these problems, the planning process should be strengthened so there is a procedure for ranking generation alternatives at the early stages of preparation and for taking only the most attractive projects to the feasibility and design stages. In the case of multipurpose projects, the contribution of the project to power generation can be easily assessed and valuea at the equivalent cost of the best electric power alternative.  - 65 - In that way, one can estimate the cost assigned to other purposes and assess the merits of the project for non-electric uses. ENDE is the institution best qualified for directing this process and should be responsible for preparing the Power Development Program. In order to reduce tensions with other institutions and get their support, the criteria to be used in preparing the plan should be widely discussed and should be evident to the interested parties. 5.21 Although generation and transmission planning should be centralized, the construction and operation of all the generation projects do not necessarily have to be centralized. In the case of electric power generation projects, only ENDE and COBEE have the experience and the infrastructure necessary to undertake their construction. The future development of the power system with few hydroelectric projects does not justify that other power companies enter into this activity. On the contrary, only one company could have the respo.;sibility for the construction of all new generation projects. Taking into account that COBEE's concession expires in 1990, and provided that a local company would be created, this is a good opportunity to make ENDE responsible for the construction and operation of all generation projects. However, there are two exceptions. If a new large multipurpose project is developed, it would be advisable to create a special executing agency for its construction; and second, the operation of small (say, less than 5 MW) thermal systems in isolated areas is burdening ENDE's administration and can be transferred to local distribution companies. 5.22 Subtransmission and Distribution. At the subtransmission and distribution level there are about 8 distribution companies responsible for power distribution to the major urban centers, which purchase energy from the two generation companies. By tradition ENDE has developed the major distribution substations at Cochabamba, Santa Cruz, Sucre, and Potosi. As the distribution systems have grown and the distribution companies as well, there is no need to burden ENDE with the responsi- bility of developing part of their distribtttion system. This responsibility should be transferred to the distribution companies. 5.23 At the distribution level, the concession for the largest distribution company, COBEE, would expire in 1990, and a decision should be taken about the extension, modification or expiration of the concession contract. This has created a lot of controversy and political turmoil, with advocates for about every possible course of action. The problem should be put in perspective, by distinguishing between political and technical considerations. The technical considerations refer to the supply to the consumers at La Paz of a reliable electricity service at a reasonable cost. In this regard, COBEE has ione a good job. It is a well organized, efficient, and responsible company who has managed to provide a low cost service with a reasonable reliability in spite of major external financial constraints. However, the uncertainty about the future of the contract has affected negatively electricity service for, of course, COBEE is not eager to make major investments in the  - 66 - development of the power system. The major preoccupation at this point would be to take, as soon as possible, a decision on the future of the contract. The Government should evaluate carefully the alternatives before a decision is taken not to extend the contract. Nevertheless, if the concession contract is not extended, a solution would be to transfer the generation and transmission system to ENDE and to have a local company responsible for power distribution. 5.24 Legal Aspects. Regarding sector regulation, the application of the NEC and the role of DINE weakened with the approval in 1985 of the Law of Municipalities, and by the Decrees 21060 and 21072 of 1985. Article 9 of the Law of Municipalities establishes that the municipal governments are responsible for the regulation of public services in their jurisdiction. There would be a conflict, therefore, between the application of the provisions in the NEC and this law. Decree 21060 contributed to the confusion by establishing that electricity rates should be negotiated between the producers and the consumers, and that, in the case of the distribution compauiies, the municipal governments would represent the consumers. Decree 21072 of August, 1985, was more precise by establishing, that as of January, 1986, the municipal governments would set electricity rates for the urban areas, according to the corresponding provisions of the NEC; that the Regional Development Corporations should set electricity rates for rural consumers in accordance with the NEC; and that the Ministry of Energy and Hydro- carbons, through DINE, should set bulk electricity rates. 5.25 After the change in regulations, the actual setting of electricity rates was erratic: tariff increases at retail level have been set by negotiations or by default in a few cases (no comments from the mnnicipal government), and in other cases tariff increases have not been approved; at the bulk level, tariff increases have been approved by DINE, creating in some cases conflicts for the distribution companies when DINE authorized a tariff increase for bulk rates and the corresponding increases at the retail level were not authorized by the municipal government. 5.26 The provisions of Decree 21072 did not weaken the application of the NEC. It only weakened the role of DINE. The provisions of the Law of Municipalities, on the contrary, are vague and may be in conflict with the application of the NEC. There are political, legal and technical issues involved in this problem. The political issue is the power struggle between the national government and the municipal and regional governments. The legal issue is whether the municipal governments can regulate public services. The technical issue is what rus es should be applied to set tariffs. The first two issues are out of the scope of this analysis. Regarding the technical issue, in our opinion, the provisions of the NEC for setting electricity rates are appropriate as long as there is supervision by a qualified group to ensure that the cost of service has been correctly evaluated and that it is reasonable. There are practical advantages to have a centralized group to perform this function in a relatively small power subsector like this, and the best suited would be DINE.  - 67 - 5.27 Therefore, a political and a legal solution should be worked out to give back to DINE the responsibility for setting electricity rates at all levels. This would require strengthening DINE's organization and establishing higher salaries to attract qualified personnel. 5.28 Performance Indicators. In general, ENDE, COBEE, and ELFEC are well organized and efficient. The deterioration of the financial situation and of their performance was due to external factors and not to inefficiencies in their operations. Regarding generation, the thermal power plants show an availability over 80%, which is adequate considering that they are diesel engines and gas turbines; their efficiencies in the range of 25% to 33% are also adequate. These results are very good, specially considering that there were difficulties to purchase spare parts, and the maintenance of thermal plants fell behind schedule as a result of the critical financial situation in the 1980s. 5.29 legarding management efficiency indicators, the number of customers per employee for the distribution companies is in the range of 200 to 400. The lowest value corresponds to COBEE which operates several hydroelectric plants, and therefore, this figure can be considered very good. The highest value corresponds to ELFEC and is excellent for a distribution company of its size. The collection period for 1986 was in the range of 70 to 160 days. ENDE and COBEE show collection periods below 80 days which are reasonable, while ELFEC and CRE have collection periods of 120 and 160 days which are too high and should be improved. Rural Energy 5.30 The MEH is the main organization dealing with energy issues, however there is apparently no department devoted to rural energy or alternative energy resources on a national level. COFER, funded through the MEH, is nominally the public organization that is involved with rural energy and alternative forms of energy. Its predecessor, INER, was involved in the original biogas program in Bolivia. COFER is now mainly involved with rural electrification and the organization currently receives only enough funds to maintain basic office functions and nothing else. There is similarly no coordination, or, evidently, cooperation, among the three government ministries pertinent to energy development, MACA, MEH, and the Ministry of Planning. The ties indicated between the Ministry of Planning and the regional development corporations is nominal. 5.31 There is virtually no coordination either on the national level or on the level of the regional development corporations with non- governmental organizations involved in rural development or with rural cooperatives. Ties should be established among the Ministry of Planning, MACA and MEH for the purpose of coordinating national energy policy. COFER should be streamlined and provided with a reasonable budget to allow promotion of alternative and other energy resources in rural areas, under the guidance of the National Energy Plan.  - 68 - 5.32 Although the regional development corporations must submit yearly plans to the Regional Directorate in the Ministry of Planning in La Paz, which technically has jurisdiction over the corporations, there is virtually no control over their activities, nor is financial support channeled through the national government. More involvement with small rural projects should be promoted, and funds should be channeled to those regional development corporations that are short of funds due to depressed levels of departmental productivity. A detailed description of the rural organizations per region is included in Annex 4 5.33 A number of international organizations participate in reforestation and alternative energy projects in rural Bolivia. However, the lack of central government coordination has resulted in often sub- optimal investment decisions. Financial Situation Hydrocarbons 5.34 The evaluation of YPFB's financial position and prospects constitates a unique challenge in view of the highly inflationary environment in recent years, the delays in closing the books, and the application of certain financial procedures which are at variance with generally accepted accounting principles. Furthermore, on certain items, there does not seem to be a consensus within YPFB's financial staff, possibly because the corporation has yet to adjust to the fiscal regime introduced in early 1986. 5.35 Weaknesses in YPFB's accounting, budgeting, and management information systems have been documented by Arthur D. Little, Booz Allen & Hamilton, and others. In summary: (i) YPFB experiences considerable delays in the submission of financial information and the accounting information is said to be inaccurate at times; (ii) the costing system is slow, and needs to be indexed to a hard currency or standard costing system in order to become meaningful; (iii) YPFB's accounting and costing systems need to be integrated; (iv) inventory costing, which is still on an historical cost basis, needs to be upgraded; and (v) internal audit has to be reorganized along functional lines. Furthermore, the geographical dispersion of YPFB's activities, and the insufficient availability of modern computers in the accounting department renders any analysis difficult. 5.36 The tax mechanisms in place have a determinant impact on YPFB's financial performance. Taxes are essentially levied on YPFB's production and sales. In 1985, these taxes were equivalent to about 40% of its gross sales; with the tax increase of early 1986, the ratio increased to  - 69 - about 70X of sales proceeds. 18/ The new taxes have had disastrous implications for YPFB--the loss for FY1986 can be estimated at US$39 million; in order to meet its financial obligations, its indebtedness to foreign oil companies increased by US$50 million and it failed to comply with over US$18 million in debt service obligations. 19/ The investment program in 1986 was reduced to about US.50 million, which compares to an average US$88 million per annum ovei 1979-83 and an anticipated average of US$125 million annually over 1985-88. 20/ YPFB's balance sheet at end-1986 shows considerable liquidity, taking into account the general state of affairs, US$78 million, but these funds are largely impounded by the Central Bank, and cannot be used by the company. 5.37 A continued reduction in YPFB's investment program will have adverse consequences. In particular, development and enhanced oil recovery projects which could ensure self sufficiency in oil products in the coming years will have to be deferred until YPFB's internal cash generation increases. 5.38 The main financial issue regarding YPFB's investment program is not foreign financing (YPFB has large unused credits from CAF, IDB and the World Bank) but the financing of local costs. The method used thus far to generate local financing (non-compliance with financial obligations to foreign oil companies, lenders, Government, etc.) is financially unsound. A preliminary analysis for FY1987 shows that even if its investment program was reduced to nil (and disbursements of foreign credits were therefore halted), YPFB would still nave a cash deficit in excess of US$50 million during the year (including compliance with its short term liabilities). As a result, the solutions to be considered include an increase in the prices of oil products (with inflationary consequences) and a reduction in taxes (with adverse repercussions on general budget revenues); regarding operating expenses, these are relatively small and cannot contribute much to a solution of 18/ The new taxes were initially interpreted as an advance against future taxes, but it now seems that they have to be charged to the current year, and that they will remain in effect until the Government can mobilize revenues at a similar level from new sources. 19/ Payments overdue are to Arlabank (US$4.7 million), Texas Commerce Bank (US$5.1 million), World Bank S-25-BO (between 6/20/84 and 12/20/86), for US$6.8 million, and Bancomer (US$1.5 million). 20/ Source: Vuelta Grande Gas Recycling Project, Staff Appraisal Report of June 4, 1986 (pages 20-22).  - 70 - the fundamental problems. 21/ YPFB's financial requirements need to be taken into consideration in the context of the ongoing review of the overall tax system. 5.39 Regarding YPFB's anticipated performance beyond 1987, unless there is a major reform in taxation, or an increase in dollar terms in the prices of oil products, one can anticipate rising deficits, declining production, and an increasingly difficult situation for the petroleum sector as a whole, including foreign oil companies. What is required as a matter of urgency is an agreement between the Government and YPFB on realistic operating and capital budgets together with their corresponding financing plans. Unless such an agreement is reached, the situation is likely to deteriorate further. Electric Power 5.40 The financial position of ENDE and the power distribution companies was strong in the late 1970s and they achieved, in general, a rate of return of about 9%. However, from 1980 to 1985 their financial position deteriorated rapidly as the result of the decline in sales, substantial reduction in real terms of electricity rates during the hyperinflation period, and increase in receivables resulting in a loss of revenues because the amount in arrears was not revalued during the hyperinflation period. In general the distribution companies could face better this situation than ENDE for, among other things, they could adapt their investment programs to the drop in the rate of growth in demand. ENDE, on the other hand, could not teduce its generation and r,slnsmission investment program at the same pace, and as a result of the substantial increase in receivables for sales to the distribution companies, and a substantial reduction in net income, it accumulated overdue debt for about US$50 million, of which about US$28 million was owed to Government (including YPFB and CBF). ENDE's income statements, and sources and uses of funds (expressed in current US$), tell part of the story. However, they should be read with caution for the financial results during this period of hyperinflation are severely distorted. 5.41 The reduction in the pace of inflation by late 1985 and the implementation of substantial increases in electricity rates reversed the trend and now most of the power companies are in a recovery path. As it was explained above, ENDE has continued to carry most of the financial burden by having average rates still at a low level. To ensure ENDE's financial recovery, the Government recently issued an Executive Decree approving the capitalization of ENDE's debt to the Government and an increase of 1.5Z per month in real terms of ENDE's rates to distribution 21/ YPFB's management, for all practical purposes, has control over operating expenses which amounted in 1986 (excluding purchases from oil companies, taxes and depreciation) to US$75 million, i.e., 12% of total cost of goods sold.  - 71 - companies, until they reach a value of 50 mills/kWh. Starting from the current levels of about 25 mills/kWh, it would take about 4 years to reach that ceiling (para. 3.23). Table 5.1 shows ENDE's average tariff and financial key indicators. Table 5.1: ENDE'S FORECASTED FINANCIAL PERFORMANCE 1987 1988 1989 1990 Average Tariff (mills/kwh) 3.6 3.9 4.4 4.9 Rate of Return (%) 1.2 2.4 4.7 7.0 Net Int. Cash Gener.(MMUSS) (001) 2.5 13.1 25.1 Source: ENDE and NEP estimates. Rural Energy 5.42 There is an almost total unavailability of agrarian or other rural financing for energy purposes. Small rural electric cooperatives must, in general, pool financial resources to purchase equipment at the full cost upfront. Tn Tarija, the Banco de Argentina, which formerly financed small rural projects, closed, leaving a vacuum in the availability of rural loans in Tarija. The Caja Central de Ahorros y Prestamos in La Paz maintains branches in each department and a number of local offices, and finances rural projects in electricity and potable water supply. Loans can be obtained through them by individuals, cooperatives and private entities. The rural loan program is financed under the USAID PL-480 program, which annually lends US$1 million to the Caja at 3% interest. The central office of the Caja re-lends to local offices at 4% interest, and the local offices lend to rural loan recipients at 6% interest (this compares to the private bank lending rate of approximately 25% in La Paz). The principle drawback of this rural lending program appears to be the lack of bank offices in most rural areas. 5.43 Inadequacies in the existing rural financing system should be investigated, and changes should be made to provide financing for small rural energy development projects, in line with priorities. Furthermore, the system by which SEMTA finances rural development projects in the department of La Paz should be evaluated, with possible applications in all three regions. 5.44 Great differences in the financial situation of the rural corporations exists because most of the financing for the corporations, as mandated by National Law, consists of a percentage of corporate profits from major departmental industries. For the Altiplano, CORDEOR, receives financing from the Vinto smelter. However, the downturn in  - 72 - smelter operations has resulted in loss of financing for CORDEOR, and other business interests dedicated to departmental development. Meanwhile, the regional Corporations in the Valleys and Tropics are financially well-off relative to the Altiplano corporations. Both regions are gas and oil producing, and so receive substantial contributions to finance regional projects. The national government must act to improve financing for the poorer regional corporations (a national issue currently subject to great controversy vis-a-vis the natural gas royalties). Institutional Strategy Petroleum (a) Restructure YPFB under economic efficiency criteria by considering a set of independent, commercially oriented divisions. The operational divisions could be responsible for exploration and production; drilling and oil-field services; refining; transport and marketing. (b) Continue in resolving the regional difficulties, between the Departments, that have negative implications for all activities of the oil subsector. (c) Develop and introduce in YPFB modern integrated accounting, budgeting, and control systems. (d) Review the tax structure on YPFB to assure its financial viability. (e) To satisfy the increase in domestic demand of oil products (30,000 to 35,000 bd), an average of 45 exploration wells each year for the period 1987-1992 are needed to increase reserves to about 250 million bbl and maintain a reserve/production ratio of 15 years. If about 10,000 bd were to be exported, 60 wells each year would be needed. This should be carried out in conjunction with a revision of operation contracts to increase all activities in the subsector. Natural Gas (a) Since gas distribution in the main towns is expected to be awarded to concessionaires in early 1988, ensure they comply with their obligations, particularly in investments. (b) Consider a separate gas utility which will consolidate the functions presently fulfilled by the three groups.  - 73 - (c) Because of the importance of gas exports to #he Bolivian economy and the fact that the current gas export agreement with Argentina is expiring in 1992, alternative arrangements need to be investigated. Electric Power (a) Work out a political and a legal solution to give back to DINE the responsibility for setting electricity rates at all levels, in accordance with the provisions of the National Electricity Code. (b) Confirm ENDE as the institution responsible for preparing the National Power Sector Development Plan. (c) Take a decision as soon as possible on the future of COBEE's concession contract, and if the contract is not extended, to transfer COBEE's generation and transmission system to ENDE once the contract expires. The distribution system should then be transferred to tha municipalities or regional activities. (d) Prepare a plan to transfer the operation of ENDE's generation plants at the small isolated systems to the distribution companies/cooperatives in these areas. (e) Transfer the responsibility in developing distribution substations in Cochabamba and Santa Cruz from ENDE to the distribution companies in those cities. Rural Energy (a) Improve the coordination among the Ministry of Planning, MACA, and MEH toward coordinating national energy policy in the rural sector and breakthroughs in the development of alternative energy resources such as biomass, geothermal, and others. (b) Investigate existing inadequacies in the rural financing system.  - 74 - Annex 1 Page 1 of 4 PETROLEUM Structure of Petroleum Demand The share of gasoline has slightly increased from 61% of the combined consumption of gasoline and diesel in 1980 to 65% in 1985. Such an increase would have been higher had more energetic measures been taken to encourage the use of gasoline as opposed to diesel in view of the relative scarcity of diesel in Bolivia. Table 1: DEMAND FOR PETROLEUM PRONUCTS, 1980-86 1980-86 Avg. Annual -------1980 ------- 1986------- Growth Rate ('000 bbl) (M) ('000 bbl) (%) (M) Gasoline 2,903 33.8 2,952 38.0 0.3 Avgas 112 1.3 76 1.0 - 6.3 LPG 1,107 12.9 1,966 25.3 10.0 Kerosene 947 11.0 331 4.3 - 16.1 Jet Fuel 673 7.8 570 7.3 - 2.7 Diesel Oil 1,881 29.1 1,563 20.1 - 3.0 Fuel Oil 958 11.2 319 4.1 - 16.7 Total 8,581 100.0 7,777 100.0 - 1.6 Source: YPFB. The commercial and domestic sector has seen its share increase from 19% of the consumption of oil products in 1980 to 28% in 1985. The absolute growth rate, however, was of approximately 3.5% per annum, slightly higher than population growth. Thus the relative increase in the share of this group is probably due more to the decline in the industrial and mining sectors than any other factor. However, a struc- tural shift has happened in consumption patterns with kerosene consumption declining by 35% and LPG increasing by 55% over their 1980 levels. On a calorific equivalent basis, LPG's share has increased from 56% to 75% of the total requirements of this sector. This is certainly due to a deliberate pricing policy promoting LPG use, as well as the relative advantages of LPG over kerosene as a cooking fuel. The decline in the share of the "other" sectors (i.e., industry, mining, agri- culture, etc.) from 28% in 1980 to 18% in 1985 can only be explained by the economic recession ir. Bolivia.  - 75 - Annex 1 Page 2 of 4 Regarding gasoline and diesel oil, the virtual stagnation in their consumption reflects the recession. The decline in the consumption of kerosene by 616,000 bbl annually is equivalent from a calorific stand- point to 840,000 bbl of LPG which is within 2% of the increase in LPG use (850,000 bbl). The huge decline of 67% or 639,000 bbl in the consumption of fuel oil can be explained by: (a) the more widespread use of natural gas; 1/ (b) the closure of the tin smelters at Potosi and Oruro (which used to consume 320,000-380,000 bbl of fuel oil per annum; and (c) the recession. As a result, the Bolivia market for fuel oil has almost disappeared. Table 2 shows the consumption of oil products by sector for 1985. Table 2: CONSUMPTION OF OIL PRODUCTS BY SECTOR, 1985 ('000 bbl) Kerosene/ Diesel Fuel Sector Gasoline LPG Jet Fuel Oil Oil Total ('000 bbl) (%) Transport 2,863 -- 586 950 -- 4,399 58.6 Industry -- 75 53 101 503 732 9.9 Agriculture -- -- 143 58 35 236 3.1 Household/Commercial -- 1,710 429 -- -- 2,139 28.5 Total 2,863 1,785 1,211 1,109 538 7,506 100.00 Source: YPFB. Reserves Proven reserves of liquid hydrocarbons (crude and condensates) are estimated at 138 million bbl, equivalent to a reserve/production ratio of approximately 21 years based on current production although many of these fields are in their decline. Probable reserves as of 1/ Nao'-ral gas sales, other than for poweir generation, increased from ' ICFD in 1980 to 8.2 MMCFD in 1986. The increase is equivalent a annual consumption of 270,000 bbl of oil.  - 76 - Annex 1 Page 3 of 4 January 1, 1987 amount to 31.7 million bbl. Only about 20% of th2 hydrocarbon potential has been explored. Bolivia covers about 1 MM km of which 41% are sedimentary basins. The sedimentary basins are divided into the Llanura Chaco Beniana, Faja Subandina, and the Altiplano. About 75% of crude oil fields discovered so far are in the Faja Subandina. A very recent discovery in the Villamontes field may increase significantly the reserve by 30 MM bbl, pending confirmation of these reserves. However, caution must be taken with these figures since they are still very preliminary. Exploration Petroleum exploration in Bolivia started in the 1920s, carried out mostly by large international companies, and led to the first dis- covery in 1927 in Camiri. A total of 323 exploration wells were drilled in Bolivia through 1986 with a discovery rate per exploration well of 1.3 million bbl of oil and condensates, and 17.2 billion cu. feet of gas. Exploration in Bolivia has been restricted to known basins which are gas prone. The National Petroleum Company (YPFB) and Occidental, indicate that there is a possibility to find large liquid reserves in the north western and south eastern regions of the Chaco Beniano basin although a greater risk is involved. Bolivia is a country which is relatively unexplored with only 0.6 wells per 1,000 km2 of sedimentary basins, while the United States has 380 and Canada 47 for the same area. Of the 28 fields discovered in the period 1976-1985, only five (Cambeiti, Espejos, Cascabel, H. Suarez, and Techi) were crude, while the others were gas or gas condensates. As a result of that exploration activity, YPFB's reserves of crude oil and condensates were increased by 53 million bbl and the private companies by 23 million bbl. In natural gas, YPFB's reserves were increased by 3.3 x 109 CF. Unless new fields are found, there will be a decline in liquids production resulting from the fact that many of Bolivia's fields are past their peak. To stimulate exploration, the COB is reviewing the legal framework for private sector activities, and intends to soon promote areas for exploration by private sector companies. The GOB in assistance with the World Bank has recently initiated a scudy of the hydrocarbon potential in Bolivia with a selection of areas for petroleum exploration. The hydrocarbon law sets the principle of state sovereignty over petroleum resources and assigns all direct responsibility to YPFB which may enter into operation contracts with private oil companies to carryout exploration and production activities. Contracts are of the production sharing type and may r,.t exceed 30 years. The contractor receives in cases of discovery 40-50% of production. However, the GOB  - 77 - Annex 1 Page 4 of 4 authorizes exports of hydrocarbons only after internal demand has been satisfied. The price paid to the private sector by YPFB is pegged to the Government selling price of Arab light crude. This has not been carried out in practice; there is an outstanding debt to Occidental and Tesoro. The Bolivian debt to C:cidental is expected to be paid in a counter trade basis, with Argentinean goods and services, to be commercialized by Occidental. The product, to be kept in a trust fund in a U.S. 'ank, shall be used in investments by Occidental in Bolivia. Debts to Occidental as related to internal oil sales will be paid by the same mechanism but with no restrictions as in the case of the gas. Tesoro is waiting for an agreement to be reached between Occidental and the GOB. This is a critical issue which needs to be resolved if the government wants to attract private investors in Bolivia. Exploration in Bolivia needs to be accelerated because of the high potential and the critical balance between domestic supply and demand. Refineries Bolivia's three refineries, which are located at Cochabamba (27,300 bd), Santa Cruz (15,000 bd), and Sucre (3,000 bd), represent twice the demand and operate considerably below capacity. They are all of the simple hydroskimming type which is suitable for local crude. Bolivia's crude are particularly light with densities of the order of 47- 50 API (oil fields) and 57-700 API (condensate fields) so that they yield a relatively high proportion of light products (LPG, gasoline), and a low one of heavy products (diesel, fuel oil). A computerized refinery model should be set up to take into account the specific circumstances of the Bolivian environment. The optimum use of the refineries needs to be determined, and consider the moment when Bolivia may be an importer to determine importing refined products or crude (if so, at what quality). A reliable refining model would help optimize for a given level of demand for oil products, and of crude oil supply, the output of the refineries. An energy audit in the refineries is also recommended, in unison with an audit of YPFB's internal consumption which is about 10% of the national consumption. In the refineries alone, internal use and losses average 8% of the feedstock (against 45% usually), notwithstanding the fact that they use increasing quantities of natural gas as fuel. The potential for energy savings at the refineries needs to be determined.  ----- ----- - * _ - - - '12 E~~~~~~~~~~~~~ j a V n -- t~i5 itc~5f~0~---|g ej-ej a .4~ ~ ~ ~ - - ; ~!Zg -:-: **-s _ ed.lN*e N PNN