Report No. 4213-BO FE PY BoHva: 1ssues and Optons fn the Energy Sector April 1983 Report of the joint UNDP/World Bank Energy Sector Assessment Program This document has a restricted distribution. Its contents may not be disclosed without authorization from the Government, the UNDP or the World Bank. FOR OFFICIAL USE ONLY Report No. 4213-BO BOLIVIA ISSUES AND OPTIONS IN THE ENERGY SECTOR April 1983 This is one of a series of reports of the Joint UNDP/World Bank Energy Sector Assessment Program. Finance for this work has been provided, in part, by the UNDP Energy Account, and the work has been carried out by the World Bank. This report has a restricted distribution. Its contents may not be disclosed without authorization from the Government, the UNDP or the World Bank. ACRONYMS AND ABBREVIATIONS Acronymns M Thousand MM Millions B Billion bbl Barrel BD Barrel per day CF Cubic Feet TCF Trillion Cubic Feet MMBtu Million of British Thermal Units T Tonnes TCF Trillion Cubic Feet KW Kilowatt MW Megawatt GW Gigawatt LPG Liquid Petroleum Gases Abbreviations ANICARVE National Association of Industrialists for Charcoal Production CDF Center for Forestry Development CORDECH Development Corporation of Chuquisaca ENDE Empresa Nacional de Electricidad (Power) GDC Gas Development Corporation INER Institute for Rural Electrification MER Ministry of Energy and Hydrocarbons (Hydrocarbon Companies) NIS National Interconnected System PERTT Executive Program for Soil Rehabilitation in the Department of Tarija YPFB Yacimientos Petroliferos Fiscales Bolivianos CURRENCY EQUIVALENTS Currency Unit Bolivian Peso ($b) Official Rate $b 200/US$ FUEL EQUIVALENTS (Gross values: As used by Bolivian MEH) Product Unit Sp. Gr. Kcal/kg MMBtu/Unit Crude Otl bbl 0.745 11,507 5.409 Natural Gas MCF - - 1.045 LPG (Lquid Petroleum Gas) bbl 0.550 11,834 4.107 Motor Gasoline 0.700 11,612 5.129 Aviation Gasoline-800 " 0.700 10,401 4.594 Naptha 0.775 11,500 5.624 Kerosene 0.798 11,112 5.595 Jet Fuel A-1 0.807 11,762 5.989 Diesel Oil 0.800 11,112 5.609 Fuel Oil 0.850 11,112 5.960 Other Fuels 5.500 Ton of Oil Equivalent 10,000 39.683 Lubricants 0.88 Asphalt 1.05 Fuelwood kg 3,500 Charcoal kg 7,480 Bagasse kg 1,800 Electricity Generation Mwh 11,377 Consumption Mwh 3413 This report is based on the findings of an energy assessment mission which visited Bolivia in January, 1982. The members were Ms. Ursula Weimper (Mission Leader), Takashi Takayama (Economist), Andres Liebenthal (Economist -Conservation Specialist), Luis Luzuriaga (Power Engineer), William Beattie (Forester), Charles McPherson (Legal Specialist), Can Toktar (Reservoir Engineer), E. Mariani (Mechanical Engineer, Consultant), T. Ritter (Geologist, Consultant). Secretarial assistance for this report was provided by Mrs. Angelica A. Fernandes and Mrs. Josefina Regino-Suarez. TABLE OF CONTENTS Page No. I. SUMMARY AND RECOMMENDATIONS........................... 1 Overview ........... . ..o....................... 1 Gas Export Project to Brazil.. ............. 2 Domestic Market................................ 3 Oil Deficit.................................... 4 Investment in Increased Oil Supply.......... 5 Investment in Gas Pipelines............... 6 Demand Management .................................. 6 Foreign Trade........................... .. 7 Electric Power... .. . .......................... 8 Fuelwood and Other Renewable Energy Sources...... 8 Policy Implications ..................................... 10 Investments . ........... .. ............... 10 Energy Pricing................... 11 Hydrocarbons.............................. 11 Electric Tariffs......... ................. 11 Institutions .........0.0... ................ 12 Technical Assistance......................... 13 II. THE ECONOMY AND ENERGY ......... ....................... 14 Background*....................*.................. 14 Recent Economic Developments................... 15 Present Energy Demand Structure.................. 17 Trends in Energy Consumption by Energy Form...... 19 Energy Consumption in the 1980s.................. 21 Projections of Energy Consumption to year 2010... 23 III. ENERGY RESOURCES .................................. . ...... 25 Hydrocarbons.....ooo....oooo&oo.oo.o ....... . 25 Oil Fields............................... 27 Condensate Fields .......*0..............o... 27 Gas Fields .................................. 28 Exploration**........ ................... 28 Hydro-Potential.......0...... ................. 29 Geothermal Energy.................. 31 Coal **...................................... 31 Renewable Resources.............................. 31 Forestry Reserves. ......................... 31 Solar Energy............................... 32 Solar Ponds.................. 33 Windpowero................... ...... 9......... 34 Agricultural Waste Products................. 34 Recommendations...... ..*.. ........................ 36 - ii - Page No. IV. THE OIL DEFICIT. ......... .............. ................... 38 Oil Supply - Demand Balance.... .................. 38 Liquid Hydrocarbon Production Forecast........*.. 38 Projected Oil Balance....... 41 Qualitative Balance..... .............................. 42 LPG Supply-Demand Balance ................... 43 Short Term Options to Improve the Qualitative Balance . . " . ........... . ..*.o... .... . 44 Demand Management ...... . ...... .. ........... .. .... .... 44 Conservation and Substitution Potential.......o.. 44 Industry..................................... 44 Transport.................... .........o..... 48 Energy Efficiency in Transport............. 49 Households and Commerce.................... 50 Gas Pipeline Network....... .............*.... 51 Potential for Asphalt Substitution.....oo........ 55 Recommendations . ........ ..... . ...........o.. 55 V. ELECTRIC POWER............... ... ..... .. . ... . .... .... 58 Interconnected Power Systemo .... .... ... 58 Electric Power Demand Projection............ 58 Expansion of Generating Capacity......o..... 59 Power Generation in Isolated Systems............. 62 Recommendations. ...... ....... .... . ... .. ... ..... 64 VI. REFORESTATION AND POTENTIAL FOR SMALL SCALE RENEWABLE ENERGY USE.......... ... o ... . ..... .... ...... 65 Fuelwoodo.....o.....o...... *.o .. ...... . .. .... 65 Altiplano#...... ........... ........ . . . 65 Tar ja. .. ... .. ... .. ... .. .....0....... 66 Chuquisica .......... *........0. .. ... ... .. 67 C 68 Wood and Charcoal Stoves.........o...o........... 69 Components of an Forest-Based Energy Development 69 VII. ENERGY PRICES...... o....... ..... . ..*o.**o.... 71 Energy Investments............................... 71 No Gas Export Pipelineo.................... 72 With Gas Export Pipeline....*............. 74 Energy Prices......................... ....... 74 Absolute Prices..... ................ .*... 74 Oil Product Prices0.... ....... ...... .... 75 Power Rates..o.. .... .. *. oo....... . .. .. .. 77 Long Run Marginal Power Costs............... 77 Relative Prices ......... .*.8 ... 0.*........... 78 Hydrocarbons. . ... ........ ..... . 78 Incremental Gas Production Costs............ 78 Exploration Costs............ ... ... .... . 78 Development Costs.... ....................... 79 Operating Costs..........,,..*.o.... . 79 Transport Costs........ .................. ... 79 - iii - Page No. Summary of Incremental Gas Costs................. 79 Fuel Oil/Gas Price Ratio......................... 80 Liquid Products Price Structure.................. 81 LPG Prices ...... ........ ...... . . .. 81 Gasoline Prices ............................. -o- 81 Gasoline/Diesel Price Ratio....................- 81 LPG/Kerosene Price Ratio.oo......... ........... 82 Institutions.. .. ............ ................. ...o.. 84 Hydrocarbons... ...... .... .......... .. ........ 84 Power Sector ....... o.......oo-o................. 87 Rural Electricity and Small Scale Renewables..... 88 Recommendations................ .......... -.. 88 Pricing... o......#..... .... ...o... 88 Institutions ......... 0..0.......... ...... 89 VIII. SURPLUS GAS UTILIZATION............. .... ..... 90 Export Project to Brazil................**.*o ...... 91 Reserves..* . *.* .. .. .. . ......... ............ 92 Prices...................... ...........92 International Gas Export Contracts................. 94 Base Prc............. ...94 Brazil's Energy Situation..oooooo...........,..... 97 Industrialization of Natural Gas.o.G.................. 100 Ammonia-Urea....... .................. ... 100 Market Considerations.o........................... 101 Domestic Market for Nitrogenous Fertilizers...... 101 International Markets. ......101 Production Costs...........0....0.............. 103 Synthetic Fuels: Conversion of Gas to Liquids......... 103 Mobil's Methanol-to-Gasoline Process..eo...... 104 Methanol .. ... ......... *66&o Go.....6 104 Domestic Marketa. ...... . 104 Export Potential......... ..,,......... 105 Production Co s t......... 108 SASOL - Synthol and Arge Liquification Processes...... 108 - iv - TABLES Page No. 1.1 1981 Bolivia's Energy Market Structure................ 4 1.2 Change in Pattern of End-Use Commercial Energy Consumption ............ .............. 5 2.1 Hydrocarbons and the Balance of Payment............... 15 2.2 1981 Bolivia's Energy Market Structure................ 17 2.3 Commercial Energy Consumption, 1981.................... 18 2.4 Energy Intensity in the Bolivian Economy....y......... 20 2.5 Domestic Petroleum ?roduct Sales 1971-81............... 21 2.6 Projected Commercial Energy Requirements .............. 23 2.7 Projection of Long Term Energy Consumption........... 24 3.1 Remaining Proven Hydrocarbon Reserves........ 26 3.2 Hydropower Projects: ENDE's Expansion Program 1981-91 30 3.3 Sugar Industry - Energy Balance - 1980................. 35 4.1 Projection - Oil and Condensate Production............. 39 4.2 Gas Production Forecast ............ .......... 39 4.3 LPG Extraction Capacity and Use................. 40 4.4 Liquid Hydrocarbon Balance - 1981-1985................. 41 4.5 Liquid Hydrocarbon Balance - 1986-1990............... .. 42 4.6 Qualitative Imbalance 1981-1990..... 4................ 43 4.7 Energy Consumption at Major Metallurgical Projects..... 46 4.8 Potential Gas Market... ......................... * ... #... 52 5.1 Projected Demand for Electricity - 1990.0.0......... 59 5.2 Forecast - Bolivia's Total Gross Generation & Demand... 60 5.3 Hydro Versus Gas Power Development Sensitivity to Interest Rates and Gas Prices..... . 61 7.1 Investment Requirements Energy Sector.....o........... 73 7.2 Petroleum Product Prices: Retail vs. Opportunity Cost.. 76 7.3 Average KWh Prices of Electricity.............. 77 7.4 Incremental Gas Price.... . ................... o ...... 80 7.5 Current Retail Prices in Energy Terms......i699n.00.. 81 7.6 Fuel Use in Road Transport, 1975-81................ 82 7.7 Residential/Commercial Sector............ 0 .......... 83 8.1 Gas Surplus Estimate... *................o........... 91 8.2 Base Price and Escalation Factors in International Gas Trade.. . o.. . . 0. .......................... . 95 8.3 Brazil: Possible Supply/Demand Refinery Balance in 1985.,...... ........ . .. . . .. . .. . . ..... .. 98 8.4 Brazil: Fuel Prices - Retail Level as of July 1982.... 99 8.5 Brazil: Natural Gas Prices - October 1981..........o.. 99 8.6 Supply/Demand Balance for Nitrogen Fertilizers......... 102 8.7 Urea Export Prices ..................................... 103 8.8 Central and South American Methanol Capacity - 1979... 106 8.9 Surplus/Deficit Analysis................. o ........... 107 8.10 Methanol Prices Projectionr......................... 107 -v - ANNEXES Page Nn 1.1 Gross Domestic Product by Sector of Origin, at Constant Prices............................... ..... 109 1.2 Energy Balance, 1981 ...................................... 110 1.2A Energy Balance - Explicative Notes..................... II1 1.3 Energy Balance - 1981..................................... 114 1.3A 1981 Final Energy Utilization............................. 115 1.4 Energy Balance Projected to 1990 - Base Case........... 116 1.4A Summary of Scenario Specifications..................... 117 1.5 Energy Balance Projected to 1990 - Base Case with Substitution............................................ 118 1.6 Energy Balance Projected to 1990 - Base Case with Substitution and Conservation........................ 119 1.7 Projected Energy Balance to 1990 - Accelerated Growth Case - With Substitution Gas...... ............ 120 1.8 Changes in the Structure of Supply and Demand to 1990.. 121 1.9 Long Term Projection of Domestic Gas Requirements...... 122 1.10 Hydrocarbon Reserves........ .... .. ... ....so .... s... 123 1.11 Result of Past Exploration - 1960-1980................. 124 1.12 Liquid Hydrocarbons Production Mid 1981 Forecast....... 125 1.13 Revised Forecast - Liquid Hydrocarbons Production Forecast ................. . . o . ... . ... . .... 126 1.14 1981 Refining Capacity....................*........... 127 1.15 Gasoline Balance 1981................................. 128 1.16 Petroleum Product Sales on Domestic Market............. 129 1.17 1981 Sales of Petroleum Products on the Interna Market .................................. 0........6.... 130 1.18 Foreign Trade Alternatives for Petroleum Products...... 131 1.19 Gas Supply - Oil Fieldsd.............s.........*..... 132 1.20 Gas Supply - Condensate Fields........................ 133 1.21 Gas Supply - Mainly Gas Fields......................... 134 1.22 1981 Gas Utilization................................. 135 1.23 1981 YPFB Oil and Gas Sales to Industryr............ 136 1.24 Potential Market for Natural GasG............a........ 137 1.25 Potential Market for Natural Gas. ................. 138 1.26 List of Identified Hydroelectric Projects...e......... 139 1.27 1981 Power Generation Capacity......................... 140 1.28 Statistical Data and Forecast for the Power Sector Peak Demand. .......................... . . . . .# 141 1.29 Statistical Data and Forecast for the Power Sector Gross Energy Generation.............. .. .... 142 1.29A Revised Projection of Electric Power Demand............ 143 1.30 Power Generation Alternatives. ................... 144 1.31 Investment Requirements - Energy Sector - Hydrocarbons 145 1.32 YPFB Revised Operational income - 1982................. 146 1.33 Investment Program 1981-87................... ... 147 1.34 Retail Prices of Major Petroleum Products, La Paz 1975-82....................................... ...... 148 - vi - Page No 1.35 Boomerang Area - Exploration and Development Cost Estimate ... .............. ..* ........ . .*.... 149 1.36 Transport Cost Monteagudo-Sucre Extension to Cochabamba and La Paz............... o ............. 150 1.37 Transport Cost - Altiplano Pipeline - Santa Cruz - Cochabamba and La Paz...eo..... ... .... .... ..... 151 1.38 Mean annual Wind :3peed................................. 152 1.39 Global Radiation Values ...... ..6*. **................ 153 1.40 Sugar Production, Residues, and Energy Consumption..... 154 1.41 Alcohol Production from Sugarcane...................... 155 2.00 Brief of Geology. ..... s................................ 156 3.1 Ammonia-Urea: Investment Cost Indicators............... 163 3.2 Ammonia-Urea Complex................................... 164 3.3 Ammonia--Urea CompLex... o..... e.......... o ............. 165 3.4 Methanol: Investment Cost Indicators.......o........... 166 3.5 Methanol: Assumptions for Cost Calculations............ 167 4.0 Technical Assistance Requirements...................... 168 MAPS IBRD 16591 IBRD 16592 IBRD 16593 IBRD 11938R I. SUMMARY AND RECOMMENDATIONS Overview 1.01 Bolivia has a large energy resource base (1230x106 TOE) relative to its present internal needs (1.9x106 TOE). The hydropotential is by far the largest known resource, but only 287 MW of a total potential of 18,000 MW have been developed. its hydrocarbon resources 1/ consist mostly of natural gas (some 6.7x10 CF or 176x106 TOE) and a more modest amount of oil and condensates (187x106 bbls or 25x106 TOE). The modern Bolivia economy is based on liquid fuels, which currently supply almost four-fifths of commercial energy requirements. Natural gas has been recently introduced and its share is still less than 10%. Incremental demand of commercial energy will have to be provided through a balanced development of gas and hydropower production, transport and utilization facilities, in such a way that the domestic and export market potential can be achieved while minimizing the strain on the country's borrowing capacity. These options are evaluated in Chapters 3, 4 and 5. 1.02 The available options to increase energy supplies will have to be complemented by a massive program to assist energy users to increase the substitution of gas for liquid fuels, to reserve the scarcer liquid fuels to priority uses where their value is highest and to increase the overall efficiency of energy use. The essential condition to stimulate this substitution process is the pricing of the individual energy forms at a level that reflects their opportunity costs. In addition, this will require an active and carefully directed program of demand management. 1.03 The rural population of Bolivia still relies mostly on fuelwood for their energy needs. In the Altiplano, this population suffers from a century old shortage of fuelwood which has contributed to its total deforestation and substantial degradation of its soil. This has also extended to the adjacent valleys, which are now largely denuded, especially near the traditional mining areas of the southern Altiplano. Although the improvement of this situation must be supported by a long term program of reforestation and utilization of agricultural wastes, the energy issue cannot be considered in isolation from integral rural development and long range agricultural resettlement policies. Some of the possible initial steps are presented in Chapter 6. 1.04 Overriding these energy problems, Bolivia faces a critical balance of payments disequilibrium that has paralyzed the country and threatens future growth prospects. This makes it urgent to evaluate the energy sector's capability to increase foreign exchange earnings; present gas exports to Argentina already provide 30% of these earnings. (Chapter 8). 1/ Includes proven and probable reserves. -2- Gas Export Project to Brazil 1.05 A long-standing proposal for a gas export project to Brazil is currently being negotiated., The decision to go ahead depends on the certification of sufficient reserves and on the agreement of a mutually acceptable price for gas. 1.06 The mission has evaluated the data on gas reserves and considers that on the basis of present information on the resource base, there are sufficient grounds to be confident that the new export commitment can be satisfied. A reserve evaluation study, shortly to be contracted, will provide further guarantees. 1.07 The exportable gas surplus has been estimated on the basis of internal requirements over a 30-year period (2.7-3.1 TCF) and the existing gas export commitment to Argentina (0.8 TCF). The internal demand is estimated under an extreme scenario assuming that final energy requirements would grow at 4% p.a., that oil supplies would decline by 2% per year and that incremental power requirements would be gas- generated. It has further been assumed that Bolivia would build in the 1990's a commercial sized ammonia-urea complex and possibly a plant to convert gas into methanol or gasoline, and operate these plants over 20 years (Table 8.1). 1.08 The gas export project to Brazil is based on a supply commitment of 400 MMCFD or 2.9 TCF over 20 years. If reserves of gas are substan- tially less than the present estimate for proven (5.0 TCF) and probable reserves (1.7 TCF) or if exports to Argentina continue after 1991, there could well be a supply gap. Therefore, appraisal activities to prove up reserves in known fields and intensive exploration to discover new resources must take place in the event the export project is implemen- ted. On the other hand, 30% of the internal estimated gas requirements correspond to power generation, which could alternatively be supplied through a carefully balanced hydropower development program. 1.09 The price negotiations are crucial for the export project and difficult because of the present oil surplus in international trade and because of Brazil's efforts to restructure its internal energy market. In principle, the two governments had agreed in 1978 to price the gas in terms of the thermal equivalent of the liquid fuels to be replaced in the Sao Paulo area. In the short term, this means that the gas will be related to the price of industrial fuels, mainly fuel oil. There are several possible interpretations to this agreement (paras 8.7), and they produce an estimated price range for gas of US$3.67-5.30/MCF 1/ in Sao Paulo and a border price range from US$2.30-3.92/MCF in 1982 dollars. This compares with a current border selling price to Argentina of US$4.27/MMBtu. 1.10 The large price ranges indicate the difficulty of reaching a favorable agreement. At the lower end of the price range, the project would not cover Bolivia's long term economic costs, considering that the 1/ For gas with calorific value of 1010 Btu/CF. - 3 - production and transport cost of gas to the border is US$1.65/MCF 1/ and that the incremental capital cost of switching to hydropower is equal to some US$0.94/MCF. Another aspect to consider is the net effect on the trade balance. Even at the lower price, the project would generate an increase of about US$200 million in net foreign exchange earnings, assuming that the project's cost (US$800 million) will be financed through international loans and repaid during the first ten years of the project. Other elements to be taken into account in the negotiations are the security of supply which this project would provide Brazil and the contribution that gas would have on the air quality of Sao Paulo. 1.11 The mission also reviewed gas conversion processes (ammonia-urea and liquefaction to methanol and gasoline) and found that at present neither of these provide a realistic alternative to direct gas exports. These projects have a poor rate of return, in some cases even negative net back values for gas, because the domestic market is too small to provide a reasonably guaranteed scale of production and the international market has a high risk because of the excess supply likely to occur during the second half of the 1980's. 1.12 However, there exists a real possibility of industrial complementarity between Brazil and Bolivia. Both governments agreed in 1978 to enter into joint ventures for processing gas. On the basis of this precedent, the mission strongly recommends that Bolivia continue to explore the joint development of a fertilizer and/or a methanol plant with Brazil. (See Chapter 8 for details). Domestic Market 1.13 In 1981, Bolivia consumed internally about 2.8 MMTOE of primary energy and exported 1.9 MMTOE. Natural gas exports to Argentina represented 98% of the exports, the rest consisted of LPG, gasoline and naphthas. The internal demand structure is described in Table 1.1 below. 1/ Assumes an average transport cost between Santa Cruz and the Bolivian-Brazilian border of US$0.62/MCF and a production cost of US$1.03/MCF. Table 1.1: 1981 Bolivia's Domestic Energy Market Structure GROSS SUPPLY NET DEMAND Source 000'TOE % SECTOR 000'TOE % Biomass 987 35 Industry 419 20 Hydro 310 11 Oil 1100 39 Mining 64 3 Natural Gas 441 15 TOTAL 2838 100 Transport 660 31 Intermediate Demand 351 12.4 Residential/ Statistical Commercial 1002 46 Adjustment 342 12.1 Final Consumption 2145 Final Consumption 2145 100 Source: Annex 1.14 1.14 The long range projection of future energy demand is particularly difficult for Bolivia because the energy sector and the economy are undergoing major transitions. In order to provide an analytical basis on which to assess policy options, three alternative demand scenarios were developed. These were based on the assumption that economic recovery would be slow until 1985 and that thereafter the economy would grow on an average rate of 5% per year. A. Oil Deficit 1.15 Projections of oil supply and historic demand trends indicate that a supply deficit of over 13 MBD equal to 40% of the demand for oil products will occur by 1990. This will exacerbate the qualitative imbalance which Bolivia already faces between the refinery yields and the type of products demanded by the market (Para. 4.11). 1.16 The mission recommends a three-pronged approach to avoid the long term oil deficit: (a) supply-oriented investments to compensate for the rapidly declining oil production and so postpone the onset of a major oil deficit; (b) investments in gas transport to substitute for oil; and (c) demand management measures, including pricing policies, to induce energy users to change their pattern of consumption and use energy more efficiently. 1.17 The mission proposes, as a minimum objective by 1990, the reduction of Bolivia's dependence on oil from the current 77% to 55% of total final commercial energy consumption, compensated by increased direct use of natural gas and of LPG derived from gas (Table 1.2). - 5 - Table 1:2 Recommended Change in Pattern of End-Use Commercial Energy Consumption (%) Energy Forms 1981 1990 Oil derived products 77 55 Gas derived LPG 9 23 Natural gas 4 10 Electricity 10 12 Total 100 100 Investment in Increased Oil Supply: 1.18 The investment requirements to maintain an adequate supply of liquid hydrocarbons for the domestic market have been estimated at US$440 million (1980 prices) during the period 1982-1990. During the first years, emphasis should be on the development of already discovered condensate fields and on enhanced oil recovery projects. Some of these projects have already been delayed and their further postponement would lead to an unmanageable oil deficit by 1985. The mission fully supports the early implementation of the Vuelta Grande development project, and suggest that other recently discovered fields, such as Tacobo and Montecristo, be evaluated. Similarly, the mission supports YPFB's endeavours to obtain financing for the Monteagudo and La Pena secondary and tertiary recovery projects and for the LPG extraction plant at Vuelta Grande. It further suggests that feasibility studies for enhanced recovery projects be made for the oil fields of Caranda, Camiri, and Cambeiti, which still contain significant amounts of oil (Chapter 3). 1.19 The actual proven reserves-to-production ratio for liquid hydrocarbons is close to a minimum acceptable level (12 years). Therefore, exploration efforts during the first period should be concentrated on defining the extensions of the fields already discovered and confirming the existence of probable oil and condensate reserves. The prospects of finding new oil fields in conventional structural traps are modest and only stratigraphic traps offer the potential for large additional resources although the exploratory risk is high. YPFB has an interest in initiating this type of risky exploration activity, but the mission considers that while this program may be economically justified it should be postponed to the second half of the decade unless private companies are willing to take most of the risk (para 3.14). 1.20 It is the mission's opinion that the results of the negotiations with Brazil do not affect crude and condensate production, because it is less dependent on the expansion of the gas market than originally thought. The already developed condensate fields provide the bulk of present oil and gas production. During the next 10 years oil production from these fields can only be sustained if gas is reinjected to achieve maximum recovery of liquids. Consequently, their net gas production will -6- increase slowly. During this time, new export commitments will have to be supplied from new and mostly dry gas fields, developed specifically with that objective, and these do not contain large amounts of liquids. This opinion must be validated by a detailed reservoir engineering study for each field with a large gas production potential. Such a study will also provide the basic input for an optimization model, required to program the orderly development of Bolivia's hydrocarbon resources. Investment in Gas Pipelines: 1.21 The Altiplano region uses 90% of the fuel oil and 60% of all petroleum products consumed in Bolivia. Therefore, this region must be the prime target for substitution by gas. There are two separate pipeline projects for the Altiplano with a total investment cost estimated at US$170 million. The first (US$130 million) is a new line from Santa Cruz to Cochabamba and the reconversion of an existing oil pipeline to extend the service from Cochabamba to Oruro and La Paz. IDB has approved a loan for this project, which would have an initial capacity of 33 MMCFD and a final design capacity of 90 MMCFD. 1/ The second project resulted from an emergency decision taken by YPFB, induced by the delay in the disbursement of the former loan. This project is to extend the existing southern Altiplano line Monteagudo-Sucre not only to supply Potosi, but also Cochabamba and connect there with the reconverted line to Oruro and La Paz. This line (US$40 million) is planned to have a gas carrying capacity of 25.7 MMCFD. 1.22 The simultaneous construction of both projects will result in an initial excess capacity in Cochabamba of 39 MMCFD 2/ and in high transport costs. On the other hand, the capacity of the southern emergency line will be fully used by 1985, thus limiting the substitution process in the following years. In view of the investments already made in the expansion of the Monteagudo-Sucre line, the mission recommends that this line be completed and that the decision on the new Altiplano pipeline be postponed to 1985-86, when the market trends become clearer.. 1.23 The mission considers that the project to build a pipeline network in the Tarija department is not justified at this time. Demand Management 1.24 There is scope for energy and, specifically oil, conservation in all sectors of the Bolivian economy, but main emphasis should be placed in the transport and industrial sectors, including in the latter metallurgy and the energy sector itself. 1.25 The transport sector should be given priority because it accounts for 60% of total final demand for refined petroleum products. A 15% reduction in the projected 1990 consumption in transport would save 1/ In the meantime, YPFB has modified the design of the Altiplano pipeline nd will therefore have to renegotiate the loan. 2/ Capacity of 55 MMCFD at Cochabamba versus an immediately connectable demand of 16.1 MMCFD, in Cochabamba, Oruro and La Paz. - 7 - enough liquid fuels to supply the requirements of the household sector, without having to develop gas distribution pipelines in Bolivia's major cities. Among the immediate measures should be included: (a) improving traffic flow in urban areas, by introducing and enforcing parking and stopping regulations, staggering work hours to spread commuter rush over a longer period; introducing priority lanes for mass transport; (b) continuing the import ban on diesel-engine vehicles; (c) sustaining an effort to rehabilitate the road infrastructure and improve road maintenance to increase the efficiency of transport. At the same time, the mission recommends that a study be made to evaluate the feasibility of replacing part of the asphalt (most of which must be imported) used in road paving by mineral sulphur, to reduce the cost of paving; and (d) carrying out studies to improve truck capacity utilization (increasing load factors) in interregional freight traffic. 1.26 In the industrial sector, the expected changeover to natural gas in major plants offers an opportunity to survey their energy requirements and to plan the conversion program in a way that the efficiency of energy utilization (gas, liquid fuels and even electricity) is increased to a level consistent with the best current practice. The mission suggests that YPFB create a technical advisory service to promote and assist industries in their conservation projects. 1.27 Energy surveys and audits should immediately be made in about two dozen major industrial plants, including tin smelters, cement, glass, paper, ceramics, sugar plants and the oil refineries. At the same time, it is suggested that the scope for product waste recovery by pollution control equipment be assessed. Once potential savings are identified and quantified, YPFB should provide technical assistance to evaluate and implement projects and credit lines should be opened to those enterprises which have agreed on an conversion-conservation project with YPFB (paras. 4.16-4.29). Foreign Trade 1.28 Currently, the oil industry has a surplus of gasoline and LPG and confronts an increasing shortage of diesel and fuel oil. This imbalance between refinery yields and the structure of demand cannot be solved through refinery modification. However, in the long term, the substitution by gas will considerably alleviate the problem. 1/ 1/ The Bolivian crudes yield on the average 62% of light fractions, 33% of middle distillates and 5% of fuel oil, while the domestic market demands 52% of LPG and gasolines, 38% of kerosene and diesel and 11% of fuel oil. - 8 - 1.29 In the meantime, YPFB tries to barter its surplus with neighboring countries. Despite high transport costs, which probably cannot be reduced without considerable investment, Bolivia could profitably expand its foreign trade if its industry could use fuel oils with higher sulphur content. The mission recommends that YPFB study the characteristics of the fuel oil burning equipment of its major industrial clients (paras. 4.13-4.14). B. Electric Power 1.30 In early 1983, the national power company ENDE reassessed its expansion program and modified its 1981 investment plan, to take into account the lower than expected growth in energy demand, the country's present financial constraints and the transfer of the La Paz market to ENDE. 1.31 In the new version of the electric plan, it is estimated that demand for electricity would grow at 5.2% per year during 1982-1985, increasing to 6.5% p.a. in the period 1985-1990. Under these assumptions, ENDE considers that, with the capacity additions currently being executed, energy and peak demand can be supplied until 1986, and that final decisions on further capacity expansion and on the choice of the primary energy source for power generation can be postponed a few years. 1.32 The economic choice between gas-based thermal generating capacity and hydro-power expansion depends on the opportunity cost of natural gas. The mission has estimated (assuming a 12% discount factor) that if the export value of gas in Santa Cruz is above US$3.30/MCF then the least cost solution for future expansion is the development of Bolivia's hydropower potential.. 1.33 The mission, therefore, recommends that the hydropower projects be postponed until the negotiations with Brazil have been completed and Bolivia's economic prospects have become clearer. This would also provide the necessary time to resolve the technical issues related to two specific hydropower projects (Illa and Misicuni) and to revise the cost estimates of other projects, including the geothermal alternative. In the meantime, additional capacity requirements can be supplied by the installation of gas turbines or combined cycle. 1.34 Most of the isolated and rural power systems depend on scarce diesel for power generation. ENDE is gradually assuming responsibility for the power supply in these systems, and should consider the possibility of connecting them with the integrated system and/or study the feasibility of installing small hydro plants or other renewable-based generating equipment. C. Fuelwood and Other Renewable Energy Sources 1.35 Bolivia has considerable forest resources and exports about 90,000 m3 high quality wood products per year. However, these resources are located mainly in the scarcely populated tropical lowlands. In the Altiplano, there is practically no remaining forest cover and the large - 9 - rural population relies on shrubs and animal waste to satisfy their energy requirements, with consequent adverse effects on the already highly eroded environment. In the southern tip of Bolivia (Tarija), uncontrolled past deforestation has caused an erosion problem of major proportion. In some of the Altiplano valleys, soils are not suitable for sustained agricultural activities and reforestation could provide the local population a means to increase their agricultural revenue through the sale of timbers, fuelwood and charcoal. 1.36 Total fuelwood consumption is estimated at 2.1 MMton in 1980, of which 42% is in the Altiplano and 29% each in the valleys and the lowlands. In addition some 2,500 tons per year of charcoal are being produced, most of which comes from the Santa Cruz and Chaco regions and is consumed in Bolivia's tin smelters some 1,000 km away. In the Altiplano unconventional energy technologies, such as biogas, windpower and solar energy, are expensive relative to the income of the rural household and require a social and technical environment that can only be brought about through continuous technical support. Furthermore, the conditions of the Altiplano limit considerably their potential to serve as fuel for cooking. The mission therefore recommends that the energy problem of this region be treated as a part of integral rural developmemt programs and energy technologies be adapted taking into account the conditions of each location. 1.37 A national forest program needs to be developed to improve the supply of energy, protect the soils from erosion and to rationalize the exploitation of tropical forests. The mission has identified three specific areas of action. (a) In the Altiplano, it is suggested that the already existing and successful reforestation projects LOS OMASUYOS/LOS ANDES be expanded to meet the demand for seedlings and technical assistance of the intended local population. Furthermore, assistance is required for agricultural research of multipurpose crops (food and energy) and applied forestry research to identify new trees which would survive in the harsh Altiplano climate. In addition, a site should be identified near ORURO to develop a reforestation program with fast growing fuelwood species in order to guarantee supplies of charcoal at lower cost to the tin smelter of VINTO. (b) In the Tarija Valley, the current soil recuperation program should be expanded to avoid further loss of agricultural lands. (It is estimated that some 800 Ha of land are being lost per year). It is suggested that small woodlots and strategically located industrial forest plantations be developed to take the pressure off the few remaining wooded areas and allow regeneration. The program has to be complemented by protection from over- grazing and civil construction works. (c) In Chuquisaca, the regional development corporation has been successful in developing a reforestation and - 10 - conservation project in an area which has almost been completely deforested. This project promotes planting of small woodlots near the local ceramics industry and, thus, reduces the cost of firewood to these companies, creates immediate employment, provides a cash income for the rural population, and improves soil conservation and water management. Technical and financial assistance to increase the capacity of the nurseries, improve species selection, reforestation techniques and monitoring activities and expand into new rural areas are required. (d) In the tropical lowlands, technical assistance should be provided to rationalize exploitation of industrial woods and to improve the efficiency of charcoal production. This program should include forest management techniques, harvesting practices, transport, and use of waste wood. D. Policy Implications 1.38 The considerable investment requirements, the level of energy prices in the internal market and some institutional weaknesses are the main constraints to achieving the sector's objectives. Therefore, the mission recommends some policy changes to overcome these limitations. Investments 1.39 The minimum energy sector investment requirements for the decade are estimated at US$2,300 million, assuming that the gas export project to Brazil is implemented. The annual capital expenditures would raise from about US$210 million per year during the period 1982-86 to about US$300 million per year for 1986-1990. This would represent approximately 53% and 60%, respectively, of the estimated total public investment budgets for both periods. These shares for energy are extremely large considering the need for stimulating the other sectors of the Bolivian economy and the country's limited borrowing capacity, and indicate that the alternative strategy of increasing private participation in the development of the sector should be considered (paras 7.11-7.13). 1.40 Under the assumption that the pipeline project does not materialize, the minimum investment requirements in energy would decrease to about US$1,000 million, with annual average expenditures of US$82 million during 1982-86 and US$142 million during 1986-1990. This represents 21% and 28%, respectively, of estimated total public capital spending. The difference between the two scenarios is mainly due to the direct cost of developing the gas fields and building the export pipeline and to the switch from gas to hydro for expanding the generating capacity of the electric system. - 11 - Energy Pricing Hydrocarbons 1.41 There are two different pricing problems to be solved in the hydrocarbon sector: the absolute price level and the relative price structure (Chapter 7B). 1.42 On November 6, 1982, the Bolivian Government increased domestic oil product prices by about 200% to an average of about US$16 per composite barrel. Although these prices are still 50% below their opportunity cost the measure is a significant step towards restoring the financial position of the oil corporation (YPFB). The mission recommends that prices be pegged to the dollar and raised gradually and periodically at a higher rate than internal inflation and that the Bolivian Government adopts the objective of setting prices at the oppor- tunity cost level. 1.43 The relative prices of oil products and natural gas must be structured so as to give the right incentives to interfuel substitu- tions. The price of gas should reflect its opportunity cost or its supply cost. Fuel oil and diesel prices must be increased to the level of gasoline in energy equivalent terms to reflect their scarcity. Simultaneously, the kerosene price and the price of domestic LPG should be increased to avoid their use as substitute fuels in the industrial sector. 1.44 The opportunity cost of natural gas depends on whether or not a pipeline to Brazil is built. Immediately, the price of gas should be doubled to US$2.00/MCF, to cover its production and transport costs. At that level, it would be equivalent to a fuel oil price of US$11.40/bbl and allow an adequate margin for recovering the expenditures in conversion equipment. Once the exports to Brazil take place, the price of gas in Bolivia should be raised to the equivalent of the export net back in Santa Cruz plus transport cost. Under the lowest price assumptions, this value should be in the order of US$2.80-3.65/MCF. Electric Tariffs 1.45 ENDE is in a very strained financial position. Although the Electricity Code guarantees a 9% rate of return, the corporation achieved only a 6.8% rate of return in 1981. In 1982, the Government authorized a 517% increase in tariffs (54% in February and 300% in November). However, the average bulk tariff (US+3.7/kWh) is still below the estimated long run marginal cost (US45.85/kWh under the hydro-based expansion alternative) and does not permit meeting ENDE's objectives of a 9% rate of return and level of self-financing of 44%. Thus, the mission recommends that tariffs be gradually adjusted upwards by a rate higher than internal inflation with the objective of reaching the level of the long term marginal costs. 1.46 Furthermore, there are considerable differences in the tariffs applied by the regional distribution companies, both in terms of the levels of the energy and demand charges and of their structure. The - 12 - mission urges the Government to proceed as soon as possible with a national tariff study. Institutions 1.47 To meet future energy needs, the Ministry of Energy and Hydrocarbons has to fully assume its responsibility for formulating energy policies, coordinating plans and monitoring the execution of projects within the energy corporations. To this end, a strong and capable planning department must be created, adequately staffed and trained. (Chapter 7C) 1.48 To achieve the desirable changes in the pattern of consumption, the support of the Bolivian population must be obtained through a public information campaign, technical assistance, a legal framework and credit lines for conservation project evaluation and implementation. 1.49 In the hydrocarbons sector, the policy regarding private participation in the activities of the sector must be more clearly defined. The general Hydrocarbon Law and/or its regulations should be revised to adjust the contract model to the current features of international contract formulas. It is suggested that attention be given to forms of private sector participation that, while not conferring any title to production, would directly link contractor remuneration to successful increases in petroleum production. It would also be advisable to modify the tax laws and change the taxable income basis from gross to net revenues. These measures would enhance interest in marginal prospects and induce private participation in peripheral activities. 1.50 The loss of professional staff in YPFB, the inadequate delegation of authority and accountability and the lack of coordination between operating and financial objectives are serious problems that hamper the national oil company's performance. The mission recommends that the following measures to strengthen the institution be implemented: (a) Definition of the specific functions of each managerial and operating unit, with clear formulation of objectives, staff requirements and control systems. (b) Reform of the salary structure, directly relating salaries of management and technical personnel to the level of responsibility, productivity and to the competitive levels in the private sector in and outside Bolivia. (c) Outline of a career development program, taking into account YPFB's long term managerial and technical personnel requirements. (d) Introduction of new and upgrading of already existing administrative and financial control systems and methods, in order to provide management with up-to-date and continuous information on stocks, flow of inputs and outputs, and on financial transactions. - 13 - (e) Introduction of modern analytical tools (models) to plan and evaluate investment strategies and to optimize present operations. (f) Contracting an outside productivity and performance expert, with sufficient authority to induce changes that will result in cost savings. 1.51 In the power sector, the long standing issues with the Bolivian Power Company have apparently been solved by the Government's announced decision to nationalize this private company. The integration of the largest market (La Paz) into the national power company (ENDE), was an additional reason for revising that company's development program. In addition, the Mission recommends that a national tariff study be performed. 1.52 A sustained and orderly effort must be made to improve rural energy supply. The Institute of Rural Electrification does not have the technical and financial capability to execute such a policy. The mission recommends that an alternative institutional arrangement be sought for executing the rural electrification programs. Technical Assistance 1.53 The main areas in which external assistance is required and not yet provided can be grouped as follows: (a) planning at the global energy level as well as in specific fields of the hydrocarbon, power and forestry sectors (b) demand management including energy surveys and audits; and (c) specific studies. This assistance should emphasize training of local personnel to insure continuity of action. A detailed list is provided in Annex 4. - 14 - II. THE ECONOMY AND ENERGY Background 2.01 Bolivia has a population of 5.7 million and an area of 1.1 million km2, divided in three regions with distinct economic and trade patterns. About half of the population is located in the Altiplano, (a highland three to four thousand meters high) occupying about one third of the country's area in the west and southwest. The valleys (Yungas) and the tropical lowlands (Llanos) in the east and north account for 49% of the population and 65% of the area. 2.02 Although each region has a good energy resource base, the Altiplano has currently a huge energy deficit. The Altiplano valleys have a substantial hydropotential and the highlands itself have good solar irradiation but these resources have not been fully developed and no hydrocarbon deposits have been found in this region. The rural population suffers from an acute shortage of fuel, because of the almost complete absence of forest cover (depleted since colonial times). The urban population and the energy intensive mining and metallurgical activities depend on liquid fuels (65% of Bolivia's total consumption), which are met by supplies from the lowlands through a well developed pipeline system. Also, the Altiplano region is now being connected with the eastern electric power system based on natural gas. This offers the choice between expanding the generating capacity by developing the Altiplano hydropotential or importing electric power from the eastern lowlands. 2.03 The lowlands have a low population density but experienced remarkable economic growth during the 1970's, largely based on the exploitation of this region's hydrocarbon resources. In addition, they benefit from relatively virgin agricultural lands with high productivity. This region maintains close trade relations with Brazil and Argentina whereas the Altiplano is better connected with the Pacific through Peru and Chile. 2.04 Bolivia is a vwt exporter of energy. The weight of energy in foreign trade (Table 2.1) has continuously increased over the decade, despite the fact that the exportable oil surplus has ceased to exist and that Bolivia depends now on the willingness of one customer (Argentina) to buy its natural gas. - 15 - Table 2.1: Hydrocarbons and the Balance of Payment (millions of US$) 1970 1976 1978 1980 1981 Net Hydrocarbon Exports: 1/ Crude oil 13.2 112.6 42.3 - - Petroleum Products (1.1) (6.0) (6.8) 22.6 2.5 Gas - 59.9 78.5 220.9 326.2 Total 12.1 166.5 114.0 243.5 328.7 Total Exports 2/ 206 637 705 1,044 1,015 Total Imports 2/ 180 674 912 958 1048 Net Trade Balance 26 (37) (207) 86 (33) Share of Hydrocarbons in Foreign Trade: % Hydrocarbons/Total Exports 5.9 26.1 16.2 23.3 32.4 Hydrocarbons/Total Imports 6.7 24.7 12.5 25.4 31.4 I/ Data derived from YPFB printouts. 2/ Central Eank of Bolivia. Exports and imports include non-factor services. 2.05 The isolation of the individual regions and the relatively small population have not permitted the establishment of strong internal links between Bolivia's productive sectors. Thus, economic growth depends heavily on the level of economic activity in the industrialized world. Bolivia's agriculture accounts for about 16% of GDP, provides employment for over 45% of the labor force and contributes 10% to exports. Mining and hydrocarbons account for 11% of GDP and 90% of exports, but employ only 5% of the labor force. Manufacturing contributes only 14% to GDP and 7.5% to employment. The service sector's share is about 60% in GDP and 40% in employment (Annex 1.1). Recent Economic Developments 2.06 Bolivia is currently going through one of the most difficult phases of its economic history. Since 1979 the country has been facing severe foreign exchange constraints, caused by declining prices for its mineral exports and the increasing cost of foreign debt service. The immediate consequence of the balance of payments disequilibrium and - 16 - fiscal deficit was a slowdown in GDP growth from 5% per year during 1970- 1978, to 2% in 1979, 0.8% in 1980, -0.6% in 1981 and a 7.4% negative growth in 1982. In 1981, the per capita GDP was already 6% lower than in 1978 and urban unemployment has been growing while capacity utilization has continuously declined since 1979. 2.07 The Bolivian government has to make difficult choices to gradually redress the economy. It has opted for a foreign exchange policy that gives priority to the repayment of the foreign debt. This debt equals some two years of export earnings and its service represents in 1982 an estimated 66% of export earnings. To this end, the GOB has curtailed the allocations of foreign exchange, devalued the Bolivian currency 1/, and eliminated subsidies on basic foodstuffs. This strategy has a high cost in terms of foregone output and in social well-being, as already evidenced by the events of 1982. 2.08 Prospects for next few years are dim. The international economic recession has reduced mineral and agricultural prices to an historical low. Even if world economic growth resumes, prices are likely to remain stagnant for some time. Manufacturing exports, that could become competitive as a result of the domestic deflation, start from such a small base that their impact on the foreign trade balance will remain quite small. Adding to these prospects the country's overextended credit position, it becomes clear that the lack of foreign exchange will restrict imports, investment, and therefore growth, unless a new source of foreign earnings is tapped. This is the reason why the long standing project to export natural gas to Brazil has now been revived. If contract negotiations with Brazil are successful, a pipeline could be built in about four years and Bolivia could possibly expect to triple its hydrocarbon export revenue. 2.09 On November 6, 1982, the Government has announced important economic measures. These aim at: (a) introducing some stability in the foreign exchange market by reunifying the two markets prevailing since March 1982 and establishing a single exchange rate of $b200/US$, and (b) by increasing public sector enterprises income and tax receipts. This is especially relevant for the future development of the energy sector. Prices for hydrocarbon products were increased by about 200% and electricity tariffs by 300%. This restores a more adequate level of revenue to finance the crucial investments required to meet projected energy demands. 1/ On February 5, 1982 the peso was devalued from $b25/US$ to $b44/US$. In March 1982 a dual foreign exchange market was established; 40% of all export proceeds were purchased by the Central Bank at the rate of $b44/US$ and the remaining 60% were sold on the free market. In June 1982, the free market exchange rate was $bl20/US$, by September it reached the $b300/US$ mark. On November 6, 1982, the two rates were reunified at $b200/US$. - 17- Present Energy Demand Structure 2.10 In 1981, Bolivia consumed internally about 2.8 MMTOE of primary energy and exported 1.9 MMTOE. (Annex 1.14) Of the internal gross con- sumption, 39% was provided by crude oil and condensates, 15% by natural gas, 11% hydropower and 35% by biomass. (Table 2.2) Of the exports, 98% consisted of natural gas (via the pipeline to Argentina) and the rest of LPG, gasolines and naphthas. 2.11 The per capita energy consumption of 500 kgoe is comparable to that of countries with similar levels of income, but low in relation to other Andean countries (which average 880 kgoe) or the Latin American region (1,010 kgoe) which have a higher level of income. Similarly, there is a large differential between urban and rural energy consumption within Bolivia. On a per capita basis, the rural population uses probably about one-fourth the energy of the urban and then mostly non- commercial fuels. These comparators serve to illustrate the energy implications of economic growth and the need to initiate at an early stage programs to improve the energy supply to Bolivia's rural areas. Table 2.2: 1981 Bolivia's Energy Market Structure GROSS SUPPLY NET DEMAND Source OOOTOE % Sector OOOTOE % Biomass 987 35 Hydro 310 11 Oil 1100 39 Natural Gas 441 15 Industry 419 20 TOTAL 2838 100 Mining 64 3 Intermediate Demand 351 12.4 Transport 660 31 Statistical Residential/ Adjustment 342 12.1 Commercial 1002 46 Final Consumption 2145 Final Consumption 2145 100 Source: Annex 1.3. 2.12 The intermediate demand for energy in conversion, transport and distribution absorbs about 12.4% of gross supply. The consumption of gas in the export pipeline amounts to about 10% of throughput. Two refineries have been converted to use gas as fuel, but the largest one (Cochabamba) still relies on liquids (mainly gasoline). Electric transmission and distribution losses are estimated at 16% of gross generation. Evidently, the efficiency with which energy is used in the energy sector itself can be improved and the mission recommends that this sector be included in the conservation effort. - 18 - 2.13 Table 2.2 above also provides an indication of energy consumption by economic sectors. About 31% of total final energy is consumed in transport; 23% in the mining and industrial sectors and 46% can be allocated to residential, commercial and other sectors. It is estimated that 75% of the residential/commercial consumption consists of biomass (fuelwood, shrubs and dung) which is used with a lower efficiency than commercial energy forms, and about 30% of industrial consumption consist of bagasse used in the sugar cane industry. 2.14 About 60% of final market requirements are supplied from commercial energy sources and liquid hydrocarbons provide the bulk of this demand. Although important gaps in information exist, an attempt to allocate this demand by sectors of consumption and type of fuel is made in Table 2.3 below. 1/ Table 2.3: Commercial Energy Consumption, 1981 (MTOE) Total Liquid Elec- Gaso- Kerosene Fuel Hydro- tri- Sectors LPG line Jet Fuel Diesel Oil carbons Gas city Total Industry 8 - 28 34 116 186 54 32 272 Mining - - 2 17 9 28 - 37 65 Transport 4 389 99 165 3 660 - - 660 Residential/ Commercial 140 - 62 - - 202 - 55 257 Total 152 389 191 216 128 1076 54 124 1254 Shares: % 86 4 10 100 % 14 36 18 20 12 100 Source: Annex 1.3. 1/ For example, most LPG sales are in 10 kg containers aimed for household. However, there is evidence that industries bought them because they are cheaper or because the equipment to supply or use industrial LPG is insufficient. It also appears that a significant portion of LPG was illegally exported. On the other hand, purchases of diesel oil for power generation in isolated electric networks were allocated to intermediate demand and do not figure in final energy consumption. This statistical treatment enhances the relevance of the transport sector as user of diesel oil. - 19 - Trends in energy consumption by energy form 2.15 The trend of commercial energy consumption in Bolivia over the last decade has closely followed the performance-of the economy. During the relatively prosperous first half of the decade, frem 1970-76, when the economy grew at almost 6% per year, the consumption of commercial energy grew at 10.2% per year (Table 2.4). With the slowdown of the economy in the second portion of the decade, GDP grew on the average at only 3% per year, commercial energy consumption growth also fell, to 5.8% per year. The increase in the commercial energy/GDP elasticity from 1.7 to 2.0 between the two periods is due to the commissioning of energy intensive industries and probably to a decrease in the efficiency with which energy is used, characteristic of periods of low capacity utilization. - 20 - Table 2.4: Energy Intensity in the Bolivian Economy Annual Growth Rate % 1970 1976 1978 1979 1981 2/ 1970-76/76-79/79-81 All Sectors Value Added (106$US 1970) 1,031 1,456 1,552 1,584 1,587 5.9 2.9 0.0 Commercial Final Energy Consump- tion-Total (MTOE 1/) 609 1,079 1,294 1,302 1,303 10.0 6.5 0.8 Liquid Fuels 539 928 1,121 1,141 1,122 9.5 7.1 -0.8 Electricity 66 96 114 121 124 6.4 8.0 8.0 Gas - 48 47 30 57 - - 23.3 Energy Intensity (Kgoe/US$) 0.591 0.741 0.834 0.822 0.795 Energy Intensity at the Margin (tons/million US$) 1.00 1.00 1.31 1.74 1.71 1/ Total includes other commercial energy forms such as coke and charcoal. 2/ The energy balance for 1981 was developed by Mission using a methodology slightly different from the previous balances prepared by MEH. In ordere to facilitate comparison, adjustments were made in the figures for 1981 given in this table. Source: Energy Balances - Ministry of Energy and Hydrocarbons 1970-79. Mission estimate 1981. 2.16 The trends in the liquid petroleum consumption are shown in Table 2.5. It is to be noted that since 1978 sales of all oil products excluding LPG have stagnated and were 4% lower in 1981 than in 1978. Diesel oil and aviation fuels' sales have grown on the average by about 15% per year during the decade. Pricing policies have stimulated the use of diesel oil in transport and its use as industrial fuel has further been encouraged because of the progressive deterioration of the quality of fuel oil available in the Bolivian market. The rapid increase of - 21 - demand for aviation fuels reflects the country's landlocked situation and the poor internal road and railway networks. Table 2.5: Domestic Petroleum Product Sales 1971-81 Average Annual Change Energy/GDP % Elasticity Total Sales 8.5 2.01 LPG 1/ 34.2 8.07 Gasolines 5.8 1.37 Diesel 14.6 3.45 Aviation Fuels 15.1 3.55 Fuel Oil 3.6 0.86 1/ Kerosene sales grew at 4.3% per year between 1971 and 1978. After that year they declined on the average by 15.4%, being substituted by LPG. Source: Annex 1.16 2.17 About 72% of the urban and 9.1% of the rural population have access to electricity and the average per capita consumption (268.5 kwh in 1981) is low compared to the Latin American average (850 kwh). The historical figures indicate that electricity sales increased from an average of 6.5% p.a. during 1970-76 to 8% p.a. in 1976-1981, and the elasticity with respect to GDP jumped from 1.06 to 2.76. However, this explosion was regional and due to the fast industrial expansion in the Santa Cruz area and to a lesser extent in Cochabamba, and to ENDE's capability to finance new generation facilities to supply this attractive market. Sales in the Oriental (Santa Cruz) System grew at an average of 20% p.a. and in the Central (Cochabamba-Oruro) System at 8.8%, whereas the demand in the rest of the country rose on average by 5.5%/year (Annex 1.29). ENERGY CONSUMPTION IN THE 1980s 2.18 The long range projection of future energy demand is generally subject to a wide margin of error and this task is made particularly difficult for Bolivia because the energy sector and the economy are undergoing major transitions. In order to provide an analytical basis the mission has opted for the following scenarios for 1990: (a) Baseline Scenario: this projection is based on global energy consumption/GDP elasticity of 1.2 and a commercial energy consumption/GDP elasticity of 1.7. Under this assumption, final commercial energy demand would be 58% - 22 - higher in 1990 than in 1981, and the oil deficit would be equal to 610 MTOE or about 13MBD (Annex 1.4). (b) Baseline Scenario with Substitution: in order to compensate for the oil deficit, gas would have to substitute for all liquid fuels in the industrial sector and also provide for 32% of the commercial energy requirements of the residential/commercial sectors. This implies a huge investment effort in the construction of gas distribution networks in major industrial cities (Annex 1.5). (c) Baseline Scenario with Substitution and Conservation: It is reasonable to assume that the efficiency with which energy is used in Bolivia could be increased by at least 15%, and that as a result the commercial energy/GDP elasticity would decrease to 1.2. In this projection, electricity supply was maintained at the level projected in scenario (a), thus implying additional replacement of liquid fuels. Under this scenario, the oil deficit would be reduced to 171 MTOE, equivalent to about 18 MMCFD of natural gas which would be supplied exclusively to the major industrial consumers (Annex 1.6). (d) Accelerated Growth Scenario with Substitution: In order to assess a more extreme case, the final demand of scenario (a) was increased by the specific industrial projects the Bolivian Government and private enterprise are considering for implementation during this decade. Furthermore, ENDE's projection of power demand (Chapter 5) was introduced. Under these assumptions, the oil gap in final consumption to be covered by natural gas would increase to 750 MTOE or 78 MMCFD (Annex 1.7). 2.19 In all the former projections it has been assumed that the incremental power requirements of the integrated system will be gas generated, those of the isolated networks are diesel fueled. Similarly, most of the refinery fuel is natural gas. These requirements have to be added in order to arrive at primary demand for energy, indicated in Table 2.6. - 23 - Table 2.6: Projected Commercial Energy Requirements (MTOE) 1991 Baseline Accelerated Growth With With 1981 Baseline Substitution Substitution and Conservation Total Primary Requirements 1846 2833 2430 3255 Hydro 310 310 310 310 Oil 1/ 1095 1608 980 980 Gas 441 915 1140 1965 Final Domestic Demand 1254 1980 1683 2391 Oil Products 961 1533 932 920 LPG from Gas 115 167 379 459 Natural Gas 54 79 171 750 Electricity 124 201 201 262 1/ Does not include natural gasoline obtained from gas and processed in the refineries. This stream is included in gas. Projections of Energy Consumption to year 2010 2.20 The relevance of natural gas in the Bolivian economy is likely to increase substantially over time to satisfy domestic energy require- ments and to serve as an input into industrial processes, as well as a generator of export earnings. 2.21 The domestic market has a first claim on gas reserves. In the case of Bolivia, gas will substitute for oil deficit which otherwise would have to be imported. The length of time over which domestic gas requirements are computed has a significant impact on the exportable surplus volume, and then on the gas utilization policy. Many countries have fixed this period as a function of their energy options and the lead time estimated for new technologies to economically replace natural gas. For instance, Canada has set aside gas reserves equivalent of 30 years domestic requirements; New Zealand has enacted a conservation policy limiting production to a level which will leave 50% of the Maui field reserves in place in the year 2000, in order to assure supplies to direct consumers of gas through 2030. 2.22 The definition of this period is crucial in the case of Bolivia, because internal gas utilization has only started, and it will take at - 24 - least 20 years to develop a gas pipeline network to supply the main consuming sectors in regions with highest population densities. To estimate the potential demand for gas during the next three decades, the following assumptions were made: (a) during the 1980's, demand would follow the path described under Scenario C (para 2.18); (b) the Bolivian economy would grow at about 4% p.a. during the following two decades, and the energy/GDP elasticity would be 1.2 in the 1990's and be equal to one thereafter; (c) Bolivia's potential hydro would not be developed during the period and oil and condensate production would decrease by 2% p.a. (d) natural gas would provide all incremental demand of the final consuming sectors as well as supply the energy requirements of the energy sector itself (Table 2.7). 2.23 Under this extreme scenario, natural gas would supply 59% of final energy consumption and 69% of total demand (including intermediate and final uses). It is to be noted that 30% of total gas consumption would be used for power generation. However, Bolivia has a large hydro and geothermal potential that could be developed, releasing natural gas for alternative uses. The final choice must be based on a realistic economic analysis. Table 2.7: Projection of Long Term Energy Consumption (in MTOE and %) 1981 2000 2010 MTOE % MTOE % MTOE % Intermediate Demand 448 1579 2511 Natural Gas 372 1418 2318 Oil 76 161 193 Final Consumption 2145 100 4125 100 6106 100 Biomass 891 42 898 22 898 15 Electricity 124 6 374 9 645 11 Liquid Hydrocarbons 1076 50 1118 27 939 15 Natural Gas 54 2 1735 42 3624 59 Source: Annex 1.9. - 25 - III. ENERGY RESOURCES 3.01 Bolivia's commercial energy resources are estimated at 1,230 million tons of oil equivalent, which at the present rate of domestic consumption would be sufficient for the next 400 years. However, this relative abundance glosses over potentially severe supply constraints, because of the unequal rate at which resources are currently being exploited. The resource base includes 18,000 MW of feasible hydro potential 1/ (84%), 6.7 trillion cubic feet of recoverable gas reserves 2/ (14% of resources) and 187 million barrels of oil (2%). Furthermore, Bolivia has excellent solar irradiation and a large agricultural potential, which could provide renewable energy. Bolivia also has a geothermal zone, deposits of uranium in quantities not yet defined and indications of coal and lignite. What is needed is a well structured program to develop these resources over time at a minimum cost and with maximum and equitable benefit to the various groups that comprise the Bolivian society. Hydrocarbons 3.02 The proven recoverable reserves of Bolivia as of July 1, 1982, are estimated to amount to 26 MMB of crude oil, 78 MMB of condensate and 5.0 TCF of gas (Annex 1.10). 3/ 3.03 The probable recoverable reserves are estimated to amount to 83 MMB of crude and condensate, and 1.7 TCF of gas. The probable reserves include the fields recently discovered by YPFB (Tacobo, Huayco, and Montecristo), and by Tesoro (Los Suris, Escondido and Taiguati). Furthermore, possible reserves are estimated at 17 MMB of crude oil, 43 MMB of condensate and 1.6 TCF of gas. This estimate only reflects the statistically calculated results expected from the next five years exploratory program. 3.04 The history of exploratory activities shows that 112 structures have been tested and 34 discoveries have been made. More than two-thirds of the resources discovered consist of natural gas and more than 75% of all hydrocarbons are contained in only 7 fields. Annex 1.11 relates exploratory efforts during the last 20 years to the discovery of reserves. It shows that the overall success ratio is high (one out of five exploratory wells is a producer), but that results are declining. 1/ Calculated at the thermal equivalent of 2867 kcal/kWh, over 40 years. 2/ Includes proven and probable reserves. 3/ All reserve estimates were obtained from internal sources of YPFB. The company does not report changes in reserves' levels, due to new discoveries, extension of field limits or increased recovery factor. Proven reserves include Class I and II; probable reserves include Class III as of July 1981, plus estimates of recent exploration results. - 26 - While 195 BCFGE I/ were found per successful well in the 1960's, only 115 BCFGE were discovered in the 1970's. Furthermore, practically no oil fields have been discovered in the 1970's. However, it is important to note that three discoveries in 1978 have found 20% of the total gas reserves. This development is undoubtedly due to better seismic techniques that more clearly outline the actual structure of the Bolivian geology. 3.05 A preliminary geological brief (Annex 2) expressed caution with respect to the complex geological structure of Bolivia, which introduces a large degree of uncertainty in any reserve estimate. However, the brief gives further reasons to believe that in traditional areas (Subandean Basin and a portion of the Chaco-Beni lowlands) additional, but moderate amounts of hydrocarbon resources could be found. YPFB intends to extend exploration to new areas (stratigraphic features in the northern flank of the Subandean), expecting to find larger sized deposits. Based on the present volume of proven and probable gas reserves, the mission recommends careful alloctions of this resource to those projects with the highest returns for Bolivia. 3.06 Most fields contain gas and condensate and therefore an increase in oil reserves follows much the same pattern as the additions to gas reserves. The major exception to this rule is the Boomerang Hills Area, where the gas is dry. The relative proportion of oil to gas reserves contained in the fields permits grouping them into three categories. Their level of remaining reserves is indicated in Table 3.1: Table 3.1: Remaining Proven Hydrocarbon Reserves 1/ Liquids Gas Total Resrves Class I, II and III 187.2 MMB 6696 BCF Oil Fields 26.9 5.8 Condensate Fields 67.7 54.3 Gas Fields 5.4 39.9 Total 100.0 100.0 I/ YPFB uses three categories of proven oil reserves I, El and III. There is a discussion within YPFB on whether group III should be included in probable reserves as done in this Table. Data to July 1, 1982. Source: Annexes 1.10, 1.19, 1.20, 1.21. I! Billion cubic feet of gas equivalent. - 27 - 3.07 Oil Fields: About 27% of Bolivia's recoverable liquid reserves are located in these fields. The crudes produced have a density ranging from about 470 to 500 API. 1/ Some already depleted fields contained heavier crudes, such as Bermejo in the South, with 25.30 API. All these fields produce associated natural gas and the gas/oil ratio has increased over time up to 10 MCF/B. These oil fields are generally small in size and are in an advanced state of depletion, with productive capacity declining at a rate of 20% per year. Only two (Camirt and Caranda) originally contained reserves of more than 50 MMB and only two additional fields (Monteagudo and La Pena) contained more than 10 MMB. Only five fields have remaining proven reserves of more than 1 MMB. These are Monteagudo (19 MMB), Caranda (16 MMB), Camiri (10 MMB), La Pena (3.5 MM) and Cambeiti (1.3 MMB). 3.08 The mission recommends that reservoir engineering studies be undertaken to assess the feasibility of enhanced recovery projects in these fields to compensate for the high rate of decline in production. YPFB, which owns them, has already initiated secondary and tertiary recovery projects in Monteagudo and La Pena. In Monteagudo, a first pilot water flooding project 2/ was successfully implemented in 1980 and a full fledged project was intended to come on stream in 1981, but has been delayed due to lack of financing. 3/ The project is of vital importance, because it still could reverse the field's declining production by 1985-86 from 2.4 MBD in 1982 and 1.2 MBD in 1985 to a peak of 5.2 MBD in 1990. Simultaneously, YPFB has initiated supplementary recovery at La Pena, where it injected into the formation some 30M m3 of LPG in 1981, obtaining the recovery of an equivalent volume of a 490 API crude oil. The economies of the project seem to be adequate, because YPFB hopes to later recover the injected LPG. The company plans to double LPG reinjection. 4/ This product is produced in Colpa some 30 kms to the north of La Pena. 3.09 Condensate Fields: About 68% of liquid reserves and 54% of proven gas reserves are contained in these fields. They produce condensates with a density ranging from 55 to 700 API. The gas/oil ratio of originally discovered reserves varies between 8 MCF/B (Tita) to more than 40 MCF/B (La Vertiente). This group contains the largest sized deposits. Rio Grande had original recoverable reserves of 78 MMB and 1.4 TCF of gas. Remaining reserves are estimated at 23 MMB and 1.1 TCF of gas. The other large field is Vuelta Grande, which is estimated to contain 44 MMB of condensate and 800 BCF of gas. Other fields with 1/ Density is indicative of the proportions of light, medium and heavy distillates that can be obtained when processing these crudes. The higher the API number, the lower the yields of heavier products. 2/ Financed by IBRD - under the Petroleum Appraisal Drilling and Recovery Engineering Project 1979. 3/ Included in the proposed IBRD loan for Vuelta Grande. T/ It has presented a request for financing this project to IDB. - 28 - remaining condensate reserves of more than 10 MMB are Porvenir and Montecristo. I/ 3.10 The joint gas-oil production imposes the need for carefully simulating the reservoirs and reevaluating their production programs. Maximum total physical recovery of liquids is achieved over time when gas is reinjected to maintain the reservoirs pressure. In the retrograde gas condensate fields, reinjection is essential and no gas should be produced until such time as the revenue from condensate recovery does not cover reinjection costs. In the case of the Vuelta Grande field, it is estimated that the economic limit for condensate production will be reached 20 years after initial exploitation, and only then will the field be operated as a gas field. Technically, however, it is possible to have a net gas production at an earlier stage. Nitrogen seems to be a good substitute for natural gas as a pressure maintenance agent. Economically, the substitution is feasible if the market value for natural gas is higher than the production cost of nitrogen. This is not the case under present economic conditions. 3.11 Gas Fields: Only in one of the structures of the Boomerang area has oil been found. In general, these fields contain only small amounts of condensates and the gas is usually dry. The gas fields located northwest of Santa Cruz in the Boomerang area are only now being evaluated; 2/ other gas fields might have been discovered in the past but were not evaluated because there was no market for this resource. 3.12 The gas produced in the first two categories of fields generally contains heavier hydrocarbons that can be separated in two streams: (a) natural gasoline (pentanes and heavier) and (b) LPG (propane and butane). On the average, about 4 to 6% of the gaseous volume consists of heavier hydrocarbons that can be extracted. The economic feasibility of LPG recovery from the gas of the Boomerang area will have to be studied. Exploration 3.13 Bolivia's hydrocarbon resources consist mostly of natural gas. Therefore, wildcat exploration for oil will not be an attractive investment until the market for gas is developed. 3.14 Should the market remain restricted to domestic requirements and exports to Argentina, then efforts should be concentrated only in defining the extensions of the fields already discovered. The prospects of finding new oil fields in conventional structural traps are modest. Therefore, YPFB has an interest in initiating exploration for stratigraphic features where it hopes to find oil, although the exploratory risk is considerably higher and will result in higher i/ The latter was discovered in 1976 but has not yet been fully evaluated. It does not figure in some of the production forecasts prepared by YPFB. 2/ IBRD-IDB Engineering Loan. - 29 - costs. The mission considers that investments in exploration for stratigraphic features are economic, but should be postponed until the present critical financial constraints ease. 3.15 Should the export project to Brazil materialize, then exploration is necessary and financially feasible. In that case, YPFB, which holds in reserve the areas with the highest hydrocarbon potential, could enter into favorable agreements with private operators, inducing them to risk capital in exploration for stratigraphic traps and in other high risk areas (see Chapter 7). 3.16 In its five year plan 1981-85, YPFB proposed intensifying exploration with investments of some US$320 million during the period. Three-fourth of the program was to be implemented by YPFB, the rest by existing private operators. Under the financial constraints that have developed since 1980, this program must be revised. The mission recommends that in the immediate future YPFB concentrate its efforts in fully evaluating already detected structures and investigate alternative measures that would permit participation of private companies in exploring higher risk prospects. 3.17 The Bolivian Government has invited private participation in exploration several times in the past. At present, only Occidental (US) and Tesoro (US) operate in Bolivia. YPFB has opened new bids in 1981 and intends to assign three areas located in the northwest Subandean Foothill Area, the Madre de Dios portion of the Beni, and to the East of Santa Cruz. These appear to be the only unassigned areas that have the prerequisites for hydrocarbon production. As an enticement, the private companies were offered a share in potential future markets for gas. In future biddings YPFB could consider tying exploration within the reserved known producing area to exploration for stratigraphic traps along the eastern flank of the basin. Hydro-Potential 3.18 The economically exploitable hydroelectric potential has been estimated at 18,000 MW with an annual generation of 90,000 GWh, enough to cover the growth of electricity demand for another 40 to 50 years. Numerous studies have been made of some of the rivers, and projects with a capacity of some 10,300 MW and generation of 51,000 GWh have been identified (Annex 1.26). At present, installed hydroelectric capacity (287 MW) represents less than 2% of Bolivia's potential. 3.19 Some of these projects are of very large dimensions and far removed from major demand centers. Their development cannot be envisaged at present. Some others imply joint development with neighboring states and are being studied under an 0AS regional effort. Another group of projects serves multiple purposes (electricity, irrigation, drinking water), and therefore each region takes active interest in the decision making process. This is the case of Misicuni in Cochabamba, Illa in Sucre and Rositas in Santa Cruz. Restraint should be exerted by the central government to avoid regional pressures that lead to less than - 30 - optimum investment decisions. The projects included in ENDE 's 1981 expansion program are indicated in Table 3.2. 11 Table 3.2: Hydropower Projects: ENDE's Proposed Expansion Program 1981-91 Project Firm Capacity Annual Generation Status and Comments (GWh) 1. San Jacinto 7 21 Construction contracted in December, 1981. 2. Sakahuaya 72 362 Final design and bidd- ing documents ready. 3. Huaji 26 (Feasibility study in 180 (progress. 4. Pachalaca 14 (Generation for the La Paz (market. 5. Icla 90 365 Engineering design in progress. Multi-purpose project. 6. Misicuni 104 460 Feasibility studies completed. Multi- purpose project. 7. Palillada 110 632 Feasibility studies in progress. 8. San Jose 150 840 Only preliminary studies available. 3.20 The evaluation of the expansion program has raised several questions: (a) what is the opportunity cost of capital at which relevant comparison between hydro and gas-based thermal power projects should be made? (b) what is the future economic price for natural gas? and (c) are quoted investment costs reliable and do they reflect realistic appraisals? These questions are discussed in Chapter 5. 1/ In February 1983, ENDE reassessed this expansion program; in the new plan only single purpose hydroelectric projects are included (Huaji, San Jose and Sakahuaya). - 31 - Geothermal Energy 3.21 Bolivia has favorable prospects for developing its geothermal potential, which would make it possible to install at least 350 MW 1/ of electric generation. The most promising field "Sol de Manana" has been identified in the area of Laguna Colorada. One well drilled indicated the existence of high enthalpy conditions (1500C at 127 meters depth) but did not provide sufficient information on the deep hydrogeologic conditions of the field. Further geological and geophysical investiga- tion is needed before an exploratory drilling program can be envisaged. A recent pre-feasibility study 2/ for this field, concludes that a 30 MW power plant could be installed at a cost of US$2,000/kW in 1980 dollars (US$50 million for the development of the field and the power plant and US$10 million for a 200 kms long transmission line to Atocha.) The project will have to be further studied taking into account its remote location with respect to the power markets, and compared with hydropower alternatives. Coal 3.22 Although the coal and lignite deposits found in Bolivia do not appear industrially exploitable at present, the Geological Institute should evaluate more fully their size and characteristics. Consideration should be given to small scale exploitation, to serve as household fuel for the Altiplano rural population. 3.23 An antracite type of coal deposit exists near Copacabana on the Lake Titicaca. Reserves of about 200 thousand tons of coal have been established with an ash content of 35-50%, sulphur 0.38-13%, and volatile materials 14%. Less known indications of coal exist in the department of Cochabamba (Apillapampa and Apopaya). Lignite appears in Cochabamba, Tarija and Chuquisaca. Finally, some peat deposits have been spotted in the Altiplano (Ulla-Ulla and near La Paz). Renewable Resources Forestry Reserves: 3.24 Bolivia has large forestry reserves and is a considerable exporter of high quality wood products. However, these resources are located mainly in the scarcely populated tropical lowlands. In the Altiplano, where 50% of the population is located, the availability of energy is very low due to the climatic conditions and the removal of forest cover since colonial times for fuelwood and for the production of pit-props (mine timbers) and for the smelting of ore (silver, tin, gold). In the Altiplano plateaus (about 3,700 meters of elevation), oxygen tension is 40% below that at sea level, temperatures are low and 1/ "Evaluacion y Aprovechamiento de Recursos Energeticos en Bolivia," UNDP, 1979. 2/ "Proyecto de Desarrollo Geotermico del Area de Laguna Colorada", Electroconsult, Italia. March 1982. - 32 - precipitation is seasonally limited. Changes between day and night temperatures are in the order of 17oC and night frosts are frequent. The combination of seasonal dryness and low and rapidly changing temperatures retards the decomposition of organic matter. This slows nutrient cycling and the formation of soils. Furthermore, poor soil composition and atmospheric conditions, which enhance water runoff and evaporation, increase the general dryness of the area. As a result, growth of plants is slow and confined to grasses and herbs and occasional pockets of low trees. Another region in which uncontrolled deforestation has caused an erosion problem of severe proportions is Tarija in the south-west of Bolivia. 3.25 By contrast, the northeastern tropical lowlands of Bolivia are heavily forested and thinly populated. Forest removals are accelerating for industrial purposes (wood is a major export product) and for agricultural colonization, especially in the Santa Cruz region. At present, there is little control on the rate at which extraction takes place. 3.26 Despite these difficult conditions, reforestation is a financially, economically and technically viable activity as has been shown by a number of successful programs. These, however, must be significantly expanded and new ones begun, if adequate supplies of fuelwood, charcoal and other forest products are to be provided, and if erosion control and agricultural production are to be improved. There are three particularly important programs: Los Omasuyos/Los Andes project in the Altiplano, PERTT in Tarija and CORDECH's project in Chuquisaca. The mission strongly recommends that the experience of these projects be evaluated and that the program be substantially expanded (para 6.03-6.13). Solar Energy 3.27 In principle, solar radiation in Bolivia is suitable for thermal and photovoltaic applications. Global radiation values are estimated between 350 and 750 cal/cm2/day. The highest values are reported for the Altiplano region (Annex 1.39). 3.28 Only limited efforts have been made to disseminate solar technologies in Bolivia. A few private companies have attempted to build solar water heating systems for households in urban areas. Another company is applying passive solar energy to space heating in a low-cost housing project in La Paz. The Institute of Physical Research, in a joint rural development program with the World Bank, has constructed greenhouses in the Altiplano (Ulla-Ulla project). 3.29 In the Altiplano, solar greenhouses are very cost effective. The experience has shown that vegetables and other cash crops (flowers) can successfully be grown, improving the livelihood of the local rural population. It is recommended that the rural extension agencies be endowed with the necessary technical and financial resources to disseminate this technology and to provide adequate follow-up assistance. - 33 - 3.30 Private entrepreneurs have introduced solar water heating systems in Bolivia since 1980 and a number of units have been installed in single-family houses in La Paz, Cochabamba and Santa Cruz. However, the penetration rate has been slow due to the low price of petroleum products and electricity rates in the Bolivian market and because of the local equipment manufacturers' lack of technical expertise. 3.31 It can be estimated that the installation of solar water heaters in 15,000 residential and commercial buildings could reduce the expansion requirements of the integrated power system by some 30 MW. I/ Assuming that the installed cost of these systems ranges between US$200-300/kW and that hydropower has a development cost of US$2,000/kW, the net capital savings exceed US$50 million. It is therefore recommended that the Ministry of Energy and Hydrocarbons and ENDE undertake a study to determine what set of policies would be required to promote this option. First of all, technical assistance should be obtained to insure good quality equipment and installation. Furthermore, institutional arrangements to alleviate the first cost barrier of installing the solar water heaters will have to be investigated. The power companies (preferably ENDE) could consider financing the installation and supervise the maintenance of these systems, recovering capital and operating charges through the regular electric bills over a suitably extended period. ENDE would benefit from improved load factors and demand manage- ment, and cheaper capacity expansion. Solar Ponds 2/ 3.32 The Government requested comments on the option of generating electricity from Bolivia's largest salt lake, Solar de Uyuni, located approximately 400 kms south of La Paz. There were no data available on the lake's characteristics. However, the mission was informed that the lake is very shallow, with depths not exceeding 50 cms (1.6 ft) and has an area of about 17,000 km2. Thus, it has a theoretical energy potential of 85 GW. 1/ Solar water heaters can displace up to 3-4 kW of capacity demand per urban high income household for 200-300 kW (electric) installed, depending on the coincidence of water heating demand with power system peak demand (commonly 50-70% coincidence). 2/ Salt ponds collect and store solar energy. Normally, salinity gradient salt ponds are characterized by a surface convective zone, and a gradient zone that serves as a transparent insulator for a lower convective zone where solar radiation is collected and stored as heat. A heat exchanger is required to extract this heat. As salt is added to create a greater salt concentration on the bottom than on the surface to restrict convection, the bottom temperature is much greater than the surface water. Optimum performance requires keeping the surface zone thin and maintaining a thickness of more than one meter in the gradient zone. - 34 - 3.33 Solar ponds should be considered as a long term alternative for power generation. However, the technology has not been completely proven and only one industrial sized pond (5 MW) is currently being built in Israel at a cost of US$20 million. Other projects are being considered in Cyprus and Tunisia. The mission therefore recommends a preliminary study to obtain data on which to evaluate the real potential, on items such as the salinity level in the lake, evaporation rates, subsoil structure, underground water movement, prevailing wind speeds, etc. Bolivia should also keep abreast with the developments of solar ponds in the world. This would allow Bolivia to incorporate this source in its long term power strategy, and compare it with the hydropower and geothermal options. Wind Energy 3.34 The available data on mean annual wind speeds for various regions of Bolivia (Annex 1.38) indicates low to medium wind regimes suitable only for water pumping. 3.35 In 1981, a Savonius rotor windmill was built in the Altiplano to test the feasibility of using the rotor in conjunction with a manual water pumping system. The lack of reliability of the Savonius rotor performance, even after 20 years of piecemeal experimentation in several developing countries, hardly justifies the continuation of this research line in Bolivia. It is suggested that in future water pumping projects the design of the more conventional multi-bladed windmills and their more recent variants should be used. Agricultural Waste Products 3.36 The dispersion of agricultural activity and the cost of collect- ing vegetal and animal waste is a major obstacle for the use of this biomass as an energy source. Major crops in Bolivia are sugar cane, corn, wheat, rice, potatoes, cassava, cotton, soybeans, coffee, etc. A conservative estimate of the energy value contained in the residues of Bolvia's 1980 agricultural production indicates that an equivalent of 10 MB/D of oil is potentially available from this source. Only a small fraction of this potential is being used as boiler fuel in the sugar industry and as cooking fuel by the rural population of the Altiplano. It appears that, in general, residues are plowed under in Bolivia. 3.37 Given the site specific nature of agricultural residues, further research is necessary to identify localities where supply and demand can be matched and economic projects developed. In this regard, it is suggested that the US AID 1/ initiative to develop and apply a survey and planning methodology for assessing rural energy needs and village level energy resources be further pursued. 1/ USAID - 1980: A Rural Energy Survey and Planning Methodology for Bolivia", prepared by Practical Concepts Incorported. - 35 - 3.38 Bolivia's sugarcane productions and mills are located in the Departments of Tarija and Santa Cruz. At present bagasse does not satisfy the mills joint sugar and alcohol production energy needs, and supplemental natural gas, oil and firewood are used (Annexes 1.40- 1.41). The analysis of the theoretical energy balance for the sugar cane sector shows that energy is being used at about 41% efficiency (Table 3.3). Table 3.3: Sugar Industry - Energy Balance - 1980 Total Energy 109Btu Requirements 6 Sugar Cane Processing 2,579,506 tons x 1.38x10 Btu/ton 1/ = 3560 Alcohol Production 25,854,000 Its. x 11.22 Btu/It. 2/ = 0.3 Total Requirements: = 3560.3 Energy Used Bagasse 850,000 tons x 8.8x106 Btu/ton 3/ 7480.0 Natural Gas 576.7x106CFx1045 Btu/CF = 602.7 Oil (Diesel) 8650 tons x 44x106 Btu/ton = 380.6 Fuelwood 9973 tons x 13.9x106 Btu/ton 138 6 Total Energy Used = 8601.9 Difference 5041.6 Efficiency of Use = 41% 1/ World Bank Report No. 3510-MAS, Mauritius: Issues and Options in th Energy Sector, P. 44. Theoretical energy requirements is 1.38x10 Btu/ton of sugar cane. 2/ Alcohol from molasses has an energy requirement of 0.56 kcal/kcal of ethanol. Ethanol's calorific value is 5.048 kcal/1tr. 3/ This energy potential is calculated using a very conservative heating value of 8,800 Btu per kg. of bagasse with 50% moisture. 3.39 The mission recommends that a study be made to assess the economic implications of achieving a higher efficiency in the use of bagasse and other sugar cane residues. In a well managed sugar mill, a net bagasse surplus of about 15 to 75 kg (dry weight) 1/ per tonne of cane should be available for alternative uses, depending on the level of 1/ According to "Briquetting surplus sugarcane bagasse to a material suit- able for export as a pulp and paper feedstock" published by the Division of Chemical Technology (Technical Paper No. 11), Commonwealth Scientific and Industrial Research Organization, Australia 1982. - 36 - technology applied and percentage of bagasse dry weight (fibre) per tonne of cane fresh weight. The latter depends on seasonal as well as species factors. Furthermore, in harvesting sugarcane the following values of residues 1/ are generally left on the field. It has been proven that in leaving these residues on the land does not increase the fertility of the soil. Therefore, this material, which is equivalent to almost eight times the bagasse surplus, could be used for energy purposes. Sugarcane Residues Weight per tonne of cane (kg) Fresh Weight Oven-dry Hash 90 72 Top and Green Leaves 170 51 TOTAL 260 123 It is recommended that each individual sugar mill be studied in Bolivia, to assess ways on how to improve their energy efficiency and the highest value use to which surplus bagasse and residues should be allocated. These alternative uses include: (a) power generation for the national grid; (b) energy for alcohol production; (c) pelletization and use as boiler fuel in other industries; (d) briquetting for use as household cooking fuel or as industrial fuel; (e) as input into a paper mill. 3.40 The above indicates that there is no justification to build gas pipelines to supply the energy needs of sugar cane mills. These plants should be in a position to satisfy current energy requirements as well as sustain increased alcohol production mainly using bagasse. This recommendation is in particular applicable to the projected gas pipeline in the Department of Tarija, which should not be built until the energy efficiency study of the two Bermejo sugar mills is completed. Recommendations 3.41 (a) The activities in the hydrocarbon subsector depend on the decision regarding gas exports to Brazil. In the event that this project is not implemented, YPFB should concentrate efforts on maintaining the level of liquid hydrocarbon production. This implies executing the Vuelta Grande, Monteagudo and La Pena projects, defining the extension of already known oil and gas condensate fields and evaluating further secondary and tertiary recovery projects. If the gas export project materializes, then a 1/ According to: "The Potential for Liquid Fuels from Agriculture and Forestry in Australia" published by Commonwealth Scientific and Industrial Research Organization, Australia, 1979. - 37 - considerable exploratory effort is necessary to define ultimate gas resources. In this case, private participation in the sector's activities should be encouraged. (b) In spite of Bolivia's considerable hydro potential, investment decisions in hydropower development should be delayed until the gas export project has been decided upon and until the technical questions relating to the Icla and Misicuni projects have been clarified. (c) Further geological and geophysical investigation is needed to evaluate the economic feasibility of the geothermal project of the field "Sol de Manana". As soon as Bolivia's financial constraints ease, this energy source should be further evaluated. In the longer term, solar ponds built in the Uyuni salar lake could also provide an alternative for power generation. (d) The use of bagasse and of other sugarcane residues must be studied. In all sugar mills there is a potential to enhance energy efficiency and to make available a surplus of organic material for (a) power geneneration for the national electric system; (b) energy for alcohol production; (c) pelletization and use as boiler fuel in other industries; (d) briquetting for use as household cooking fuel; (e) as input into a paper mill. (e) Coal deposits should be evaluated as to their small scale exploitation to serve as household fuel for the Altiplano rural population. (f) The dissemination of solar greenhouses in the Altiplano and of solar water heaters in urban areas should be enhanced. Technical and financial assistance to these projects should be sought for by the Bolivian Government. (g) The US Aid project to study rural energy needs and village level resources should be pursued. The results would enable designing projects in reforestation, agricultural waste recycling, windpower, small scale hydro and other renewable energy sources. - 38 - IV. THE OIL DEFICIT & DEMAND MANAGEMENT 4.01 The purpose of this chapter is to determine the nature and the magnitude of Bolivia's impending oil deficit and to evaluate alternative strategies to maintain an adequate energy supply to the modern sector of the Bolivian economy. The first section outlines the assumptions on which the oil production forecast to 1990 were made and compares these to projected demand for oil products. The second part examines the extent to which interfuel substitutions and conservation are feasible, considering the sectoral and regional limitations. The third portion of this chapter discusses the various gas pipeline projects being considered for making gas available to the major energy consuming regions of Bolivia. A. OIL SUPPLY - DEMAND BALANCE Liquid Hydrocarbon Production Forecast 4.02 The supply of liquid hydrocarbons (including LPG) depends on the implementation of specific projects. In 1981, it was hoped that the full development of Forvenir, 1/ the enhanced recovery of La Pena, 2/ and Monteagudo, 3/ and especially the development of the retrograde gas condensate field of Vuelta Grande 3/ were going to stabilize crude and condensate production during the first half of the decade and allow the necessary time to evaluate further the resource potential and the feasibility of exploiting the gas fields of the Boomerang area. In addition, YPFB planned to increase LPG production from gas fields from 3 MBD in 1981 to 12 MBD in 1986, mainly by increasing the amount of gas supplied to the existing plant in Rio Grande and by building two new plants in Vuelta Grande and Porvenir. Under these assumptions, total liquid hydrocarbon productLon would have increased from 27 MBD in 1981 to 40 MBD 4/ in 1986 (Annex 1.12). The projected decline thereafter indicated that the effect of current projects had been compensated by the natural high decline in the productivity of Bolivia fields. There is still a group of fields where secondary recovery could bring forward a significant amount of production. 4.03 The financial resources available to YPFB have been considerably less than postulated in the development plan. The most important project--Vuelta Grande--has not been initiated; the Monteagudo recovery project is being implemented but has not yet been completed. The existing gas plant at Rio Grande is working below capacity and YPFB has considered the possibility of dismantling part of this plant's equipment and use it for Vuelta Grande. 1/ By Occidental Petroleum. 1/ By YPFB, loan from IDB requested. 3/ By YPFB, to be financed through an IBRD loan. 4/ Includes 2.1 MBD from Boomerang area. - 39 - 4.04 It has therefore been necessary to modify the production forecast, assuming that the pending projects will be reactivated by mid- 1983. In 1982 and 1983 the full impact of the Porvenir field development should be felt and give Bolivia an exportable surplus until 1984. Table 4.1: Projection - Oil and Condensate Production (MBD) YPFB's 1981 Estimates Mission Revision 1981 1985 1990 1985 1990 Oil Fields 6.8 5.7 5.5 4.9 7.5 Condensate Fields 15.2 19.4 10.7 12.4 10.4 Gas Fields - - 2.2 - 2.2 Total 22.0 25.1 18.4 17.3 20.1 Source: Annexes 1.12 and 1.13. The difference between these estimates is due to an estimated delay of two years in project implementation. 4.05 The major sources of current gas production are condensate fields. Although their net gas production cannot be increased beyond a certain level in the short run without impairing the recovery of liquids 1/ this volume will increase over time as condensate reserves become depleted and will be sufficient to satisfy domestic gas requirements and the export commitments to Argentina. Therefore, investments in the development of the gas fields in the Boomerang area are justified only in the case of the gas pipeline agreement with Brazil. Table 4.2 Gas Production Forecast Natural Gas (MMCFD) 1981 1985 1990 Oil Fields 8.5 28.0 24.0 Condensate Fields 240.0 285.0 294.0 Gas Fields - - 330.0 Total 249.0 313.0 648.0 Source: Annexes 1.19, 1.20, 1.21. 1/ At present, this level of flexibility is estimated at around 25 MMCFD or 5% of current production which is approximately the amount of gas being flared or lost in these fields. (Annex 1.22). - 40 - 4.06 The future of LPG depends on the construction of extraction facilities and of the pipeline system that will provide the gas stream to these plants. As shown on Table 4.3, present capacity utilization is low, due to the declining availability of natural gas to existing plants. The two largest projects--Vuelta Grande and Porvenir--are located relatively close to each other, and it would be advisable to assess whether it is not more economic to build only one of these plants and connect both fields with gas with pipelines. Table 4.3: LPG Extraction Capacity and Use (tons/day) 1981 1985 1990 Rio Grande 1/ 450 450 450 Colpa 2/ 20 35 35 Camiri 1/ 16 40 40 Vuelta Grande 2/ 3/ - - 356 Porvenir 2/ - 225 225 Altiplano Pipeline 1/ - - 23 Total (tons/day) 485 750 1,129 Total (barrels/day) 5,546 8,576 12,910 Production (barrels/day) 3,044 5,975 10,040 Capacity Utilization (%) 55 70 78 1/ Information from YPFB's development program. 2/ Information from YPFB's production forecast. 3/ Vuelta Grande is projected to be commissioned by 1986. 4.07 The gas of the Subandean and Chaco region has on the average a propane and butane content of about 4-6% mol. This means that, theoretically, for each 100 MMCFD 2.8-4.3 MBD of LPG can be extracted. Thus, YPFB's projection to produce some 12 MBD of LPG from the condensate fields represents probably 100% of maximum potential with a gas production of 294 MMCFD by 1990. On the mission's revised production schedule it has been assumed that only 10 MBD or 80% of the potential LPG extraction will be available by 1990. 1/ The gas in the Boomerang area is much drier. The analysis will show whether the gas contains an economically recoverable liquid fraction. Total recoverable reserves of LPG have not been determined. Assuming that 4% of condensate gas reserves (3.1 TCF) consists of heavier hydrocarbons (C3 and C4), it can 1/ The baseline projection of the energy balance is made assuming a 10 MBD LPG production in 1990. Under the accelerated growth scenario, a LPG production of 12 MBD was assumed. - 41 - be estimated that the resource base is in the order of 88 x 106 barrels or equal to 24 years production at a rate of 10 MBD. 4.08 To achieve the potential maximum production at a minimum cost, the mission urges YPFB to proceed with a detailed engineering study for each field. This study will provide the necessary input for an optimization model required to program the orderly development of the fields, schedule their production ratios, plan the gas pipeline systems and locate the new LPG extraction facilities. Projected Oil Balance 4.09 The comparison between the mission's production forecasts and the demand projections (Table 4.4) shows that in the short term the industry should have a comfortable surplus. The deficit foreseen for 1985 is due to a delay in the projects and can be bridged by carefully managing existing productive capacity. The situation however reverts to a continuous deficit at the end of the decade. The deficit will have to be supplied through substitution and demand management. Table 4.4: Liquid Hydrocarbon Balance - 1981-1985 (MBD) 1981 1982 1983 1984 1985 Production 1/ 27.2 30.5 29.9 28.9 25.4 Demand 2/ 26.4 25.4 25.4 25.4 26.0 Exportable Surplus 0.8 5.1 4.5 3.3 (0.6) 1/ Revised Forecast scenario. 2/ Baseline scenario projection, includes 2.4 MBD as intermediate demand. 4.10 The balance for the period 1986-1990 can be projected as indicated in Table 4.5, assuming the baseline scenario with conservation and the full implementation of all programmed oil and LPG projects. - 42 - Table 4.5: Liquid Hydrocarbon Balance - 1986-1990 (MBD) 1986 1987 1988 1989 1990 Liquid Production 1/ 33.5 36.5 35.2 34.7 34.2 Demand 2/ 28.3 30.7 33.4 36.3 39.4 Surplus (Deficit) 5.2 5.8 1.8 (1.6) (5.2) I/ Crude, condensates and natural gasoline. 2! Baseline scenario with conservation, includes intermediate demand. Qualitative Balance: 4.11 Bolivia is faced with a severe imbalance between the type of petroleum product demanded by the market and the products that can be refined from domestic crude. Bolivian crude and condensates are unusually light and yield only 15% diesel oil and 5% fuel oil, but about 56% of gasolines and naphthas. On the other hand, 34% of demand consists of diesel and fuel oil. The growth in the consumption of these fuels was encouraged by the pricing policies of the Government, which followed the international price structure and did not consider the characteristics of the Bolivian crude supply. The imbalance will deteriorate in the future, with increased share of condensates in crude input. Currently, to balance market requirements with refinery yields, YPFB has rationed the use of fuel oil, diluted diesel and fuel oil with gasoline, (35% in diesel and up to 95% in fuel oil), exchanged small quantities of products with neighboring countries, and promoted the use of LPG and natural gas, which are in relatively abundant supply. - 43 - Table 4.6: Qualitative Imbalance 1981-1990 Refinery Yields Consumption Surplus/(Deficit) 1981 1990 1981 1990 1981 1990 % MBD MBD MBD % MBD MBD MBD 4/ 3/ Gasolines 56 13.6 12.4 8.3 35 13.4 5.3 (1.0) Kerosene 10 2.4 2.2 1.8 8 2.6 0.6 (0.4) Jet Fuel 8 1.9 1.8 1.6 7 2.9 0.3 (1.1) Diesel Oil 15 3.6 3.3 5.4 23 7.9 (1.8) (4.6) Fuel Oil 1 0.2 0.2 2.7 11 3.7 (1.5) (3.5) Reduced Crude 1/ 4 1.0 - - - LPG 6 1.5 2.3 4.1 17 6.3 (2.6) 2/ (4.0) 2/ Total 100 24.2 22.2 23.9 100 36.8 0.3 (14.6) 1/ This is a feedstock for the lube plant. Part (82%) of the stream is recycled to the fuel oil pool, once paraffins have been extracted. 2/ LPG from natural gas more than covered this deficit in 1981. 3/ Consumption projected under baseline scenario, assuming no substitu- tion. 4/ Includes natural gasoline. LPG Supply-Demand Balance 4.12 The availability of LPG is crucial in the transition period of the Bolivian economy, because it can substitute for practically all uses of petroleum products in areas in which the energy demand density is insufficient to justify the construction of gas pipelines. Assuming an availability of 10 MBD of LPG from gas plants and 1.3 MBD from refineries in 1990, LPG would supply 53% of household commercial energy require- ments, 32% of industrial needs and 20% of road transport fuels. 1/ A shortfall in LPG supply would imply increased investment in the gas distribution network, or accelerated and higher cost extraction of petroleum or imports of liquid fuels. Currently, considerable amounts of propane, butane and natural gasoline are exported in the gas stream to Argentina, in part because some of the gas is being produced where there is no LPG extraction facility. It is recommended that special consideration be given to the domestic requirements of LPG in the gas planning study proposed in this report. 1/ Under the baseline scenario with a 15% conservation effort. Annex 1.6. -44 - Short Term Options to Improve the Qualitative Balance 4.13 Bolivia currently trades LPG and naphtha for diesel and fuel oil with neighboring countries to improve the domestic product balance. The large scale use of this option is constrained by the lack of import pipelines and the fact that domestic refineries as well as the other industrial equipment were apparently designed to handle low sulphur crude oil and products. 4.14 Annex 1.18 shows that trade with the Caribbean exchanging light products for heavy fuel oil would only be justified if the price differential between gasoline and fuel oil is US$13/bbl in that market, amount which is equal to the sum of export and import transport costs; assuming an exchange trade with Ecuador, the necessary price differential is about US$10/bbl. Under present market conditions, such a differential could well be negotiated if Bolivia could purchase high sulphur products or crude and import them in large quantities. It is, however, first necessary to investigate whether the sulphur problem would cause damage to existing installations. The second constraint is more difficult to solve. Current imports are made via railroads; exports in a certain volume can be pumped through the existing and unused pipeline to Arica (Chile). The mission recommends that YPFB investigate alternative routes to reduce transport costs. A more economic access to the foreign trade alternative would facilitate better management of future oil production and avoid incurring heavy substitution costs. B. DEMAND MANAGEMENT: Conservation and Substitution Potential 4.15 The Bolivian oil industry will confront increasing difficulties in maintaining constant levels of liquid hydrocarbon production. By the end of the decade, incremental demand cannot be supplied unless major efforts have been made to reduce waste in energy use and a coordinated policy has been implemented to induce a shift of demand towards those energy forms which are in more ample supply. In the medium term, direct use of natural gas appears to be the most economic alternative for substitution. In the longer term, economic trade-offs of substitution between natural gas, electricity and other liquid fuels that can be produced from natural gas, have to be evaluated. In the following, the conservation and substitution potential in each economic sector are discussed. (i) Industry 4.16 This sector offers the opportunity of achieving significant changes in the pattern of energy consumption with relatively small technical and financial resources. Energy use is heavily concentrated. A dozen major plants account for almost half of industry's petroleum consumption. Six major customers consume 15% of total electricity sales. One large smelter consumes virtually all of the charcoal. The industry's consumption of LPG, kerosene, diesel and fuel oil was about - 45 - 260 MTOE in 1981. (Annex 1.23) This amount if totally substituted by natural gas would be equivalent to 27 MMCFD. The projection of this sector's requirements to 1990 under the baseline scenario would increase the maximum substitutable market to 381 MTOE or 40.0 MMCFD. 4.17 A detailed survey of the industrial fuel market performed by GDC I/ recently concluded that, at current prices and from the point of view of individual consumers, there are no technical or economic impediments to substituting natural gas for liquid fuels in the industrial market. 2/ The report did not analyze the economic and financial feasibility of building the pipeline network to supply the market. 4.18 Furthermore, the mission's preliminary survey of eight large industrial plants (of which five were in the public sector) suggest that the efficiency of fuel use--primarily petroleum products but to a limited extent electricity as well--could be significantly improved. A 15% saving could have reduced liquid oil consumption in 1981 by as much as 30 MTOE (or 650 BD) and power requirements by 100 Gwh. 4.19 The metallurgical industry is composed of one large tin smelter (ENAF at Vinto) in operation since 1970 and five other large projects in varying stages of implementation. The Vinto smelter consumes about 36% of the fuel oil sold in Bolivia, and virtually all of the charcoal, which is used as a reducing agent. The capacity of the other projects and their associated energy consumption is listed in Table 4.7. 4.20 All metallurgical plants under construction or planned confront difficulties, because (a) there is a question on whether sufficient ore will be available to operate these plants at an acceptable utilization factor; (b) the economics of La Palca are being questioned on the ground of the overrun in investments and the efficiency of the process technology; (c) the plant has a serious air pollution problem. As a result of these problems, it is probable that the other two planned projects will have a considerable delay in their implementation. YPFB is committed to supply the energy requirements of Vinto and La Palca with natural gas by 1983, or supply these plants with fuel oil at the energy price equal to natural gas. This contract is the prime reason for the accelerated expansion of the Monteagudo-Sucre pipeline. It is recommended that the economic feasibility of these projects be revised before YPFB goes ahead with the investments in pipelines to supply the energy requirements of these plants. Their economic profitability should not be artificially increased through an implicit subsidy of natural gas, by pricing it below its opportunity cost. I/ Internal Demand for Natural Gas and LPG in Bolivia, by GDC, Inc., Draft of April 1982. 2/ There are a few instances where interchangeability is not complete; for instance metallurgical requirements for specific fuel or for extremely high temperatures. - 46 - Table 4.7: Energy Consumption at Major Metallurgical Projects Energy Consump- Input tion at Location Capacity Capacity Plant Status Owner Department Metal (MTY) (MTOE) Vinto In Opera- ENAF Oruro Tin and 90 71 tion Antimony concentrate La Palca Start-up COMIBOL Potosi Tin 140 26 (ore) Karachipampa Planned ENAF Potosi Lead and 53 16 Silver (ore) Machacamarca Planned COMIBOL Oruro Tin ? 20 Sponge Iron Envisaged SIDERSA Santa Cruz Iron ? 18 Ore Process- ing Envisaged SIDERSA Mutun Iron ? 6 4.21 The mission recommends that an energy survey and audit be performed in Vinto, to assist management in the conversion to natural gas and to achieve at the same time improvement in the plant's efficiency. It is also suggested that the scope for product waste recovery by pollution control equipment be assessed. 4.22 The manufacturing sector is comprised of some eight energy- intensive cement, glass and ceramic plants; of about a dozen of medium- sized textile, food-processing and beverage industries; and a large number of small scale and widely dispersed enterprises. 4.23 The industries in the first two groups were mostly established in the 1970s with modern technology. However, the energy efficiency of these plants has suffered because of the low quality of fuel oil available in recent years, the uncertainty related to the timing and extent of the Government-mandated changeover, first to LPG and then to natural gas, the economic crisis which has hampered and delayed industry's efforts to import essential spare parts and has affected maintenance practices, and finally, the lack of incentive on the part of the managers of public owned enterprises. 4.24 In the areas of Santa Cruz and Sucre, most of these plants have already been converted to natural gas. In the Altiplano, some of them - 47 - have provisionally been converted to LPG, awaiting the construction of a natural gas pipeline. A more rapid substitution to LPG has been constrained by insufficient investment in transport, storage and distribution facilities. 4.25 The mission recommends that energy surveys and audits be performed in the largest industrial organizations to identify and quantify the opportunities for energy saving and assist these enterprises in the changeover to natural gas. However, this effort has to be complemented by a revision of the financial performance of public owned enterprises. Many of the industries in which the Bolivian Development Corporation is a major shareholder are uneconomic and are being subsidized and managers have no incentive to reduce costs and save energy. 4.26 It is suggested that the technical know-how required to conduct the energy survey and recommend efficiency improvements should be developed within YPFB, which could provide it as a customer service, assisted by outside consultants. This would also provide valuable information for YPFB in planning for the upgrading its refining and expanding its distribution facilities. Thus the mission recommends that YPFB establish an energy advisory service to promote and assist in the efficient use of energy in all sectors of the economy. 4.27 Within the manufacturing subsector, the sugar industry should be considered as a special case. Energy is used rather inefficiently (para 3.38-3.39) for sugar refining and alcohol production. While sugar production is not expected to increase, the industry has plans to expand alcohol production and to divert bagasse as raw material for a paper mill. 4.28 The mission suggest that three separate studies be made: (a) assessing the present use of energy in each sugar mill and means to increase their efficiency; (b) revising the economic feasibility of increased alcohol production, taking into account alternative uses of molasses and the market for alcohol; and (c) studying the feasibility and location of the paper mill, projected for Tarija, and its impact on the energy requirements of this region. 4.29 The mining industry is a relatively minor (4%) energy consuming sector. It is characterized by its geographic isolation and predominant use of electricity (50% of the sector's requirements). In 1981, about half of the industry's power requirements were purchased from the network, a quarter was hydro-generated and a quarter was generated using diesel sets. Their direct and indirect use of diesel and fuel oil represents about 11% of the total consumption of these fuels. Because of their geographic isolation, substitution alternatives away from liquid fuels are limited. In specific locations mini-hydro, conversion to LPG, and geothermal applications could be developed. However, the priorities of this sector are directed in the immediate future towards increasing productivity to counter rising production costs and intensifying exploration. - 48 - (ii) Transport 4.30 Bolivia's internal transportation needs are largely met by road vehicles which carry about 93% of the freight (mostly agricultural 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 about 58% of the exports (largely mineral products) 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, the transport sector depends entirely on petroleum products and in turn accounts for 61% of all final petroleum consumption. Road vehicles consumed 80% of the total, railroads 3% and airplanes 17%. Of additional importance in the qualitative balance is the fact that 58% of all diesel sales 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. 4.31 The consumption of diesel in transport has increased rapidly, especially from 1975 to 1981 when its share in the road fuel market rose from 15% to 28%. This development was encouraged by the fuel pricing and vehicle import policies of the government. Although diesel prices have now been raised to the same level as gasoline, diesel is still used by about half of the trucks and buses, a majority of which undoubtedly replaced gasoline-powered models. It is recommended that the Government encourage the gradual reduction of the stock of diesel powered vehicles by further raising the price of diesel relative to that of gasoline. Once the pricing incentives are in place, this would permit a gradual loosening of the rigid restrictions on diesel vehicle imports, thus enabling diesel to be used for the sizes and types of vehicles for which gasoline engines are not available. In this connection, the Government's plans for the establishment of a diesel truck assembly plant also need to be reviewed, in view of the possibility that a gasoline (or LPG, CNG or synthetic fuel) powered vehicle may be more economical. 4.32 The use of compressed natural gas (CNG) should be studied in the later part of the decade as a means to advance the use of natural gas. It should be noted that CNG not only has a potential of substituting for gasoline in spark engines, but also successful tests of CNG in diesel engines are currently being made. As an alternative, the use of methanol derived from natural gas has to be examined. Such a study would have to take into account such considerations as the potential demand and storage/filling implications, including safety, training and maintenance requirements. 4.33 YPFB has been selling LPG for vehicles since 1980 and currently serves about 4000 cars and trucks out of six specially equipped service stations. Sales have multiplied from 415 TOE in 1980 to 4073 TOE in 1981. While the current price differential moderately encourages the switch to LPG, the Government is no longer promoting it because of a - 49 - shortage of LPG at the pump. To minimize the investment required for LPG distribution and retailing in the short term, the effort should initially concentrate on urban use vehicles in the largest cities, such as buses, taxis, car fleets, and short-haul trucks. Later the distribution system could be expanded on a country-wide scale. Energy Efficiency in Transport 4.34 The energy intensity of transportation has abruptly declined in 1980, possibly as a result of the recent price increases. This limited evidence suggests that the transport sector may be highly responsive to the costs of fuel which, according to a recent study, constitute between 5-19% of its operating costs 1/, and act to reduce those costs. While pricing remains the most important tool for encouraging the efficient use of fuel, the Government can also improve the situation by measures tending to improve traffic flow in urban areas, improving the quality of the road network, and increasing drivers' awareness of energy saving methods. An important step to rationalize the use of fuel in inter-urban freight transport has recently been taken by the Bolivian Government, when it eliminated monopolies in automotive transport. 4.35 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 over and 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. This study should complement the ongoing Bank-financed National Transport Study, which has focused on interurban transportation. 4.36 Recent data from the U.S. indicate that changes in the driving behavior of vehicle operators can reduce fuel consumption per vehicle by about 10-15%. 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 time-tested and generally known, but the problem is to motivate the drivers. In the US this has been achieved through a program of contests and financial incentives. It is recommended that the Government establish a driver training and I/ Bolivian National Transport Study, Working Paper 33a, Analysis of Vehicle Operating Costs, June 1980. - 50 - motivation program that would enable Bolivia to take advantage of these very economical energy saving opportunities. 4.37 Another source of energy savings can be a sustained effort to rehabilitate the existing road infrastructure and improve road maintenance. The National Transport Study found that 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. That study estimated that a truck consumes about 5% 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 condition. Thus, while fuel savings constitute only a fraction of the major (50%-80%) savings in transport costs that can be obtained through road rehabilitation and improvement, these savings are nonetheless important when considering the large volume of fuel consumed in road transport. (iii) Households and Commerce 4.38 While per capita energy consumption in Bolivia is low by Latin American standards and most households use energy only for cooking and lighting, these energy requirements account for nearly half of the country's final energy consumption. Furthermore, with population growing at 2.5% per year and a gradually rising standard of living, these energy requirements are expected to grow at least as rapidly as those of the rest of the economy. Three quarters of household energy is provided from biomass, which consists of fuelwood in the valleys and lowlands, and shrub and dung in the Altiplano. This will continue to be the predominant household fuel at least for the next decade, although substitution by commercial fuels is likely to increase rapidly, especially in the Altiplano where biomass is extremely scarce and where the fuel with the most rapid growth will be LPG, which is not only substituting for kerosene 1/ but also displacing biomass as suggested by its rapid recent growth rate. About 28% of the households have access to electricity and this proportion should gradually increase as a result of rural electrification. Consumption of electricity in this sector has risen on the average by 20% p.a. over the last six years. 4.39 This sector must be included in the plan to restructure the energy demand. The projected energy balances show that it is likely that the kerosene and LPG available for this sector will not be sufficient to meet projected demand. Therefore, consideration should be given in the short term to introducing gasoline as a household fuel. For the longer term, the gas pipeline projects should be planned so as to permit extending the gas service to major urban areas early next decade. Simultaneously consideration should be given whether substitution by electricity should be promoted. 1/ LPG sells at less than 50% of the price of kerosene, on a caloric basis. - 51 - C. GAS PIPELINE NETWORK 4.40 The capital-intensive nature of pipeline projects requires that the routing be chosen to guarantee an adequate initial throughput and that their size and configuration allow future expansion. This implies that the first main lines must be directed to meet markets with fairly concentrated demand, with small seasonal or daily deviations from the average. The GDC study (Annex 1.24) identified the main bulk industrial consumers and their geographic location. The mission adjusted these estimates (Annex 1.25) according to additional information. Table 4.8 quantifies a maximum demand, and compares it with the bulk market, singling out the most energy intensive industries. This information is grouped into specific regional pipeline projects. The bulk market includes the industrial users that can be reached with minimum investment 1/ in a fairly short time. The maximum demand estimate includes a widely dispersed universe of medium to small consumers and it is not yet certain that these can be connected economically. 1/ The investment cost for lateral branches from the main line has been estimated by IDB at US$ 9.1 MM (1981 US$). - 52 - Table 4.8: Potential Gas Market (MMCFD) 1990 1981 Baseline Moderate Growth Regions Actual Scenario Scenario Altiplano - North La Paz, Oruro, Cochabamba Maximum Demand 24.4 31.0 34.8 Bulk Market 16.1 21.3 23.2 Altiplano - South Sucre, Potosi Maximum Demand 5.1 11.0 12.9 Bulk Market 4.1 9.7 9.7 Santa Cruz 1/ Maximum Demand 17.3 35.9 70.6 Bulk Market. and currently supplied with gas 13.6 30.5 57.2 Tarija Maximum Demand 1.2 2.5 2.5 1/ The bulk demand includes gas-based power generation. The projection assumes that all future Bolivian requirements will be gas-generated and that all incremental capacity will be installed in Santa Cruz. Source: Annex 1.25 4.41 In Santa Cruz, a set of pipelines have already been built, which serve the industrial park, ENDE's thermal power plant and a group of industries to the north of the city. Apparently, these lines were constructed individually and do not conform a system designed for long term expansion. 4.42 Camiri and Sucre are being served from the Monteagudo oil field. The line has also been extended to Potosi, to supply the immediate requirements of La Palca (metallurgy) and its associated power plant. The capacity of this regional system is 20.7 MMCFD, well in excess of the requirements of this region. It has therefore been decided to proceed to expansion Phase II, which would connect this branch with the North-South gas export line to Argentina and provide additional supply of gas. To the north it would be extended to Cochabamba, partially using an existing oil pipeline. YPFB further proposes to - 53 - connect it at Cochabamba with the reconverted line leading to Oruro and La Paz. This whole expansion project is an emergency solution to the pressing need to substitute for fuel oil in the Altiplano, and which was induced by the delay in the approval and disbursement of loan. 4.43 Apparently, YPFB has been able to advance this project as scheduled (it was to be operational by mid-1983). The mission considers that its capacity will be sufficient to provide for the immediate fuel requirement of bulk consumers, including power generation and refineries in the Altiplano region. It would be better to delay the second new pipeline until the growth prospects of the Bolivian industry become clearer. 4.44 The mission's financial analysis (Annex 1.36) shows that under the baseline demand scenario and at a discount rate of 14%, the average transport cost through this line (Monteagudo-Sucre extension) would be US$1.12 MCF. 4.45 The northern Altiplano, with the cities of La Paz, Oruro and Cochabamba, uses 47% of total industrial fuel and 90% of all fuel oil. There is an urgency to supply this region with gas at a competitive rate because the main consumer of fuel oil is the metallurgical sector, which has to compete in international markets. 4.46 In 1980, YPFB negotiated with IDB a loan for building a new Altiplano pipeline. This decision was based on a comparative analysis with the southern Altiplano solution discussed in para. 4.42. It appears that at that time the northern alternative was more advantageous. The southern line was only going to serve the Sucre and Potosi markets. 4.47 The northern pipeline was projected to carry gas from Santa Cruz to La Paz, with intermediate stations at Cochabamba and Oruro. The project has a total cost of US$138.5 million including contingencies and financial charges during construction, for which IDB approved in 1981 a US$97.00 million loan. The proposed line consist of the following elements: (i) 1 12" diameter, 262 miles long new pipeline between Santa Cruz and Cochabamba, with a total (fully allocated) cost of US$104.8 million; (ii) the repair and partial replacement of an existing 6" product pipeline, 231 miles long between Cochabamba and La Paz, with a cost of US$7.5 million; (iii) distribution laterals in main cities, at a total cost of US$9.1 million; (iv) compressor stations and terminals in Cochabamba and Oruro (US$9.8 million); and -54 - (v) a gas processing plant in Santa Cruz (US$7.4 million). The pipeline was originally planned to become operational during the third quarter of 1984, with an initial throughput capacity of 33 MMCFD and a final capacity of 90 MMCFD. The project has at this stage a delay of at least one year. 4.48 In the meantime, YPFB has modified the design of this gas pipeline and will therefore have to renegotiate the loan with IDB. The main differen- ces between the two designs are: (a) Gas Input: in the new project the pipeline would be fed with the dry gas that exits from the adsorption plant in Rio Grande at a pressure of 1400 psi. This change of origin for the pipeline would eliminate the need to build a new gas treating plant in Palma Solar; (b) The total length of the pipeline increases to 283 miles, and its diameter is reduced from 12" to 10"; and (c) the carrying capacity will be 41.4 MMCFD in the first phase, expandable to 60 MHCFD. YPFB has estimated the .investment cost for the first phase at US$65 millions (in end-1982 prices), with a foreign exchange component of US$32 million. 4.49 Under the assumption that only major industrial consumers would be connected to the pipeline the financial evaluation of this project shows that at a 14% discount rate, the average throughput cost would be US$1.97/MCF (Annex 1.37). This compares with an estimate of US$0.72/MCF, if the supply were extended to a much wider range of consumers in line with the substitution requirements. 4.50 Should both projects (extension of Monteagudo-Sucre and the original Northern Altiplano pipelines) be implemented simultaneously, then a capacity of about 60 MMCFD will exist for an initial market not exceeding 20-23 MMCFD. The mission recommends postponing the decision for the new pipeline for two years. 4.51 'In the south, YPFB has consideced the construction of a pipeline that would serve the towns of Tarija, Bermejo, Emborozu and El Puente. It would have an initial capacity of 19.5 MMCFD of gas, either from a deep structure in the Bermejo gas field, where drilling is in progress or from a nearby Argentinian gas field (Ramos). The investment cost is estimated at US$14.5 million for a total length of 240 kms. 4.52 The department of Tarija, located in the southern tip of Bolivia, had an industrial fuel consumption of some 13 MTOE in 1981. There are only a few large consumers scattered in the region: a power station and a glass factory in Tarija and two sugar mills near Bermejo; a paper factory in Emborozu is under construction, which will eventually - 55 - use bagasse as raw material. The sugar mills argument that the withdrawal of bagasse together with a planned expansion in their alcohol production, would substantially increase their purchased energy requirements. The mission disagrees as indicated in Para 3.39. Finally, there is a plan to build a cement factory in El Puente. The total estimated demand of the region would grow from about 1.5 MMCFD of gas equivalent in 1981 to 2.5 MMCFD in 1990 under the moderate growth scenario. But it would increase to 7.7 MMCFD in the case that all projects be implemented. This is still way below the design capacity proposed. 4.53 The pipeline in Tarija is not only overdimensioned but also based on the demand of industrial expansion projects which are highly questionable. The sugar mills are already being subsidized; the paper mill will initially operate with imported pulp; the requirements of the power stations will diminish when the San Jacinto hydroproject (7 MW) enters into operation in 1983. The mission therefore recommends that this project be postponed. D. POTENTIAL FOR ASPRALT SUBSTITUTION 4.54 Although this does not have a direct impact on the energy balance, the mission recommends that Bolivia should study the use of sulphur as an agglomerate for road construction, replacing the current asphalt mixture with sulphur up to 50% in weight. The technique of emulsifying sulphur in a hot asphalt mixture has proven to be advantageous in construction and in road maintenance. Pavement tests have shown that it produces denser pavement surfaces, reducing humidity penetration and providing higher resistance and not requiring specialized handling equipment. 4.55 Bolivia's mountain chains have several volcanoes which contain mineral sulphur deposits. There are a few companies, all located in San Pablo de Naper that produce native sulphur in open pit mining. Present annual capacity is estimated to be 215 tons per year 1/. It is necessary to evaluate the cost at which new capacity could be developed. 4.56 Bolivia's annual consumption of asphalt is about 6,000 ton of which one-third for new asphalt cement paving and two-third for road maintenance. Only a very small portion is locally produced and the bulk of requirements have to be imported in drums at a very high cost. The substitution could therefore mean substantial savings of foreign exchange. Recommendations 4.57 (a) To maintain an adequate level of liquid hydrocarbon supply during the present decade and allow some production flexibility, the envisaged development of 1/ World Sulphur and Sulphuric Acid Atlas - the British Sulphur. - 56 - Vuelta Grande and the enhanced recovery projects at Monteagudo and La Pena should be executed as soon as possible. Also, it is recommended that an LPG extraction facility be built in the Chaco region to allow the processing of gas from Vuelta Grande, Porvenir and other fields. The location of such a plant should be determined through a gas optimization study. (b) To improve in the short term the qualitative balance of petroleum products, YPFB should consider the possibility of expanding its foreign trade and investigate whether large industrial consumers could safely use imported high-sulphur fuel oils. Furthermore, YPFB should explore ways in which to introduce gasoline as a household fuel in substitution of kerosene. This would make available a larger refinery stream to produce jet-fuel for the aviation industry. (c) The energy management program has to comprise a monitored shift of demand from liquid hydrocarbons to energy forms which are in more ample supply, higher efficiency in energy use, and adequate economic and financial incentives. Prime targets for the program should be the industrial and the transport sectors. (d) In the industrial sector energy conversion and conserva- tion activities should be simultaneous, and be based on detailed energy surveys and audits in the major industrial plants. YPFB, assisted by outside consultants, should set-up an internal advisory group to provide technical assistance for defining in each plant the most adequate conversion and conservation projects and for monitoring their execution. (e) Furthermore, it is necessary to insure that the industries that will be supplied with natural gas are economic, and that their profitability is not artificially increased through an implicit subsidy of gas, by pricing this resource below its opportunity cost. (f) The sugar cane processing industry should receive special attention in the conservation program. It is necessary to study the efficiency of bagasse use and determine the optimum allocation of surplus bagasse. At the current status of technology, sugar industries should not only be energy self-sufficient, but be net exporters of energy. (g) The transport sector is the largest consumer of petroleum products and should be given priority in the conservation effort. Substantial savings could be achieved in the short term by improving the traffic flow in urban areas and by increasing the local factors in the interregional - 57 - freight traffic. It is also recommended that the efforts to rehabilitate the road infrastructure be sustained. (h) The shift of demand in the transport sector should comprise in the short term: (i) continued ban on the import of diesel-engine vehicles, and (ii) gradual conversion of gasoline motor vehicles towards the use of LPG. In the longer term, the use of compressed natural gas (CNG) or of synthetic fuels should be studied to substitute for both transport fuels. (i) The present consumption of biomass in the rural areas is insufficiently known. In order to adequately plan for the long term supply of energy for the rural population, it is necessary to carry out extensive energy surveys, evaluating present consumptions and efficiency in energy use. (j) The simultaneous construction of a new gas pipeline from Santa Cruz to Cochabamba and the extention of the Monteagudo-Sucre pipeline to Cochabamba will result in the short term with an excess capacity that increases transport costs. It is recommended that the Monteagudo- Sucre extension be completed, and that the IDB loan be used for reconverting the existing oil pipelines to gas and for building the lateral branches to supply gas to the major industrial users in Cochabamba, Oruro and La Paz. The decision to build the main new gas pipeline Santa Cruz to Cochabamba should be delayed until 1985-86. (k) The pipeline project in Tarija cannot be justified and it should not be built in the near future. (1) The use of mineral sulphur as an agglomerate for asphalt paving should be studied. Potentially, asphalt imports could be substantially reduced. - 58 - V. ELECTRIC POWER Inteconnected Power System 5.01 Bolivia has a total installed capacity of about 500 MW, 62% of which is hydro, 25% is thermal gas-based and the rest (13%) consists of diesel generators in isolated stations (Annex 1.27). The interconnected system is comprised of three zones: North (La Paz) connected in 1980, Central (Cochabamba and Oruro) and South (Potosi, Uyuni and Sucre). The Oriental System (Santa Cruz) is to be connected to the national system by a transmission line to be completed in 1985. With this project, the interconnected system will have a considerable flexibility in the choice of its future primary energy source. Electric Power Demand Projection 5.02 ENDE's power development plan proposed in 1981 was based on a continued rapid growth of demand: 8.8%/year during 1981/85 and 8.2%/year during 1985-1990. ENDE's forecast assumed that as in the past, the average growth would be led by the expected expansion in the Oriental System, where rates of 16.4% p.a. were estimated for 1981-85 and 11.1% thereafter. The pattern of electricity consumption was expected to change, reflecting a faster growth of industrial consumption as compared with mining consumption. Losses in the system were 7.2% for distribution and 4.7% for transmission during the 1970's. These were kept at the same level in the forecast. A 1983 revision of this plan indicates that energy demand will grow at a slower rate. The new estimates envisage an average growth of 5.2% p.a. between 1982 and 1985 and of 6.5% p.a. between 1985-1990. Still, it is expected that the Oriental System will increase at an higher than average rate (Table 5.1 below). 5.03 The mission considers that the new projection is more adjusted to the current economic reality, which necessarily has to affect the demand of the 4,000 industrial and mining units that purchase 56% of the electricity sold in Bolivia. Similarly, the extension of the services to areas with no access to electricity at present will only be financially possible if the income of these new clients allows them to pay for the service. 5.04 Therefore, the mission suggests that ENDE should periodically revise its demand forecasts, incorporating the changes in economic trends, the performance of major mining and industrial branches, and the effect of tariff adjustments. The period 1981-85 is the critical one. Under present economic prospects GDP in 1985 will still be 2% below the level of 1981, in constant terms. However, if the economy recovers rapidly during the second half of the decade and the large public industrial development projects materialize, economic growth may well be above the 5% p.a. assumed in the mission's baseline scenario. Therefore, the mission adopted in the accelerated growth scenario (Annex 1.7) ENDE's former projection for 1990 as an extreme case. - 59 - Table 5.1: Projected Demand for Electricity - 1990 Actual 1981 2/ 1990 Estimates ENDE 3/ ENDE 4/ Baseline Scenario % GAh % Owh (Mh % Gwh Mining 31.0 393.7 22 582 n.a. 27 550 Industrial 25.5 323.5 35 925 n.a. 25 510 Rest of Economy 43.5 551.1 43 1137 n.a. 48 978 Total NIS 1/ 100.0 1268.3 100 2644 n.a. 100 2038 Other Areas - 235.1 - 400 n.a. - 301 Total Demand 1503.4 3044 n.a. 2339 Losses 16 173.9 13 455 n.a. 13 349 Gross Generation 1677.3 3499 2811 2688 Rate of Growth (1981-90) % 8.5 5.9 5.4 1/ National Integrated System. The Oriental System, which will be integrated into NIS by 1984, is included in the 1981 NIS total. 2/ Figures changed according to information contained in the Draft Electric Plan - 1983. 3/ ENDE's estimates made in 1981. 4/ ENDE's estimates made in 1983. Source: For 1981 and 1990 ENDE: Annexes 1.28, 1.29, 1.29A. Mission baseline scenerio: Annex 1.04. Expansion of Generating Capacity 5.05 Although the long lead time involved in power projects makes it advisable not to use too conservative estimates of future demand which may leave ENDE with inadequate reserve capacity, the company is currently reassessing its expansion projects, with the purpose of postponing the largest investment commitments until the economic prospects become better defined. The revised expansion requirements are estimated by ENDE at 161 MW for the period 1983-1990. This compares with the former estimate of 300 MW. This new figure matches the estimates made by the mission (Table 5.2). - 60 - Table 5.2: Forecast - Bolivia's Total Gross Generation & Demand 1980 1990 ENDE's (Accelerated growth scenario) Gross Generation Requirements (GWh) 1/ 1,565 3,499 Maximum Demand (MW) 322 719 Baseline Scenario Gross Generation Requirements (GWh) 1/ 1,565 2,688 Maximum Demand (MW) 322 560 Scenario Differences Generation Requirements (GWh) 811 Maximum Demand (MW) 159 Total Effective Existing Capacity (MW) 406 Additional Capacity Required: (1980-1990) 2/ ENDE's Projection (MW) 313 Baseline Projection (MW) 154 1/ Losses in transmission and distribution assumed 13% of gross generation. 2/ Net generation capacity, without considering capacity reserve, which should be at least 15% of peak demand. 5.06 Another source of uncertainty for the power development program resides in the choice of the primary energy source. Chapter 3 has already provided information on Bolivia's considerable hydro-potential, that has on the average an estimated investment cost of US$2,000/kW, and on a specific identified source of geothermal energy which could also be developed. In addition, a transmission line is being constructed between the eastern power system and the interconnected central system. This opens the opportunity of choice of developing the hydrocapacity in the valleys or increasing gas-based thermal power generation in the east. 5.07 The choice among these alternatives is a function of the cost of capital and of the price of gas. At a low opportunity cost for capital and at international prices for gas, the renewable energy sources become the least cost solution for the expansion. However, the financial constraints in Bolivia suggest a rather high opportunity cost for -eapital and the price at which incremental quantities of gas could be exported has not yet been defined and could be lower than the international price, both conditions resulting in a least cost solutions favoring thermal generation. To illustrate this point, in Table 5.3 below, the cost of the hydropower project of Sakahuaya (the first to be built in the development program with a cost of US$2,083/kW) is compared to gas-based - 61 - thermal alternatives. A gas turbine has the lowest effective investment cost (US$400/kW) 1/ of all, but operates at a less efficient rate than combined cycle plants. The option of a combined cycle station in Cochabamba is also included in the comparison, to illustrate the alternative of transporting gas from Santa Cruz to Cochabamba to generate electricity there. Table 5.3: Hydro Versus Gas Power Development Sensitivity to Discount Rates and Gas Prices Generation Cost and Break-Even Gas Prices 12% 14% 16% Hydro Power Sakahuaya Generating Cost (USf/kWh) 5.20 6.01 6.83 Cochabamba Combined Cycle Break-Even Gas Price (US$/MCF) 2.36 2.93 3.51 Santa Cruz Combined Cycle Break-Even Gas Price (US$/MCF) 3.13 3.78 4.44 Santa Cruz Gas Turbine Break-Even Gas Price (US$/MCF) 3.33 3.91 4.51 Source: Annex 1.30. 5.08 The-break even price for gas so determined indicates that, at a 12% discount rate, the construction of a gas turbine in Santa Cruz is justified if the opportunity cost for gas is below $3.30/MCF; at a 14% discount rate (which is more in line with the present financial situation of Bolivia) this price rises to US$3.90/MCF. 5.09 ENDE's 1981 least cost expansion program for the period 1982-87 included mostly hydroelectric projects, which were selected assuming international prices for energy products. In view of Bolivia's uncertain economic growth prospects, its balance of payments difficulties and the fact that at present the opportunity cost of natural gas is not likely to exceed US$3.30/MCF, the mission recommends that generating capacity expansion in the immediate future be gas-based. The combined effect of lower demand expansion and gas-based incremental generation would reduce ENDE's generation investment requirements from approximately US$600 million to US$120 million for the rest of decade. However, hydropower 1/ An availability rate of 75% is assumed for gas turbines. The invest- ment cost used refers to effective capacity and not the installed capacity cost. - 62 - projects must be phased in once the financial constraints ease and economic growth stabilizes, in order to maintain the gas reserve/demand balance (Table 8.1), in the case the gas export project to Brazil is implemented. 5.10 There is another reason for suggesting that the hydropower projects be postponed. Recent information presented by an UNDP financed study 1/ suggests that Icla and Misicuni hydro power projects require some important design changes, and that investment costs could be higher than present estimates. Moreover, the consultant suggests that there may be other lower-cost solutions, involving construction of power-only projects such as. San Jose and Rio Zongo. 5.11 Most of these arguments have been incorporated by ENDE in the 1983 Power Expansion Plan. According to the reassessment made, the energy and peak demand can be met until 1986 with the capacity additions currently being constructed. (These include a fourth unit of 18 MW to be added to the Santa Isabel hydropower plant (1984), the enlargement of the Corani reservoir (1984), and an additional 22.8 MW gas turbine in Santa Cruz (1983). Alternative expansion options are being considered for 1986-1990, including single purpose hydroelectric projects and gas power projects. The mission considers that the proposed plan is reasonable and that ENDE should complete the economic and financial analysis of the alternatives, to arrive at a least cost investment program. At the same time, the mission suggests that ENDE should obtain technical assistance to revaluate its multiple purpose hydropower projects and to update the construction costs of all the projects should be updated, using a uniform normed cost approach. This would imply developing a cost manual for Bolivia, with proper adjustments to the specific conditions of each region. Power Generation in Isolated Systems 5.12 The isolated and rural power systems do not have a flexibility of choice. A continuous study must be made to assess new alternatives. In some cases, the issues are clear, and the mission makes the following recommendations. (a) Villamontes: ENDE has installed two dual-fuel thermal units, rated 1,200 kW each, served from the gas pipeline to Argentina; service is provided to approximately 3,000 people. Since the gas supply to this part is ample, ge- neration expansion should be continued on the same basis. (b) Yacuiba: ENDE provides service to about 13,000 people, using purchased power from Argentina, limited for technical reasons to 1,000 kW. Negotiations should continue with 1/ "Comparacion Tecnica de Proyectos Hidroelectricos en Bolivia" by Pierre Meystre, Consultant, Switzerland, March 1982. - 63 - Argentina to increase the amount of power available to satisfy future expansion of the demand. (c) Bermejo: SETAR provides service to 6,500 inhabitants from a 600 kW diesel plant. The alternative of power purchases from Argentina should be investigated, to substitute existing plant and cover the expansion of the system. (d) Camargo: ENDE has installed two diesel power plants, rated 500 kW each, to serve 10,000 people. When justified by the demand growth, this town should be connected to the NIS (Southern System). (e) Tarija: ENDE has installed 5,200 kW in diesel plant, and the Asociacion San Jacinto of which ENDE is a partner, has started the construction of the multi-purpose San Jacinto hydro-project, which would permit ENDE the generation of 7,000 kW. Because of the importance of this system, it should be connected to the NIS by 1990. (f) Trinidad: ENDE is in charge of the service to this town of 15,000 people, installed capacity is 2,000 kW in diesel- generation. Studies made by ENDE with the assistance of a consultant ruled out the possibility of using wood as an alternative to diesel-fired plants, because of the great distances which firewood would have to be carried, difficulties in transport during the rainy season (seven months per year), etc. Since no hydro sites appear possible in the area, the system would have to continue its expansion based on diesel-plants until other forms of generation are possible (biomass, solar, wind power, etc.). (g) Pando Area: The northern Departamento del Pando, with its capital Cobija, has several small diesel installations, operated by the Corporacion de Desarrollo del Noroeste. ENDE should continue studying possibilities of installation of some hydro-plants to substitute partially for thermal generation in the area. (h) Rural Electrification: The Instituto Nacional de Electrifacion Rural (INER), an agency of the Ministry of Energy, responsible for providing electricity to isolated villages and small towns, has so far provided installa- tions, mainly diesel plants, to some 50 villages. In addition, the local distribution companies have programs to extend their distribution lines to the neighboring rural areas. ENDE has also invested considerable amounts of money in the construction of some 4,500 km of primary and secondary lines, installations which are normally handed over, at the end of its construction period, to the local distribution company or local institutions. The management of current operations as well as future decisions relating - 64 - to new investments should be reviewed in the context of a comprehensive plan. Recommendations 5.13 (a) Complete the economic and financial analysis of the new power development plan and arrive at a flexible and coherent optimum solution for the 1986-1990 power generation expansion. (b) The choice between natural gas and hydro-based expansion of the generating capacity depends on the decision of the gas export project to Brazil. (c) Obtain technical assistance to evaluate the changes in design recommended by the UNDP consultant for the multi- purpose hydropower projects of Icla and Misicuni. (d) To update and uniform the cost information on ENDE's project list, the company should develop a cost manual for Bolivia, with proper adjustments to the specific conditions of each region. (e) In isolated power system, new alternatives should be continuously studied to reduce their dependence on diesel oil. In the rural area, the management of current operations and future investments in power should be reviewed in the context of a comprehensive rural electrification plan. - 65 - VI. REFORESTATION AND POTENTIAL FOR SMALL SCALE RENEWABLE ENERGY USE 6.01 Bolivia has considerable forest resources and exports about 90M m3 of high quality wood products per year. However, these resources are located mainly in the scarcely populated tropical lowlands. In the Altiplano, there is practically no remaining forest cover and the dense population relies on shrubs and animal waste to satisfy their energy requirements, with consequential adverse effects on the already highly eroded environment. In the southern tip of Bolivia (Tarija), uncontrolled past deforestation has caused an erosion problem of major proportion. In the valleys, wood is being exploited more rationally and the population has interest to increase their agricultural revenue by reforestation. 6.02 The use of fuelwood and other biomass by the rural population is insufficiently known. Only in 1980 was an OLADE-sponsored survey initiated, which covered 32 villages in the valleys and semitropical areas of the La Paz department and one village in the Beni Department. Based on the results of this survey and with the use of information from other Latin American countries, the Ministry of Mines and Hydrocarbons estimated a daily per capita consumption of 1.9 kg in the Altiplano, 2.5 in the valleys and 3.1 in the tropical lowlands. The mission consideres that these figures are too high. The experience in other countries indicate an average daily per capita consumption varying from 1 to 1.5 kgs. It is not clear whether these figures represent only household consumption or whether the differeInces also account for industrial use of fuelwood. Total fuelwood consumption is estimated at 2.1 MMton in 1980, of which 42% is in the Altiplano and 29% each in the valleys and the lowlands. It is recommended that the survey of fuelwood consumption be extended to obtain more reliable data for the reforestation projects. A. FUELWOOD Altiplano 6.03 Unconventional technologies, such as biogas, windpower and solar energy, are expensive relative to the income of the rural household and require a social and technical environment that can only be brought about through continuous technical support. Furthermore, the climate of the Altiplano limits considerably their potential to serve as fuel for cooking. The mission therefore recommends that the energy problem of this region be treated as a part of integral rural development programs and energy technologies be adapted taking into account the conditions of each location. 6.04 Agricultural research should be addressed to increase plantation of multi-purpose crops. For example, there is a species known since pre- colonial times in the Altiplano that provide high protein grains, has celulosic stems that can be used as fuel, and fixes nitrogen to the soil: Chemopodium Quinoa, a leguminous plant. Modern research to increase - 66 - productivity of these plants and to find processes for expanding its markets (it has a potential to substitute for wheat) are necessary. 6.05 Reforestation has proven successful in the Omasuyos/Los Andes project which is currently being implemented. This is a part of the program of the Altiplano Rural Development Institute (IDRA) funded by the World Bank. The forestry component aims at reforesting areas in those two Altiplano provinces for production of fuelwood and local construction materials. Species trials to identify new trees which would survive the harsh Altiplano climate will also be carried out. In the meantime, conifers and Eucalyptus grandis will be planted with emphasis on the more favorable micro-climate near Lake Titicaca. The project has been very successful in developing demand by individuals and community groups for seedlings and technology for establishing small temporary nurseries and for planting trees. The demand for seedlings already far exceeds the capacity of existing government nurseries. Expansion of a CDF nursery near Huarina from a capacity of 200,000 seedlings per year to 600,000 will therefore be carried out in 1982 by the Project Unit in agreement with the CDF. Field visits to the existing nursery and various planting sites revealed considerable local interest in the planting program. Tarija 6.06 In this eroded southern part of Bolivia, a soil recuperation program is being executed (PERTT). This program is using the approach of assisting rural community groups in the establishment of their own small nurseries with a production of around 30,000 plants per year for use by the group members. Since these communities become actively involved in their own seedling production, they have an inherent interest in planting the trees well. PERTT gives the necessary technical assistance for establishing the nurseries, provides the communities with seed and materials and gives technical advice for planting. It also maintains several larger nurseries (capacity about one million seedlings per year each) in the Tarija Valley, which produce seedlings for sale and/or for planting on public lands. While the program has been a technical and economic success, it is still a small-scale program compared to the area's needs. Although just under 500 ha were planted in the three-year period 1978-80, it has been estimated, with the aid of aerial photographs, that over 70% of the Tarija Valley's soils are "severely" eroded and that agricultural and grazing lands are being lost at the rate of over 800 ha per year. FAO evaluated the situation in Tarija and recommended a strong soil conservation program based on intensive extension, services to improve pastures and grazing and cultivation practices. Small woodlots and strategically located industrial forest plantations would take pressure off the few remaining wooded areas for supplying fuelwood, local construction needs and industrial wood needs. This, plus protection from over-grazing, would allow the eroded hillsides to regenerate naturally in a relatively short time (3-5 years). Civil works (check dams, river bank gavions, etc.) and reforestation in critically eroded areas would also be needed. - 67 - 6.07 The mission suggests that PERTT program be investigated as a potential rural development program with emphasis on low-cost, efficient soil conservation activities and the establishment of woodlots for domestic fuelwood and construction needs, industrial charcoal production, and industrial roundwood (a newly built pulp and paper mill does not have sufficient wood raw material to operate at capacity and wood pulp must be imported from Chile). Chuguisaca 6.08 Another reforestation and conservation project is being developed by the Chuquisaca Regional Development Corporation (CORDECH) exclusively with Government funds and local technology. It has been highly successful in developing a reforestation/conservation awareness in the rural population of the region. The social and economic importance of the program is significant. 6.09 The Department of Chuquisaca is largely of forestry vocation in that its soils in general are not suitable for sustained agricultural activities. Many farmers have abandoned their land and moved to lower tropical areas to the east where malaria and other diseases have taken a heavy toll. Much of the area of Chuquisaca was covered with large valuable cedars of which only a few specimens remain. These and other trees were cut for mine timbers, construction wood and firewood and charcoal for smelting silver, gold and tin. As a result of this cutting and a rigorous environment which makes natural regeneration difficult, the area is now almost completely deforested. Local ceramics (roof tiles, bricks) companies, mostly small operations, are purchasing firewood from about 60 km away. This fuelwood accounts for almost 25% of the production costs of tiles and could be produced in small woodlots near the ovens. This is one of the objectives of the reforestation program. By promoting reforestation, CORDECH is creating immediate employment in the planting activity. The forests have excellent growth rates and will provide cash income to the rural population. Agricultural activities will supply enough food for subsistence. There are already examples of families who have returned to the land they have previously abandoned and wish to reforest it. The benefits in terms of soil conservation and improved water flow and quality are also expected to be great. Demand for seedlings already exceeds the two million trees per year capacity of the program's nurseries. 6.10 A US$1 million project funded by IFAD will establish ten new nurseries in three additional provinces to the south of Sucre (Oropeza, Yamparaez, Zudanez). This is a successful program which needs technical assistance to improve its nurseries, species selection, reforestation techniques and monitoring activities and needs financing to expand into new rural areas. The FAO Forestry Department has agreed to provide technical assistance, although fielding of specialists has been delayed now for nearly a year. The successful methodology developed for promoting reforestation, the good growth rates being obtained with Eucalyptus grandis and Pinus radiata (over 5 m3/ha/yr) plus good markets - 68 - for industrial and domestic fuelwood, pit-props and industrial roundwood are factors which make this an excellent project, for which external financing should be requested. B. CHARCOAL 6.11 Charcoal consumption is estimated at 25,000 tons per year. Over 85% of the charcoal consumed in Bolivia's tin smelting industry, (as a reducing agent) comes from the Santa Cruz and Chaco regions. The average transport distance is over 1,000 km by dirt road. Essentially 'free' wood from residues of crosstie manufacture in the Chaco and from land clearings near Santa Cruz, together with lack of raw material closer to the smelting center in Oruro allow the long distance transport to continue despite its heavy costs and energy consumption. The transport cost of the charcoal is equal to its value at the charcoal producing site ($b2,500/ton). Discussions and visits with the Charcoal Producers Association (ANICARVE) and the consuming smelter (ENAF) indicated that the charcoal producers are not efficiently organized with respect to timber harvesting. Large, high-value logs are converted to relatively low value charcoal for: lack of industrial infrastructure in the rural areas (small sawmills); lack of markets for logs for crossties and sawnwood (economic recession); lack of proper harvesting and transport equipment (trees are cut and bucked with saws and loaded by hand). Also, a rather unusual division of labor leads to cutting of large trees. One group cuts the trees and has a quantity quota which can be made up quickly by cutting a few large trees. Another group loads the trees onto trucks and must contend with manipulation of the large logs. The ANICARVE group requested a line of credit for investments in small sawmills and harvesting equipment. They also requested technical assistance for improving utilization of their forest resources. As a result of this visit, the mission contacted the US Forest Service, which was organizing a seminar on charcoal manufacturing for USAID in Brazil. The Brazilians are very advanced in industrial charcoal production and offered the course for other countries to attend. The result of this contact was that the President of ANICARVE attended the seminar in March 1982. 6.12 Because of the wood resource supply/demand situation, the Santa Cruz area will be the center of charcoal production for at least five to ten more years despite its distance from the principal market. The charcoal producers should therefore be given technical assistance to improve the efficiency of their industry and provide lines of credit to purchase capital equipment to modernize their operations if studies show this to be feasible. 6.13 In the meantime, the Government should develop a reforestation program with fast-growing fuelwood species near the Oruro area in order to guarantee supplies of charcoal ten years hence at lower cost to the smelter. Species and planting trials should be initiated as soon as possible in the Oruro area and in the now deforested traditional charcoal supply areas nearby. - 69 - Wood and Charcoal Stoves 6.14 The long existing scarcity of fuelwood in the Altiplano has induced the design of a locally produced stove which appears to be energy efficient. It is made of clay and sand and the top hole fits perfectly the convex shape of the cooking pot's base. In the lowlands, more primitive stoves are used. It is recommended that the traditional stove of the Altiplano be evaluated. Should the tests confirm its efficiency, a program should be developed to adapt it to the rest of the country. This would be a means to create a new cottage industry in the Altiplano. COMPONENTS OF AN FOREST-BASED ENERGY DEVELOPMENT 6.15 It is recommended that a forest-based energy development project for Bolivia should comprise several components: (a) reforestation for charcoal production in the Oruro area. A feasibility study would have to be undertaken to determine: planting sites; species to be planted (this information to be improved by a species elimination and trials program included in the project); methodology and detailed costs of planting; and delivered cost of charcoal to smelter. Strategically and economically this is potentially the most important reforestation program which could be developed for Bolivia. The responsibility for developing this project would have to be determined (CDF and/or ENAF and/or regional development corporation for Oruro); (b) technical assistance for and expert evaluation of the forestry, charcoal manufacturing and charcoal transport activities in Santa Cruz. Depending on consultant recommendations, lines of credit would be opened to mechanize and modernize these operations; (c) project for an expanded reforestation project in the CORDECH area for fuelwood production for domestic and industrial needs and for industrial raw material production; (d) expansion of the Omasuyos/Los Andes forestry project and the development of similar projects in other Altiplano regions to produce fuelwood. This would substitute the burning of dung which could be used for fertilizer. A strong species trials component would be necessary for selecting trees resistant to the rigorous Altiplano environment. The data generated by the MEH/OLADE fuelwood survey would be the basis for determining areas with critical fuelwood shortages; (e) preparation of a forest energy and soil conservation project in the heavily eroded Tarija Valley. Plantations for charcoal and pulpwood production would also have markets according to contacts with Tarija groups. The FAD suggestion for establishing a charcoal for export (to - 70 - Argentina) firm in the Chaco region of Tarija should be investigated; (f) research to increase plantation of high protein crops (such as Chemopodium Quinoa and other leguminous plants) in the Altiplano, which would simultaneously provide food and fuel and help stem the erosion problem and fertilize the soil; (g) minimum investment requirements to execute these projects are estimated at US$30 million, allocated in the following manner: (i) expansion of the Omasuyos/Los Andes projects US$ 7 million, including applied agricultural-forestry research; (ii) extension of the Chuquisaca reforestation and conservation program US$4 million; (iii) soil conserva- tion project in the Tarija Valley US$10 million; (iv) technical assistance to industrial charcoal producers US$1 million; (v) establishment of a tree plantation near Oruro for the production of industrial charcoal US$8 million. - 71 - VII. MAJOR POLICY IMPLICATIONS 7.01 Major policy changes are necessary to enable the energy sector to cope with the task of supplying future internal energy requirement and increasing its contribution to foreign exchange earnings. To place these issues in the proper perspective, the first section of this Chapter sums up the main investment categories previously discussed. It then analyzes energy pricing and institutional issues that have to be resolved. A. ENERGY INVESTMENTS 7.02 The share of the consolidated public sector's capital expenditures has decreased from 15% of GDP in 1977 to 5.7% in 1980. In 1981, these investments amounted to the equivalent of some US$385 million or 6.6% of GDP. During the period 1982-85, it seems prudent to assume that the Bolivian economy will not be able to sustain an annual public investment program of more than 7% of GDP or some US$400 million (in constant 1980 prices), given the poor economic outlook and the fiscal constraints. Should GDP grow at 5% in real term after 1985, then the investment capacity will have to increase at a higher rate. To establish a reference mark with which investment requirements on the energy sector can be compared, the mission assumes that average total public invest- ments during the period 1986-90 will be US$500 million per year. 7.03 The investment plans for 1981-86, submitted by the energy corporations in 1980, estimated total capital expenditures of US$2,073 million in constant 1980 prices (YPFB US$1,553 million and ENDE US$520 million). This would represent an annual outlay of US$415 million, which clearly exceeds the present capability of the Bolivian economy. To assist the Bolivian Government in the difficult process of screening priorities and allocating scarce resources to the most fundamental projects, the mission reviewed the investment programs of each energy corporation. 7.04 The decision on the gas export project to Brazil is the most important determinant of the sector's investment requirements. Firstly, it would accelerate economic growth and therefore increase the levels of internal energy demand. Secondly, it would require a direct investment in gas production and transport facilities of about US$800 million, which is roughly equivalent to 50% of YPFB's investment program. Thirdly, the hydro-based alternative would become the least cost solution for expanding the power generating capacity. The combined effect of higher demand for power and the choice of the hydro-option would increase ENDE's investment expenditures in generation from US$120 to US$600 million (para 5.09) for the period 1982-1990. 7.05 The mission adopted two investment scenarios: (a) The decision to implement the gas export project is not taken; and - 72 - (b) An early positive decision on this project is reached. Both scenarios are divided into two four and a half years periods: 1982- 86 and 1986-90. The mission included not only those projects listed in the energy corporations' development plans, but also additional investments that have been discussed in previous chapters. The results are summarized in Table 7.1. No Gas Export Pipeline 7.06 Due to the much lower than expected growth in energy demand during 1981-85 and an estimated more moderate growth during the second half of the decade, it is safe to assume that the levels of energy demand estimated for 1986 on which the investment plans were based will not be reached but at the end of the decade. 7.07 Total energy investments under this scenario are estimated at US$1,012 million, with an average annual expenditure of US$82 million during the first half o:E the period and US$142 million during the second. This represents 21% and 28%, respectively, of the total public investment for the two periods. 7.08 YPFB's minimum capital requirements were estimated at US$181 million for period 1982-86 and at US$406 million for the second period. These figures are based on the criteria that no exploration would take place until mid-1986 and then only half of YPFB's program would be excuted. Development of fields would be limited to Vuelta Grande during 1982-86, Espino and half of the new fields development program would be carried out in period 1986-90. Production drilling and secondary recovery projects would be executed as planned. In transport, the extension of the Monteagudo-Sucre gas pipeline and the repair of the Cochabamba-La Paz line would be implemented to enable substitution by gas in the industrial sector of the Altiplano before 1986, and some natural gas distribution networks would be built after 1986 to enable substitution of other consumers in the major urban areas (Annex 1.37). 7.09 ENDE's capital requirements are estimated at a total of about US$293 million (US$113 million for 1982-86 and US$1.80 million for 1986- 90). These include ongoing works as indicated in Annex 1.10, comprising some hydropower projects and the transmission line between the oriental and central electric systems. Also allowance is made for distribution networks, which are not included in ENDE's investment budgets. It is estimated that during 1986-90, demand for electricity would grow as estimated by the mission under the Baseline Scenario (Table 5.1) and that capacity expansion would be gas-based. Table 7.1: Investment Requirements Energy Sector (1980 prices - million US$) 1982 - 1986 1986-1990 Without With Development Pipeline Pipeline Without With Programs to Brazil to Brazil Pipeline Pipeline suppy Hydrocarbons Exploration 296 - 25 177 271 Development 515 98 222 169 293 Processing 79 0.3 0.3 - 3 Transport 571 47 485 3 119 Marketing 92 35 35 57 57 Studies - 4 8 - - Power Generation 477 70 70 120 450 1/ Transmission 43 43 43 - - Distribution - 35 35 60 60 Reforestation and Research - 10 10 20 20 Conversion - conservation study 2 2 2 4 Private investment in equipment 20 20 30 30 Institutional Strengthening, Training 10 10 5 5 TOFML (constant 1980 prices) 369.3 965.3 643 1312 I/ Based on demand projection for electricity as estimated by mission. Under ENDE's set of projections this would increase to US$600 million. - 74 - 7.10 Further capital allowance has been made for investment in reforestation (US$30 million), in energy conservation (US$54 million), and in institutional strengthening (US$10 million). With gas export pipeline 7.11 Under this scenario, the mission considers that the financial restrictions will remain, and that only those investments directly or indirectly related to the gas export pipeline should be made. Even under this conservative approach, the amount of financial resources required become extremely high. Investments are estimated at US$965 million during 1982-86, or US$214 million per year, more than half of total public capital resources. During 1986-90, they amount to US$1,312 million, equal to almost US$300 million per year or 60% of public capital expenditures. These figures indicate that substantial foreign financial assistance is required and that it would be convenient to consider ways of increasing private participation in the development of the energy sector. 7.12 YPFB's capital requirements were estimated at US$770 million during the first period and US$740 million during the second. During 1982-86 only minimal exploration is included, the development of the Boomerang fields and the construction of the gas export pipeline. In the second period, YPFB's projected exploration and development program is fully implemented and it is also assumed that the new Santa Cruz- Cochabamba pipeline would be built. The mission has, however, excluded the investment in the ammonia-urea complex, considering that it should be postponed to the 1990's. 7.13 ENDE's investment needs are estimated at US$658 million for 1982-90. The considerable increase over the first scenario (para 7.09) are due to the choice of hydro development over gas-based capacity expansion. The demand projections on which the second period investments are based are the same as in the first scenario. B. ENERGY PRICES 7.14 Two crucial pricing problems confront Bolivia. The first refers to the absolute price level which determines the income of the energy corporations and their capability to remain in business. The second relates to the relative prices of the various energy forms which must be structured so as to give the right incentive to shift demand towards the more abundant energy sources. 1. Absolute Prices: 7.15 Bolivia is undergoing a readjustment of its internal price structure. While the Bolivian peso was devalued and the foreign exchange rate has increased by 700% 1/ since January 1982, its internal inflation 1/ On November 6, 1982, the Government reunified the exchange rates to $b200/US$. - 75 - rate was only about 110% from January to August 1982. The difference between the two rates gives an indication of the high social cost of this readjustment, and permits understanding of Government's reluctance to carry it beyond tolerable levels. 7.16 Both energy corporations (YPFB and ENDE) have been hurt by these events. However, their immediate financial position differs consider- ably. The power corporation depends on domestic revenues which have been increased by a total of 517% (in February by 54%, and again in November 1982 by 300%) while its investment program has probably increased by 460% 1/ and its current expenditures by 100%. 7.17 YPFB's financial position has nominally improved because of the large component of export revenue in its total sales revenue. 2/ However, it is not clear whether the Government allowed the corporation to retain these earnings. Oil Product Prices: 7.18 Bolivia is no longer a surplus petroleum producer and it is in the country's interest to encourage conservation and to accelerate the transition towards a balanced pattern of energy consumption. To achieve these objectives, prices should signal to consumers the opportunity cost of using petroleum products. This cost should reflect the relative scarcity of each product in the domestic market; that is, full net-back value (fob) obtainable from exporting products where there is still a supply surplus (basically napthas, gasoline and LPG), and fully expensed import cost for deficit products such as diesel and fuel oil. In the longer term prices must reflect the full import cost. 7.19 In the course of 1982, the price of petroleum products rose substantially in nominal terms, but declined in real terms as a result of rapid inflation and the depreciation of the Bolivian peso. Thus, the economic measures taken in February meant that the price of the composite barrel declined from US$34 and US$27. From that level, the real price fluctuated downwards to a minimum of about US$5.90/bbl. The new economic measures imposed in November resulted in a major increase to about US$16/bbl. However, this is still less than half of the opportunity cost of US$37/bbl, as shown in table 7.2 below. I/ Assuming 60% foreign component at an average devaluation rate of 700% and 40% domestic at 100% inflation. 2/ Annex 1.32 estimates that the operational revenue has increased from a budgeted surplus of US$180 million to US$370 million with the double exchange rate. - 76 - Table 7.2: Petroleum Product Prices: Retail vs. Opportunity Cost (US$/bbl) 1981 Shares in Retail Price Total Sales Opportunity 1981 Feb. '82 Nov. '82 % 3/ Cost 2 1/ Gasoline Premium 1.3 36.26 44.52 36.14 27.83 Gasoline Superior 31.3 33.47 38.16 28.91 19.88 Kerosene 7.6 47.60 25.44 18.07 6.36 Diesel Oil 21.6 42.17 38.16 28.91 18.29 Fuel Oil 11.2 43.06 34.98 27.10 17.49 Jet Fuel 2.0 47.60 54.60 57.27 61.74 Jet Fuel LAB 5.4 47.60 54.60 57.27 n.a. 5/ Avgas 100 Oct. 1.3 66.08 84.00 62.05 21-36.75 6/ LPG Domestic Use 15.5 22.98 10.30 6.83 2.18 Industrial Use 0.8 22.98 10.11 8.78 6.12 Automobile 0.5 22.98 19.08 18.07 11.93 Average Barrel 4/ 98.5 37.30 34.03 26.84 16.26 (19.25) 7/ INDEX 100.0 91.2 72.0 43.6 1/ Conversion made at the official exchange rate of $b44/US$. 2/ Import price of products that are scarce (diesel, fuel oil) and FOB export netbacks of products that are in more ample supply (LPG, gasoline, Avgas), based on Platt's Oilgram, March 24, 1982; general purpose tanker rates at 190 WS and actual 1981 overland transport costs. 3/ Shares as indicated in Annex 1.17. 4/ About 1.5% in volume consist of non-energy products sales. 5/ The price for Lloyd Aereo Bolivianos has not yet been decided. 6/ The lower price is for meat transport flights. 7/ Composite barrel excluding LPG. 7.20 While Government has succeeded in raising prices above the fully expensed cost level of about US$16/bbl and thus insured the financial viability of oil operations in the short term, prices are still far from reflecting the true economic value of oil. The mission recognizes the giant step already taken. At the same time, it recommends that the Government adopts opportunity cost as the pricing principle and adjust prices gradually aid periodically at a higher rate than internal inflation to achieve its objective level as soon as possible. - 77 - Power Rates: 7.21 Power rates underwent the same pattern of increase in nominal terms associated with a decline in real terms as shown in Table 7.3 below. Table 7.3: Bolivia: Average KWh Prices of Electricity (Current Prices per average kWh) 1980 1981 Feb. 1982 Nov. '82 Companies $b USf $b US $b US4 $b US4 ENDE (Bulk sales) 0.69 2.8 1.20 4.8 1.85 4.2 7.40 3.70 BPC (La Paz) 0.82 3.3 1.35 5.4 1.51 3.4 7.10 3.55 CRE (Santa Cruz) 1.15 4.6 1.78 7.1 1.96 4.5 7.50 3.75 ELFEC (Cochabamba) 1.11 4.4 1.70 6.8 1.88 4.3 7.10 3.55 CESSA (Sucre) 1.21 4.8 1.66 6.6 1.84 4.2 8.16 4.08 SEPSA (Potosi) 1.42 5.7 2.00 8.0 2.18 5.0 7.50 3.75 SETAR (Tarija) 1.64 6.6 2.39 9.6 2.57 5.8 7.50 3.75 7.22 ENDE confronts a very strained financial position. Although the Electricity Code guarantees a 9% rate of return, the corporation achieved a 6.8% rate of return in 1981. The mission recommends that the financial situation of ENDE be reviewed and that the bulk sales tariff be increased in accordance with the scheduled increases in the rates of return, that would permit an agreed average self-financing ratio of 44% for the period 1981-86. 1/ Long Run Marginal Power Costs (LRMC) 7.23 Previous studies made by the Bank 2/ indicate that ENDE's bulk rates should be based on the LRMC, which would allow the generation of local funds to finance up to 44% of the expansion program. For ENDE's least-cost solution based mainly on a hydroelectric development, the LRMC, calculated in an approximated way by the average incremental 1/ Simons Resource Consultants in a preliminary review of the power sector recommend that the National Electrical Code should be amended to allow for interest charges on overdue accounts. (Guaranted rate of return to be increased from 9% to 15%). 2/ ENDE V. POWER Project - Staff Appraisal Report No. 3617-B0. - 78 - cost, in constant currency, at a discount rate of 12%, was USt5.85/kWh. 1/ This compares to an average tariff of US 3.7/kWh. This indicates that tariffs have to be increased by at least 58% to allow meeting ENDE's objectives. 2. Relative Prices: Hydrocarbons 7.24 The relative prices of oil products and natural gas must be structured so as to give the right incentives for interfuel substitutions. The price of gas should reflect its production and transport costs (without the pipeline to Brazil), or its opportunity cost (with the pipeline to Brazil). Fuel oil and diesel prices must be increased to those of gasoline in energy equivalent terms to reflect their scarcity. Simultaneously, the kerosene price and the price of domestic LPG should be increased to avoid their use as substitute fuels in the industrial sector. To provide a comparator for the price of gas, the following estimate of the long term incremental costs has been made. Incremental Gas Production Costs: 7.25 An economic distinction should be made between gas produced in condensate fields and gas from mainly gas fields. The former are developed because of the associated condensate and because of their relatively high content of propane and butane which can be liquified. It has been shown that the natural gas from these fields is enough to supply *domestic requirements for the next 20 years. Gas from the Boomerang area can be developed only if a new market outlet for gas is found. Thus, the feasibility of the alternative uses for natural gas has to be compared with the incremental cost of producing these reserves. Exploration Costs: 7.26 For the purpose of incremental costs, the relevant discovery cost is that of the future. A sound practice of the hydrocarbon industry is to replace each cubic foot of gas produced by discovering a new one. To estimate future costs, YPFB's five year exploratory program (1981- 1985) was used. The program specified a total expenditure of US$325 million in 1980 prices. 7.27 Assuming that the reserves discovered during the 1981-85 period will be produced over the following 15 years, and that the opportunity 1/ This 1981 Plan assumed a gas price increase from US$1.55/MCF in 1982 to US$4.50/MCF in 1989 and thereafter. The reassessed Power Plan is based on a constant gas price of US$3.00/MCF. - 79 - cost of capital is currently 14%, the exploration cost can be computed at US$0.47/MCF 1/. Development Costs 7.28 To estimate this category of costs for the Boomerang area, YPFB's development plan for 1981-85 was used. It includes detailed additional geophysical work, step out exploratory wells to define the limits of the fields and the various productive horizons, development drilling, investment in a gas/liquid separation plant, and basic gathering and transport pipelines. The result of the exercise is very much dependent on the rate at which gas is to be produced and the capital cost. Assuming the basic production schedule, the development cost can be estimated at US$0.45/MCF (Annex 1.35). 7.29 It has been indicated (para 3.10) that it is technically possible to accelerate production of natural gas in condensate fields, beyond the optimum efficient level, if a substitute for natural gas is reinjected into the reservoirs. The production cost of nitrogen by cryogenic air separation techniques, is estimated at US$0.8 to US$1.2 per MCF, based on the United States experience for locations where field energy costs range between US$2-3/MMBtu. Operating Costs 7.30 Operating costs are derived from YPFB's annual financial statements 2/ and estimated at US$0.11/MCF. Transport Costs 7.31 Based alone on investments for the Altiplano pipelines and the foreseeable gas throughput, the transport cost for gas is estimated at US$1.20-2.00. YPFB should study the advantages in applying an uniform gas price throughout the country, distributing the regional transport cost to all gas users. Summary of Incremental Gas Costs 7.32 The technical incremental cost of producing, gathering and transporting gas in Bolivia are estimated on Table 7.4: 1/ Annual recovery of investment is US$53 million. Average annual production is 1703.6 x 109 CFGE/15 years = 113.6 x 109 CFGE per year (Annex 7.5). It is evident that with accelerated production, this cost would decline. On the other hand, this cost will increase over time because of diminishing returns. 2/ In 1980, YPFB produced some 52 BCF of gas. US$5.9 million are operating costs. They exclude taxes, royalties, purchase of gas from private operations, interest payment and depreciation. - 80 - Table 7.4: Incremental Gas Costs (US$/MCF) Boomerang Condensate Fields Exploration Costs 0.47 0.47 Development Costs 0.45 1.20 1/ Operational Costs 0.11 0.11 Sub-total 1.03 0.58-1.77 Transport Costs 1.12 - 1.97 1.12 - 1.97 Total 2.15 - 3.00 1.70 - 3.74 1/ Applies only if incremental volumes must be produced. 7.33 The so derived incremental production cost for natural gas currently being produced (US$0.58/MCF) is substantially higher than the accounting cost (US$0.18/MCF), calculated by YPFB for the first four months of 1982, which is based on past investments. Both values have to be affected by royalty and income tax, calculated in Bolivia on the basis of gross revenues. According to YPFB's estimate these amounted in 1982 to US$0.24/MCF. Thus, YPFB's supply cost is estimated at US$0.42/MCF, while its real economic cost is at least US$0.82 MCF. Finally, in the Table above, future average transport costs to the Altiplano region were estimated to range from US$1.12 to US$2.00/MCF. The added economic cost of US$1.94-2.79 compares to a present price of US$1.00/MCF. At this price, the investments required to supply the market in the future are not economic. Fuel Oil/Gas Price Ratio 7.34 The GDC gas survey in Santa Cruz indicated that "the experience of industrial gas conversion had shown that there are no technical problems involved with the conversion and that the average cost for converting was $b5.75/MMBtu of fuel consumed annually. These costs varied from a low $bl/MMBt,u to a high of approximately $bl7.50/MMBtu. At the mid-1982 cost differential between fuel oil and natural gas ($b210.18/MMBtu vs $b42.85/MMBtu or a ratio of 4.9:1), this would mean that the average industrial consumer would recover the cost of conversion within 1.5 years, with a cost recovery range of 3 months to 4.5 years for the low and high cases." Liquid Products' Price Structure 7.35 The present relative price structure in thermal equivalent terms is s shown in Table 7.5 below. - 81 - Table 7.5: Current Retail Prices in Energy Terms US$/MMBtu Gasoline 5.43 Gasoline Regular 3.88 Kerosene 1.14 Diesel Oil 3.26 Fuel Oil 2.93 LPG Domestic Use 0.53 Industrial Use 1.49 Automobile 2.90 LPG Price: 7.36 The current price for LPG distinguishes between domestic, industrial and transport uses. Domestic LPG, which represents the bulk of sales, is currently priced below the production cost, estimated at US$2.30/bbl in 1982, 1/ and well below the full expensed supply cost considering the transport and distribution costs of LPG. Maintaining these prices in the future would mean jeopardizing future production plans. The strategy in the long term should aim at unifying these prices. In the short term, the price for domestic and industrial LPG should be equalled (to inhibit substitution, which leads to an increased distribution cost for YPFB) and raised to at least 50% of the opportunity cost. Gasoline Prices 7.37 The large price differential between high octane and low octane gasoline is not justified on: (a) refinery costs nor (b) opportunity cost. In addition, about 60% of the vehicles operate at high altitudes, where the octane requirements are much less important. Therefore, the price of superior gasoline (low octane) should be increased and the distribution of high octane gasoline limited to the lowlands. This reduces refinery and distribution costs for gasoline. Gasoline/Diesel Price Ratio 7.38 The policy of pricing diesel fuel below gasoline has induced substitution in the transport sector as indicated in Table 7.6 below. Given the domestic supply constraint of diesel, it is recommended 1/ For the first eight months of 1982, YPFB estimates the production cost of LPG at US$5.00/bbl from the refinery (26% of total) and at US$1.35/bbl the LPG produced at gas plants. - 82 - that the price for this product be elevated to the price level of gasoline in thermal equivalents. Table 7.6: Fuel Use in Road Transport, 1975-81 (MTOE) Fuel 1975 1976 1977 1978 1979 1980 1981 Gasoline 296 313 338 356 368 374 375 Diesel 54 63 98 130 134 147 150 LPG 0 4 Total 350 376 436 486 502 521 529 Prices (US /gal.) Prior to Dec. '75 Dec. '79 Jan. '81 Nov. '75 Nov. '79 Dec. '80 Jan. '82 Feb. '82 Nov. 82 Gasoline Premium N.A. 94.6 90.8 106.0 86.0 66.0 Gasoline Superior 20.8 66.2 75.7 90.8 68.6 47.3 Diesel Oil 10.4 24.6 60.5 90.8 68.8 43.5 LPG N.A. N.A. 45.4 43.0 15.6 LPG/Kerosene Price Ratio 7.39 The present ratio between the prices of these fuels is adequate to induce residential consumers to continue substituting by LPG, as the supply of this fuel increases. However, the large difference between these two domestic fuels and industrial diesel and fuel oil will lead to uncontrollable substitution and in the end will defeat the social objective pursued with this pricing policy. Furthermore, it is suggested to consider replacing kerosene by gasoline for rural household uses. This can only be achieved if kerosene and consequently LPG prices be increased in parity with gasoline. - 83 - Table 7.7: Residential/Commercial Sector (MTOE) 1975 1976 1977 1978 1979 1980 1981 Kerosene 134 117 108 99 98 90 62 LPG 34 43 56 69 84 115 140 Prices (US /gal.) Prior to Dec. '75 Dec. '79 Jan. '81 Nov. '75 Nov. '79 Dec. '80 Jan. '82 Feb. '82 Nov. '82 Kerosene 4.7 5.7 15.1 60.6 43.0 15.1 LPG N.A. 4.6 14.8 24.5 16.3 5.2 Source: YPFB and Staff estimates. - 84 - C. INSTITUTIONS 7.40 The Ministry of Energy and Hydrocarbons (MEH) is responsible for formulating energy policies and for regulating the exploration, exploitation, industrialization and utilization of all energy resources, except forestry which is under the responsibility of the Ministry of Agriculture. 7.41 In principle, the MEH carries out its regulating functions for the hydrocarbon sector through the Direccion Nacional de Hidrocarburos and has under its jurisdiction the oil and gas corporation Yacimientos Petroliferos Fiscales Bolivianos. The electric sector is regulated by the other department of MEH, the Direccion Nacional de Electricidad (DINE). The National Power Company (ENDE) as well as the Rural Electrification Institute (INER) are also under the jurisdiction of this Ministry. 7.42 MEH is insufficiently equipped to exercise its functions and to coordinate the efforts necessary to successfully meet Bolivia's future energy needs. It is suggested that a strong and capable energy planning department be created within this Ministry. I/ 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 the economic cabinet must be established. This Department working together with strengthened Hydrocarbon and Electricity Divisions, 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 established between economic objectives and energy, and would coordinate with the Ministry of Agriculture in order to develop programs intended to increase the rural population's standard of living, including energy supply. 7.43 The Bolivian population must be made aware of the profound changes in energy demand structure that are necessary to ensure future economic growth. Therefore, the Government through MEH will have to lead a public campaign to explain its strategy and obtain the population's support. The conversion and conservation objectives must be brought about by a two-pronged approach: (a) technical assistance and credit lines for project evaluation and implementation; and (b) legal enforcement. 7.44 The organization and management of the energy corporation has been analyzed in former Bank reports and specific programs to strengthen these institutions are underway. In the following only those recommendations that are related to specific issues dealt with in this report will be discussed. I/ In early 1983, an initial Planning group was set up, sponsored by OLADE-EEC. - 85 - Hydrocarbons 7.45 The Bolivian Government will have to revise its policy regarding private participation in the sector. This report has highlighted the dramatic efforts needed to meet domestic demand. Furthermore, in the event of an agreement on the large export project to Brazil, production of gas will almost double. As a result, exploration will have to be promoted, new fields developed and investments in surface handling equipment made. This requires a large increase in professional and managerial capability and financial resources. It is not certain whether YPFB will be able to face these challenges alone and build-up its institutional capability in the short time within which these efforts must be made (about five years). 7.46 However, the mission considers that the present legal framework is not the most favorable to the Bolivian interests nor to the potential private participants. Currently, Bolivia's general Hydrocarbon Law postulates private participation in exploration, development and production of hydrocarbons under production sharing contracts. Also the law authorizes YPFB to agree on sole risk contracts for exploration alone (Article 51). The general Hydrocarbon Law does not define the production sharing percentages nor the production distribution systems. It is YPFB's responsibility to agree on these terms with each individual contractor and for each acreage. Furthermore, the law establishes that YPFB shall retain the volumes necessary to pay for the contractor's national and departmental tax liabilities. These volumes are valued at the well head price. In the present contracts, company/government splits are 40/60 or 50/50 of gross production. Taxes 1/ are paid by YPFB on the total volume produced. The companies' tax liability is fully met out of the Government's share of production. 7.47 The manner in which the general Hydrocarbon Law is being applied has several shortcomings: (a) the rigidity of the sharing arrangement deters exploration for marginal fields while obtaining for the Bolivian Government too small a profit share of large discoveries; (b) because the contractor's income tax is paid by YPFB, there are considerable doubts about whether US companies are able to obtain a foreign tax credit for Bolivian income tax liabilities; (c) because the law limits private participation to exploration, development and production, YPFB has the obligation to enter into all other peripheral activities (transport, refining, marketing). This distracts the limited technical and financial resources of the national oil company, when it should concentrate them on those objectives with the highest financial and economic returns. 7.48 The mission, therefore, recommends that the Government revise its general Hydrocarbons Law and/or the regulations that norms its 1/ There are two main taxes: (a) a 11% royalty paid to regional departments, and (b) a 19% income tax to the National Treasury. Both are based on international values of crude oil, minus deductions for processing and transporting costs as well as own consumption. - 86 - application and the tax laws. It should obtain the advice of legal and economic specialists on the current features of international contract formulas, including new contractual approaches to facilitate greater participation of private oil companies such as secondary recovery contracts in YPFB's acreage, "exploration only" contracts, service contracts and joint venture contracts, and design a new model contract. 7.49 Some Bolivians consider that the production sharing agreements should only be contracted for high risk ventures, in geologically less known or geographically removed zones, and that the best prospective areas should remain reserved for YPFB's activities. Undoubtedly, this opinion stems from the desire to use natural resources to the fullest for the country's economic development. However, it does not take into account that the sooner the resource is being produced, the derived revenues can be reinvested in the economy. At present, the financial limitations do not permit YPFB to develop the hydrocarbon potential at the rate necessary to backup the economic recovery process and to lead the country into a phase of steady growth. The economic reasoning therefore induces to consider capturing foreign investments for the development of Bolivia's hydrocarbon resources. A possible strategy could be to invite private operators to enter into agreement to explore high risk prospects, such as for stratigraphic traps, being compensated with a share in an area reserved for YPFB. Another alternative would be to offer the private participant a share in the gas export market 1/ in proportion to the reserves of gas discovered. It would also be desirable to investigate ways of involving private companies as service contractors on YPFB's acreage, establishing a fee payment for actual results. 7.50 Efficient management of the sector will provide guarantee that the resources are optimally exploited. The institutions must be capable of formulating and executing clearly defined and well coordinated programs and projects. The Ministry of Energy and Hydrocarbons must assume its role, defining an objective energy policy and supervising the operating companies. The mission recommends: (a) support for the Planning Division (Direccion de Planea- miento) as the unit in charge of formulating and evaluating energy strategies; and (b) staffing the Hydrocarbons Division (Direccion Nacional de Hidrocarburos) with qualified and independent personnel, as the unit in charge of reviewing the operations of YPFB and of private companies. 7.51 The loss of experienced professional staff in YPFB, the inadequate delegation of authority and accountability and the lack of 1/ Tesoro and Occidental were given a share in the export market of Argentina (a total of 80 MMCFD) and in the new contracts currently under discussions, the operator is guaranteed a 50 MMCFD share in the Brazilian market, should this project become a reality. - 87 - coordination between operative and financial objectives, hinder the performance of the company. The mission recommends the following specific measures to strengthen the institution: (a) Definition of the specific functions of each managerial and technical department, setting objectives, evaluating staffing requirements and establishing control systems to insure that objectives are met. (b) Revision of the salary structure, to directly relate remuneration to the level of responsibility and productivity, and indirectly to the salary levels in the private sector, within and outside of Bolivia. (c) Formulation of a career development program for professionals in technical and managerial positions, taking into account the long term staff requirement of YPFB. (d) Introduction of new administrative and financial control systems and revision of existing systems, in order to provide management with up-to-date and continuous information on stocks, on input and output flows and on financial transactions. (e) Implementation of analytical models that facilitate evaluation and planning of future activities and permit to optimize current operations. (f) Hiring a productivity expert, on a fixed term contract, with sufficient authority to promote performance and to reduce costs. 7.52 Furthermore, the company should incorporate into its scope of responsibilities the promotion of demand management and energy conservation. A specific user-oriented advisory group should be created, which would operate in close coordination with the marketing departments. It would assist consumers in implementing projects leading to higher fuel-use efficiency and to substitution from scarce to abundant energy forms. Furthermore, YPFB has to be given authority to monitor and enforce these programs. Power Sector 7.53 A preliminary review of the power sector of Bolivia 1/ indicates the need for a major study of the legislation, organization, financing and operations of the entities involved in the power sector. The mission recommends that this study be executed at the earliest. 1/ "Report on the Study of the Power Sector of Bolivia," by Simons Resource Consultants, Canada 1982, financed by UNDP. - 88 - 7.54 From the organizational and legal point of view, the mission shares the preliminary review's recommendations that the National Electrical code be updated and that DINE be given more independence to act and to make decisions on tariff recommendations. Similarly, that ENDE be restructured both as to its Board of Directors and its management to facilitate delegation of authority and decision making. 7.55 The Bolivian Government announced in November 1982 the decision to Nationalize the Bolivian Power Company, which has served the market of La Paz under a longstanding concessionary agreement. This will give ENDE an expanded financial base and the possibility of planning the expansion of its system on a larger and sounder basis, but also calls for stengthening of ENDE's technical system and long term economic and financial planning capability. Rural Electricity and Small Scale Renewables 7.56 INER was created for the purpose of introducing electricity in small towns and villages. It established power supply (mainly diesel based) in about 50 rural centers, where INER formed cooperatives to generate electricity and collect revenue based on tariffs designed to cover costs. Many of these have failed due to inability to operate, maintain and administer the plants. The mission recommends that the management of current operations as well as future decisions relating to new investments should be reviewed in the context of a comprehensive rural electricity plan. 7.57 INER has attempted to expand its program into alternative energy sources, investigating the applications of solar, wind, biogas and small hydro. However, this organization does not have the staff, technical skills or funds to carry out effectively such a dissemination program. The mission suggests that an alternative institutional arrangement be sought to execute the rural electrification program. Recommendations Pricing (a) The Bolivian Government should adopt the concept of oppor- tunity costs as the pricing principle for all energy products and increase prices to that level as soon as possible. (b) The prices for petroleum products should be pegged to the dollar and increased gradually and periodically at a rate higher than internal inflation. (c) The relative price structure of petroleum products should reflect the constraints on domestic supply. Fuel oil and diesel prices should be increased at the level of gasoline prices in energy equivalent terms. Simultaneously, kerosene and LPG for domestic use should be increased at - 89 - the same level, to avoid interfuel substitution in the industrial sector. (d) The price of natural gas should be raised to US$2.00/MCF in the short run, and to its true economic cost in the longer term. (e) Similarly, power rates should be adjusted gradually towards its long run marginal cost level, by periodic increases at a rate higher than internal inflation. (f) There is a need to make a national tariff study to rationalize the differences in the tariffs applied by the regional distribution companies, both in terms of the level of energy and demand charges and of their structure. Institutions (g) Insuring the objectivity of the Ministry of Energy and Hydrocarbons, backing of the small global planning unit and strengthening the capability of the Hydrocarbon and Electric Divisions. (h) Carrying out a public campaign to alert the public on the energy situation and to ensure cooperation for implementing the conservation and conversion strategy. (i) Reorganizing the management structure of both energy corporations to facilitate delegation of authority and decision making and improving coordination. (j) Revision of the hydrocarbon and/or its regulations and the tax laws, in order to incorporate current features of international contract formula, including new contractual approaches to facilitate greater participation of private oil companies. - 90 - VIII. SURPLUS GAS UTILIZATION 8.01 Surplus gas is defined as the volume difference between recoverable reserves and existing commitments. This chapter attempts to quantify this surplus and to estimate returns that could be expected if this gas were directly exported or converted into fertilizers or liquid fuels. 8.02 In Chapter 2, a long term projection to year 2010 of maximum gas demand was made. The estimated internal gas requirements (2.7 TCF over 30 years) exclude the inputs of natural gas into the large industrial complex envisaged for the Mutun area (export oriented steel mill and chemical plants). To insure that this quantity of gas is available in the future when such projects become economically feasible, it is necessary to make adequate choices at an early date. The obvious consequence of entering into an additional export commitment is that electric power requirements will have to be generated from hydro, geothermal or other sources. Such a decision would free some 0.8 TCF of gas, or 30% of total internal requirements, for other uses. The incremental capital cost associated with the hydropower option is a real cost that should be recovered through the gas export price (para 8.11). 8.03 At present, Bolivia has only one export commitment. It supplies 200-220 MMCFD of gas to Argentina on a contract that expires at the end of 1991 1/. Because of political considerations, it can be expected that Argentina will continue to purchase gas at the end of the contract, in spite of its own substantLal gas resources. 1/ This is a take-or-pay type contract, with some flexibility in terms of periodic offtakes. The base price is revised every quarter and was US US$4.27/MMBtu in early 1982. Argentina also purchases additional amounts of heavier hydrocarbons contained in the gas flow at a price equivalent to Arabian Gulf spot market prices for LPG and natural gasoline. - 91 - Table 8.1: Gas Surplus Estimate (109CF) 1982-2000 1982-2010 Gas Resources (Proven and Probable Reserves) 6,700 Internal Commitments Direct use as fuel (final demand) 383 1386 Power generation 315 809 LPG extraction 106 169 Fuel losses and consumption in hydrocarbon industry (10% of production) 160 320 Total Internal Commitments 964 2684 Export to Argentina to 1991 800 800 (or to year 2001) (1600) (1600) Total Commitments 1764 3484 (2564) (4284) Gas Surplus 4936 3216 (4136) (2416) Gas requirement for the export project to Brazil over 20 years 2,920 1/ Based on exports to Argentina until 1991. Source: Mission estimate. Export Project to Brazil 8.04 In October 1978, Bolivia signed with Brazil a letter of intent for the supply of 400 MMCFD of gas to the Sao Paulo area. The contract negotiations are now underway. The agreement is conditional on: (a) Certification of Reserves: can Bolivia certify and set aside an amount of natural gas reserves sufficient to supply the contract over 20 years? (b) Purchase price: can the parties agree on a price for gas which is economic for the purchaser and attractive to the seller? - 92 - 8.05 Reserves: Table 8.1 clearly illustrates the importance of this condition. The contract's aggregated commitment over 20 years is equal to 2,900 x 109CF, which are precariously in balance with the surplus calculated over 30 years. The balance is further endangered by the uncertainty relating to the reserve base. To lift some of these doubts, YPFB has initiated, with assistance from IDB/IBRD, an exploratory program of the gas fields in the Boomerang area and Vuelta Grande. The program is successfully underway and it is hoped that it will reach its objective by March 1983. Furthermore, YPFB will shortly contract a reserve certification program for its proven reserves classed in groups I, II and III. This program will include the following fields: Santa Rose, Yapacani, Enconada, Palometas, San Roque, Naranjillos, Vuelta Grande, Colpa and Rio Grande. However, it has to be noted that these programs will not add to the amount of 6.7 TCF used in Table 8.1, but simply provide a greater certainty to that number. Price 8.06 The letter of intent defined the parameters for price negotia- tions. It was agreed that the price basis would be the international price of these liquid fuels which are to be replaced by natural gas in Sao Paulo. The border price was defined as the difference between the base price and the average cost of transportation from Sao Paulo to the Bolivian border. 8.07 The price basis chosen does not have a single meaning. An international price can be defined in at least three ways: (a) the price of the liquid fuel at the refinery gate of a major exporting center (such as the Caribbean), plus freight and related expenses to Sao Paulo; (b) the price at which Brazil would be able to sell its fuel surplus in international markets. This implies a net back calculation of refinery price at a major exporting center (Caribbean), less the transport cost from Sao Paulo to the refinery center; (c) the price to the final consumer of the liquid being replaced which is derived from imported oil. 8.08 From the point of view of Bolivia, the price of gas must generate sufficient revenue to cover all gas supply related expenditures, must provide a compensation for the switch to hydropower generation and for the depletion of the national resource. 8.09 A recently concluded basic engineering study of the Santa Cruz- Sao Paulo pipeline provides a good basis for estimating the transport cost. The study arrives at a technical investment figure for the line of US$1,184 million in 1982 prices, which if escalated to completion (1986) would increase to US$1,695 million. The average unit transport cost to - 93 - pay for this investment, plus operational expenses, is estimated at US$1.99/MCF, separated into: (a) US$0.62/MCF for the Bolivian portion 1/ and (b) US$1.37/MCF for the Brazilian transport from Corumba to Sao Paulo. 8.10 Furthermore, the export project implies that Bolivia will incur in investment expenditures to develop the already discovered gas fields, in new exploration costs to replenish the resource base, in transport costs from the fields to the export pipeline, and in additional operational costs. The sum of these cost elements has been estimated (Table 7.4) at US$1.03/MCF. 8.11 Compensation for the switch to hydropower generation can be calculated as the result of dividing incremental capital costs by the gas export volume, both elements discounted at an appropriate rate. This compensation is estimated at about US$0.94/MCF 2/ if both flows are uniformly distributed over time and discounted at the same rate. 8.12 The addition of these cost elements (para 8.09-8.11) permits to arrive at a minimum border price of US$2.59/MCF. This figure does not include compensation for the depletion of Bolivia's natural resources in the form of royalty or taxes. 8.13 Given the magnitude of the investment (about US$800 million in current prices for Bolivia in the transport pipeline and in the development of the gas fields), the important policy implications of the projected pipeline and the wide price range within which the decision can be taken, the mission recommends that the Government obtains expert advice from professionals that have a good understanding of the international as well as Brazilian-Bolivian economic and energy issues. The present negotiating climate is particularly difficult because of the world economic stagnation, the softness of the oil market and the doubts regarding the extent to which the energy market should and will be restructured during the next decade or two. 8.14 To assist the Government in this endeavor, the following sections discuss: (a) the terms of reference of selected international gas export contracts; (b) the Brazilian energy situation; and (c) the alternative uses of gas as input into chemical plants and gas conversion into liquid fuels. 1/ The average transport cost for the Bolivian section assumes for early 1990's an increase in the throughput from 400 to 520 MMCFD to supply the gas requirements in the Mutun area. Should these industrial projects be delayed, the transport cost could be slightly higher. 2/ Power expansion requirements are estimated to increase from 406 MW in 1981 to 719 by 1990, to 1336 MW by 2000, and to 2304 MW by 2010. Total capacity addition is 1898 MW over the period. Incremental capital cost is calculated as the difference between US$2000/kW for hydro and $550/kW for gas-based units. Total export sales are 2.920 TCF over 20 years at a regular flow of 400 MMCFD. - 94 - A. International Gas Export Contracts 8.15 There are currently a number of gas export contracts in force and many of these have been revised in the recent past. Table 8.4 gives a sample of the terms of these contracts in reference to the choice of base price and escalation factors. The conclusions that can be drawn from these examples are discussed on the next page. 8.16 Base price: Gas is a clean-burning and versatile fuel; in addition it has characteristics of its own that give it a value above the thermal equivalent as, for example, in glass manufacture and petro- chemicals. Table 8.2 illustrates that base prices are currently in the US $4.25-6.36/MM Btu c.i.f. range. I/ A few contracts are based on a f.o.b price, such as Algerian contracts with France and Belgium; a few others specify border prices. I/ This is equivalent to a price for a barrel of fuel oil of US $24-30, assuming a transport cost that varies between USf25 and $2.00/MCF. Table 8.2: Base Price and Escalation Factors in International Gas Trade PRESENT WORLD GAS PRICES ($/MMBtu) INDEXATION TERMS VOL ALPHA HOW Importer Exporter (bcm/y) FOB CIF 1/ AS OF PERIOD FACTOR INDEX APPLIED U.S. CANADA 28.3 - 4.94 2/ 1.82 Irreg. 1.00 Crude imports to Toronto/US Alt. Fuels Price U.S./BORDER GAS MEX/PEMEX 3.1 - 4.63 3/ 1.82 Qtrly. 1.00 20:80 ratio of No.2 and No.6 fuels in major U.S. cities % Change FRANCE/GAZ DE ALG/SONATRACH 9.1 5.12 2/ 4/ 2.82 Qtrly. Eight crude oils Absolute FRANCE Btu Equiv. BELGIUM/DISTRIGAZ 5/ ALG/SONATRACH 2.5 6/ 5.12 2/ 7/ 1.82 .50 Crude Exported by LNG producers Absolute .50 Crudes Imported by Belgium Btu equiv. U.S./DISTRIGAS ALG/SONATRACH 1.4 5.82 2/ 1.82 1/2 yrly. .5/.5 Prices of No. 2/No. 6 oil in NYH % Change U.S./TRUNKLINE 1/ 5/ ALG/SONATRACH 4.5 3.94 1.82 1/2 yrly. .5/.5 Prices of No. 2/No. 6 oil in NYH % Change GERMANY NETH/GASUNIE 23.9 4.45 10.81 GERMANY NORWAY 8/ 9.7 4.25 7.81 ) .95 LSFO (1%) with 5 Month Lag GERMANY USSR 9/ 11.0 Yearly .96 .64 LSFO, .22 beating oil .10 wage developments GERMANY USSR/Yamal 10.5 4.65 2/ 4.65 10/ 7.81 1.00 20% crude oil, 40% gasoil, % change 40% LSFO JAPAN ABU DHABI 3.0 - 2/ 6.36 11.81 JAPAN/JILCOGP (Osaka Gas, Kyushu Elec. Chubu Elec, Kansa, Elec. Nippon Steel) INDO/BADAK 10.5 5.93 2/ 11.81 Oils imported by Japan. JAPAN BRUNEI 7.5 5.77 2/ 11.81 JAPAN US/ALASKA 1.5 5.86 2/ 11.81 1/ For LNG projects, approximately 40J/MMBtu should be added for regasification costs, except for Trunkline/Algeria and U.S. Distrigas/Algeria which include regasification. 2/ Basis of Contract. 3/ To achieve parity with Canada. 4/ 13.5% of the fob price will be paid by the French Government. 5/ Not in operation. 6/ From 1982-85. At that time, price is renegotiable and volume increases to 5 bcm. 7/ Due to "favoured nation" clause, actual contract price will depend on outcome of Algerian negotiations with France, Spain and Italy. 8/ Does not include Statfjord gas. 9/ Does not include proposed additional gas through the proposed Soviet (formerly "Yamal") pipeline. To/ Contracts are denominated in importing country currency and contain a floor price of about $5.40/MMBtu. Source: IEA - Natural Gas - Prospects to 2000. - 96 - 8.17 The base price reflects the lower thermal equivalent value in markets where gas has to compete with other fuels for the industrial and electricity generation markets. This appears to be the case of Sao Paulo, because of the economies of scale of the pipeline project and because reaching the residential/commercial sector, implies high distribution costs (low volume use and great seasonal variance). 8.18 In countries where there are severe restrictions on sox and NOx emissions, users are prepared to pay a premium of about USS1.0-1.50 MMBtu, as the comparison between Japanese and European contract prices illustrates. Sao Paulo has a severe pollution problem. The use of natural gas would substantially reduce the cost of the antipollution measures. 1/ 8.19 The absolute level of the base price has increased substantially in recent years. The parity with liquid fuels is fixed, depending on the negotiators' perception of factors such as energy scarcity and security of supply. For example, the export price of gas from Holland to neighboring countries is set at a border base price of US$4.45/MMBtu. The border price for the Mexican-US gas trade is US$4.63/ MMBtu. The reference point in the case of the European contracts is the price of low sulphur fuel oil; in the Mexican-U.S. deal, the gas price was calculated using a 20:80 ratio of the average prices of No. 2 (heating) oil and No. 6 (fuel) oil in a representative sampling of United States cities. 8.20 The indexation clauses of gas contracts contain the following elements: (a) Period: the interval at which indexation is applied varies from three to six months; the shorter the period the better for the seller as the reference period is usually chosen as the previous interval for the indexation. (b) The alpha factor: refers to the portion of the base price which is affected by the index change. It generally is 1.0. (c) Index: Currently the contracts tie the gas price changes to the variation in crude oil or petroleum product prices. It is important to choose an oil reference price over which none of the trade partners have control. Thus the average price of crude imports into Brazil should not be an acceptable index to Bolivia. Also some contracts have currency adjustment clauses, which can be important if the two partners have very dissimilar foreign trade structures., (d) Application of index: This refers to whether the index is applied as an absolute amount or as a percentage change. 1/ IBRD has granted a loan to Sao Paulo for pollution control. - 97 - This is especially important when the base price of gas is lower than the thermal equivalent of the index elements at the time the contract takes effect. (e) Most favored nation clause has been included in some cases. This should be of interest to Bolivia in case Brazil and Argentina enter into a gas trade agreement in the future. 8.21 As the letter of intent does not provide clarity regarding the liquid fuel that will be replaced by natural gas, nor establish a mechanism of indexation, the mission recommends that in the contract a formula be built in that would raise the base price from the fuel oil reference to diesel or to the barrel of crude oil. Similarly, the indexation should be referenced to a basket of products or crude oils, to increase its stability. 8.22 Furthermore, given the magnitude of the investment in the development of gas production and in the pipeline, Bolivia should also set a floor price in case the indexation goes negative and introduce a take-or-pay clause to guarantee sufficient revenues to cover investments. 8.23 Finally, this negotiation could serve as an example for intensifying trade among developing countries. Therefore, the parties should put their best endeavors to facilitate joint venture projects as set out in the initial letter of intent, especially for a fertilizer and a methanol plant. 8.24 Bolivia is under great pressure to increase foreign exchange earnings to pay back the external debt and to finance essential imports. The gas export contract to Brazil would mean an increase in future export capability and therefore enhance the Government's position in renegotiating debt and obtaining new capital outflows to bridge the current gap. Bolivia's negotiating team is therefore induced to reach an agreement as soon as possible. The Brazilian team, on the contrary, has no immediate reason for wanting to come to the end of negotiations. B. Brazil's Energy Situation 8.25 Brazil is making a major effort to restructure its energy market and reduce the country's dependence on imported oil. The program calls for a total reduction of oil imports from 1,700 MBD by 1985 under the business-as-usual-scenario to 1,150 MBD. This is to result from the following measures: increased domestic oil production 250 MB/D; interfuel substitution 350 MB/D; and conservation 200 MB/D. The substitution and conservation programs will affect in different degrees the demand for individual petroleum products. For example, it is estimated 1/ that the share of fuel oil in total demand will decrease from 30% in 1978 to 22% by 1985. In a similar manner, gasoline will decrease its share from 23% 1/ Brazil: Energy Assessment Report, IBRD -1982. - 98 - to 14% during the projection period. The fuels with growing shares are diesel, LPG and Naphtha. This shift requires adjustment of the refining capacity. Table 8.3 shows that without such an adjustment the surplus of fuel oil would at least be equivalent to 70 MBD. Table 8.3: Brazil: Possible Supply/Demand Refinery Balance in 1985 1/ ('000 bbls/day) Product Supply Demand Surplus/(Deficit) Gasoline 145 162 - 17 Diesel Oil 364 384 - 20 Fuel Oil 319 248 71 LPG 72 120 - 48 Naphta 90 107 - 17 Others 2/ 114 135 - 21 Total Products 1,104 1,156 - 52 1/ Assumes that the 1985 crude oil slate is similar to that in 1978; that no further conversion capacity beyond that currently envisaged is added; and that there would be a desire to limit direct product exports. 2/ Others include kerosene, lubes, solvents, greases, paraffin and asphalt. Source: Brazil Energy Assessment Report 8.26 The region around Sao Paulo is Brazil's most important industrial center as the fuel consumption figures show. In 1978, Sao Paulo consumed 125 MBD of fuel oil, or 40% of total sales in Brazil; industrial diesel consumption is estimated at about 25 MBD, or 33% of diesel sales in the region. 8.27 It is difficult to estimate the industrial fuel consumption of Sao Paulo by 1985-86 (about 150 MBD in 1978). It has been announced that 100% of ZESP's power system in Sao Paulo must substitute to coal (about 10 MMTY); and that by end of 1984 all fuel oil in cement, iron and steel plants must convert to coal. The industrial coal price in Sao Paulo is estimated at about US$30/ton or US$1.5/MM Btu for Rio Grande do Sul coal. This price is the result of heavy subsidization. 8.28 Brazil's oil products' prices are aligned to international levels, and carry a high excise tax. Fuel oils have a quality differential of about US$7/Bbl for sulphur; this is similar to world market differential of about US$1.60/MM Btu. - 99 - Table 8.4: Brazil - Fuel Prices - Retail Level as of July 1982 1/ US$/unit Unit US$/MMBtu LPG 0.14 lb. 4.98 Natural Gas 5.76 MCF 5.51 Gasoline Premium 2.79 Gallon 22.85 Gasohol 2.79 Gallon Diesel 1.67 Gallon 12.50 Motor Alcohol 1.63 Gallon Kerosene 1.70 Gallon 12.76 Fuel Oil No. 6 High Sulfur 29.15 Barrel 4.89 Low Sulfur 36.14 Barrel 6.50 Bunker C. 25.74 Barrel 4.32 Source: Energy Detente, July 9, 1982 Exchange Rate Cr. 169.51 per US$1.00 8.29 Sao Paulo has currently no access to natural gas; a naphtha based town-gas system exists which serves a reduced number of industrial consumers. However, it is of interest to reproduce here the Brazilian gas price structure for the different types of consumers, which shows a subsidy for gas as a feedstock, and a penalty of 34% above the thermal equivalent of fuel oil, for its use as fuel. Table 8.5: Brazil: Natural Gas Prices - October 1981 1/ Type of user US$/MMBtu Petrochemical Industry 2.87 Fertilizer 2.08 Steel Industry 2.27 Other Users (as a combustion fuel) 6.80 1/ Converted at the exchange rate of CR$115/US$1. 8.30 The brief review of the Brazilian and regional energy scene indicates that the proposed gas imports from Bolivia (400 MMCFD equivalent to 70 MBD of fuel oil) could be important. They will probably represent some 30% of total industrial oil consumption by 1985, which implies changes in the investment programs for refining and for coal production and transport. Private industry will also have to incur some expenditures to adapt to the new fuel. - 100 - 8.31 From the point of view of price, the individual consumer will not be willing to pay more than the thermal equivalent for the fuel currently used less conversion costs. If the anti-pollution effort is serious, this replacement fuel is low-sulphur fuel oil. C. Industrialization of Natural Gas 8.32 As an alternative for the pipeline to Brazil, the Bolivian authorities want to explore gas conversion technologies for producing fertilizers and/or liquid hydrocarbons to supply the domestic market and for export. None of these possible routes appear to be financially feasible at present. The domestic market is too small to provide a reasonable production scale, while the international market has a higher risk because of the excess supply likely to occur during the second half of this decade. Annex 3 provides the technical data on which the following conclusions on ammonia/urea, methanol, methanol-gasoline and gasoline-diesel are drawn. Ammonia-Urea 8.33 The manufacture of ammonia-urea can in principle be attractive. On the average, the net back value for gas in this use is estimated at about US$3,0-3.5/MCF 1/ for a large export plant. The mission estimates, however, that the Bolivian project would have a negative return of US$1.50/MCF of gas used in the plant. 8.34 Bolivia's planning commission (CONEPLAN) approved in July 1981 the project for an ammonia-urea complex. In January 1982, YPFB contracted a basic engineering study for a 165 tons/day ammonia plant (Haldor Topsoe technology) that would produce 250 tons/day of urea and at a later date some 50 tons/day of ammonia nitrate. This plant would in practice require an input of 8 MMCF/d of natural gas. This capacity was selected on the basis of the optimum use of fertilizers for a fully developed agricultural sector in Bolivia. The plant would be built at a cost of US$85 MM (1980 dollars), close to the Palma Sola refinery in Santa Cruz. The financial analysis is based on a 70/30 debt/equity ratio and a world price for urea of US$260/ton. 2/ It was further assumed that surpluses would be marketed in Brazil at the international price less US$25/ton to account for transport to the Brazilian border. 8.35 It should also be noted that in the initial letter of intent (1978) signed between Bolivia and Brazil for the gas export project, it was agreed that a fertilizer plant for export to Brazil would be built as a joint venture in Bolivia. Since then, Brazil appears to have lost interest in such a joint venture. 1/ Bank's in-house estimate. 2/ IBRD estimate for 1990 concurs with this figure. - 101 - Market Considerations (a) Domestic Market for Nitrogenous Fertilizers 8.36 Bolivia imports all its fertilizer requirements. Total imports for the agricultural year 1978/79 were 4,000 tons, of which 1,900 tons were nitrogenous fertilizers. 1/ This amount has practically not increased over the last 10 years. It is equal to applying 0.6 kgN/Ha of arable land and compares with an application considered adequate of 50- 100 kgN/Ha. This is the lowest rate of nitrogen use in Latin America. 8.37 As in many developing countries, the structure of relative prices in Bolivia discriminates against agriculture, with the result that this sector has a low technology level and low productivity. . For example, the average corn yield is only 1,370 kg./ha (or 18 bushels/acre). This compares with a world average of about 3,000 kg./Ha or an US average of about 100 bushels/acre. Current nitrogen consumption (1,900 tons of N equal to 4130 tons of urea) is only 5% of the proposed plant size (80,000 tons per year). Should the Bolivian Government commit itself to the full and accelerated development of agriculture it still would take at least 20 years to absorb the proposed capacity. 2/ It is evident that during the economic life of the plant, it will be mostly export-oriented. (b) International Markets 8.38 Ammonia is a feedstock for fertilizers and for chemicals (synthetic fibres, resins, etc.). Major additions to productive capacity have initiated operations or are scheduled to come on stream in USSR, Mexico, Trinidad, Middle East, Canada, etc. This development will induce competition and pressure on ammonia prices, (and in effect on all nitrogenous fertilizers) and force suppliers to take full benefit of the economies of scale at the production and shipping level. 8.39 A recent market study 3/ estimates world-wide demand growth for ammonia over the 1980-2000 period at an average of 4.1% per year, increasing from 69 million tons of nitrogen (MMTN) to 155 MMTN. 8.40 Bolivia's first choice of export markets consists of neighboring countries. It is estimated that the Latin American regions' supply- demand balance for ammonia will improve during the period. Mexico, Brazil, Venezuela, Chile, Trinidad and Argentina have plans to increase capacity. Thus, despite the projected growth of 6.8%/year in demand, the total deficit for the region is likely to decrease from 1.1 MMTN in 1980 to 0.5 MMTN by 1990. Brazil, Argentina and Peru are likely to have a deficit position in nitrogen trade whereas Chile will have a surplus. 1/ FAO Fertilizer Yearbook - 1979. Figures refer to metric tons of nutrients : N, P205, and K2 0 2/ In Burma, such an effort was made. During the last 15 years, Tertilizer consumption increased at 17% p.a., from 8 to 86 MT in the period 1964-1979. 3/ Chem System Inc. & Davy McKee, Petrochemical Plan for Thailand, March 1982. - 102 - Table 8.6: Supply/Demand Balance for Nitrogen Fertilizers (MTN) Country 1980 1985 1990 1995 2000 Brazil Demand 800 1500 2100 2600 3130 Supply 290 850 1300 1700 2230 Trade (510) (650) (800) (900) (900) Argentina Demand 60 120 200 280 350 Supply 45 70 80 300 300 Trade (15) (50) (120) (20) (50) Chile Demand 50 110 180 250 300 Supply 90 120 450 450 450 Trade 40 10 270 200 150 Peru Demand 100 150 200 250 300 Supply 70 70 270 270 300 Trade (30) (80) 70 20 - Source: Chem Systems Inc., Davy McKee - Market Studies - March 1982. Revisions by Mission. 8.41 According to these figures, Brazil is by far the most interesting potential buyer. That country's deficit of ammonia as fertilizer feedstock is likely to rise from 0.5 MMTN to 0.8 MMTN between 1980-1990. In addition, Brazil's market for industrial ammonia is expected to grow at 7%/year from 0.1 MMTN in 1980 to 0.5 MMTN by 2000. To penetrate that market, Bolivia would have to be competitive not only with urea produced from domestic feedstock but with nitrogenous fertilizers (such as ammonia nitrate) derived from imported ammonia. Brazil's fertilizer industry is controlled by PETROFERTIL, a subsidiary of Petrobras, which should be contacted by Bolivia to explore further a possible joint venture. This company has recently started up a large ammonia/urea complex at Araucaria (1200 ton/day ammonia) based upon partial oxidation of heavy residuum asphalt which is a more complex and more expensive route. Two additional natural gas-based complexes are under construction. 8.42 International urea prices are expected to increase only moderately because of the likely surplus in world market. However, as illustrated in Table 8.7, expert opinions differ substantially. - 103 - Table 8.7: Urea Export Prices (US$/metric ton) (US$/Metric Ton) Current Prices Constant 1981 1/ 2/ Prices 2/ 1981 230-250 216 216 1985 320-350 270 213 1990 610-620 450 265 1/ Obtained from the study by Chemsystem Inc. 2/ IBRD - Commodities and export projections - June 1982. (c) Production Costs 8.43 The scale of the plant is very significant in production economics. A world scale complex (1,000 ton/day of ammonia and 1,700 ton/day urea) would cost about US$300-450 million and the unit investment cost would be about US$600-900/ton/year of urea. A plant of the size proposed for Bolivia could have an investment cost as high as US$1,200/ton/year of urea. 8.44 The financial evaluation of the Bolivian ammonia-urea project (Annex 3.2) would result in a production cost of about US$340/ton, well above the cost of importing urea from world markets. This calculation was arrived at assuming a 10% discount rate and zero value for gas. Thus, should the project be implemented, Bolivia would have to absorb a net loss of US$1.53/MCF of gas put into the plant. 8.45 In light of these figures, it is suggested that Bolivia insist in its gas negotiations with Brazil on a joint venture to build a world size fertilizer plant. If the gas pipeline to Brazil is built, it might be profitable for both parties to locate the ammonia-urea plant near the largest market, because it is cheaper to transport natural gas than to transport liquid, refrigerated ammonia or solid urea. The financial evaluation indicates that such a plant would provide Bolivia with a net return of US$1.50/MCF of gas. 8.46 The mission shares the Bolivian Government's concern to increase agricultural output and to supply fertilizers at a reasonable price. It is suggested that Bolivia improve urea marketing practices, to reduce the cost of fertilizer to the final consumer. Synthetic Fuels: Conversion of Gas to Liquids 8.47 The Bolivian hydrocarbon industry has been considering the Fischer-Tropsch route, modified by SASOL in the Republic of South Africa, and the methanol-to-gasoline (MTG) route worked out by Mobil Oil Company as alternatives for using surplus gas. The preliminary economic - 104 - evaluation prepared by professionals of YPFB 1/ was reviewed by Bank staff. In general, it was found that the costs associated with these projects are much higher than the estimates used in the Bolivian study. Because these routes lead to the production of synthetic fuels and use energy in the conversion process, the netback value for gas that can be expected to be achieved is considerably lower than the value of gas in direct use as a fuel. Among these alternatives the manufacture of methanol seems to be the most interesting and therefore should be studied in greater detail. Mobil's Methanol--to-Gasoline Process 8.48 In January 1982, the New Zealand Government signed the final agreement with Mobil to build a synthetic gasoline plant using natural gas. The cost of the plant is now estimated at US$1.2 billion, an upward revision from US$500 million quoted in the initial project agreement in April 1980. The plant will have a nominal plant capacity of 570 MT/year of synthetic gasoline (or about 15,000 B/SD). These figures contrast with YPFB's assumptions of an investment of US$570 million and a capacity of 20,000 B/SD. According to YPFB, the gasoline plant would require input of 6,320 T/SD of methanol or the equivalent of four trains of 1580 T/SD each and total gas requirements would amount to 174.2 PMCF/D. 8.49 It must be emphasized that the New Zealand plant is the first commercial size plant of this type being built. The results of this venture are of interest to many countries in which security of supply, or high transport costs (in landlocked countries) are determining factors. It is still too early to estimate a cost per barrel of gasoline produced. Synthetic gasoline will probably not be competitive with imported oil and as an export alternative for gas, this route will provide a lower netback value than the methanol route. Given Bolivia's high opportunity cost of capital at this time, the mission suggests that further consideration of this route be postponed. Methanol 2/ 8.50 New chemical applications and the perspective of methanol use as a synthetic fuel have renewed the interest in this basic product and have opened new market opportunities for natural gas. However, it is the mission's opinion that these developments will be slow unless dramatic events create an interruption in the world oil supply. (a) Domestic Market 8.51 In terms of Bolivia's internal market, methanol could immediately be used as a gasoline extender, high-octane additive, (106- 116 RON) in low-level methanol/gasoline blends (up to 5%). Such a use does not require any engine refitting or replacement of parts in the 1/ Evaluacion tecnico-economica preliminar - Proyecto Conversion Gas Watural en Hidrocarburos Liquidos - Juno 1981. By Ing. D. Pozo, J. Barrientos & Lic. M. Camacho. 2/ Much of the material is extracted from: "Emerging Energy and Chemical Applications of Methanol: Opportunities for Developing Countries", World Bank, April 1982. - 105 - vehicle fleet nor any modifications in the existing gasoline distribution system. This market would be equivalent to 500-700 barrels per day (60- 90 tons/day). 8.52 The use of higher-level blends or of straight use of methanol in spark-ignition engines and in diesel engines can only be considered in Bolivia once the international automobile industry brings forward engines modified or redesigned to the characteristics of this fuel. It is not economic to custom-retrofit cars in Bolivia. 8.53 Given the shortage of liquid fuels and in particular of heavier distillates in the domestic market, methanol could become an industrial and household fuel in areas where gas pipelines are not economic. Because methanol use would require some modifications of equipment and has some storage and handling problems which are not fully known, it would be advisable to use methanol in blends to mitigate those problems. Assuming a 50% volume blend, this market could absorb some 1,500 BPD of methanol (about 190 TPD), I/ displacing approximately 825 BPD of oil products. 2/ 8.54 Thus, the immediate domestic demand for methanol as fuel (250 TPD) represents about 50% of the minimum economic size of a modern methanol plant. The most common size is 1,000 T/SD, export plants being built are in the 2,000-2,500 TPD size range for single train plants. These are the plants that will determine the international trading price for methanol in the future. 8.55 The feasibility of a methanol project will thus depend on additional domestic and export markets. On the domestic side, methanol could provide the first building block for a chemical industry. 3/ For example, half of the world chemical methanol consumption is in formal- dehyde production. This product is an input to the manufacture of thermo-setting resins of industrial application, among which the wood industry is very important. Bolivia has a large forestry potential but the size of this potential market has yet to be quantified. (b) Export Potential: 8.56 Many of the new export methanol plants being built in gas rich countries are high risk ventures, because they gamble on an early development of a large scale fuel market for methanol. It is still uncertain whether this market will develop. It depends on the oil supply balance on the relative economics of adapting the vehicle engines and parts to this new fuel and the feasibility of the methanol to gasoline conversion processes. 1/ Figure includes 100% of kerosene market, and 20% each of diesel and fuel oil demand. 2/ Taking into account the lower calorific content of methanol (8,570 Btu/lb or 3.79 MMBtu/bbl). 3/ To enable the necessary flexibility, the project should be conceived as a chemical-grade methanol plant, which anyway does not appear less cost efficient than a plant producing fuel-grade methanol. - 106 - 8.57 The mission suggests that Bolivia should study this alternative at the end of the decade. By that time, both the international market balance and the internal supply of liquid hydrocarbons will be better defined. 8.58 At present, 97% of the methanol market is chemical. Most of this market is mature and will increase at a moderate rate in the future. New capacity being built or planned largely exceeds projected chemical methanol demand, and there is a likelihood of significant surplus developing in the 1985-87 period. 8.59 Brazil and Argentina are the only two countries with direct methanol production. Trinidad is the only new country with a firm project. Trinidad has abundant natural gas reserves with a limited domestic market. A methanol plant targeted for exports has been developed as one way to utilize natural gas. Table 8.8: Central and South American Methanol Capacity - 1979 (Thousand Metric Ton Per Year) Company Location Capacity Feedstock Future Brazil Alba Cubatao, Sao Paulo 20 Fuel Oil +10 (1980) Copenor Camacari, Bahia 60 Nat. Gas + 5 (1980) Prosint Rio de Janeiro 50 Naphta +10 (1980 Total 100 Argentina Atanor Rio Tercero, Cordoba 15 Nat. Gas +100 (1985) Casco (Borden) Pilar, Buenos Aires 20 Nat. Gas Total 35 Trinidad National Energy Corporation Point Lesas - Nat. Gas +440 (1984) Total 16-5 8.60 It is to be noted that the plants in Brazil and Argentina are all below economic size and that those that use as feedstock liquid fuels have a considerably higher production cost. They are justified because their production is captive, used mainly for formaldehyde production. Thus, it can be inferred that the plants in Brazil could have interest in entering into a joint venture with Bolivia not only for methanol but also for formaldehyde production. Brazil needs additional methanol capacity by 1984/85 and already imported 15 thousand tons in 1979 from the USA. 8.61 There are a group of projects to increase the productive capacity of methanol. However, it is estimated that Brazil might become increasingly dependent on methanol imports from lower cost energy centers - 107 - by the mid to late 1980s. Imports could reach 40-45% of its requirements by the end of the century. A contradictory project is being planned by Copenor. It consists of 1,000 tons per day methanol plant to be on stream by the 1985-87. Originally, the methanol was to be used for the production of chemicals. However, the current plan is for most of the output from the plant to be sold to PETROBRAS for blending with gasoline, which would directly compete with the ethanol program. 8.62 On the Pacific Coast, the market potential for chemical methanol is about 150 T/D in deficit neighbouring countries. But because methanol is a liquid and can be transported by pipeline, Bolivia could enter international trade by using the existing oil pipeline to Arica (Chile). Table 8.9: Methanol Surplus/(Deficit) Analysis (Thousand Metric Tons) 1985 1990 2000 Brazil (35) 60 (215) Argentina (2) 33 (5) Chile (30) (37) (60) Peru (4) (6) (14) Ecuador (10) (14) (30) Balance (81) 36 (324) 8.63 International price trends for methanol will depend on the development of a market of some size for methanol as a fuel in developed countries. These prospects depend in turn on the interface between the future prices of methanol and of petroleum products. Given the projected overcapacity, it is likely that there will be a decline of methanol prices in constant terms. The World Bank assumes in its current project evaluations two price scenarios: (a) that methanol will escalate at the same rate as gasoline, and (b) there will be no real term escalation until 1990. Table 8.10: Methanol Prices Projection (in 1980 constant US$ per ton of methanol) 1980 1985 1990 Scenario (a) 220-240 272 307 Scenario (b) 220-240 240 240 Source: World Bank. Methanol: Opportunities for Developing Countries - 108 - (c) Production Costs 8.64 The Bank 1/ has estimated the production cost of methanol at US$180/ton, for a 1000 T/D capacity and assuming a 20% rate of return on investments, in constant terms and assuming zero value for gas. Under the constant price scenario, the economic value of gas resulting from such a project would be US$2.0/MCF. (d) SASOL - Synthol and Arge Liquification Processes: 8.65 Although these technologies are of special interest to Bolivia because they permit production of middle distillates and even heavier products, they cannot be considered at this time. In addition to the high capital cost 2/, and large gas needs, these plants require trained manpower and important volumes of water and waste disposal facilities. 8.68 YPFB's preliminary analysis showed that the Sasol route was much less favorable than the Mobil MTG alternative. It is impossible at this stage of development to judge the relative economics of these routes. It is therefore suggested that Bolivia postpone a decision on this issue. At present there are several new technologies for gas liquification being researched, for example, some development work is being made on ultrasound liquefaction. 1/ World Bank: "Emerging Energy and Chemical Applications for Methanol: Opportunities for Developing Countries". April 1982. 2/ At 14% interest rate, 20 years economic life, the capital cost alone can be estimated at US$38/bbl of refined product. Gross Domestic Product by Sector of Origin, at Constant Prices (in million of 1970 US$) 1/ GDP at Market Prices Avg. Annual Growth % Sector 1970 1976 1979 1980 1981 1970-76 1976-80 1981 Agriculture 189 251 259 259 261 4.9 0.8 2.1 Trad. 167 212 212 Nontrad. 22 39 42 Industry 314 447 470 464 467 6.1 0.6 Mining 97 113 101 102 2.5 -2.5 0.1 Metallurgy 0 5 7 8 75.8 12.5 n.a. M-anufactur- ing 150 221 251 247 6.7 2.8 -2.8 Construction 43 61 69 66 6.0 2.0 Hydro- carbons 10 26 17 16 17.7 -11.4 -7.9 Power 14 21 25 25 7.0 2.9 Services 537 769 873 887 884 6.2 3.6 n.a. Transport 78 140 176 179 10.2 6.3 Other 459 629 697 708 5.4 3.0 GDP Total 1040 1468 1597 1610 1612 5.9 2.3 -0.6 N 1/ Exchange rate 1US$ = 11.90 $Bol. 1970 Source: Country Economic Report, September 1982. Bolivia: Energy Balace.- 1981 (original nita) OIL CONDENSATE NATURAL KEROSENE NON-FNF.ROY PET. TOTAL PET. LOSSES & OWN RESOURCES FUELWOOD BAGASSE HYDRO AND N. GASOLINE. GAS LPG GASOLNS JETF EL DIFSFL OTL PHEL OIL, PROWICTS PROMICTS ELECTRTfTTY CHARCOAL CONSMTPTTON HT 17 NT 2/ -W) - -OO 5/ %~6 -B '7 t .,8 M. 11--'97 - GI1 107 C 1 ACTIVITIES PRODUCTION 2,280 850 1,081 1,277 88,430 Export (70,689) (36) (14) Iport 44 Consumption in Export Pipeline (6,853) GROSS DOMESTIC SUPPLY 2,280 850 1,081 1,277 10,888 (36) (14) - 44 - - (6) - CONVKRSION: Gas Plants 122 (3,335) 177 - - - - - 177 Petroleum Refining (1410) (1,058) 88 792 227 280 14 n.A. 1401 50 Lube Plant (09) 77 (32) 32 TPFB Consumption n-s- (0) (1) (19) (1) r. r(I-) Power Generation (1081) (3,858) (67) (17) 1719 Transmission & Dist. Losses (570) (275) Charcoal Conversion (140) 71 119 Changes in Stock and Adjustment 11 4 (108) (1) (105) 105 SECONDARL DOMESTIC SUPPLY 2140 850 1081 - 2,067 233 665 226 186 13 26 134o FUEL BLENDING (187) (18) 63 142 - - AVAILABLE FOR DOMESTIC FINAL DEMAND 12/ 2140 850 - - 2,067 233 478 208 249 155 26 1349 1444 Non-Energy Demand - 850 26 (26) DOMESTIC FINAL ENERGY DEMAND 2,067 233 478 208 249 155 - 1321 Industry 10 2,062 12 32 3o 140 - 223 175 21 Rasidential-Comm. 2130 5 215 70 75 636. Transport Road 6 461 177 619 Air 17 103 120 Rail and Barge 1 17 4 ?2 Mining 2 21 11 14 433 Source: Mission estimates - see explicative notes for each item. - 111 - ANNEX1.2A Page 1 of 3 ENERGY BALANCE EXPLICATIVE NOTES 1. Fuelwood: Data includes direct and indirect (charcoal) consumption: (a) Direct consumption was estimated in 1980 Energy Balance (MEH) at 2,086 Mtons or 730 MTOE, based on partial results of a fuelwood consumption survey. Specific per capita fuelwod consumption by region is estimated at: Altiplano: 1.88 kg/day/inhabitant Valleys: 2.51 kg/day/inhabitant Tropical Lowlands: 3.14 kg/day/inhabitant Projection to 1981 was made assuming a 2.7% population growth. (b) Charcoal consumption is based on direct information provided by ENAF. It does not include other industrial charcoal consumption. Wood to charcoal conversion assumes a 35% efficiency. 2. Bagasse: ENERGY POTENTIAL is calculated using a conservative heating value of 8,800 Btu/kg of bagasse, with 50% moisture content. ENERGY REQUIREMENTS are calculated in function of volume of sugar cane processed and alcohol produced. The theoretical energy requirements are: (a) 1.38 MMBtu/ton of sugar cane and (b) 0.56 kcal/kcal of ethanol for alcohol production from molasses. Calorific value of ethanol is 5.048 kcal/1ts. Source of information: Tables 1.40 and 1.41. 3. Hydropower: Volume data: ENDE's statistics Conversion factors: At production level: 2867 kcal/KWh (30% efficiency) At consumption level: 860 kcal/KWh (100% efficiency) Difference: Allocated to losses 2007 kcal/KWh 4. Crude Oil, Condensates and Natural Gasoline; Source: Production - YPFB's actual figures. Table 1.12: Input into Refinery Adjusted for Production. - 112 - ANNEX 1.2A Page 2 of 3 5. Natural Gas: Net gas production: conversion factor used: 1,114 Btu/CF. Gas for final demand: conversion factor used: 1,045 Btu/CF Gas for gas plant: energy content equal to sum of energy content of natural gasoline and LPG Gas production excludes gas reinjected, gas lift, flared or lost, or used as fuel in field or in gas plants. Source: Table. 1.22 Petroleum Products: Source: YPFB computer printouts. 6. LPG: Includes liquid petroleum gas from refineries and from gas plants. 7. Gasolines: Includes all automotive and aviation gasolines. A portion of the refinery gasoline stream is also used as refinery fuel; another portion is used as blending stock into the diesel and fuel oil stream. At the refinery level, it also includes the so-called "hydrobon", a light stream that is fed to the plat- forming unit. 8. Diesel: Part of the diesel stream is diverted to the lubricant plant. Diesel oil also is the main fuel for power generation in isolated and rural networks. The volume of diesel used by the mining sector is allocated to final consumption although a portion of it is used for power generation. 9. Now energy products are not represented in the balance. These include solvents, ether,asphalt, lube oil, paraffin, etc. 10. Electricity: Figures represent. net generation and were converted at 860 kcal/KWh. Deduction for transmission and distribution losses is equal to 16% of gross generation. Source: ENDE - 1981. - 113 - ANNEX 1.2A Page 3 of 3 11. Charcoal: Represents only the consumption of the ENAF's tin smelter. In 1981 it was 60 tons/day x 365 days/year. Some sources estimate that this company's consumption represents about 85% of total charcoal consumption. 12. Available for final demand: The allocations to the various consuming sectors were made on the following principles: Gas: Actual YPFB's sales distribution reports. Petroleum Products: Where not directly available, the distribu tion used in the 1980 Energy Balance was followed. Electricity: ENDE's sales report for 1980. 3olivia: Energy Balance 19AI (thousands of tons of oil equivalent) ENFRGY SECT. OIL CONDENSATE NATURAI. KEROSENE & CONqTIMPTION STATISCAL TOTAL FUELWOOD BAGASSE HYDRO AND N.GASOLINE. GAS LPG GASOLINES JET FUEL DIESEL OIL FTIEL OIL VLECTRICITY CTARCOAL AND LOSSES ADJUSTMENTS ENERGY PRODUCTION 798 189 310 b/ 1095 2483 4A75 Export (Net) (1862) (23) (11) (1896) Import 19 39 Consumption in Export Pipeline (180) (1SO) GROSS DOMESTIC SUPPLY 798 189 310 1095 441 (23) (ll) - 19 - - 2838 CONVERSION Gas Plants 105 (242) 115 22 Petroleum Refineries (1162) (28) 57 644 208 197 11 71 24 Fower Generation (310) (102) (60) 149 107 217 - Charcoal Conversion (49) I 11- Transmission & Distri- bution Losses (15) n.s. (3) (1) (11) (1) (24) 55 Inefficiency Bagasse Use (63) 61 Statistical Adjustment and Changes in Stock (14) 3 (90) 101 TOTAL ENERGY SECTOR CONSUMPTION & ADJUST7fENT 151 342 (693) SECONDARY DOMESTIC SUPPLY 749 126 - - 54 152 540 207 165 12 124 16 2145 Fuel Blending (151) (15) SI 116 - AVAILABLE FOR DOMESTIC FINAL DEMAND 12/ 749 126 - - 54 152 389 191 216 17 124 16 2145 Industry 4 126 54 8 28 14 116 37 17 414 Residential-Co.mercial 745 .s. 140 62 55 1002 Transport Road 4 375 150 529 Air 14 99 112 Rail & Barge I 15 3 la Mining 2 17 1 37 64 n.s. - not significant Source: Mission estimate, based on assumptions explained In notes. Bolivia: 1981 Final rnergv 1tilization 1/ (N!TOF) Natural Kerosene/ Sectors Fuelwood Bagasse Gas LPC rasolines Jet Fuel I)iesel Oil Fuel (il I lectricitv otal Nistribution F Industry 1 42 43 6 4 10 81 3' 10 30.0 Residential/commercial 112 98 10 9n 7) 38.1 Transport Road 1 75 75 151 90.7 Air 3 2n 21 .7 Rail and Barges - 1 f J0 1.4 Mining - B - 17 4. Total 113 42 43 105 78 43 oA Rn 119 70 Distribution % 15.5 5.k 5.9 14.4 10.7 5.9 11,1 12? 1 .* - 0n.0 NOTES: 1/ Takes into account approximate efficiencies of energy utilization. Conversion at following factors: Commodity Sector Efficiency Fuelwood Residential/Commercial 15% Industry 20% Bagasse Industry 33% Natural Gas Industry 30% LPG Industry 80% Residential/Commercial 70 Transport-Road 307 Gasoline Transport-Road 20% Transport-Air 20% Kerosene Industry 157 Residential/Commercial 30% Transport-Rail 15% lining 15% Jet Fuel Transport-Air 20% Diesel Oil Industry 30% Transport-Road 25% Transport-Rail-Barges 30% Mining 30% Others 25% Fuel Oil Industry 70% Transport-Rail-Barges 50% 'lining and Others 70% Electricity Industry 1001% Residential/Commercial 907 Mining 100% Bolivia: Energy Balance Projected to 1990 - Base Case (MTOE) Fuelwood Bagasse Hydro Oil, Condensates Natural LPG Gasolines Kerosene Diesel Fuel Electricity Charcoal Energy Sector Total Total Growth Natural Gasoline Gas Jet Fuel 011 Oil Cons. & Losses Energy 1990/1981 Production 817 189 310 998 2957 5271 Export (Net) (1862) (1862) Import Requirements 610 610 Consumption in Export Pipeline (180) (180) Gross Domestic Supply 817 189 310 1608 915 Conversion Gas PLants 152 (351) 167 32 Petroleum Refineries (1760) (28) 71 632 291 460 177 157 Power Generation (310) (414) (98) 231 591 Charcoal Conversion (67) 22 45 Transmission & Distribution Losses (43) (30) 73 Inefficiency in Bagasse Use (63) 63 Statistical Adjustment and Changes in Stock Total Energy Sector Consumption and Adjustment 961 (961) Available for Domestic Final Demand 750 126 79 238 632 291 36-2 17 201 22 -T28 Industry 5 126 79 11 39 47 161 51 22 541 28% Residential/Commercial 745 220 88 97 1150 13% 2/ Transport Road 7 609 244 860 63% Air 23 159 182 63% Rail and Barge 2 24 5 31 63% Mining 3 47 11 53 114 33% 1/ Assumes an average elasticity of 1.2. Elasticity for commercial fuels is 1.7, which appears to be reasonable. 2/ Growth of fuelwood demand assigned to LPG with an efficiency ratio of 1:4.7. Source: Mission estimate. Summary of Scenario Specifications Economic Variables Baseline Scenario Accelerated Expansion Scenario Population Growth 4% urban, 2% rural same GDP Growth % 1982 = (5.0%) same 1983 - 0.0% 1984 = 1.0% 1985 = 2.0% 1986-90 = 5.0% Industrial Value Added 1982 = -5% same as Baseline plus expansion projects 1983 = 0% identified by GDC, incl. Ammonia - Urea 1984-85 = 1.5% Plant, Aceile Fino, Molinera Oriente, 1986-90 = 3.5% Hilanderia Santa Cruz, CBN, FNV, SOBOCE Mining Value Added SarLe as industry Twice the growth of Baseline scenario Metallurgical Value Added Vinto & La Palca expansion Vinto, La Palca and Karachipampa Agricultural Value Added 1986-90 = 3.5% 1986-90 = 5.0% Power Growth Rates Household/Commercial Urban Population Growth x 1.20 Urban population growth by 1.4 Manufacturing Industrial V.A. Growth x 1.30 Industrial VA growth by 1.6 Mining Mining V.A. Growth x 1.0 Mining VA growth by 1.4 Liquid & Gas Demand Growth Household/Commercial Urban = Urban Pop. Growth x 1.0 same Rural = Rural Pop. Growth x 1.0 Rural Population Growth x 1.0 minus fuelwood minus constant fuelwood cons. consumption declining at 4%/year Manufacturing & Metallurgy Industrial V.A. Growth x 1.0 As indicated in Table 1. Vinto and La Palca Vinto, La Palca and Karachipampa Mining Mining V.A. Growth x 1.0 same Transportation GDP Growth x 1.3 GDP Growth x 1.35 Bolivia: Energy Balance Projected to 190 - Base Case with cihstitutIon (M'aOF) Condensates vnerv qertor & Natural Natural Kerosene/ ronsumntion Total Biomass Hydro Gasoline Cas LPG Casoline Jet Fuel Tiesel Fuel Oil lectrfcitv charcoal an,3 Loss rnerqv Production 1006 310 908 3479 S703 Export (1862) (1 R") Consumption in Export Pipeline (180) (lgn) Statistical Adjustment (18) (18) Cross Domestic Supply 1006 310 080 1437 1711 Conversion Gas Plants q9 (478) 379 1/ Refineries (1079) (77) 50 585 212 171 12 1,6 Power Generation (310) (414) (9A) '31 Sol Charcoal Conversion (67) 24 49 Losses (63) (in) 9A Adjustment 59 (959) Available For Final Demand 876 - - 468 429 9p5 21? 71 1' 201 P9 78 Industry 131 - - 337 51 17 S41 Residential/Conmercial 745 - - 131 146 31 07 11n Transport Road - - 283 562 15 860 Air - - ?1 150 IR? Rail & Barges 19 1? 1I Hining 5 9P 3 114 1/ Based on 10 !IBD LPG production at gas plants. Bolivia: Energy Balance Projected to 1990 - Base Case with Substitution and Conservation Crude, Condensates Energy Sector & Natural Natural Kerosene/ Consumption Total Biomass Hydro Gasoline Gas LPC Gasolines Jet Fuel Diesel Fuel 0il Electricity Charcoal & Losses Energy Supply Production 1006 310 998 3182 9496 Exports (1862) (1847) Consumption in Export Pipeline (180) (180) Statistical Adjustment (18) (18) Gross Domestic Supply 1006 310 980 1140 T436 Conversion Gas Plants 99 (478) 379 Refineries (1079) (77) 50 585 212 171 12 126 Power Generation (310) (414) (9s) 231 591 Charcoal Conversion (67) (? 4 Losses (63) (3A) Adjustment Available for Final Supply 876 - - 171 429 5895 2? 73 12 201 22 -751 Industry 131 171 106 ? 91 ?' 4A3 Residential/Commercial 745 183 64 97 10RF Transport Road 140 562 29 71I Air 23 11? 199 Rail and Barges 16 1n 26 Mining 44 93 97 Bolivia: Projected Energy Balance to 1990 - Accelerated Growth Case -- With Substitution Gas (MTOE) Oil, Energy Sector Condensates Consumption Total Natural Natural Kerosene Non Energy Total Growth Biomass 11ydro Gasoline Gas LPG Gasolines Jet Fuel Diesel Fuel Oil Electricity Charcoal Products Energy 1990/8 Production 777 310 998 4007 6092 Export (Net) (1862) (1862) Consumption in Export Pipeline (180) (180) Statistical Surplus 1/ (18) (18) Gross Dosestic Supply 777 310 980 1965 4032 42% Conversion Gas Plants 99 (558) 459 3/ - Refineries (1079) (77) 50 585 212 171 12 126 - Power Generation 4/ (310) (580) (110) 301 699 - 0 Charcoal conversion (67) 22 45 - Losses (63) (39) 102 Adjustments for Energy Sector 972 (972) Available for Final Domestic Demand 647 - - 750 509 585 212 61 12 262 22 3060 43% Industry 131 573 - 92 22 918 95% Residential/Commercial 516 177 199 - 20 112 1024 2% 2/ Transport Road 310 561 - i 882 69% Air 24 165 189 69% Rail and Barges 20 12 32 69% Mining 7 50 - 58 115 41% 1/ Crude surplus due to thermal equivalent factor used. 2/ Slow growth is due to reduction in fuelwood and change over to fuels that are used with higher efficiency. 3! LPG availability calculated on the basis of a 12 MBD prediction from gas plant. Implies full capacity utilization of present Rio Grande Plants. 4/ Power Generation: Gas Based: 58%; Hydro 31%; Diesel 11%. Bolivia: Changes in the Structure of Supply and Demnd to 1990 Baseline 1990 Without With With Substitu- Accelerated Growth 1981 Substitution Substitution tion & Conservation With Substitution Primary Fuels for Donestic Market - Total (MIDE) 2838. 3839. 3733. 3436. 4032. % Share Biomass 34.8 26.2 26.9 29.3 19.3 Hydro 10.9 8.1 8.3 9.0 7.7 Oil 38.8 41.9 38.5 28.5 24.3 Gas 15.5 23.8 26.3 33.2 48.7 Losses % of Gross Domestic m 1/ 12.4 25.0 22.9 24.9 24.1 Available for Final Demand (MIDE) 2145. 2878. 2878. 2581. 3060. % Distribution Industry 19.5 18.8 18.8 18.7 26.7 Residential/omercial 46.7 40.0 40.0 42.2 33.5 Transport 30.8 37.3 37.3 35.3 36.0 Mining 3.0 4.0 4.0 3.8 3.8 Fuels for Donestic Final Supply % Share Biass 40.6 31.2 31.1 34.8 21.9 Oil Production 45.7 53.3 32.4 36.1 30.1 LPG from Gas 5.4 5.8 13.2 14.7 15.0 Natural Gas 2.5 2.7 16.3 6.6 24.5 Electricity 5.8 7.0 7.0 7.8 8.5 co 1/ Losses for 1981 are actual. For 1990, they also include statistical adjustnents. Source: Energy Balances. Amnexes 1.3, 1.4, 1.5, 1.6, 1.7. Bolivia: Long Term Projection of Domestic Gas Requirements (MTOE) Acrumulated Gas Requirements MTOE 1981-4000 1981-2010 1981 1990 1995 2000 2005 2010 1981-90 1990-2000 2000-2010 1981-2010 10 CF 10CF (Scenario C) Supply Requirements Hydro 1/ 310 310 310 310 310 310 Gas 441 1,140 1,965 3,153 4,408 5,942 7,048 20,558 44,778 72,384 849 2,428 Oil 2/ 1,095 980 886 801 724 654 LPG and Natural Gasoline 57 445 478 478 478 478 Conversion Processes Gas: Power Generation 10/ 102 414 554 876 1,268 1,788 2,322 5,995 13,000 21,317 315 809 LPG & Nat. Gasoline 3/ 242 478 478 478 478 478 3,240 4,780 4,780 12,800 10/ 106 169 Refineries 8! 28 77 71 64 58 52 473 708 580 1,761 45 64 Oil: Non-Energy Products 4/ 16 16 16 16 16 16 Isolated Power Systems 9/ 60 98 119 145 160 177 Final Demand 5/ 2,145 2,581 3,263 4,125 5,019 6,106 Biomass 1/ 891 898 898 898 898 898 Electricity 6/ 124 201 274 374 491 645 Liquid Hydrocarbons 7/ 1,076 1,311 1,229 1,118 1,026 939 Gas 54 171 862 1,735 2,604 3,624 1,013 9,075 26,418 36,506 383 1,386 1/ Assumed constant over period. 2/ Assumes 2% decline in oil production. 3/ In 1990 includes 10 MBD of LPG and 2.1 MBD of natural gas. Thereafter supply remains constant. 4/ 1.5% of crude production in 1981 - maintained constant over projection period. 5/ Economic growth projected at 4%/year and elasticity of 1.2 to 2000 and 1.0 to 2010. 6/ Economic growth projected at 4%/year and elasticity of 1.6 to 2000 and 1.4 to 2010. 7/ Projection obtained as differential between production less intermediate demand plus LPG and natural gasoline production. 8/ 8% of crude throughput. 9/ Projected at 4% per year to 2000 and 2% thereafter. 10/ Converted at 3.0 MBtu/CF. - 123 - ANNEX 1.10 Bolivia: Hydrocarbon Reserves Crude Oil Gas in Solution Condensate Free Gas MMBLS MMMCF MBBLS MMMCF (a) Proven Recoverable Reserves at July 1, 1982 (Class I and II) YPFB - Existing Fields 25,518 66 55,907 4,146 Private Companies - - 22,455 743 Sub-total 25,518 66 78,362 4,889 (b) Semi-Probable Recoverable Reserves (Class III) YPFB 23,403 25 50,365 717 Private Companies - - 1,873 226 Sub-total 23,403 25 52,238 943 Total Reserves I, II, III 48,921 91 130,600 5,832 (c) Probable Identified Reserves YPFB Tacobo - - - 78 Huayco - -- 48 Montecristo - - - 204 Tesoro Los Suris - - 489 64 Escondido - - 6,300 341 Taiguati - - 859 38 Sub-total - 7,648 733 PROVEN AND PROBABLE RESERVES TOTAL 48,921 91 138,248 6,605 Class I: Volume recoverable from wells already drilled and in zones that have been perforated. Class II: Volume recoverable from existing wells in (a) zones not yet perforated; and (b) feasible secondary recovery projects that do not require additional wells. Class III: Volume to be recovered through (a) drilling of new wells in continuous extensions of fields partially developed and outside of drainage area; (b) feasible secondary recovery projects that require additional wells to be drilled. Source: Mission estimates based on YPFB data. ANNEX 1.11 Bolivia: Result of Past Exploration - 1960-1980 RECOVERABLE RESERVES DISCOVERED PHYSICAL EFFORT Number of Seismic Exploratory Oil Condensates Natural Gas (109 CF) Total 1! Exploratory Successful Work Drilling (106 Bbl) (106 Bbl) Oil Fields Gas Fields 10 CFGE Wells Wells (km) (km) 1960 60.3 0.8 161.3 124.5 597.4 19 3 n.a. n.a. 1961 9.7 11.6 27.7 574.0 710.3 15 1 n.a. n.a. 1962 - 70.2 - 1261.0 1619.0 13 1 n.a. n.a. 1963 - - - - - 11 2 n.a. n.a. 1964 8.1 2.6 -8.4 112.9 175.7 10 6 n.a. n.a. 1965 21 0.7 22.0 -32.6 165.3 9 1 . 1966 - - - - 3.1 13 3 n.a. n.a. 1967 37 - 55.6 39.4 283.7 9 n.a. n.a. 1968 - 4.4 - 319.6 342.0 10 1 n.a. n.a. 1969 - - - - - 5 2 n.a. n.a. 1970 - - - - - 4 . 1971 - - - - 6 - 966 52.9 1972 - 0.3 - 17.7 19.2 5 1 2,536 33.8 1973 6.2 0.4 5.2 315.0 353.9 5 3 2,433 33.8 1974 - - - 103.0 103.0 5 1 11,012 23.9 1975 - - - 0.4 0.4 7 - 16,857 37.0 1976 2 4.1 8.3 94.7 134.3 12 5 11,400 80.6 1977 0.2 3.7 1.1 210.0 231.0 10 4 8,331 78.3 1978 - 36.3 - 949.8 1334.9 13 4 5,269 91.4 1979 - 1.0 - 17.0 22.1 5 1 1,057 64.8 1980 - 9 - 200 245.9 6 0 1,024 74.0 TOTALS 145.1 145.1 289.6 4371.9 6141.2 192 39 60,885 570.5 1/ Cubic feet of gas equivalent. Oil & Condensate converted at 5.1 MCF/bbl. Source: YPFB Information and Mission estimate. - 125 - ANNEX 1.12 BOLIVIA: LIQUID HYDROCARBONS PRODUCTION MID 1981 FORECAST (Bble/Day) Crude and Condensate Accumulated Remaining Fields Reserves July 1, 1981 Production Reserves (MBbls) 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1982-90 1, II & III Proven I & II, Proven III (MBbl) (MBbl) CRUDE AND CONDENSATE YPFB Caranda 8875 6925 1150 1150 950 750 600 450 350 300 250 200 1825 13,975 Colpa 4227 714 1000 762 1000 1100 900 800 700 600 500 500 2505 2,436 Rio Grande 20554 2823 8926 7640 6900 6500 6000 5400 4800 4300 3800 3400 17790 5,587 La Pena 3077 394 1308 1250 1000 750 550 400 300 250 150 100 1734 1,737 Palmar 1781 - 804 960 950 800 500 400 250 150 150 100 1555 226 Naranjillos 816 - - - - - - - 300 200 200 200 329 487 Enconada 289 1215 - - - - - 400 400 400 400 400 730 774 Yapacani 4400 NA - - - - - 1300 1300 1300 1300 1200 2336 2,064 Palometas 395 NA - - - - - - - - - - - 395 Santa Rosa 1536 226 - - - - - 400 400 400 400 400 730 1,032 Palacios 957 NA - - - - - - - - - - - 957 Santa Cruz 100 50 50 50 50 - - - - - 73 27 Camirl 2752 7548 886* 875 800 700 1100 2350 3000 2650 2350 2050 5794 4,506 Monteagudo 10112 8907 2446 2090 1700 1900 2050 2750 4300 5200 4000 3150 9906 9,113 Tatarenda 200 - 233 325 250 200 150 150 100 100 - - 465 (265) Caigua 48 524 94 50 - - - - - - - - 18 554 Bermejo 292 - 100 200 150 150 100 100 100 50 50 - 329 (37) Sanandita 0 125 100 100 50 50 50 50 50 - 210 (210) Cambeiti 1284 - 214* 150 100 50 50 - - - - - 128 1,150 Vuelta Grande 23500 28150 6 3000 7500 7000 6000 5600 5150 4700 4400 4400 35,827 Espino 747 679 662 690 1150 650 300 200 150 100 50 - 1201 225 Occid. Tita 1318 - 1373 725 400 250 150 100 - - - - 593 725 Tesoro. La Vertiente 3174 1409 1760 1500 1500 1500 1500 1500 1500 1500 1500 5022 (1848) Occid. Porvenir 22009 2715 988 6550 7700 5850 4050 2400 1500 1200 1000 800 10968 13756 Other fields 427 14931 405* - - - - - - - - - - 15358 TOTAL CRUDE CONDENSATE 112,870 75,751 22,004 25,352 27,700 28,800 25,100 25,150 25,100 23,900 20,850 18,400 80,064 108,557 OF WHICH NEW PRODUCTION 1,725 7,200 10,400 10,220 13,300 15,350 15,700 14,050 12,900 36,808 NATURAL GASOLINE YPFB Rio Grande 2003 1900 2400 2400 2400 2400 2400 2400 2400 2400 Camiri 101 TOTAL NATURAL GASOLINE 2104 1,900 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 OF WHICH NEW PRODUCTION 450 450 450 450 450 450 450 450 1,314 LPG YPFB Rio Grande 2940 4485 4660 4660 4660 4660 4660 4660 4660 4660 15244 Golpa 349 1048 990 932 815 640 524 466 350 2232 Camiri 104 175 186 175 163 151 151 140 140 140 519 Vuelta Grande - - - - - 4077 4077 4077 4077 4077 7441 Occid. Porvenir - - - 2912 2912 2912 2912 2912 2912 2912 7440 TOTAL LPG 3044 5,009 5,894 8,737 8,667 12,615 12,440 12,313 12,255 12,139 32,876 OF WHICH NEW PRODUCTION 110 1,002 3,845 3,775 7,724 7,607 7,479 7,421 7,363 16,909 GRAND TOTAL TOTAL LIQUID PRODUCTION 27.152 32 261 35 994 39 937 36 167 40 165 39 940 38 613 35 505 32,939 120,642 TOTAL NEW PRODUCTION 2rr4T % 20.H 13 * Production Included in "Other Fields" Source: YPFB Internal Projections - 126 - ANNEX 1.13 REVISED FORECAST BOLIVIA: LIQUID HYDROCARBONS PRODUCTION FORECAST (Bbls/Day) Crude and Condensate Fields Reserves July 1, 1981 (MBbls) 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Proven I & II, Proven III CRUDE AND CONDENSATE YPFB Caranda 8875 6925 1150 1150 950 750 600 450 350 300 250 200 Colpa 4227 714 1000 762 1000 1100 900 800 700 600 500 500 Rio Grande 20554 2823 8926 7640 6900 6500 6000 5400 4800 4300 3800 3400 La Pena 3077 394 1308 1250 1000 750 550 400 300 250 150 100 Palmar 1781 - 804 960 950 800 500 400 250 150 150 100 Naranjillos 816 - - - - - - - 300 200 200 200 Enconada 289 1215 - - - - - 400 400 400 400 400 Yapacani 4400 N.A. - - - - - 1300 1300 1300 1300 1200 Palometas 395 N.A. - - - - - - - - - - Santa Rosa 1536 226 - - - - - 400 400 400 400 400 Palacios 957 N.A. - - - - - - - - - - Santa Cruz 100 - - 50 50 50 50 - - - - - Camiri 2752 7548 886 1/ 875 800 700 1100 2350 3000 2650 2350 2050 Monteagudo 10112 8907 2446 2090 1700 1450 1240 1650 1800 2400 3800 5200 Tatarenda 200 - 233 325 250 200 150 150 100 100 - - Caigua 48 524 94 50 - - - - - - - - Bermejo 292 - 100 200 150 150 100 100 100 50 50 - Sanandita 0 - - 125 100 100 50 50 50 50 50 - Cambeiti 1284 - 214 1/ 150 100 50 50 - - - - - Vuelta Grande 23500 28150 6 - - - - 7400 7400 7100 6600 6000 Espino 747 679 662 690 1150 650 300 200 150 100 50 - Occid. Tita 1318 - 1373 725 400 250 150 100 - - - - Tesoro. La Vertiente 3174 1409 1760 1500 1500 1500 1500 1500 1500 1500 1500 Occid. Porvenir 22009 2715 988 6550 7700 5850 4050 2400 1500 1200 1000 800 Other Fields 427 14931 405 1/ - - - - - - - - - TOTAL CRUDE CONDENSATE 112,870 75,751 22,004 25,352 24,700 20,850 17,290 25,450 24,400 23,050 22,550 20,050 NATURAL GASOLINE YPFB Rio Grande 2003 2000 2000 2000 2000 2000 2000 2000 2000 2000 Camiri 101 100 100 100 100 100 100 100 100 100 TOTAL NATURAL GASOLINE 2104 2,100 2,100 2,100 2,100 2,100 2,100 2,100 2,100 2,100 LPG YPFB Rio Grande 2940 2900 2900 2900 2900 2900 2900 2900 2900 2900 Colpa 2/ Camiri 104 175 186 175 163 151 151 140 140 140 Vuelta Grande - - - - - - 4077 4077 4077 4077 Occid. Porvenir - - - 2912 2912 2912 2912 2912 2912 2912 TOTAL LPG 3044 3,075 3,086 5,987 5,975 5,963 10,040 10,040 10,040 10,040 GRAND TOTAL TOTAL LIQUID PRODUCTION 27,152 30,527 29,886 28,937 2 6 1 4 9 1/ Production included in "Other Fields" 2/ Used for injection at La Pena. Source: Energy Assessment Division Estimates - 127 - ANNEX 1.14 Bolivia: 1981 Refining Capacity Capacity Throughput HBD MBP Cochabamba: Primary Distillation: New Unit 1/ 27,500 15,215 Old Unit 19,000 - Hydrobon - Platforming 7,000 2,607 Gas Plant (LPG ton/day) 230 90 Lube Oils 444 Energy Consumption (gasoline) 860 As % of throughput 5.77 Santa Cruz: Primary Distillation: New Unit 1/ 15,000 7,249.7 Old Unit 5,000 - Hydrobon - Platforming 6,400 1,910 Gas Plant (LPG tons/day) na 38 Energy Consumption (natural gas) 864.9x106CF as % of throughput 6.2% Sucre: Primary Distillation 3,000 1,803.8 Energy Consumption (natural gas) 193.8x106CF as % of throughput 5.6% 1/ These units were built at a cost of US$ 190 million and commissioned in 1978. na: Information not available Source: YPFB and mission estimates. BOLIVIA: GASOLINE BALANCE 1981 (M-3) FIELD REV. TOTAL TOTAL 9IEFFFPNCFE REFINERIES COCHABAMBA % PALMASOLA % SUCRE 1 (BOLSILLE) 7 PPODTTCTTON SALES On. - SAL,FS First Stage Processing White Gasoline - 41,184 673 41,9S7 Light Gasoline 167,828 73,540 - 241,369 Medium Gasoline 196,018 50,194 - 246,217 Hydrobon 1110,859 262,139 Total Gas Stream 515,127 58 234,593 56 41,184 39 673 53 791,577 (56) Total Processed 883,040 420,758 104,6R7 1,269 1,40q,754 Reprocessed Gasolines Motor Extra (75 octanes) 13,575 927 14,502 6,948 7,954 Motor Superior (82 oct.) 287,605 107,834 36,695 437,134 435,19 (1,062) Motor Premium (92 oct.) 9,868 9,952 2,938 - 22,758 18,4R2 4,976 Aviation (100/130) 18,694 -- 18,694 17,124 1,170 White Gasoline 466 466 7RQ (12A) Aviation Gas (80/87) 8 8 8 Total Finished Gasoline 329,750 17,786 4'1, 0 26 48S8,562 07A,347 10,75 Production Gasoline Streams Difference Finished Gasoline 185,377 116,807 158 673 3nj,015 BOLIVIA: Petroleum Product Sales on Domestic Market (M3) Gasolines Kerosene Diesel F.O. L.P.G. Aviation Other Total GDP Fuels Fuels 1971 278.929 129.312 91.789 110.606 11.723 34.222 562 657.143 12.985 1972 292.315 138.760 100.988 117.239 16.086 36.633 716 702.737 13.732 1973 307.357 150.743 114.368 116.889 23.275 40.744 753 754.129 14.668 1974 326.547 160.631 135.454 136.953 35.484 52.499 734 848.302 15.563 1975 364.579 167.224 173.404 144.712 51.352 68.532 750 970.553 16.353 1976 385.599 171.761 207.711 149.689 64.909 77.584 797 1058.050 17.469 1977 415.265 172.814 257.719 164.299 84.824 91.453 991 1187.365 18.064 Z 1978 438.238 173.817 292.540 161.493 104.378 106.888 1146 1278.500 18.628 1979 452.438 165.214 292.632 148.672 126.736 119.701 1292 1306.685 19.007 1980 461.528 150.485 299.080 152.334 175.931 124.825 1466 1365.649 19.161 1981 460.249 105.306 299.846 155.054 233.182 104.282 2167 1360.086 19.353 GROWTH RATE (%/year) 5.807 -0.215 14.63 3.623 34.19 15.05 8.507 4.237 Elasticity 1.37 (0.051) 3.45 0.86 8.07 3.552 2.008 Oil Consumption/GDP I-' ANNEX 1.17 - 130- Bolivia: 1981 Sales of Petroleum Products on the Internal Market B/D % Gasoline - Extra 112.82 0.5 Superior 7498.48 31.3 Premium 318.46 1.3 Gasoline White 13.60 - Ether 1.46 - Solvent 22.28 0.1 Kerosene 1814.34 7.6 Diesel 5166.13 21.6 Fuel oil 2671.47 11.2 LPG - Domestic 3707.39 15.5 Industrial 1/ 202.04 0.8 Automobile 108.38 0.5 Aviation gasoline 80/87 oct. 0.13 - " " 100/130 oct. 84.42 0.4 " " 100 car 214.07 0.9 Jet Fuel Lab 1284.10 5.4 Jet Fuel A-1 480.25 2.0 Aviation Oils 7.39 - Automobile Oil 209.34 0.9 Asphalt - Cement 12.05 - 23,928.6 100.0 1/ Propane and butane added to this category source. Mission estimate from YPFB sales data. - 131 - ANNEX 1-18 Foreign Trade Alternatives for Petroleum Products (in US$/bbl) 1/ Transport Cost Import Price fob Maritime Overland Price cif From Caribbean Gasoil-Diesel (45 cetane) 32.76 2.31 6.88 41.95 Fuel Oil (0.3% S) 33.70 2.50 6.88 43.08 From Ecuador Fuel Oil 32.3 1.12 6.88 40.30 Transport Cost Export Price Maritime Overland fob Bolivia To Caribbean LPG (ton) 250.0 33.77 62.65 153.58 Gasoline 37.8 2.19 1.45 34.16 To Ecuador Gasoline 35.9 0.98 1.45 33.47 1/ Calculated on the basis of posted prices - Caribbean - March 1982. Source: Mission estimates. Bolivia: Gas Supply - Oil Fields RESERVES (109CF) PRODUCMION (106CFD) Year Originally Proven Class Class Original 1981 Production (106 CFD) Fields Discovered Discovered I & II III Gas/Oil Ratio Actual 1985 1990 2000 Subandean Bermejo Pre--1960 0.1 0.5 Toro - 0.5 - - - - - - Camiri 137.2 3.6 1.7 2,419 2 2 1 - Camatindi - - - - - - Los Monos 9.8 8.9 0.3 6,666 - - - - Guayruy - - - - - - - Buena Vista " Tatarenda 1962 2.2 2.2 - 554 - - - - San Alberto Mlnteagudo 1967 95.0 57.4 - 2,564 7 6 6 6 Caigua 1973 5.2 1.1 - 851 - - - - Cambeiti 1976 8.3 5.6 - 4,213 - - - - Espejos 1979 - - - - - - - - Lowland Caranda 1960 285.8 173.6 24.2 4,256 20 19 16 12 La Pena 1965 54.5 25.7 3.4 2 2 1 1 - 10TAL 598.1 279.1 29.6 31 28 24 18 Source: YPFB internal data, updated to July 1982. kH Bolivia: Gas Supply - Condensate Fields RESEWES (109CF) PRDuCTIoN (106CFD) Year Originally Estimated Proven 7/1/81 Original 1981 Projected Fields Discovered Discovered Cat. I-II III Gas/Oil Ratio Actual 1985 1990 2000 I & II CF/B Lowlands Madrej ones 1959 16.7 16.7 0 13,916 - - - - Colpa 1961 601.4 235.8 59.6 30,192 45 40 28 20 Rio Grande 1961 1,261.3 1,028.0 92.4 17,249 57 113 167 236 Palmar 1964 41.1 18.1 2.1 39,324 20 16 5 - Santa Cruz - 3.9 3.5 - 35,000 4 2 - - Motecristo 1976 0.4 0.4 288.6 29,518 - - - - Tita-Techi 1976 94.3 20.3 - 8,507 30 7 - - NIco 1979 0.2 0.2 - 21,000 - - - - La Vertiente 1978 210.8 174.5 - 43,604 50 50 50 50 Vuelta Grande 1978 838.5 838.5 - 9,430 - - - - Porvenir 1978 107.0 106.3 - 29,847 - 50 44 - Espino 1979 16.4 6.7 23.0 22,222 12 7 - T(AL 2,449.0 465.7 218 285 294 306 Source: YPFB - internal information. Updated to July 1982. Note: The Mission obtained several reserve estimates, two of which are dated July 1981 and the others relate to earlier assessments. There are discrepancies between the two recent ones and there is no way to relate changes from one year to another. This indicates that reserves estimates are being manipulated incorrectly and do not marit confidence. Bolivia: Gas Supply - '1,ainly Gas Fields" RESERVES (109CF) PRODUCON (106CFD) Original Year Originally Estimated July 1981 Gas/Oil Ratio 1981 Projection Field Discovered Discovered Prov. I & II III MCF/B Actual 1985 1990 2000 Subandean Bulo Bulo Lwlands Naranjillos 1964 876.4 75.8 - 90 - - 20 - Yapacani 1968 319.6 319.6 134.6 103 - 100 100 - Enconada 1972 17.7 17.7 74.6 61 - 30 30 - Palometas 1973 315.0 315.0 - 807 - - - 70 Santa Rosa 1973 947.0 947.0 144.0 620.0 - 180 180 130 Palacios 1974 103.6 103.6 - 108 - - - 30 Rio Seco (GE) 4.8 4.8 4.6 157 - - - - TOTAL 1,783.5 357.8 - - 310 330 230 S Source: YPDB - internal information - 135 - ANNEX 1.22 Bolivia: 1981 Gas Utilization (106 CF) Economic Use in Field, Reinjection Lost or Market or Processing and Gas Lift Burned Total Oil Fields Bermejo 157 Caigua 32 Camiri 660 2,616 256 Cambeiti 423 Monteagudo 1,368 578 San Alberto 11 La Pena 642 618 Caranda 435 3,658 711 Sub-Total 3,105 6,274 2,786 12,165 Share (%) 25 52 23 Condensate Fields Espino 4,593 402 Palmar 7,377 169 Colpa 16,300 1,451 Rio Grande 24,709 68,172 1,379 Tita 16,593 Porvenir 513 La Vertiente 16,597 4,998 Sub-Total 86,682 68,172 8,399 163,253 Share (%) 53 42 5 TOTAL 89,787 74,446 11,185 175,418 Share (%) 51 42 6 Source: YPFB - Computer Printouts - 136 - ANNEX 1.23 1981 YPFB Oil and Gas Sales to Industry (MTOE) Departments Diesel Oil 1/ Fuel Oil LPG Gas Total La Paz 20.64 47.00 2.61 - 70.24 Oruro 15.04 55.17 1.85 - 72.06 Cochabamba 14.71 30.32 2.86 - 47.89 Potosi 5.67 5.35 0.07 - 11.09 Sucre 3.17 0.92 0.08 30.08 34.25 Camiri 1.09 . . 2.60 3.69 Sub-total 60.32 138.76 7.47 32.68 239.23 Santa Cruz 32.74 2.57 0.08 108.38 143.77 Tarija 0.95 2.56 - 3.41 6.92 Bermejo 0.95 2.56 - 3.41 6.92 Rest of Country 8.60 0.25 0.09 0.35 9.29 TOTAL 106.62 146.47 7.56 144.82 405.47 1/ Assumes that 40% of diesel sales are industrial. A portion of this volume should be allocated to intermediate demand, because it is used to generate electricity. Source: YPFB - sales statistics; does not include consumption in refineries. Bolivia: Potential Market for Natural Gas (MMCFD/Day) Actual Base Case Optimistic Case Pessimistic Case 1981 1986 1991 1996 2001 1991 2001 1991 2001 La Paz - 7.4 9.5 12.9 18.7 10.3 21.6 7.8 12.7 Oruro - 4.8 5.9 7.5 10.1 10.3 16.7 5.4 8.1 Cochabamba - 10.6 13.8 15.9 19.4 14.9 22.2 13.1 16.5 Potosi - 5.5 6.4 6.5 6.6 6.4 6.6 5.5 6.5 Chuquisaca 3.6 4.7 5.2 6.1 7.5 5.6 8.0 4.9 6.3 Sub-Total 3.6 33.0 40.8 48.9 62.3 47.5 75.1 36.7 50.1 Santa Cruz 15.5 25.9 26.9 28.5 31.0 48.4 79.0 26.5 50.1 Tarija 0.4 1.5 2.1 2.5 2.8 2.2 2.9 2.1 2.6 TOTAL 19.5 60.4 69.8 79.9 96.1 98.1 157.0 65.3 81.7 Source: GDC. The Internal Demand for Natural Gas and LPG in Bolivia. 4_ - 138 - ANNEX 1.25 Potential Market for Natural Gas 1990 1990 1981 Baseline Accelerated 1981 Baseline Accelerated Main Fuel MTOE MTOE MTOE MMCFD MMCFD MMCFD La Paz Cervecerta Bol. N. F.O. 3.5 6.0 6.0 0.4 0.6 0.6 Fea. Nacional Vidrio F.O. 8.6 11.2 23.0 0.9 1.2 2.4 Fanviplan (Glass) F.O. 6.8 6.8 8.0 0.7 0.7 0.8 Soboce (Cement) F.0. 17.5 23.0 27.0 1.8 2.4 2.8 Subtotal 36.4 47.0 64.0 3.8 4.9 6.6 Other Industries F.O. 10.6 12.0 18.0 1.1 1.2 1.9 Other Industries LPG 2.6 3.0 4.0 0.3 0.3 0.4 Other Industries Diesel 20.6 22.0 26.0 2.1 2.3 2.7 Total Industrial Fuels 70.2 84.0 112.0 7.3 8.7 11.6 Oruro ENAF (Smelter) F.0. 51.7 71.0 71.0 5.3 7.4 7.4 Other Industries P.O. 3.5 4.0 5.0 0.4 0.4 0.5 Other Industries LPG 1.9 2.0 2.5 0.2 0.2 0.3 Other Industries Diesel 15.0 18.0 20.0 1.6 1.9 2.0 Machacamarca (Smeltet) 1/ - - - - - (2.7) Cement Plant 1/ - - - - (2.6) Total Industrial Fuels 72.1 95.0 98.5 7.5 9.9 10.2 Cochabamba Coboce (Cement) F.O. 13.8 28.0 28.0 1.4 2.9 2.9 Vidriolux F.O. 6.1 10.0 11.0 0.6 1.1 1.2 Industrias de Aceite F.O. 2.8 4.0 4.0 0.3 0.4 0.4 Subtotal 22.7 42.0 43.0 4.7 4.7 4.7 Refinery Gasoline 45.0 45.0 45.0 4.7 4.7 4.7 Other Industries F.O. 7.6 10.0 13.0 0.8 1.0 1.4 Other Industries LPG 2.8 3.6 3.6 0.3 0.4 0.4 Other Industries Diesel 14.7 19.0 20.0 1.5 1.9 2.0 Total Industrial Fuels 92.8 119.6 124.6 9.6 12.4 13.0 Potosi La Palca F.O. 4.0 26.0 26.0 0.4 2.7 2.7 ENDE Diesel 1.0 17.0 17.0 0.1 1.8 1.8 Subtotal 5.0 43.0 43.0 0.5 4.5 4.5 Other Industries F.O. 1.3 1.7 1.7 0.1 0.2 0.2 Other Industries LPG 0.1 0.2 0.2 - - - Other Industries Diesel 4.7 6.0 6.0 0.5 0.6 0.6 Karachipampa 16.0 1.8 Total Industrial Fuels 11.1 50.9 66.9 1.1 5.3 7.1 Sucre Fancesa NG 13.0 28.0 28.0 1.3 2.9 2.9 YPFB-Refinery NG 5.0 5.0 5.0 0.5 0.5 0.5 ENDE-Power NG 17.0 17.0 17.0 1.8 1.8 1.8 Subtotal 35.0 50.0 50.0 3.6 5.2 5.2 Other Industrial 7.0. 0.9 1.2 2.0 0.1 0.1 0.2 Other Industrial Diesel _T__2 70 4.0 0.3 0.4 0.4 Total Industrial Fuels 39.1 55.2 56.0 4.0 5.7 5.8 Santa Cruz Aceitera Oriente NG 3.5 4.0 4.0 0.4 0.4 0.4 Other Industry NG 19.5 28.0 30.0 2.0 2.9 3.1 YPFB-Refinery NG 23.0 23.0 23.0 2.4 2.4 2.4 ENDE-Power NG 85.0 238.0 626.3 8.8 24.8 65.3 Subtotal 1 683.3 13.6 30.5 71.2 Other Industry F.O. 2.6 3.8 3.8 0.3 0.4 0.4 Other Industry Diesel 32.7 48.0 48.0 3.4 5.0 5.0 Aommnia-Urea Project - - 77.0 - - 8.0 Sponge Iron-Plant 1/ (17.9) Mutun Ore Processing 1/(58) Total 66.0 T"--8 TI32T 3 TS 84.6 Tarija Criosal F.O. 2.0 4.0 4.0 0.2 0.4 0.4 Bermejo Sugar Mills F.O. Bagasse 3.0 5.0 5.0 0.3 0.5 0.5 with Paper Mill) 1/ - - (4.1) Paper Plant - 5.0 5 0 - 0.5 0.5 Cement Plant 1/ - - - - - (1.2) Other Industries Diesel 7.0 10.0 10.0 0.7 1.0 1.0 Total 12.0 24.0 24.0 1.2 2.5 2.5 TOTAL COUNTRY Manufacturing 245.0 344.0 460.0 25.0 36.0 47.0 Metallurgy 52.0 97.0 113.0 5.0 10.0 12.0 Power Plants 103.0 272.0 660.0 11.0 28.0 69.0 Refineries 73.0 73.0 73.0 8.0 8.0 8.0 Total 473.0 786.0 1306.0 490 .0 -1 T6 70 1/ It is assumed that the marked projects will not be implemented during the present decade. Their joint additional demand would sum 34 MMCFD of which 26 in metallurgy (Machacamarca) and 9 MMCFD in manufacturing substitution of bagasse in sugar mills (3.5 MMCFD), cement plants in Tarija, and Oruro, etc. Source: Mission estimates. - 139 - ANNEX 1.26 BOLIVIA: List of Identified Hydroelectric Projects Present Unit Invest- Year of Name of Project River Type Capacity Energy Status ment Cost 2 Estimation (MW) (GWh) USS/kW 1. San Jacinto Tolomosa E/I 7 21 FD 5,000 80 2. Sakhahuaya Unduavil/Taquesi E 72 362 FD 1,760 81 3. Icla Pilcomayo E/I 90 365 FD 1,860 79 4. Misicuni Misicune E/I 104 460 FD 2,040 78 5. Rositas Rio Grande E/I 400 2,060 F 1,500 76 6. Aguas Calientes I Pilaya E 90 579 F 1,290 81 7. San Jose Paracti E 150 840 PF 1,250 76 8. Palillada Miguillas E 110 632 PF 1,040 76 9. Tirata La Paz E 94 409 P 2,800 76 10. Lloja La Paz E 130 583 P 2,000 76 11. Huara La Paz E 100 380 P 2,000 76 12. Santa Rosa Tamampaya E 23 105 P 1,800 76 13. Umabama Tamampaya E 37.5 160 P 1,000 76 14. Ilumaya Tamampaya E 54 235 P 900 76 15. Imamblaya Tamampaya E 80.8 455 P 1,600 76 16. Siete Lomas Tamampaya E 242 1,039 P 900 76 17. Condor Cala Miguillas E 75 350 P 1,900 76 18. Tangara Miguillas E 108 715 P 1,200 76 19. Tiquimami Coroico E 50 340 P 1,000 76 20. Pabellonani Coroico E 50 337 P 800 76 21. Huancane Coroico E 110 760 P 1,000 76 22. Challa Coroico E 35 235 P 900 76 23. Choro Coroico E 100 740 P 900 76 24. Bala Bent E 1,608 10,600 P -- -- 25. Cachuela Esperanza Beni E 10 40 P -- -- 26. Huaji Zongo E 26 125 P 1,800 81 27. Pachalaca Zongo E 14 67 P 2,200 81 28. Banda Azul Paracti E 114 635 P 800 76 29. La Vina Rio Grande E 70 247 P -- -- 30. Molineros Rio Grande E 130 569 P -- - 31. Pucara Rio Grande E 182 797 P -- 32. Caine Rio Grande E 162 1,254 P -- 33. Puente Arce Rio Grande E 130 550 P 800 72 34. Charobamba Rio Grande F 214 550 P -- -- 35. Seripona Rio Grande E 420 1,700 P 600 72 36. Canahuecal Rio Grande E 500 2,000 P 600 72 37. Las Juntas Rio Grande E 172 1,350 P 800 72 38. La Riguera Rio Grande E 320 1,340 P 700 72 39. Pena Blanca Rio Grande E 520 2,490 P 600 72 40. La Pesca Rio Grande E 740 3,030 P 600 72 41. Turuchipa Pilcomayo E 66 286 P -- -- 42. San Jose Pilcomayo E 280 1,226 P -- -- 43. Esperanza Pilcomayo E 123 539 P -- 44. Sta. Elena Pilcomayo E 341 1,494 P -- -- 45. Machigua Pilcomayo-Pilaya E 202 885 P -- -- 46. Yuquirenda Pilcomayo E 255 1,116 P -- -- 47. Churro Pilcomayo E 244 1,070 P -- -- 48. Paichu Pilaya 8 204 1,019 P 1,300 81 49. Aguas Calientes II Pilaya B 181 764 P 800 81 50. Arenales Pilaya E 94 412 P -- -- 51. El Pescado Pilaya E 202 885 P -- -- 52. Incahuasi Pilaya E 24 P -- - 53. Las Pavas Bermejo E, BN 147/2 400/2 PF 2,000 79 54. Arrazayal Bermejo E, BN 166/2 521/2 P 2,000 79 55. Desecho Chico Bermejo E, BN 36/2 78/2 P 600 79 56. Cambari Tarija E 136 613 P 700 79 57. Astilleros Tarija E, BN 106/2 504/2 P 6,200 79 58. San Telmo Tarija E, BN 68.5/2 275/2 P -- -- 59. Polvarada Tarija E, BN 27/2 60/2 P -- 79 60. Juntas San Antonio Bermejo-Tarija E, BN 48/2 165/2 P -- -- TOTAL 10,295.55 50,816.5 1/ Type of Project: E - energy; E/I - energy and irrigation, BN - binational. 2/ Present Status of the Project: FD - final designs ready or being prepared; P - feasibility study ready; PF - pre-feasibility studies; P - preliminary studies only. 3/ Unit cost referred to January 1981 price levels using inflation indices. Costs for projects with only preliminary studies are rough estimates. Bolivia: 1981 Power Generation Capacity (MW) Nameplate Effective Hydro Thermal Total Hydro Thermal Total % of Total ENDE 108 113 221 105 101 206 50.7 BPC 142 - 142 128 - 128 31.6 CESSA 2 - 2 - - - - ELFEC 6 - 6 2 - 2 0.5 OTHER PUBLIC SERV. 1/ 1 26 27 - 20 20 4.9 COMIBOL 22 20 42 13 4 17 4.2 OTHER SELF PRODUCERS 6 54 60 3 30 33 8.1 TOTAL 287 213 500 251 155 406 100.0 PERCENTAGE OF TOTAL 62 38 100 C 1/ Trinidad, Tarija, Pueblos, etc. Bolivia: Statistical Data and Forecast for the Power Sector Peak Demand (MW) Northern Central Southern Oriental Other Total NIS Diversity Year System System System System Areas Country Demand Factor Actual 1975 71.6 64.0 23.6 18.2 41.7 219.1 1976 73.6 67.6 25.5 21.5. 42.2 230.4 1977 77.6 77.0 27.2 26.7 45.0 253.5 1978 82.4 85.2 27.0 31.9 49.3 275.8 1979 91.3 88.5 28.8 37.3 50.9 296.8 1980 98.7* 95.2 29.7 46.7 51.2 321.5* 1975-80 Growth % 6.6* 8.3 4.7 20.7 4.2 8.0 1981 103.5* 1/ 101.5* 31.7* 51.2 53.3 341.2* 236.7* 2/ Forecast 1982 116.6 114.6 35.6 60.2 56.9 376.6 259.0 0.97 1983 119.4 124.3 40.1 70.1 59.4 409.3 275.4 0.97 1984 123.4 134.9 44.6 81.6 62.7 445.1 293.9 0.97 1985 128.3 146.3 48.6 95.0 67.6 485.8 401.5 3/ 0.96 1980-85 Growth % 5.3 9.0 10.4 15.3 5.7 8.6 8.2 1986 137.5 157.8 52.8 105.8 83.8 537.7 435.7 0.96 1987 145.5 170.3 57.5 117.4 87.5 578.2 471.1 0.96 1988 153.8 183.7 62.5 130.3 91.4 621.6 509.1 0.96 1989 162.7 198.3 67.9 144.7 95.4 669.0 550.7 0.96 1990 171.9 213.9 73.9. 160.5 99.5 719.2 595.4 0.96 1985:-90 Growth % 6.0 7.9 8.7 11.1 8.0 8.2 8.2 0.96 I/ Includes the area of Yungas from 1981 onwards. 2/ The NIS includes the Northern, Central and Southern Systems. 3/ The Oriental System is integrated to the NIS. 4/ Diversity factor is lower after 1985 due to the connection of the large Oriental System. Source: ENDE-1981 - Figures for 1980 and 1981 revised according to the Draft Report "Plan Nacional de Electrification" where indicated by an asterics. co Bolivia: Statistical Data and Forecast for the Power Sector Gross Energy Generation (GWh) Northern Central Southern Oriental Other Total NIS Year System System System System Areas Country Generation Actual 1975 322.2 348.7 114.7 79.0 192.4 1057.0 1976 331.0 381.8 127.8 96.7 194.7 1132.0 1977 352.8 437.9 142.7 119.0 207.3 1259.7 1978 375.3 463.8 144.8 142.7 227.2 1353.8 1979 403.6 489.3 139.4 165.6 234.8 1432.7 1980 426.9 541.2 159.4 202.7 236.1 1566.3 1975-80 Growth % 5.8 9.2 6.8 20.7 4.2 8.2 1981 441.7 1/ 579.6 180.3 234.8 240.9 1677.3 1201.6 2/ 1980-81 Growth % 3.5 7.1 13.1 15.8 2.0 7.1 Forecast 1982 523.9 634.9 174.7 269.0 262.3 1864.8 1333.5 1983 556.1 695.7 202.8 313.3 274.1 2042.0 1454.6 1984 590.9 706.4 225.6 364.6 288.9 2176.4 1522.9 1985 627.5 753.2 245.7 424.4 311.9 2362.7 2050.8 3/ 1980-85 Growth % 6.6 7.8 10.2 15.9 4.9 8.6 9.1 1986 665.2 817.6 267.1 472.5 386.5 2608.9 2222.4 1987 705.1 883.4 290.5 524.6 403.4 2807.0 2403.6 1988 747.4 953.5 315.7 582.2 421.7 3020.5 2598.8 1989 792.2 1028.6 343.4 46.3 440.0 3250.5 2810.5 1990 839.7 1108.8 373.4 717.4 459.0 3498.6 3039.3 1985-90 Growth % 6.0 8.1 8.7 11.1 8.0 8.2 8.2 1/ Includes the area of Yungas. 2/ The NIS includes the Northern, Central and Southern Systems. 3/ The Oriental System is integrated to the NIS. Source: ENDE 1981 - Figures for 1980 and 1981 revised according to the Draft Report "Plan Nacional de Electrificacion." Bolivia: Revised Projection of Electric Power Demand (ENDE) Gross Energy Generation (GWh) 1982 1983 1984 1985 1986 1987 1988 1989 1990 Total Bolivia Denand (GWh) 1764.8 1855.5 1951.2 2052.8 2184.4 2325.4 2476.3 2638.1 2811.2 Total Integrated Systens Demand (GWh) 1519.1 1604.8 1695.5 1792.0 1917.1 2051.4 2195.4 2350.2 2516.1 Peak Deannd (MW)* 293.9 310.5 328.1 346.7 370.9 396.9 424.8 454.7 486.8 Central System Denmand (GWh) 608.0 637.8 669.0 701.8 749.5 800.5 854.9 913.1 975.1 Peak Demand (M) 106.8 112.0 117.5 123.3 131.6 140.6 150.1 160.4 171.3 Southern System Demand (GWh) 192.6 205.7 219.6 234.6 248.7 263.6 279.4 296.2 313.9 Peak Demnd (MW) 34.4 36.7 39.2 41.8 44.4 47.0 49.8 52.8 56.0 1 Northern System Demand (GWh) 462.6 482.3 502.8 524.2 554.4 586.3 620.0 655.7 693.4 Peak Demand (MW) 105.4 109.9 114.4 119.2 126.0 133.2 140.7 148.6 156.9 Oriental System Demand (GWh) 255.9 279.0 304.1 331.4 854.5 401.0 441.1 485.2 533.7 Peak Demand (MW) 55.8 60.8 66.3 72.3 79.5 87.4 96.2 105.8 116.4 Other Areas Demand (GWh) 245.7 250.7 255.7 260.8 267.3 274.0 280.9 287.9 295.1 Peak Deand (MW) 65.5 65.8 68.1 69.5 71.2 73.0 74.9 76.7 78.6 * Diversity Factor = 0.98 > Source: Draft Report "National Electrification Plan" - February 1983 Bolivia: Power Generation Alternatives Cost Study Sakahuaya Cochabamba Santa Cruz Santa Cruz Data Unit Hydro Plant Combined Cycle Combined Cycle Gas Turbine Installed Capacity MW 2x36 = 72 1/ 2x45+1x45 2/ 2x36+1x36 3/ 4x24 = 96 4/ Effective Capacity MW 72 72 72 72 Net Generation GWh 360 360 360 360 Thermal Efficiency Kcal/Kwh - 2200 2200 3050 Gas Consumption CF/Kwh - 8.35 8.35 11.58 Investment Cost Total (1982) US$ Million 150 74 59 29 Plant 130 74 59 29 Transmission 20 - - - Investment Cost Unit (1982) US$/KW Per KW Installed 2083 550 550 300 Operating Costs: Total USt/Kwh 0.15 0.21 0.18 0.17 Fixed US$/KW Installed 7.0 4.0 4.0 4.0 US /Kwh 0.14 0.15 0.12 0.11 1 Variable (Non-Fuel) US /Kwh 0.01 0.06 0.06 0.06 Economic Life Years 40 15 15 15 Calculation Capital Cost 12% discount rate t/Kwh 5.05 3.02 2.41 1.18 14% 5.86 3.35 2.67 1.31 16% 6.68 3.69 2.94 1.44 Non-Gas Generating Costs f/Kwh 12% Capital Costs 5.20 3.23 2.59 1.35 14% 6.01 3.56 2.85 1.48 16% 6.83 3.90 3.12 1.61 Break Even Gas Price $/MCF 12% Capital Cost - 2.36 3.13 3.33 14% "- 2.93 3.78 3.91 16% "- 3.51 4.44 4.51 I/ Assuming a 100% availability of capacity in a hydro-power plant. 2/ The availability in a combined cycle equipment is assumed to be 66% (one of the two turbines is not operating). Due to the altitude of Cochabamba, the turbines have an additional de-rating of 20%. 3/ For Santa Cruz, the de-rating does not apply. 4/ Gas turbines are assumed to be available 75%, (one out of four turbines is not working). Source: Mission Estimate - 145 - ANNEX 1.31 Bolivia: Investment Requireents - Energy Sector - Hydrocarbons (in 1980 prices) YPFB 1982-1986 1986-1990 1981 - 1985 Without With Without With Physical (1980 prices) Pipeline Pipeline Pipeline Pipeline Hydrocarbons Work (Million US$) to Brazil to Brazil to Brazil to Brazil EXPLORATION Prospection Geology 3,560 kas 3 - - 3 3 seismic 2,155 kms 12 - - 12 12 Shales 2 - - 2 2 Seismic-Stratigraphic a/ 3,400 kms 13 - - 13 13 Boomerang 5 - 5 - Drilling Stratigraphic wells b/ 28 43 - - 21 43 Structural c/ 41 144 - - 72 144 Structural-step-out 15 54 - - 54 54 Boomerang 12 20 - 20 Development Vuelta Grande: Wells 5 18 18 18 - Gas Recycling Plant 24 24 24 - LPG Plant 4 4 4 - - Espino Wells 4 15 - - 15 15 Gas Plant 7 - - 7 7 New Fields Wells 43 182 - - 91 182 Boom ield Equipment 7 33 - - 20 33 Gas Fields: Wells 17 84 - 84 - - Production Wells (Caranda, Colpa, Rio Grande, La Pena) 17 40 40 40 - Gas Processing Plant Santa Rosa (360 MMPCD) 40 - 40 - - Gas Compreosio Golpa 3 - - 3 3 Secondary Recovery Camiri (Water Injection) 8 - - 8 8 Secondary Recovery Monteagudo (water Injection) 5 5 5 - - Tertiary Recovery La Pena (LPG Injection) 2 2 2 - - Others Drilling Equipment 4 45 - - 25 45 Production Facilities 5 5 5 - - Processing Ammonia-Urea 76 - -- Av-gas 100-130 Santa Cruz 0.3 0.3 0.3 - - Thermostable residues 3 - - - 3 Transport Pipeline to Brazil 389 - 389 - - Santa Cruz-Altiplano d/ 76 27 27 - 112 Extension Monteagudo-Sucre- Phase II (cost 21.2) 13.4 13.4 13.4 - - Yacuiba-Tarija 30 - - - Gas Gathering Boomerang 49 - 49 - Porvenir-Nancardines 1 1 1 - - Lateral gas lines: Porvenir-Vuelta Grande 3 3 3 - Vuelta Grande-Taguipa 1 1 1 - - Villa Montes-Chorety 2.0 2 2 - - Gatherline Lines-New Fields 7 - - 3 7 MARKETING-DISTRIBUTION Natural Gas 14 14 14 - - Distribution Networks: in La Paz, Santa Cruz, Sucre, Potosi 57 - - 57 57 Service Stations 6 6 6 - - Terminal La Paz 15 15 15 - - Total YPFB 1554 181 768 406 743 a/ The most interesting area is the Rio Grande North; IDB has in principle (1982) agreed to finance the seismic exploration of this portion. The other favorable area is Madre de Dios, for which two service contracts have have been negotiated. b/ IDB has also agreed to finance the drilling of 8 wells t the Rio Grande North area. c/ Of these, 31 wells have the objective of finding new fields and 10 are to find deeper structures. d/ Figure for Altiplano pipeline was revised according to IDB project description. - 146 - ANNEX 1.32 Bolivia: YPFB: Revised Operational Income - 1982 (million $b) YPFB's Original Feb. 1982 Rate of Revision Rate of Change Budget Revision Change Mid-1982 1/ Respect Budget Sales Revenue 18,095 28,749 59 28,749 5q Internal Market 7,956 11,111 39 - - General Oil Producers 6,366 7,932 25 - - Aviation Products 817 2,004 145 - - Lube Oils 529 805 52 - - Others 243 370 53 - - Exports 9,870 17,368 76 36,081 266 Via Arica 496 873 Gas to Argentina 9,229 16,240 LPG to Brazil 145 254 Other Revenue 270 270 - 270 - Operalional Expenditures 13,546 20,594 59 31,841 135 Operational Budget 2/ 3,454 5,119 48 4,900 142 Other Expenditures 3/ 2,707 4,684 73 13,264 390 Taxes 6,305 8,925 42 8,925 42 Interests and Commissions 1,080 1,866 73 4,752 340 Balance 4,550 8,155 33,259 Balance (US$) 4/ 186 185 371 1/ Mission Revision based on double exchange rate: $b 44/US$ for 40% of revenue and $b 120/US$ for 60% of revenue. All foreign exchange expenditures at $b 120/US$. 2/ Assumes 20% foreign component - 80% national escalated at 80% inflation. 3/ Assumes 100% foreign component. 4/ Budget at 24.51; February 1982 at 44; an6 Mission revision at $b 89.6/USS. - 147 - ANNEX 1.33 ENDE: Investment Program 1981-87 (in million US$-1980 prices) ONGOING WORKS: 60.5 (a) Interconnected System Generation: Sta. Isabel Enlargement 0.6 Corani-Dam Enlargement 44.9 Potosi-Gas Turbine 8.3 Transmission 4.2 (b) Other Systems 2.5 FUTURE WORKS: 459.6 (a) Interconnected System Generation: 371.9 Sakahuaya and T/L - Hydro 89.9 Icla and T/L - Hydro 167.0 Palillada and T/L - Hydro 78.1 Sta. Isabel - 4th Unit - Hydro 2.4 Santa Cruz - 5th Gas Turbine 7.2 Pilaya and T/L - Hydro 27.3 Transmission Central-Oriental Interconnection 42.7 42.7 (b) Other Systems San Jacinto - Hydro 12.3 45.0 Trinidad - Thermal 2.6 Cachuela - Esperanza 14.0 Transmission - Subtransmission 14.1 Other Small Work 2.0 TOTAL INVESTMENT 520.1 Source: ENDE V Power Project Report - Annex 4.4 Retail Prices of Major Petroleum Products, La Paz, 1975-82 ($b/liter) Prior to Dec. '75- Dec. '79- Since Since Since Nov. '75 Nov. '79 Dec. '80 Jan. 81 Feb. 5, 1982 Nov. 6, 1982 Gasoline - super 1.10 3.50 5.00 ( ( 20.8 25 - premium n.a. 5.00 6.00 7.00 10.00 10.00 35 Kerosene - domestic 0.25 0.30 1.00 (4.00 5.0 8 - industrial use 0.40 0.50 4.00 ( Diesel - public (0.55 1.30 4.00 (6.00 8.00 10.4 23 - power generation ( 2.50 ( on Fuel oil 0.30 1.10 4.00 5.50 7.50 5.7 22 LPG a/ - domestic use ( ( 2.00 ( 3.50 5 - industrial use (-- (0.50 (1.30 (3.00 4.50 14 - automotive use ( ( ( ( 5.00 15 Natural gas (per MCF) -- 20.00 20.00 25.00 45.00 a/ $b/kg Source: YPFB Bolivia: Boomerang Area - Exploration and Development Cost Estimate (in 1980 constant prices - million US$) 1981 1982 1983 1984 1985 1986-1993 1994 1995 1996 1997 1998 1999 2000 INVESTMENTS EXPLORATION Seismic 3.3 2.2 Drilling 18.3 1.9 Overheads 2.2 0.4 DEVELOPMENT Drilling 15.1 28.8 40.0 Gas Plant 20.0 20.0 Gathering Pipes 5.0 5.0 Overheads 1.5 5.3 6.5 TRANSPORT To Colpa 5.0 17.5 Co1pa a Mineroa 57.1 TOTAL 23.8 4.5 16.6 64.1 146.1 Net Present Value (14%) 170.3 Net Present Value (12%) 179.5 GAS PRODUCTION (106CFD) Enconada 30 10 - - - Yapacani 100 100 90 50 20 10 0 Santa Rose 180 180 180 160 140 140 130 130 TOTAL GAS PRODUCTION (1O6CFD) 113.2 106 99 77 58 55 47 47 Net Present Value (14%) 378 x 106CF Net Present Value (12%) 445 x 109CF Average Cost: (14%). USSO.45/MCF (12%). US$0.40/MCF Bolivia: Transport Cost Monteagudo-Sucre Extension to Cochabamba and La Paz Investment 1/ (JS$ Operating Gas Total Gas nspo 4/ Phase I Phase II Phase III Maintenance 2/ Consunption 3/ Outflow eCFD 10-CF/y 1981 13.2 10.0 0.2 23.4 3.6 1314 1982 11.2 4.8 0.7 0.2 16.9 3.6 1314 1983 15.0 1.17 0.4 16.57 22.1 8067 1984 1.62 0.4 2.02 24.3 8869 1985 1. 0. 2.02 25.7 9380 1986 1.62 0.4 2.02 25.7 9380 1987 1.62 0.4 2.02 25.7 9380 1988 1.62 0.4 2.02 25.7 9380 1989 1.62 0.4 2.02 25.7 9380 1990 1.62 0.4 2.02 25.7 9380 1991 1.62 0.4 2.02 25.7 9380 1992 1.62 0.4 2.02 25.7 9380 1993 1.62 0.4 2.02 25.7 9380 1994 1.62 0.4 2.02 25.7 9380 1995 1.62 0.4 2.02 25.7 9380 1996 1.62 0.4 2.02 25.7 9380 1997 1.62 0.4 2.02 25.7 9380 1998 1.62 0.4 2.02 25.7 9380 1999 1.62 0.4 2.02 25.7 9380 2000 1.62 0.4 2.02 25.7 9380 2001 1.62 0.4 2.02 25.7 .9380 Total (at 14% discount rate) 60.88 54,325.8 Average Transport Cost: US $1.12/MCF 1/ Phase I (1980 US$) refers to investnents mde in late 1980. Phase II (1982 US$) refers to extension to Cochabamba and Phase III to Cochabamba-La Paz. 2/ 3% of accuilated investnent in previous year. 3/ Priced at US$11 ICF - Consumption as estimated by YPFB for compression stations is 1.1 1*0FD. 4/ Supply limited to 25.7 MMCFD - Total connections in 1983 are 11 new custoners in La Paz, Oruro and Cochabamba. - 151 - ANNEX 1.37 Bolivia: Transport Cost -Altiplano Pipeline - Santa Cruz-Cochabamba and La Paz Baseline Demand Scenario Investment Operation & Gas Costs Gas Sales (1000 US$) Maintenance Consmption MMCFD MMCFY 10 CF 106US$ 1982 968 0.97 - 1983 19,547 19.55 - - 1984 53,754 53.75 - - 1985 26,054 750 27 26.83 6.0 2,190 1986 - 3000 137 3.14 24.3 2/ 8,870 1987 - 3000 164 3.16 25.3 9,234 1988 - 3000 186 3.19 26.3 9,600 1989 - 3000 220 3.22 27.3 9,964 1990 - 3000 258 3.26 28.3 3/ 10,330 1991 - 3000 275 .3.28 29.5 10,768 1992 752 3000 346 4.10 30.8 11,242 1993 - 3028 369 3.40 32.1 11,717 1994 4,176 3028 542 7.75 33.5 12,227 1995 - 3175 590 3.77 35.0 12,775 1996 7,380 3175 660 11.22 36.4 13,286 1997 6,864 3433 707 11.00 38.8 14,162 1998 16,696 3673 806 21.18 41.3 15,075 1999 - 3904 905 4.81 44.0 16,060 2000 5,124 3904 1015 10.04 47.0 17,155 2001 - 3904 1140 5.04 49.8 18,177 2002 6,864 4084 1280 12.23 52.6 19,200 At 14% Discount Rate 98.11 49.699 $1.97/MCF 1/ As estimated by YPFB - IDB includes technical costs only. 2/ Main 1981 clients without increase and La Palca and ENDE in Potosi. 3/ 80% of 1990 total demand for the region. For the 1990's escalation is based on GDC's incremental values, base case. - 152 - ANNEX 1.38 BOLIVIA: Mean Annual Wind Speed Department Station Wind Speed (Km/hr) La Paz El Alto 6.9 Cochabamba Cochabamba 3.5 Todos Santos 4.1 Santa Cruz Camiri 5.2 Puerto Suarez 7.4 Concepcion 13.9 Robore 10.8 Santa Cruz 19.2 San Jose 12.2 San Ignacio de Velasco 8.9 Beni Riberalta 6.3 Santa Ana 11.1 San Ignacio de Moxos 8.9 Guayaramerin 5.6 Trinidad 13.0 Magdalena 8.5 Rurrenabaque 4.1 San Borja 7.6 Pando Cobija 4.8 Oruro Oruro 9.6 Chuquisaca Sucre 6.3 Potosi Uyuni 6.1 Tarija Tarija 8.1 Yacuiba 9.8 Source: Instituto de Investigacion Fisicas. VALORES DE RAPIACION GLOBAL GLOBAL RADIATION VALUES R vn col/cm*/doy L-BOL#VIA 2.- ZONAS CLIMATICAS CLIMATIC ZONES g) ALTIPLANO b) LOS VALLESYYUNGA$ c) LLANOS R R R VALLYS AND YUNGAS R PL A INS 800 800- - .-- 72 12 600 7 600 - 60C00--- 600 500 G, L00 - -S4 - 0.J- - _oo-o--_ - _ - 6-00 1' 3.0 tn 500- 5w- 500- --- - - 500 - 400- - _00 - - 4oo - 400 - >000- 7too- - 200------- Z0-------0- --------- E F m i 1 M J J 0 N 0 E F M ( A 1 J J 3 0 E 4f M A i J J AA O E fM A tv J J A S O N JF MAMJJ ASOND EF MA MJJ ASONO EF M AMJJ ASOMO EF MAMJJ A$0MO ~.#F A4f.A5 ND q F4f MJJ 8 O D ~ I M4M .JA ONO F M A JJ4 ON SUGAR PRODUCTION, RESIDUES, AND ENERGY CONSUMPTION IN SUGAR MILLS 1/ 1980 Sugarcane Sugar Mills Milled Sugar Area Yield Fuel Consumed at the Sugar Mills in 1980 Per Province (for sugar) Production Planted Sugarcane Bagas§e Natural Gas Oil Firewood T T HA T/HA T 10 Cubic Feet T T Guabira 707,642 60,452 260 1,454 7,761 La Belgica 449,931 38,460 157 332,706,740 590 San Aurelio 305,913 27,653 103 244,018,000 Unagro 472,766 41,143 153 435 2,170 Santa Cruz 1,936,252 167,708 55,742 35 677 576,724,740 2,479 9,931 Ln Stephen Leigh 228,305 26,358 Moto Mendez 414,949 48,056 Tarija Bermejo 643,254 74,414 8,814 73 173 6,171 42 1/ La Industria Azucarera Boliviana, 1980 - Comision Nacional de Estudio de la Cana y del Azucar. C)a - 155 - ANNEX 1.41 BOLIVIA: ALCOHOL PRODUCTION FROM SUGARCANE - 1980 Alcohol Production 1,000 Itrs. Sugar Mills Molasses Absolute Alcohol 96 Alcohol 95 (Distilleries) T (Buen Gusto) (Mal Gusto) Guabira 33,149 7,659 897 La Belgica 18,297 5,565 821 San Aurelio 16,217 3,715 546 Unagro 21,050 3,866 606 Stephen Leigh 8,512 1,920 259 Moto Mendez 15,923 113,148 22,725 3,129 Source: La Industria Azucarera Boliviana, 1980 - Comision Nacional de Estudio dela Cana y del Azucar. - 156 - ANNEX 2 Page 1 of 7 Brief of Geology 1. Marine sediments began to be deposited over the entire area of present day Bolivia, except for the far northeastern portion during the Ordovician period. And, the Ordovician seas may have covered even the present day Brazilian Shield in Bolivia, with the sediments having been removed by later erosion. 2. Marine deposition continued, apparently without a pause, through the Silurian and Devonian periods so that at one time more than 15,000 feet of marine sandstones and shales were present over the country, again except for the far northeastern portion. Here again, a much greater thickness may have been present, as we know that erosion, which took place during later geologic periods, removed much of this section and redeposited it in the younger basins which continued to develop to the west. 3. The Ordovician section is not very well known, as it does not outcrop in the oil producing areas and has been seen in only a few exploratory wells, which are both updip from the producing area and near to the Brazilian Shield. It is essentially a quartzite and quartzitic sand with some dark grey shale. It would appear to have little chance of being hydrocarbon productive as the porosity is low and little if any source material is present from which hydrocarbons could have been generated. 4. The Silurian section is composed of sandstones and shales. Also with the section being shalier as one moves farther away from the Brazilian Shield. Although the rocks of this period are mostly shale, the Sara sandstone in the Palometas NW and Santa Rosa fields are thought to be of this age. In the former field, the Sara contains 54 meters or net pay with 10% porosity and it tested 8.5 MMCFDG with 30 b/dc (barrels per day of condensate) at a depth of 2600 meters. In the latter, it had over 65 meters of net pay with 9% porosity and tested 7.7 MMCFDG with 15 b/dc. A thick section of Sara pay sand has been reported in the Yapacani X5 development well so this section must be considered an important pay zone, particularly in the Boomerang Hills. 5. The Devonian section, which is also a elastic section, is considered to be the source of most, if not all, the hydrocarbons in the country. It is mostly a shale section, many thousands of feet thick, with varying amounts of sandstone. The shale is dark and has a high organic carbon content. Most of the many oil seeps along the Subandino Zone of the country originate either from these sands or from faults which cut this Devonian section. - 157 - ANNEX 2 Page 2 of 7 6. Sandstones within the Devonian is the reservoir at Camiri, where 46.8 million barrels of 55 API oil have been produced since discovery in 1927 and where 880 b/d is still being produced. 7. At the end of Devonian time a gentle uplift occurred, which formed an unconformity over the entire country. The Carboniferous age deposition, which followed and extended up into the Permian period, was confined to a smaller area and was no longer of marine origin, particularly in the southern half of the country. The Brazilian Shield remained a positive element and supplied sediments, part of which were undoubtedly eroded Ordovician to Devonian rocks. This deposition took place on a flood plain near the Shield and in lakes farther west. Glacial deposits are also thought to be present. Because of the general continental origin of these sediments the hydrocarbons produced from this section (and 70% of the country's reserves are in these rocks) are thought to have originated in the underlying Devonian shales. 8. Rocks of the Permo-Carboniferous are confined to the Subandino and Chaco Zones in the southern half of the country, and if they extended farther west during deposition, subsequent latter uplift and erosion have removed them. In the northwestern Subandino Zone there is little or no evidence of the rocks of this age. This lack of section may be due to erosion but more likely it is due to non-deposition as the Ichilo Fault Zone was probably activated at the end of the Devonian time. This action moved the Brazilian Shield much farther to the west than it appears to be now, as evident by the lack of sedimentary rocks of all ages, except for the Tertiary over much of the Beni. 9. Permo-Carboniferous rocks in northwest Bolivia around Lake Titicaca and also in southeast Peru have a much different depositional history and appear to have no bearing on the presently producing areas of the country. However, this northwestern area may have hydrocarbon potential, but the degree cannot be ascertained at present. 10. Because of the nature of deposition the sandstone reservoir beds are erratic in development and lenticular in nature. However porosites are good, usually 15% or better, and permeabilities are also good. Because of the lenticular nature of the sands, it is difficult to estimate reserves accurately with only a well or two on a structure. 11. A slight unconformity developed at the end of the Permo- Carboniferous deposition, but it appears to be of no importance as far as oil accumulation is concerned. 12. Except for a short marine transgression in early Cretaceous time, as evidenced by some calcerous content in rocks of that age, the remaining Cretaceous rocks, as well as the overlying Tertiary section, - 158 - ANNEX 2 Page 3 of 7 are of continental origin. These are usually typical redbeds with mostly shale and poorly developed sandstone. However, some clean, generally thin sandstones of reservoir quality do develop and are some times productive. An example would be the Tacuru (L. Tertiary) in the Vuelta Grande Xl well where four sands, totally 14.5 meters, tested 6.7 MMCFDG and 323 b/dc through a 28/64" choke. 13. Although minor structural development may have occurred in this area prior to the Andean Orogeny of Late Tertiary age, any evidence of it has been obliterated by the violent movements of said orogeny. In addition, any hydrocarbons that had been trapped in pre-Andean traps have probably migrated into the much larger, present-day traps and, sorry to say, much of the hydrocarbons have been lost through seepage from these traps. 14. Broadly speaking, there are two structural zones that have importance from a hydrocarbon standpoint. The first is the Subandino Foothills Zone where the structure is aligned with the Andean Mountain Range and where there is usually a surface expression of the structure so that surface mapping of the structure is possible. It was in the southern portion of this area that Jersey Standard geologists began their mapping in the early 1920's and where Camiri Field, which is one of the five largest fields in the country, was discovered in 1927. As the structures within this Subandino Foothills Zone are very complex structurally and as they are often thrust faulted, the subsurface high (at the hydrocarbon objective depth) does not always coincide with the surface high. This fact has caused many dry holes to be drilled and often three or four exploratory wells must be drilled on structures to either prove it to be productive or to condemn it completely. 15. The Chaco Plains, immediately to the east of the Subandino Foothills, have structures of much the same type as those in the foothills, in that they are elongate, north-south anticlines which are usually thrust faulted to some degree. But, they differ in that most have a thick section of Tertiary rocks covering them, so that they have few if any outcrops that can be mapped by geologists, and structures usually have gentler dips and less complex faulting. 16. Much seismic work was carried out in this area and also in the Santa Cruz portion of the Chaco in the late 1950's and first half of the 1960's. The work in the southern part was unsuccessful, probably due to the complicated structural development, but it was highly successful in the Santa Cruz area where the structures are broader and much simpler in structural style. Of the 28 exploratory wells drilled in the Santa Cruz area, 12 discovered hydrocarbons and eight have enough reserves to be producible. It appears that with the better seismic techniques now available, the entire Chaco Plains, to the south of Santa Cruz, will - 159 - ANNEX 2 Page 4 of 7 go through another exploration phase. Tesoro and Oxy have already begun this phase. 17. The eastern flank of the Chaco Plains in the Izozog Swamp area, some 250 kilometers south southwest of Santa Cruz, was explored for stratigraphic traps back in 1959 to 1961 when Gulf drilled 12 widely spaced stratigraphic tests. This effort was unsuccessful, but possible stratigraphic traps must be considered all along the east flank of this basin. YPFB personnel have made a study of the area to the north and northeast of Santa Cruz with stratigraphic trap exploration in mind. As this is a highly speculative venture, it should be undertaken as a last resort. 18. The remaining geologic provinces have little to no hydrocarbon potential. The Brazilian Shield has basement outcrops and these basements rocks extend far westward into the Beni under a thin veneer of Tertiary and possibly Cretaceous rocks, as evident from an exploratory well drilled near 140S and 66OW, which entered basement rock at about 2600 feet. The far northwestward portion of the Subandino Foothills Zone have a number of anticlines typical of this zone (see map) which are worthy of testing, and the adjacent Madre de Dios is worthy of additional exploration. 19. The large Eastern Andean Range is composed of Devonian through Ordovician shales and sandstones which are tightly folded, faulted and metamorphosed to some degree. Granite intrusions are present along the west portion of this geologic province. It is considered to have no oil potential. 20. The Altiplano geologic province is a large graben lying between the Eastern and Western ranges of the Andes. After the drilling of five exploration wells and the recording of about five thousand kilometers of seismic data, this graben is known to contain upwards of 10,000 feet of hard, silicified Tertiary sandstones and shales, which have no hydrocarbon potential. There may be areas within this vast graben where Cretaceous rocks may be buried and may have hydrocarbon potential and in the far northern portion some Permo-Carboniferous rocks may be present in the subsurface. However, based on the information obtained to date, this area must be considered to have very poor to non-existent hydrocarbon potential. However, commercial oil deposits have been formed in basins located in Northern Argentina (CAIMANCITO) and in southern Peru (PIRIN). Exploration History and Anticipated Exploration 21. Hydrocarbon exploration began in Bolivia in the early 1920's when Jersey Standard took a large concession in the Subandino Foothills from about the area of Camiri Field to the Argentine border. This was a continuation of their exploration effort in the same geologic province in Argentina. - 160 - ANNEX 2 Page 5 of 7 22. Their effort consisted entirely of field mapping and exploration drilling. The exact number of exploratory wells that Jersey drilled is not known, but it must have been at least ten, as they discovered a number of small fields after the discovery of the rather large (for Bolivia) Camiri Field in 1927. 23. Jersey continued sporadic exploration in the country during the early 1930's but large discoveries in Venezuela forced their attention there and then political complications, brought on by the Bolivia- Paraguay Chaco War, finally lead to the nationalization of the Jersey concession in 1938. 24. Complete stagnation of the oil industry took place for the next 15 years. The following principal events can be noted: (a) Camiri field discovered 1927 (b) Jersey Standard nationalized 1938 (c) Glenn McCarthy granted concession 1953 (d) Gulf Oil granted a concession 1956 (e) First exploratory well in Santa Cruz Area 1960 (f) Pipeline to Pacific completed 1965 (g) Gulf Oil nationalized 1968 (h) Contracts again led to private companies 1973. 25. As soon as Gulf was granted a concession in 1956, many other private companies entered Bolivia and exploration work began in earnest. However, after the expenditure of much money on seismic and gravity programs, as well as a number of exploration wells, all companies were unsuccessful with the exception of Gulf, who had made a number of discoveries in the Santa Cruz area. These had all been found by using seismic methods and not by using surface geologic studies as had Jersey Standards in their 1920 and 1930 exploration programs. 26. Economic conditions in the world oil markets in the late 19507s and early 1960's were not good, so, as the private companies completed their unsuccessful exploration programs in Bolivia, they released their concessions and withdrew from the country. And, as shortly thereafter, areas with greater potential, such as the North Sea, Iran, Australia and Indonesia, became available for exploration, the private companies lost interest in Bolivia. 27. Gulf continued with their exploration effort at a rather strong pace right up to their being nationalized. However, their early successes at Rio Grande, Colpa, and Caranda in 1960 and 961 were not repeated and reserves were added at a miniscule rate, although a large number of exploration wells and a number of discoveries (all very small) were made. - 161 - ANNEX 2 Page 6 of 7 28. The large increase in gas reserves in 1973 was due to further exploration by YPFB in the Boomerang Hills area. A number of discoveries had been made by Gulf in this area, but as they were dry gas and there was no market for such gas, Gulf did not develop the area. 29. In 1973, the Bolivian Government again opened much of the country for exploration by private companies. Thousands of miles of seismic data was recorded, much of it in the Beni Plains and Altiplano, both of which had been explored only slightly before this effort was made. However, YPFB held in reserve for themselves almost all of the Subandino Foothills Zone from Santa Cruz to the Argentine border and did hold all the Chaco Plains, Boomerang Hills and Santa Cruz area, which were immediately to the east of the Subandino Foothills. 30. On the original exploration contract areas no private companies were successful except for Occidental, which discovered the Tita Field east of Santa Cruz. 31. In 1976, both Occidental and Tesoro obtained contract areas in the Chaco Plains area on portions of that area that had been originally held in reserve by YPFB. It is on these later contract areas that they have made the Porvenir and La Vertiente discoveries, respectively. 32. It would appear that this plain area from Santa Cruz to the Argentine border has fair potential for more gas discoveries, even though many of the structures have already been tested by one or more exploratory wells. This assessment is based on the fact that better seismic techniques have made it possible to map these complicated structures more accurately. Many times it had been found that the original exploration wells were not properly located on the subsurface high at the depth of the objective horizon. 33. The Southern Subandino Foothills, which incudes the area within the foothills from about Camiri southward to Argentina has been fairly well explored and no large discoveries are anticipated. The Santa Cruz Subandino Foothills is the area to the north of Camiri and it continues to the change of direction of this zone to the northwest. This area deserves additional exploratory drilling, but the possibility of finding large fields is low. 34. The Cochabamba Foothills is that area immediately to the northeast of Cochabamba. The potential of this area, after much seismic work and the drilling of five dry exploratory wells, is very poor. 35. The Santa Cruz area, lying between Caranda and Colpa Fields on the north and the El Dorado structure on the south, has been the most prolific producing area in the country. However, it appears to be - 162 - ANNEX 2 Page 7 of 7 almost completely explored so no great increase in reserves is expected. The Boomerang Hills, a dry gas province to the north of Santa Cruz where wetter gas is produced, appears to be less explored and has a greater potential for an increase in reserves. 36. Stratigraphic traps may be present to the north and northeast of Santa Cruz as the entire geologic section thins from both less deposition and erosion toward the Brazilian Shield. There is no way to evaluate the potential of this area, but the chances of such traps developing must be considered poor. 37. The Chaco Plains area, immediately to the east of the Subandino Foothills and extending from the Santa Cruz area to the Argentine border, has the greatest potential for new discoveries. Not only have better seismic techniques made it possible to more accurately delineate the structures in this area, many of which have already been tested by dry holes, but the most recent discoveries, which have found over one trillion cubic feet of gas and 85 million barrels of condensate, were made in this area. These two important facts have made this area the focal point for exploration and only the lack of a large market for gas will slow the exploration effort. Bolivia: Ammonia-Urea: Investment Cost Indicators West Germany 1/ Qatar 2/ Thailand 3/ Bolivia 4/ Bolivia-Brazil 5/ Capacity (1000 tons/year) Ammonia 300 430 375 52.8 300 Urea 510 690 600 80 510 Investment (US$ million) Ammonia Battery Limits 70.8 na 182 na 119.2 Off-Sites 28.4 na 72 na 47.8 Total 99.2 254 167.0 a Urea Battery Limits 31.0 na 120 na 52.2 Off-Sites 25.1 na 20 na 42.3 Total 56.1 140 94.5 Total Investments 155.3 412 394 93.5 261.5 Unit Investment 305 600 1170 510 (US$/ton/year Urea) '1/ Standard Research Institute - 1981 Yearbook. 2/ Qatar Gas Utilization Study - World Bank - May 1981 (Qatar already produces urea--this is additional capacity) 3/ Davy McKee - Thailand Gas Development Plan. 4/ Bolivia: Haldor Topsoe - Preliminary Estimate 1980. Escalated at 10% for 1981. 5/ Mission estimate for a joint venture - plant located in Brazil. Bolivia: Ammonia Urea Complex Financial Analysia - Ammonia 52.8 MTY - Urea 80 MTY (in 1981 US$ million) 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 Production Volume (MTY) 1/ Ammonia 30 39 46 46 46 46 46 46 46 46 46 46 46 46 46 Urea 52 68 80 80 80 60 80 80 80 80 80 80 80 80 80 Sales Volume (4TY) Iport U.ra 46,4 61.8 73.4 72.9 72.4 71.9 71.3 70.7 70.1 69.4 68.6 67.8 67.0 66.0 65.0 Domestic Urea 5.6 6.2 6.6 7.1 7.6 8.1 8.7 9.3 9.9 10.6 11.4 12.2 130 14.0 15.0 Prices (USS/ton) Urea 213 222 232 243 254 265 269 273 277 281 285 290 294 298 303 REVENUES 11.1 15.1 18.6 19.4 20.3 21.2 21.5 21.8 22.2 22.5 22.8 23.2 23.5 23.8 24.2 Investments Fixed Capital 20.6 45.0 27.9 (9.4) Training 2.0 Working Capital 3/ 1.7 0.6 0.5 (2.8) Operating Costs Variable Costs 4/ 7.7 7.9 8.0 8.2 8.3 8.5 8.7 8.9 9.0 9.2 9.4 9,6 9.8 10.0 10.2 (excluding gas) Freight 5/ 2.3 3.1 3.8 3.8 3.8 3.8 3.9 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 TOTAL EXPENDITURES 20.6 45.0 29.9 11.7 11.6 12.3 12.0 12.1 12.3 12.6 12.9 13.0 13.2 13.4 13.6 13.8 14.0 2.0 NET CASH FLOW (20.6) (45.0) (29.9) (0.6) 3.5 6.3 7.4 8.2 8.9 8.9 8.9 9.2 9.3 9.4 9.6 9.7 9.8 22.2 Cam !!guirements: 23,927 (million cubic feet) 6/ 1,077 1,400 1,650 1,650 1,650 1,650 1,650 1,650 1,650 1,650 1,650 1,650 1,650 1,650 1,650 Net Present Value 10% (36.67) Net Value of Cas: (US$36.7 x 106)/23,927 x 106 MCF -'(13 US$/MCP) 11 Operations to start in 1985 at 65% capacity; 1986 at 85% and full capacity thereafter. T/ IBRD projections In constant 1981 prices (Table 8.9) to 1990; thereafter, 1.5% increase per year. 3/ Working capital - 15% of revenues until full capacity is reached. 4/ Includes labor and supervision US$2.0 MM/Y; maintenance 3% of fixed capital; insurance 7.5% of fixed capital; other variable rosts (catalysts, utilities) US$1.5MM. The total is US$7.7 million - escalated at 2% per year. 5/ Freight to Brazil estimated at US$25/ton - escalated 1.5% per year on exportable surplus. Domestic demand assumed to grow at 7% year. 6/ Gas requirements estimated as follows: Raw material 22.6 MCF/ton of ammonia; Fuel 13.3 MCF/ton ammonia; Total 35.9 MCP/ton Aounia. Bolivia: Ammonia - Urea Complex Financial Analysis: Ammonia - 300 MTY; Urea 510 MTY (in 1981 US$ million) 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 Production Volume (1000 tons) Ammonia 1! 195 255 300 300 300 300 300 300 300 300 300 300 300 300 300 Urea 1/ 332 434 510 510 510 510 510 510 510 510 510 510 510 510 510 Sales Volume Urea to Brazil 326.4 427.8 503.4 502.9 502.4 501.9 501.3 500.7 500.1 499.4 498.6 497.8 497.0 496.0 495.0 Urea to Bolivia 2/ 5.6 6.2 6.6 7.1 7.6 8.1 8.7 9.3 9.9 10.6 11.4 12.2 13.0 14.0 15.0 Prices (USS/ton) 3/ Urea 213 222 232 243 254 265 269 273 277 281 285 290 294 298 303 REVENUES 70.7 96.3 118.3 123.9 129.5 135.2 137.2 139.2 141.3 143.3 145.4 147.9 149.9 152.0 154.5 Investment Fixed Capital 4/ 57.6 126.0 77.9 (26.2) Training 5.0 Working Capital 5/ 10.6 3.8 3.3 (17.7) Operating Costs Variable Costs 6/ (excluding gas) 19.3 20.8 22.0 22.5 22.9 23.4 23.9 24.3 24.8 25.3 25.8 26.3 26.9 27.4 28.0 Gas Transport to Brazil 7/ 13.8 18.0 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 Urea Transport to Brazil 8/ 0.2 0.4 0.4 0.4 0.4 0.4 0.4 0.6 0.6 0.6 0.6 0.8 0.8 0.8 1.0 TOTAL EXPENDITURES 57.6 126.0 82.9 43.9 43.0 46.9 44.1 44.5 45.0 45.5 46.1 46.6 47.1 47.6 48.3 48.9 49.4 6.3 NET CASH FLOW (57.6) (126.0) 82.9) 26.8 53.3 71.4 79.8 85.0 90.2 91.7 93.1 94.7 96.2 97.8 99.6 101.0 102.6 148.2 Gas Requirements 9/ 156,165 7,000 9,155 10,770 10,770 10,770 10,770 10,770 10,770 10,770 10,770 10,770 10,770 10,770 10,770 10,770 (million cubic feet) Net Present Value (10% discount) 236.3 Net Value of Gas: US$236.3 x 100/156.2 x 105 MCF - US$ 1.51/MCF 1/ Production volume: 1985: 65% of capacity; 1986: 85%; 100% thereafter. I/ Bolivia's consumption projected to increase at 7% per year. T/ Prices: IBRD projection in constant prices to 1990. Thereafter, 1.5% increase per year. T/ Investment in fixed capital estimated with a localization factor of 1.6. Salvage value of 10% at end of 15 years. 5/ Working capital 15% of revenues until full production capacity is reached. T/ Operating costs: includes labor and supervision: US$4.00 MM/Y; maintenance 3% and insurance 1.5% of fixed capital. Other variable costs (utilities, catalysts and other input) at US$3.70/ton of urea and US$11.66/ton of ammonia). The total sums US$21.2 million escalated at 2% per year. 7/ Assumes that plan is built in Sao Paulo and that the average transport cost is US$1.97/MCF. 8/ Assumes that Bolivian requirements are supplied from Brazil, at a transport cost of US$50/ton escalated at 1.5% per year. 9/ Gas requirements calculated at 35.9 MCF/ton of ammonia. Includes feedstock and energy. Bolivia: Methanol: Investment Cost Indicators Wes German1/ aar 2/ Bolivia / Capacity (1000 tons/year) 160 320 640 693 160 320 InvPntmPntn (ITRA millinn Battery Limits 40.7 64.3 108.2 na Off-Sites 17.1 28.4 49.9 na Total Fixed Capital 57.8 92.7 158.1 358.0 93 150 Unit Investment (US/ton/year) 360 290 250 520 580 470 1/ Stanford Research Institute International. PEP Yearbook 1981. M T/ Qatar - Gas Utilization Study - World Bank 1981. Based on Saudi Arabian Case. 1 3/ Mission Estimate - Assuming localization factor of 1.6. Data compares with Case 3 - Table 12 of World Bank's Report on "Emerging Energy and Chemical Applications of Methanol: Opportunities for Developing Countries" - April 1982. Bolivia: Methanol: Assumptions for Cost Calculations Capacity (1000 tons/year) 320 Investment Cost (Million US$) Fixed Cost 150 Working Capital 8 Construction Period over 4 years - 10%, 30%, 35%, 25% Production Buildup 60%, 80%, 100% Stream Days 330 days Labor Costs (US$ million) 0.8 Overhead (US$ million) 0.7 Maintenance (% of Fixed Capital) 3% Catalysts and Supplies US$5 per ton General, Administration and Marketing (% of Sales) 2% Insurance and Other (% of Fixed Capital) 1% Source: World Bank "Emerging Energy and Chemical Applications of Methanol: Opportunities for Developing Countries", April 1982. - 168- ANNEX4 Page 1 of 2 Technical Assistance Requirements Ministry of Energy and Hydrocarbons (MEH) 1. Consolidation of the energy planning unit and set-up of an Energy Data Bank. 2. Organizational study to strengthen DINE and DNH. 3. Review of the legal framework (laws and regulations) for contracting hydrocarbon prospects with private companies. 4. Design of an energy conservation policy: legal aspects, financial incentives and information campaign. 5. Urban transport study to enhance efficient energy use. 6. Organizational study of YPFB to improve coordination and efficiency of integrated operation. It should include the following aspects: (a) Analysis of the company's organizational structure, functions and objectives of each managerial and operational unit, evaluation of present and future staff requirements, and control systems. (b) Analysis of salary structure and development of a career development program. (c) Set-up of a management information system. (d) Introduction of modern analytical planning and optimization models, including refinery model and an investment model for scheduling development of oil and gas fields. 7. Fixed term productivity expert to induce cost saving measures. 8. Set-up of a conservation advisory group to provide technical assistance to the Bolivian industry in the implementation of energy conservation and conversion projects. Training in energy management techniques. 9. Evaluation of LPG reserves and investment requirements for extract- ing, transporting and distributing LPG. 10. Pre-feasibility study for the use of compressed natural gas (CNG). Empresa Nacional de Electricidad 11. Preparation of a cost manual to uniform cost estimates of power projects and enable valid comparison among alternatives. 12. Study of the national electric tariff level and structure. - 169 - ANANEX 4 Page 2 of 2 13. Organizational study of the electric sector. 14. Formulation of a national rural electrification plan. Ministry of Agriculture 15. Formulation of a reforestation program, including the following specific projects: (a) Intensive reforestation in ORURO for charcoal production. (b) Extension of the reforestation projects in the rural areas of the Altiplano, Chuquisaca and Tarija. (c) Applied research in agro-forestry. (d) Training in forestry management and charcoal production. Special Studies 16. Options increase benefits from international hydrocarbon trade. 17. Evaluation of energy efficiency in sugar plants. Economic analysis of the uses of surplus bagasse including alcohol production. 18. Pre-feasibility study on the use of mineral sulphur for road paving. 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