Report No. 5111-SLU St. Lucia: Issues and Options in the Energy Sector September 1984 Report of the Joint UNDP/Wdd Bank Energy Sector Assessment Program Tnis doumnent has a restricted distribution. Its contents may not be disdosed without authorization from the Govemrnment, the UNDP or the World Bank. . . JOINT UNDP/IWORLD BAJK ENERGY SECTOR ASSESSMENT PROGRAM REPORTS ALREADY ISSUED Country Date Number indonesia November 1981 3543-IND Mauritius December 1981 3510-MAS Kenya Mav 1982 3800-KE Sri Lanka Mav 1982 3792-CE Zimbabwe June 1982 3765-ZIM Haiti June 1982 3672-HA Papua Nev Guinea June i9821 3882-PNG Burundi June 1982 3778-BU Rwanda June 1982 3779-RW Malavi August 1982 3903-MAL BangLadesh October 1982 3873-BD Zambia January 1983 4110-ZA Turkey February 1983 3877-TU Bolivia April 1983 4213-BO Fiii June 1983 4462-FIJ Solomon islands June 1983 4404-SOL SenegaL July 1983 4182-SE Sudan July 1983 4511-SU Uganda July 1983 4453-UG Nigeria August 1983 4440-UNI Nepal August 1983 447"i-NEP Gambia November 1983 4743-GM Peru January 1984 467?-PE Costa Rica januarv 1984 4655-CR Lesotho January 1984 4676-LSO Seychelles January 1984 4693-SEY Niger March 1984 4642-NIR Portugal Anril 1984 4824-PO Morocco March 1984 4157-MOR Ethiopia Julv 1984 4741-ET Botswana August 1984 4998-BT Cape Verde August 1984 5073-CV Gu;ne:a-BRssau August 1984 5083-CUB St. Lucia September 1984 5111-SLU FOR OFFICIAL USE ONLY Report No. 5111-SLU ST. LUCIA ISSUES AND OPTIONS IN THE ENERGY SECTOR SEPTEMBER 1984 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 Bankz This report has a restricted distribution. Its contents may not be disclosed without authorization from the Government, the UNDP or the World Bank. ABSTRACT As a small Caribbean nation of 124,000 inhabitants, St. Lucia faces several energy problems unique to its size and geographical location, many of which depend on developments in the region as a whole. The two major regional problems concern an unnecessarily expensive petroleum supply chain and the need to establish common service arrangements for the electric utility companies. The report also examines country- specific issues pertaining to energy policy, supplies, demand, and insti- tutions. With regard to supply, the report focuses on the development of indigenous energy resources such as geothermal and recommends against taking a piecemeal approach to the projects. ABBREVIAIIONS AND ACRONYMS ACL Air Conditioning and Lighting bbl barrel (159 liters; 35 imperial gallons and 42 US gallons) CAESP Caribbean Alternative Energy Systems Project CARDI Caribbean Agricultural Research and Development Institute CARICOM Caribbean Community and Common Market cc cubic centimeter CCC Castries City Council CDC Commonwealth Development Corporation CDB Caribbean Development Bank CFTC Commonwealth Fund for Technical Cooperation CIDA Canadian International Development Agency c.i.f. cost, insurance and freight CMI Caribbean Meteorological Institute CWA Central Water Authority ECOs Energy Conservation Opportunities f.o.b. free on board GDP Gross Domestic Product GOSL Government of St. Lucia GWh gigawatt hour ha hectares IBRD International Bank for Reconstruction and Development IG Imperial gallon kcal kilocalorie kg kilogram k4m2 square kilometer kV kilovolt kVA kilovolt ampere kVAR kilovolt ampere-reactive kW kilowatt kWh kilowatt hour LPG Liquefied Petroleum Gas LiCELEC St. Lucia Electricity Services m cubic meter ;TIT Ministry of Trade, Industry and Tourism MW megawatt NHES National Household Energy Survey OECS Organization of the Eastern Caribbean States OTEC Ocean Thermal Energy Conversion p.a. per annum PUC Public Utilities Commission R&D Research and Development REAP Regional Energy Action Plan (Caribbean) REDS Renewable Energy Demonstration Station SWER Single Wire Earth Return T&D Transmission and Distribution T&T Trinidad and Tobago toe tonne of oil equivalent tpa tonnes per annum UNDP United Nations Development Program USAID United States Agency for International Development VINLEC St. Vincent Electricity Services CURRENCY QUIVALETS Currency units = Eastern Caribbean dollar (EC$) EC$1.00 = 100 cents = US$0.37 US$1.00 = EC$2.70 ENEGY CONVERSION FACTORS Fuel toe per Physical Unit a/ Petroleum Products (tonnes) b/ LPG 1.08 Gasoline 1.05 Kerosene/Jet Fuel 1.03 Diesel Oil (LDO) 1.02 Electricity (MWh) 3,412 Btu/kWh c/ Biomass Fuels (tonnes) Firewood 0.33-0.35 Coconut Husk/Shell 0.37 Charcoal 0.69 a/ 1 toe = 10 million kcal = 6.61 boe = 39.68 million Btu b/ LPG = 1730 liters/tonne Gasoline = 1357 liters/tonne Kerosene/Jet Fuel = 1229 liters/tonne Diesel (LDO) = 1187 liters/tonne c/ Converted at end use thermal efficiency of 3,412 Btu/kWh. This report is based on the findings of an energy assessment mission that visited St. Lucia in October 1983. The mission team included Messrs. Zia Mian (Mission Chief), Trevor Byer (Power Specialist-CDB), Ernesto Terrado (Biomass and Renewables), Sveinn Einarsson (Geothermal-UNDTCD), Robert Van Duin (Conservation Consultant), and Michael Morrison (Researcher). Secretarial assistance was provided by Mr. Jagdish Lal. The report was discussed with the Government of St. Lucia in Aug'st 1984. TABLE OF CONTENTS Page SUMMARY OF FINDINGS AND RECOMMENDATIONS ................... i Overview .*.* .................... *....................... i Issues in the Petroleum Subsector..0..................O ... ii Issues in Power Sector ....*...................... O-* ... iii Biomass and Renewables ..................... ............... vi Energy Conservation ............. .....*................... vii Investment Implications ......... .... .......... vii I. ENERGY AND THE ECONOMY ....... v......*.. I Country Background.. .......... .......... g ............. 1 Petroleum Import Bill .................................................... 3 Energy Balance ... .......... ............. ....... ........ 3 Energy Demand Projections ............................. 4 II. PETROLEUM o............ 6............ 6 Overview .... .............. * ................. . . .. 6 Demand Projections.............. .....O.............. 8 Petroleum Prices ....... ..................... ......... 9 Dai n Issues ......andMrket.......... ..... ........ .......... 11 Distribution and Marketing ......................*..... .. 12 Petroleum Data Foe.t.... o................................ 14 oII. ELECTRICITY .............. o........... ..................... 15 Supply/Demand ......................................... 15 Electricity Tariffs... ............... ..... ...... ..... . 17 Power nemand Forecasts ...................... ........... . 29 Power Syste m Expansiont .........................0 ...... 22 Power Losses Phase...................... ....O- ...... , 26 Technical Losses ..... 0. ...*.......0................ 27 N on-Te chn ical Losses.... ......... ......... .......... 29 Geothermal Development ......o........... ..*............. 30 Intermediate Phase ........... ... ..O................. 32 Plant Construction .................. ....... ........ 32 Hydropower Development ................o................ . 33 Power Sector Investment Program ....... o....... .......... 34 Electricity Tariffs .......... ..... .......... o.. 35 Institutional Issues ....... ...o....................... 37 IV. OTHER RENEWABLES..o.......... .....o ...................... 40 Biomass .........o......................... -e....... 40 Biomass Issues ...o...... ................. .......... O.. 43 Biogas ......... o......................... o......... 45 Solar Energy ............................. ............. 46 Wind Energy ......... .................. 0 46 Ocean Thermal Energy Conversion (OTEC) .................. 47 Institutional Issues .................................... 47 Page V. ENERGY CONSERVATION ..................... .......... 48 Tourist Sector ......................... so ..... * .............. 48 Commercial and Manufacturing Sectors.. ................. 49 Government Sector......... ................................ 51 Institutional Issues ......... .o...........................soo............ 52 ANNEXES 1. Regional Issues.o..o...o......................... ...........o.o............ 54 A. Petroleum Supply Arrangements ........ o........ .............. 54 B. Comon Services for OECS Utilities ....................... 58 Co Petroleum Pricing. ....... o........ o.o ......... o.* ..... .. 61 2. Preliminary Measures and Investments Proposed in Loss Reduction Program.... o- .... .m......... ... ..... 0-00 62 3. Recent Investigations of St. Lucia's Geothermal R e s o u r c es.. -.. o.....o.. ..o.....o.o... 64 4. Table 1: GDP Trends 1977-1982 (1977 Prices)................ 65 Table 2: Estimation of Fuel Use for Transportation........ 65 Table 3: Estimation of Fuel Use by Vehicle Category-o-o- 66 Table 4: Fuel Consumption by Transport Subsector and Fuel Type ........... ...... ... . e...... 66 Table 5: St. Lucia Electricity Services Limited - Genera- tion Plant Data at December 31, 1982.- ........ . 67 Table 6: Electricity Statistics for Northern System, 1976-1982 .......... . ... . ............ . 68 Table 7: Electricity Statistics for Southern System, 1976-1982 ..... ........................ . 69 Table 8: Electricity Sales, Demand and Generation - 1982 Actual and Forecast (1983-1990) ........o .... 70 Table 9: Probable Electrical System Expansion, 1982-90..... 71 Table 10: Major Energy Consumers in St. Lucia - 1982..... ... 72 MAPS IBRD 17612 St. Lucia Power System IBRD 17800 Eastern Caribbean Refineries and Transportation Routes SUMMARY OF FINDINGS AND RECOMMENDAIIONS Overview 1. St. Lucia, with a population of 124,000 and a Land area of 616 square kilometers, is part of the chain of seven small island countries in the Eastern Caribbean (1.1). 1/ Because of its small size, geographic location, and dependence on foreign trade, several important energy issues are best addressed at a regional level as they depend on develop- ments in the region as a whole. There also are important country-speci- fic issues which need to be considered. Country-Specific Issues 2. The country-specific issues come under four main headings: policy, supplies, demand, and institutions. The policy issues relate to petroleum prices (2.7) and power tariffs (3.53). Major supply issues include fuelwood/charcoal supplies (4.1-4.4), geothermal power develop- ment (3.39-3.45), and hydro power development (3.46-3.50). On the demand side, the mission has identified a number of Energy Conservation Opportu- nities (Chapter V), and the institutional issues carry across all energy subsectors. Regional Issues 3. There are two major issues which should be addressed on a regional basis as they apply equally to all the small island economies in the region. These issues are: (a) the security of petroleum product supplies, tanker size, least- cost freight and transport strategy, and adequacy of storage facilities at the receiving ports (2.11-2.12); and (b) common services arrangements for electric utility companies following the withdrawal (3.58) of the Commonwealth Development Corporation (CDC). 1/ The seven countries of the Eastern Caribbean include Antigua and Barbuda, Dominica, Grenada, Montserrat, St. KCitts-Nevis, St. Lucia, and St. Vincent and the Grenadines. Their populations range from 12,000 in Montserrat to 122,000 in St. Lucia; all of the seven island economies belong to the Organization of Eastern Caribbean States (OECS). Economy 4. Based on export-oriented activities, the economy grew rapidly during the 1970s. GDP growth averaged 7% over the period, peaking at EC$187 million in 1979 (1977 prices). Economic growth stopped in 1980, however, and real GDP declined slightly as a result of Hurricane ALlen (1.4) which adverseLy affected agriculture and, to some extent, tourism. A modest recovery took place in 1981 and 1982 with moderate growth in agriculture and manufacturing balanced against decLines in tourism and construction. The Government development strategy emphasizes tourism, agriculture, and light industry. If the Government's policies are enforced, the economy will recover with the rehabilitation of the banana and coconut industries, further establishment of the light manufacturing industry, and increased earnings from tourism. Energy demand projections in the assessment report are based on a GDP growth rate of 4%Zp.a., as agreed with the Government. 0 5. For commercial energy, St. Lucia relies principally on imported petroleum products which supply 61% of all energy used. Although the country's US$13.8 million petroleum bill is not critical and only con- sumed 17Z of export earnings in 1982, the Government is concerned about the large price increases in recent years and their impact on the economy (1,.5). Issues in the Petroleum Subsector Freight Costs 6. Current petroleum transport costs in the Caribbean region, excluding Jamaica, are estimated to be in excess of US$18 million a year. While LPG represents only about 4Z of volume, it accounts for 25% of total freight costs (2.11). The average freight charged for liquid pro- ducts is estimated at US$2.97/bbl (for LPG, it is about US$15.23/bbl). This compares with an estimated current Worldscale/AFRA freight calcula- tion of US$0.45/bbl (for GeneraL Purpose vessels). The mission's pre- liminary estimates show that freight costs can be reduced by about 20% by developing a least-cost regional transport strategy. A proposal for a regional study to establish the feasibility of a least-cost supplies and transportation option and deveLop specific recommendations is included in Annex 1. The mission discussed this proposal with Esso, Shell, Texaco and Trintoc, who have indicated their willingness to cooperate and pro- vide support for the study. The cost of the proposed study is estimated at US$120,000. The mission recommends that independent consultants be appointed to do the stt'dy to assure an impartial evaluation. - Iii - Petroleum Prices 7. Although the Government has no formal petroleum pricing policy, it follows a sound practice of passing all costs on to the consumer (2.7). However, the relative levels of consumption tax on various pro- ducts do not reflect the relative ex-refinery posting price of each pro- duct. In the long-run, such a practice can lead to distortions in demand mix and investments. The mission recommends that the Government follow a pricing policy which gives realistic signals about the relative supply and distribution costs of each product, and that the long-cerm relative consumer prices continue to reflect this policy (2.8). Currently, the Government lacks the technical capability to evaluate various cost items (2.10). The mission recommends that the Government use the technical assistance which has been arranged on a regional basis (Annex 1-C) to assist in developing internal capabilities in the Government to review various cost items and check the information submitted by the oil industry (a regional advisor, under UNDP financing, started working with the OECS in mid-1984). Issues in Power Sector 8. The national electric utility, St. Lucia Electricity Services (LUCELEC), operates two physically separated systems. A 12 NW network serves the north end (Union power station) of the island and a 4.4 MW system supplies power in the south (Vieux Fort power station). Both systems are entirely diesel-based and jointly supply power to about 16,000 customers (3.1). The major issues in the power sector relate to resources, system losses, the system expansion program, and power sector investments and tariffs. Hydropower 9. A desk study completed in 1982 (3.46) recommends that the hydropower potential of the Millet (120 kW), Vieux Fort (260 ki) and Troumasse (160 kI) Rivers be examined. The mission believes the hydro- power potential of these rivers is limited because of: (a) intensive deforestation and cultivation in watershed areas; (b) low flows during the dry season; and (c) high sedimentation. The mission recommends that stream gauging stations be installed on these three rivers for 2-3 years (total cost about US$45,000) to collect data which will establish their realistic potential. Until the potential is known, no investments should be made in developing the hydropower potential of these three rivers. 10. A small hydropower station on the Soufriere River (50 kW installed capacity) was damaged during a storm in 1977 and taken out of service (3.47). A recent study recommends that the plant be rehabili- tated to operate 24 hours a day 7 days a week. However, there is con- siderable uncertaincy about the average output of the plant (estimated at 34 kW), and investment costs are believed to be high (US$4,000/kW in 1982 - iv - prices). For these reasons the mission considers it uneconomic to rehab- ilitate this station. Geothermal 11. Based on previous work and drilling experience, the mission believes that special priority should be given to the exploration and development of geothermal potential. A four-phase program is needed consisting of preparation, drilling and a feasibility study, as well as project preparation, and construction (3.40). The major issue is the development of a comprehensive financial and technical package for drilling three exploratory wells before activities are initiated. The wells would be 1,500 meters deep and altogether cost about US$5 million, plus US$1 million for consulting support. The drilling phase will be completed by mid-1986. If results are positive, the first 5 MW geother- mal unit could be on-stream by mid-1990, followed by another 5 NW unit in 1991 or 1992. This development could supply about 17% of electricity generation in 1990 and grow to supply about 36Z in 1991. Los Alamos National Laboratories (LANL) completed an evaluation of geothermal resources in April 1984. LANL proposes to develop geothermal resources by 1987 by installing well head turbo-alternator units. In the mission's view, this timetable appears optimistic. The Government may wish to explore possibilities for private sector participation in exploration and development of this resource. Power Losses 12. Technical and non-technical losses (Table 3.9) in both power systems are high; losses in the northern system are 26%, in the southern - 20Z. This is quite an increase over 1982 technical losses, which were 13.5% in the northern system and 11.0Z in the southern system (Table 3.10). The main causes of technical losses are: (a) low power factor; (b) the need to reconduct three northern feeders; (c) the need to upgrade voltage on some feeders; and (d) the need to charge out some distribution transformers. A power loss reduction study is expected to recommend an investment programme of about US$2.6 million (1983 prices) to bring losses down to an economic level. The optimal level for technical losses is about 8% of net generation; this should be achieved by about 1988. Additional analysis is needed to determine the justification for modi- fying the secondary distribution system when the loss reduction program is executed (3.35). 13. Non-technical losses in 1982 are estimated to be 12.0% in the north and 8.6% in the south (3.36). These losses reduced LUCELEG's revenue by about EC$1.7 million p.a. (US$630,000), or roughly five times the company's 1982 net income of EC$343,000 (US$127,000). The main causes of the non-technical losses are: (a) unmetered supplies; (b) theft and tampering; and (c) faulty meters. The proposed loss reduction program is expected to bring these losses down to about 1% by 1988. Preliminary measures and estimated investments to reduce losses are outlined in Annex 2. v Power Forecasts and Expansion Program 14. The mission reviewed the assumptions used by LUCELEC and the Commonwealth Developnent Corporation (CDC) in preparing forecasts of power sales and peak demand. The mission's forecasts reflect the impact of loss reduction and energy conservation programs. Electricity sales on the total system in the country are expected to grow at about 4.7% p.a. becween 1982 and 1990. The effect of reduced non-technical losses (about 5.4 GWh by 1988 on the 1982 base) in increasing sales should be offset by an equivalent reduction (about 4 GWh) in sales to hotels and co the manu- facturing and commercial sectors from a US$2.5 million energy conserva- tion program which has been recommended by the mission. Because of a reduction in technical Losses, power generation should rise more slowly than sales (about 2.6Z p.a. between 1982 and 1990). Peak demand in the north will grow at 4.1% p.a. and in the south at 5% p.a. A new 2.7-MW high speed diesel unit (Union 6) will come on stream in 1984, and a 1-MW skid-mounted unit would be required at Vieux Fort in 1985. The mission recommends that the new 5-MW medium or slow speed diesel 2/ unit (burning fuel oil) to be commissioned in 1987 be located at a new northern site (Cul-de-sac). In addition, the mission believes that the northern and southern systems should be interconnected in 1990 when the Vieux Fort station is phased out at the end of che decade and aLl its units are retired except the skid-mounted unit which would then be transferred to Cul-de-Sac. If geothermal potential is proved, the first 5-MW unit could be brought on stream by mid-1990. By 1991, geothermal could contribute 36X of generation, fuel oil 36%, and diesel oil 28% (3.45). Power Sector Investment and Tariffs 15. The total investment required in the power sector between 1984- 90 - including geothermal exploration (US$6 million) and development of a 5 MW unit (US$10.6 million) - would be about US$30 million (1983 prices). This estimate excludes price and physical contingencies which would be about US$10 million over 1984-90. This level of investment (including contingencies) is about five times LUCELEC's total assets at end 1982. To contribute even 10% of these investment requiremencs (about US$3-4 million), 31 the company would need not only sustained annual tariff increases, but also an equity injection in order to maintain a reasonable debt/equity ratio. 16. Two percent of residential electricity consumers account for 18% of residential eLectricity use, or more than 400 kWh/month. However, 2/ The decision whether to use a slow- or medium-speed unit should be made at the time of evaluating bids. 31 The lower limit refers to the case where the 5-MW geothermaL unit is not commissioned because of unfavorable exploration results; the upper limit assumes che geothermal potential is developed. - vi - all domestic consumers are cross-subsidized by industrial and commercial users. The current level of the industrial tariff is close to the point at which aute-generation for large industrial consumers would become competitive. This would be detrimental to LUCELEC and should be taken into account in setting new tariff levels to chis group. A tariff study based on long run marginal cost (LRMC) has been proposed which will be grant financed under the USAID regional energy project (Caribbean Alternative Energy System Project - CAESP) in mid-1984. The mission supports this study and recommends that it address the issues identified by the assessment mission. Common Services Arrangements 17. There is an urgent need to strengthen the planning, training, technical and financial management capabilities in the regional power utilities, including LUCELEC and St. Vincent Electricity Services (VINLEC). This would become even more important after the Commonwealth Development Corporation (CDC) relinquishes its management and sharehold- ing responsibilities in LUCELEC, VINLEC and the Montserrat utility com- pany, expected to occur at the end of 1984. The incidence of electrical outages and Load shedding has increased in recent years because of finan- cial and technical problems. Tariff increases hove not kept pace with increased costs, so that finance for maintenance programs and development plans has suffered. The mission fully supports the proposed regional study in the Regional Energy Action Plan (REAP) to determine the manage- ment requirements and other common services requirements needed by the small island countries' utilities. The terms of reference for this study are given in Annex I-B. Biomass and Renewables Fuelwood/Charcoal 18. The recently completed national household energy survey (NEES) estimates total charcoal consumption to be about 7,300 tonnes a year and firewood about 8,000 tpa. This implies a total fuelwood demand of 114,000 m3 C2,400 toe) compared to a sustainable yield of probably less than 40,000 m . The deficit is met through cLearing away secondary for- est lands. The mission recommends a two-step approach to deal with this supply problem: (a) establish short-rotation fuelwood plantations, 4/ and (b) improve the management of existing forests. 19. On the supply side, the mission recommends immediate steps to improve the efficiency of carbonization by introducing portable metal kilns and modified earth kilns to charcoal producers. On the demand 4/ For example, leucaena leucocephala. - vii - side, possible testing of 'coal-pots' with improved efficiencies should be explored. There is also a need for analysis on the structure of production, transport, trading and end-use of charcoal and fuelwood and to develop a policy and program to effectively manage the country's forest resources. Energy Conservation 20. The mission surveyed all the major hotels and has identified Energy Conservation Opportanities (ECOs) for air-conditioning and hot water supplies. An investment of US$1.5 million in the hotel sector could reduce electricicy use by 25%, diesel by 25%, and LPG by 40% within three years. The payback periods on air-conditioning vary between 1 year and 2.3 years and for water heating systems between 1.4 and 4.7 years. In the commercial sector, a program is needed to improve air-conditioning and lighting efficiencies; US$750,000 would be needed to achieve a 17% reduction in electricity consumption. However, paybacks are somewhat longer in this sector than in the hotel seccor. The mission estimates that about 8% (4 CGh) of present gross electricity generation could be saved through the conservation programs in the hotel, commercial and manufacturing sectors over the next three years for an investment of about US$2.5 million at the end-use Level. The mission has not attempted to assess the impact of the electricity conservation program in the hotel sector on the power system's peak demand during the evening period. 51 For the conservation measures co be successful, appropriate institutional arrangements would have to be in place. The mission recommends that the St. Lucia Development Bank and other commercial banks be involved in instituting the CDB-financed revolving fund for ECOs. These institutions should be provided with sufficient technical support to implement the program. Investment Implications 21. The major investments required in the power sector over 1984-90 are estimated to be USS30 million in 1983 prices (excluding escalation and contingency which would amount to another US$10 million). They include: 6/ (a) a US$16.6 million program for geothermal exploration and development; (b) installing a fuel oil-fired 5-MW medium speed diesel 51 The impact of electricity conservation in the commercial and industrial sectors is not expected to have an important impact on the system evening peak as may happen in the hotel sector. 6/ The costs of the interconnector are not included and remain to be determined. - viii - unit at US$4.4 million; and (c) a power loss reduction program for US$2.6 million. Additional investment in the energy sector would be needed for conservation (US$2.5 million), a fuelwood program (US$3 million), and regional scudies (US$0.2 million). r. ENERGY AND THE ECONOKY Country Background 1.1 St. Lucia is situated in the Caribbean and has 124,000 inhabitants across its 616 square kiLometers. It attained independence from the United Kingdom in 1979, and is part of the chain of seven small island countries of the Eastern Caribbean (see footnote 1). Because of its small size and geographical position, the important energy issues of St. Lucia can only be addressed at a regional level and, in many cases, depend on developments in the region as a whole. The Eastern Caribbean countries already have cooperated on some common regional economic issues. For example, they share a common monetary system and have established an Inter-Agency Resident Mission (IARM) in Antigua to strengthen institutional capabilities at the regional level. However, the region so far has not developed an organized approach in the field of energy. 1.2 The population of St. Lucia is relatively young and well educated; approximately 65% are under the age of 25, and the literacy rate is over 90%. In recent years, emigration has depLeted the country of skilled manpower and has slowed population growth to about 1.5% a year. 7/ The climate, which is characterized by a wet and dry season, combined with the rich alluvial soil, is well-suited for tropical crops. St. Lucia is a member of the Organization of Eastern Caribbean States (OECS), the Caribbean Community and Common Market (CARICOM), and the Caribbean Development Bank (CDB). 1.3 The economy is small (GDP in 1982 was US$135 million, L982 prices) and open. Exports of goods and services account for 61Z of GDP; imports for 94%. As a result of this trade gap, the 1982 balance of payments deficit on current account was 33Z of GDP. Tourism is the most important source of foreign exchange earnings, providing about half of the total. 8/ The two principal crops, bananas and coconuts, account for 23% of total exports, while the major manufacturing activities (cardboard boxes, clothing and beer) account for 14Z. On the import side, food re- presents 20% of total imports; the fuel bill about IIZ. Any major in- vestment in the economy is reflected in imports of machinery and trans- port equipment, -which in recent years have made up 20% to 30% of total imports. 71 Between 1976 and 1980, the natural population growth (births minus deaths) averaged 2.6%, p.a. 8/ In 1982, earnings from tourism were estimated at US$39.1 million. 1.4 Based on export-oriented activities, the economy grew rapidly during the 1960s and 1970s. 9/ This growth reflected increases in tourism and tourist-related construction, the estabLishment of new light industries, the undertaking of large public sector investment, 10/ and the expansion of agricultural production. Growth ceased in 1980, how- ever. Real GDP rose by only 0.4% as a result of the hurricane which adversely affected agriculture and, to some extent, tourism. Political instability, which resulted from a leadership struggle within the previous Government following independence in 1979, also may have deterred private sector investment. In 1981 and 1982 (Table 1.1), modest growth took place in the agriculture and manufacturing sectors but was balanced against decLines in tourism and construction. Construction had been the fastest growing sector between 1977 and 1981, principally due to post-hurricane rehabilitation and the construction of a transshipment and storage terminal by Hess Oil. 11/ After the Hess Oil terminal was com- pleted in 1982, construction activity fell by 30% despite a school building program and other public sector projects. Table 1.1: GDP TRENDS (1976-82) (1977 prices) Growth (Z p.a.) 1976 1979 1982 1976-79 1979-82 GDP (million EC$) 148.2 186.6 187.4 8.0 0.1 Source: Ministry of Finance, Planning and Statistics. 1.5 Prospects for economic growth in the future will depend mainly on tourism and the demand for agricultural and industrial exports. Im- provements in the balance-of-payments also may be achieved through import substitution in agriculture to reduce the food import bill, increased export earnings from rehabilitation of the banana and coconut industries, further establishment of light industries, and reduced dependency on imported petroleum products. The mission considers a 4Z annual growth in CDP through 1990 to be realistic. 9/ About 7% average yearly growth. 10/ These were mainly infrastructural in nature: port expansion, road rehabilitation, water supply expansion and airport construction. I1/ The terminal, which was built between 1977 and 1982, cost US$180 million and has a crude oil storage capacity of 5.3 million barrels. -3- Petroleum Import Bill 1.6 The petroleum import bill rose from US$5.4 million in 1978 to US$13.8 million in 1982. This reflects large c.i.f. price increases over the period, as the total volume of imports remained virtually unchanged. Although the size of the country's petroleum bill is not yet critical (Table 1.2), the Government is concerned about the large price increases and their impact on the economy. Table 1.2: PETROLEUM IMPORT COST 1978 1982 Petroleum Impo7ts (US$ million c.i.f.) 5.4 13.8 Z of Imports A 6.1 10.8 Z of Exports a 8.4 16.8 a/ Including non-factor services. Source: Economic Memorandum on St. Lucia, IBRD (October 1983). Energy Balance 1.7 The mission has constructed an energy balance for 1982 from a variety of sources (Table 1.4). The total primary energy use in St. Lucia in 1982 was 73,580 toe, of which 40,170 toe were used in final consumption. Per capita final energy use was about 320 kilograms of oil equivalent. Petroleum accounts for 61% of the total primary energy supply (excluding international aviation and bunkers), and nearly 40% of these imports are consumed in the production of electricity (all diesel). Firewood provides 37% and coconut shells 2Z of the remaining primary energy supply. Because of the low conversion efficiency of charcoal pro- duction, traditional fuels account for 22Z of final consumption. The road transport sector is the largest energy user, consuming 46%, followed by households at 31%, industry at 9%, government and other commercial users at 9%, and tourism 5%. 1.8 The country's potential for developing indigenous energy resources in the medium- and longer-term is fairly promising. The two important resources are geothermal and forests. Other potential resources include solar energy for water heating, wind-powered elec- tricity generation, and coconut shells (Chapter IV). Petroleum prospects are considered to be less promising because of the island's volcanic origin, 12/ and there is little hydro potential; the only existing micro- hydro plant (50 kW) was damaged and rendered inoperable by a storm in 1977 (3.47). Energy Demand Projections 1.9 Projections of primary energy demand are shown in Table 1.3. The underlying assumptions are: (a) in the long run, energy demand growth will average just under 3Z per annum; and (b) the major structural change in energy consumption will occur in the power sector where petroleum fuels may be replaced by indigenous geothermal resources. The projection also incorporates the effects of energy conservation programs in the electric power, tourism and commercial sectors. The first 5-MW geo- thermal unit is assumed to come on-stream in mid-1990 and generate some 14 GWh in that year which would represent 17Z of gross power generation. Table 1.3: PROJECTED PRIMARY ENERGY DEMAND ('000 toe) 1982 1985 1990 Petroleum products 50.1 54.2 55.8 Fuelwood 27.3 29.0 32.0 Geothermal power - - 3.7 Total 77.4 83.2 91.5 Z p.a. growth - 2.4 1.9 Source: Mission estimates. 12/ Caribbean Regional Petroleum Exploration Promotion Project, IBRD, 1983. Table 1.4: ST, LUCIA ENERGY BALANCE FOR 1982 I/ ('000 toe) Coconut Fuel Jet Total Total Firewood Residues a/ Charcoal Electricity Oil Gasoline Diesel Kerosene Avgas Fuel LPG Petroleum Energy GROSS SUPPLY Production 27,30 1,21 28.51 Imports 0,35 16,46 23,75 1,08 0937 4,64 3.43 50,08 50,08 Internatlonal Bunkers (0,37) (4,64) (5.01) (5.01) Total Supply 27.30 1.21 0.35 16.46 23.75 1.08 3.43 45.07 7,358 CONVERSION Power Generation 17,50 (17050) Charcoal Production (24,60) (0,22) 24.82 Conversion Losses (19.85) _/ (12,02) d' (31.87) Own Use Losses (0.28) (0.28) ' T & 0 Losses (1.26) (1,26) Net Domestic Consumption 2.70 0,99 4,97 3.94 0.35 16.46 6.25 1,08 3,43 27,57 40,17 SECTORAL CONSLWTION Road Transport: Private 4.94 4.94 4.94 Public 5.44 5,44 5,44 Freight, etc, 6.08 2,07 8.15 8.1S Industry 0.99 e/ 0,28 0.35 1,97 2,32 3.59 Iotels and Restaurants 0.91 - 0.46 0.74 1,20 2,11 Government and Other Coamercial 1.52 t/ 1,75 0.18 1.93 3.45 Household 2,70 4.97 1,23 1,08 2.51 3.59 12.49 !/ Mainly raw shell, b/ Total shell charcoal and wood charcoal. c/ 19.70 thousand toe fuelwood losses + 0,15 thousand toe coconut shell losses, d/ Actual gross thermal goneratlon efficiency of 31,3% used. e Copra drying use. f/ 23S of total sales. g/ Includes the Central Water Authority. h/ Based on household energy surveyo i/ Figures In brackets Indicate negative numbers. Source: Mission estimates. - 6 - II. PETROLEUM Overview 2.1 Between 1979 and 1982, petroleum imports dropped from about 57,000 toe to 50,000 toe, an average decline of 4.1% p.a. (Table 2.1). Excluding international bunkering (avgas and jet fuel), domestic petro- leum consumption declined at 3.9% p.a. The largest decrease was in fuel oil consumption (32.7% p.a.), which is supplied to only two establish- ments: a brewery and a copra plant. The copra company has been experi- encing increasing financial difficulties during the last few years and copra production fell by nearly one-half between 1979 and 1982. Jet fuel also experienced a significant decline between 1979 and 1982 (7.3X p.a.), reflecting a decline in the number of tourists. Table 2.l: PETROLEUM PRODUCT DEMAND, 1979-82 ('000 toe) Z Growtha p.a. - 1979 1980 1981 1982 1979-82 Aviacion Gasoline 0.29 0.36 0.31 0.37 8.5 Jet Fuel 5.83 3.57 5.63 4.64 (7.3) Gasoline 14.95 15.41 15.87 16.46 3.3 Diesel 30.71 27.96 31.66 23.75 (8.2) Fuel Oil 1.15 0.30 0.73 0.35 (32.7) Kerosene 1.24 1.08 1.03 1.08 (5.8 LPG 2.63 2.81 3.02 3.43 9.3 Total 56.85 51.49 58.25 50.08 (4.1) a/ Brackets indicate negative numbers. Scurce: Mission estimates based on Shell, Texaco and Government data. The estimates incLude Esso data up to 1981. 2.2 TabLe 2.2 gives a profile of domestic petroleum use by various economic sectors in 1982. Road transport and power generation together represent 80% of petroleum use, while the direct consumption of petroleum by households is only 8%. Sales to industry, the Government, commerce and hotels (tourism) account for the remaining 12%. 2.3 Currently all the power generated by LUCELEC is diesel-based. In 1982, the company accounted for more than 73% of diesel use, and about 40% of aLl the petroleum supply to the country. While diesel use for power generation grew by ll.9Z p.a. between 1975 and 1979, diesel growth between 1979 and 1982 averaged only 1.1% p.a. This low growth for power demand, coupled with reduced construction activity and the completion of the Hess transshipment terminal (1.4), resulted in a 8.2% p.a. decline in diesel demand. Table 2.2: DOMESTIC PETROLEUM USE BY SECTOR, 1982 ('000 toe) Power Road Government, House- Generation Transport Industry Tourism a/ Commercial holds Total Percent Gasoline - 16.46 - - - - 16.46 37 Diesel 17.50 2.07 i.97 0.46 1.75 - 23.75 53 Fuel Oil - - 0.35 - - - 0.35 1 Kerosene - - - - - 1.08 1.08 2 LPG - - - 0.74 0.18 2.51 3.43 8 Total 17.50 18.53 2.32 1.20 1.93 3.59 45.07 100 Percent 38.8 41.1 5.2 2.7 4.2 8.0 100.0 a/ Hotels and Restaurants. Source: Mission estimates based on oil industry data. 2.4 Data on the number of vehicles in the country are unreliable. However, the mission has estimated that freight accounts for about 44Z of fuel consumption for road transport, while public transport uses 29%, and private vehicles 27% (Annex Table 4). Diesel consumption represented only one quarter of fuel use for freight in 1982. Diesel use appears to be on the decline as a result of the large number of imported pick-up trucks and vans (gasoline-fueled) which are replacing large trucks used in shipping produce to market and to export terminals. 13/ 2.5 Imports of new vehicles have averaged around 900 units p.a. Traditionally, the UK was the major supplier, although by 1982 Japanese 13/ In 1979, over 80% of the banana production was shipped to the ports at Castries and Vieux Fort in large trucks via the Banana Association's boxing plants. In 1982, less than 30% of production went through the Association's boxing plants as a result of an ECC4/lb premium for fruit boxed in the field. Almost all of private growers' produce is moved to port in small pickups, hence the fuel switch from diesel to gasoline in recent years. - 8- imports accounted for 75% of the market (72% of passenger cars, 94X of vans and pick-ups, and 97% of mini-buses). Most of the Japanese vehicles are under 1,800 cc and all are fuel efficient. The public transport system is run by private owners and seems to operate efficiently and effectively. The system consists mainly of mini-buses which average 18- 20 miles per imperial gallon consumed. Although the roads in the country are fairly good, preventacive maintenance on the vehicle fleat and roads could be improved. Annual vehicle inspections, if introduced, should provide improvements in fuel efficiency. A study on energy efficiency will be financed by the Caribbean REAP and terms of reference are currently being developed by CDB and CARICOM (5.9). Demand Projections 2.6 Petroleum demand projections are shown in Table 2.3. In the next three years demand is expected to increase at about 2.7Z p.a., with most of the growth occurring in jet fuel sales from increased inter- national flights. LPG-demand growth is expected to drop from 8.3% p.a. to around 4% p.a. because of energy conservation measures and the sub- stitution of soLar water heaters for LPG-fuelled heaters in the hotel sector. The use of diesel oil is expected to reflect the increase in power generation between 1982-85 and should grow by about 2.7% p.a. However, for the 1985-90 period, important structural changes in the power sector are expected to occur which would significantly reduce the reliance on diesel oil as the primary fuel in this sector. First, in 1987, a new 5-MW fuel oil-fired medium or slow speed diesel unit is expected to be commissioned at the new power station in the north Cul-de- Sac. Second, in mid-1990, the first 5 MW unit of geothermal capacity should be commissioned. These combined effects would mean that by 1990, geothermal and fuel oil-fired power generation would account for about 18% and 39% each of system generation, with diesel oil representing the remaining 43%, compared to 100% in 1986. This would be reduced further in 1991, the first full year of geothermal operation, when geothermal and fuel oil would represent about 36% each of total generation. As a result of these changes, fuel oil consumption should grow from about 300 toe in 1985 to around 7,800 toe in 1990 and diesel oil decline from 25,800 toe in 1985 to about L7,000 toe in 1990. The combined result of these effects is that petroleum demand shouLd increase from 54,200 toe in 1985 to about 55,800 in 1990 (a growth of 0.8% p.a.). This significant decline in the growth rate compared to the 1982-85 period (of 2.7Z p.a.) would arise from the effects of energy conservation and geothermaL power generation. -9- Table 2.3: PETROLEUM DEMAND PROJECTIONS, 1982-90 al … - - - - - - …Projections - - - - - - - - 1985 1990 Actual Growth Growth Product 1982 1982-85 1985-90 ('000 toe) ('000 toe) (Z p.a.) ('000 toe) (Z p.a.) Aviation Gas 0.4 0.4 -- 0.4 -- Jet Fuel 4.6 5.6 6.5 6.2 2.1 Gasoline 16.5 L7.2 1.4 18.9 2.0 Diesel 23.8 25.8 27.0 17.0 (8.0) Fuel Oil 0.4 0.3 (4.6) 7.8 64.4 Kerosene 1.1 1.1 (0.1) 0.9 (2.8) LPG 3.4 3.8 3.1 4.6 4.0 Total 50.1 54.2 2.7 55.8 0.6 a/ Brackets indicate negative numbers. Source: Mission estimates. Petroleum Prices 2.7 The Ministry of Trade, Industry and Tourism (MTIT) is respon- sible for controlling the price of gasoline, diesel Dil, kerosene and LPG. Prices are adjusted in response to requests for increases by the oil industry, subiect to approval by the Cabinet. Although the Govern- ment has no forma_ petroleum pricing policy, it follows a sound practice of passing all costs onto the consumer. All controlled petroleum prod- ucts are taxed, the major component of which is the consumption tax. 14/ The Government has used the consumption tax, set at levels in excess of revenue needs, to absorb short-run changes in the various cost compo- nents. 15/ Annual increases in the retail price of gasoline, kerosene and diesel (Table 2.4) averaged about 1lZ p.a. between 1979 and 1982; LPG price increases have been somewhat higher (14.8% p.a.). In 1982 (an election year), kerosene and diesel prices actually declined, while the gasoline price remained unchanged. In October 1983, the prices of gaso- line (2.0%), kerosene (2.5%), and diesel (1.9%) had all declined, largely in response to downward trends in international petroleum prices. At the same time, the price of LPG (5.7%) had increased. 14/ Ad valorum taxes include a 72 stamp duty and a 2X foreign exchange remittance tax. 15/ This measure was adopted at a time when ex-refinery postings were changing frequently and the government wanted to limit the number of internal price movements. - 10 - Table 2.4: RETAIL PRICES FOR PETROLEUM PRODUCTS, 1979-82 CECS per imperial gallon) Z Growth 1979 1980 1981 1982 p.a. Gasoline 3.68 4.83 5.10 5.10 11.5 Diesel 3.48 4.53 4.90 4.84 11.6 Kerosene 3.21 4.04 4.39 4.36 10.7 LPG 4.08 5.25 5.72 6.18 14.8 Source: Government of St. Lucia. 2.8 To avoid long term distortions in product demand-mix and the future direction of investment, it is important that consumers receive proper signals about the relative availability and prices of petroleum products. At present, the consumption tax on diesel is 36%, on gasoline 26%, while kerosene and LPG taxes are only 9% of c.i.f. values (Table 2.5). These levels of consumption tax should be readjusted to keep relative prices in line with investment and fuel substitution objectives. Table 2.5: PETROLEUM PRODUCTS' PRICE STRUCTURE, OCTOBER 1983 (ECCIIG) Gasoline Diesel Kerosene LPG vi (ECC/IG) (ECC/IG) (ECC/IG) (ECc/lb) f.o.b. 274.08 243.90 266.74 34.81 Freight, Insurance 22.92 22.92 22.92 20.85 c.i.f. Zg7.0 Z66.82 Z289.66 55.66 Consumption Tax 78.27 96.16 26.27 5.00 Stamp Duty 20.79 18.68 20.28 3.90 Foreign Currency Remittance Tax 5.94 5.34 5.79 1.11 Ex-terminal Cost 402.00 WM 42.00U 0567 Marketers' Margin 58.00 58.00 58.00 40.63 Wholesale Price Wm. 45.00 400.00 106.3U - Retailers' Margin 40.00 30.00 25.00 6.00 Recail Price 500.00 4750 425.00 112.30 c a! The LPG mix consists of 80% butane and 20Z propane (4.70 lb/AG). El For a 100 lb bottle. El For a 20 lb bottle. Source: Ministry of Trade, Industry and Tourism. 2.9 Marketers' and retailers' margins are high because of low vol- umes and high allocated expenses. In the mission's view, the cost of - 11 - imports and distribution can be reduced if the internal marketing opera- tions are restructured and a regional petroleum supply procurement/trans- port system is established (2.11). 2.10 The currenc price structure is based on ad-hoc decisions with regard to the various cost elements, and the Government lacks the tech- nical capability to evaluate these cost items. The mission recommends that technical assistance be arranged on a regional basis to assist in developing internal capabilities i.t the Government to review various cost items and check the information that is submitted by che oil industry (Annex 1-C). In mid-1984, a regional advisor was assigned to OECS to perform these tasks. The Government should request his services on a priority basis. Main Issues Petroleum Supplies 2.11 The current pattern of petroleum supply and distribution in the Eastern Caribbean (as in other markets) evolved during the pre-1973 era when oil companies scruggled to obtain a larger share of the petroleum product market. The prime objective of this effort was to achieve an increase in crude oil production by increasing the market share in pro- duct demand. This strategy was adopted because of the high profit mar- gins associated with crude oil production. This situation has changed since 1973, with crude oil production passing to the oil-producing countries. Distribution activities now have to be self-supporting and because the companies continue to share small markets, they have been increasing their margins downstream to remain viable. As a result, the cost of petroleum product handling and transport has increased consid- erably. Although the industry recognizes these developments and has endeavored to reduce the number of firms in each market, it has been unable to tackle the issue of transport on a collective basis. The mis- sion identified tanker size, supply security, and transport of petroleum products as major regional issues in the Caribbean. Currently, ocean transport costs for petroLeum products among all CARICOM countries except Jamaica are estimated to be in excess of US$18 million. LPG cosrs account for about 25% of the total although they represent only 4% of the volume. The freight currently charged by the companies appears to reflect the national cost of moving small cargoes, on a single destina- rion voyage basis, from the point of loading to each of the islands taken separately. The system run by the companies differs from this in that cargoes are moved on a multiple destination voyage basis from the loading point. In this way freight costs to the companies are lowered. An important issue is: what the difference is in freight costs, for small cargoes of the single versus multiple destination operational mode. Second, if are there any economies to be gained by using larger tankers (given port limitations at certain locations), moving larger cargoes to each island, on a multiple destination basis, more infrequently, and - 12 - hence maintaining higher inventories in each island. If there are economies in such a mode, the size of the potential savings should be estimated. In the case of LPG, these issues are particularly critical because current freight costs (US$14/bbl) are about 50% of the f.o.b. price. The mission believes these costs can be brought down by develop- ing a least-cost regional transport and supply strategy and has developed terms-of-reference for such a study. Preliminary estimates indicate that freight costs can be reduced by about 20% by developing an optimum trans- portation strategy. Discussions with Esso and Shell in Barbados; Texaco, Trintoc and the Trinidad & Tobago Government in Trinidad; Shell and Esso in Curacao and Aruba; and with the Governments of St. Lucia and St. Vincent support the mission's recommendation to do a regional studv. The current refining situation in che region makes it worthwhile also to evaluate refining capacity and locations as part of the regional study. However, to expedite commissioning of the study, che mission believes the study should not examine the refinery issues because of the politically sensitive character of this question among some countries of the region. In addition, the study's scope should exclude Jamaica in the north and terminate at French Guyana in the south. The oil industry has offered its full cooperation and support for the mission's proposal for this study (Annex 1). The mission recommends that independent consultants be appointed to do the study to avoid any possible conflict of interest. The study is estimated to cost about US$120,000. 2.12 Trinidad and Tobago (T&T), and Curacao are the two main suppliers of petroleum products. T&T had initiated an oil supply financ- ing facility 16/ to insulate CARICOM trading partners from short-term price increases in petroleum products. However, most of the Eastern Caribbean States have yet to receive financial assistance under this arrangement. The facility was established for a three-year period ending December 31, 1982 and is not expected to be renewed. Presumably, retro- active disbursements would be made to the eligible Eastern Caribbean islands including St. Lucia and St. Vincent in due course. Distribution and Marketing 2.13 Two marketing companies, Shell and Texaco, import refined petroleum products into che country. 17/ Based on Custom data for 1982, 63.7% of energy petroleum products were imporced from T&T, 35.8Z from Curacao, and 0.5% from Venezuela (Table 2.6). SheLl mainLy imports from 16/ The facility which became recroactively effective on January 1, 1980, lasting until December of 1982, would provide Loans (15 years maturity, including 3 years grace at 2% annual interest) to meet the incremental cost of petroleum products over a base price obtained on January 1, 1979. 17/ in August of 1981, Esso withdrew from the market and Shell purchased Lts assecs. - 13 - Curacao, while Texaco uplifts from its Point-a-Pierre refinery in T&T. Shell owns two bulk terminals, one at Castries (formerly owned by Esso) and one at Vieux Fort. Texaco owns a terminal in Castries and buys hos- pitality from Shell for its supplies in the south. The combined storage capacity of the three terminals is estimated to be 42,780 barrels. Al- though at 1982 consumption levels this represents about 50 days supplies and adequately covers the country's needs, the capacity and inventory management situation for individual products should be reviewed as part of the regional supply study (2.11). Products are imported in tankers ranging in size from 700-5,000 tonnes. Texaco operates its own single tanker, and Shell uses a fleet of six chartered tankers. rable 2.6: PETROLEUM IMPORTS BY ORIGIN OF SUPPLY, 1982 a/ Product Trinidad Curacao Venezuela Total (M ) t<] (M (S!) tM ) (') CM3) (S) bl Avgas 369 98.9 5 * 373 0.8 Gasoline 12.493 68.4 5,776 3;.6 18,269 40.0 Kero/Turbo 1,203 99.8 3 0.2 1.206 2.6 Diesolin 14,088 59.2 9,724 40.8 23,812 52.1 Fuel oil 360 100.0 360 0.8 LPG 610 36.2 876 52.0 197 11.8 1,683 3.7 Total c/ 29,123 63.7 16,383 35.8 197 0.5 45.703 100.00 .-/ Volumetric data in this table are not consistent with data in Table 2.1. b/ Percentages show volumetric mix of various products. c/ Percentages are based on volumetric distribution of Products Dy countries. Source: Statistical DeDartment and Cayhem's records, St. Lucia. 2.14 Shell currentLy markets its products directly, while Texaco engages the services of a Local agent. 18/ Products are distributed through 36 retail stacions (IBRD Map No. 17612) and numerous dealer- ships. 19/ The large number of outlets and over-clustering are a legacy of the pre-1973 era and have resulted in low average volumes and hence 18/ Texaco's function has been reduced to operating one bulk terminal, while providing its distributor with about ECc 10/IG (USC3.1IAC) for marketing operations. The marketing is handled by one employee at the agent's general office. 19/ Two new retail outlets, Micoud and Canaries, have been commissioned since January, 1984. - 14 - high average fixed costs. In order to reduce internal marketing costs, the mission recommends an outlet rationalization exercise. Ideally, the Government should consider permitting only one company to operate in St. Lucia. Particularly since prices at all levels are controlled, there is no competition between the two companies, and their joint presence does not appear to enhance the country's security of supply. The concession- aire would be required to consolidate its operations, close some outlets in overly clustered areas, and rationalize office and administrative expenses based on the reduced level of necessary marketing activity. Petroleum Data 2.15 Consistent data on petroleum imports and market sales are not maintained by the Government and they are not readily available anywhere else. The lack of information on petroleum market sales from Esso prior to 1981 also complicated the mission's task in constructing historical demand trends. The mission visited Esso's office in Barbados to obtain historical data, which is included in the analysis. The mission recom- mends that the Ministry of Foreign Affairs, Trade, Industry and Tourism begin collecting relevant volumetric and pricing data on petroleum. The Government should make use of a petroleum pricing specialist as recom- mended in Annex 1-C. The data presented in this assessment report should be refined and upgraded as additional information becomes available. - 15 - III. ELECTRICITY Supply/Demand 3.1 The LUCELEC system consists of two separate networks and has a total of 16,000 customers (1983). The northern system near Castries is supplied by Union power station, the souchern system by Vieux Fort power station. Union, which was commissioned in L971, has an installed capa- city of 12.105 KW (five units: 4 x 2.67 MW and 1 x 1.425 MW). Vieux Fort, commissioned in 1965, has an installed capacity of 4.12 MW (2 x 1.02 MW and 2 x 1.04 MW). All units are diesel-fired (Annex Table 5). 3.2 The northern system is supplied by four feeders originating at Union power station, all operating initially at 11 kV. This distribution system includes about 130 miles of 11 kV lines, 22.5 miles of 6.6 kV lines, 18 miles of Single Wire Earth Return (SWER) 6.35 kV lines, and 2.3 miles of 2.3 kV lines. Total installed transformer capacity is around 28 MVA, with a distribution ratio of 3.5. The system operates at a fre- quency of 50 hertz with secondary distribution at 240 volts single-phase and 416 volts three-phase. 3.3 The southern system is supplied by two 11 kV feeders out of the Vieux Fort pover station. The system consists of 52 miles of 11 kV net- work and 3.5 miles of SWER 6.35 kV lines. Installed cransformer capacity is around 8.3 MVA with a distribution ratio of 3.0. 3.4 Between 1976 and 1982, total generacion grew at an annual rate of 6%, from 14.9 GWh in 1976 to 63.8 GWh in 1982 (Table 3.1). Growth in the north was higher (6.6% p.a.) than in the south (4.1% p.a.). In 1982, the northern system accounted for nearly 80% of generation. Generation fell by 5.3% in L980 because of a hurricane, but rose by 6.0% in 1981 and a further 3.1% in 1982. Although domestic sector sales increased by 7.6% p.a. between 1976 and 1982, total sales grew by 4.5% p.a. The 6% in- crease in relative gross generation is attributed mainly to a significant rise in non-technical losses. 20/ Growth rates for maximum demand in both northern and southern systems are slightly lower than growth in gross generation. In 1982, the load factors were 68.9% for the north and 58.6% for the south. 3.5 Own use averaged 5.1% of gross generation in the north and 4.4% in the south between L976 and 1982. The difference arises because 'office use' is included in the northern data. Own use losses at Union Station in the north have risen in the last two years because of ventila- tion problems in the radiators. Line losses are estimated as the dif- ference between net generation and sales, and therefore consist of both 20/ Faulty metering and power theft. - 16 - technical and non-technical losses. Losses in the north averaged 18% of net generation between 1976 and 1980. However, in the Last two years the situation has worsened, with losses in 1982 representing almost 26% of net generation. Losses in the south averaged 16% between 1976 and 1979. Since the hurricane in 1980, losses have risen to around 20X which is a serious drain on LUCELEC's resources. Action programs are now being implemented which would bring technical and non-technicaL losses down to an acceptable level (3.38). Table 3.1: LUCELEC POWER GENERATION, 1976-82 (GWh) Z Growth 1976 1977 1978 1979 1980 1981 1982 p.a. Northern System 34.4 38.1 43.1 46.3 45.3 48.8 50.4 6.6 Southern System 10.5 11.8 13.5 15.4 13.1 13.1 13.4 4.1 Total 44.9 49.9 56.6 61.7 58.4 61.9 63.8 6.0 Source: St. Lucia Electricity Services. Table 3.2: LUCELEC ELECTRICITY STATISTICS, 1976-82 'GWh) Growth Rate 1976 1978 1980 1982 1976-82 (Z p.a.) Gross Generation 44.9 56.6 58.4 63.8 6.0 Own Use 2.5 2.7 2.7 3.3 4.7 Line Losses 7.1 10.0 9.6 14.7 12.9 Total SaLes 35.2 44.0 46.0 45.8 4.5 Domestic 9.2 11.3 12.1 14.3 7.6 Commercial 19.0 24.2 25.8 24.4 4.3 Industrial 6.3 7.7 7.2 6.1 (0.5) Street Lights 0.7 0.8 1.0 1.0 6.1 Source: St. Lucia Electricity Services. 3.6 Sales to final consumers grew by 4.5% p.a. between 1976 and 1982. 21/ The fastest growth occurred in the domestic sector which averaged 7.6% a year. This growth rate reflects both an increasing number of customers (4.5% p.a.) and higher consumption per consumer (from 21/ 4.7% p.a. in the north and 3.9% p.a. in the south. - 17 - 841 kWh per household in 1976 to 999 kWh per household in 1982, or a 2.9% growth rate). Growth in commercial sales averaged 4.3%, and in 1982 ac- counted for 53% of total sales. Eight hotels made up almost half of commercial sales, principally for air-conditioning. Industrial sales dropped by nearly 20% in 1982 with the closing of several large enter- prises in the south. The Central Water Authority accounts for abouts40l of industrial sales, and another 30X is divided among a brewery, a card- board box manufacturer, and plastic bottle manufacturer. Between 1976 and 1979 when the country experienced rapid economic growth, the ratio of the growth rates of electricity sales to GDP was 1.51. This ratio became negative between 1979-82 when GDP fell off and _ales contracted. Electricity Tariffs 3.7 Over the 1976-82 period, LUCELEC's fuel cost 22/ increased by 17.91 p.a., from EC$1.29 per imperial gallon to EC$3.47. The major increases occurred between 1978 and 1980 when petroleum import cosrs more than doubled. The share of fuel in operating expenses increased from 51% to 64% between 1976 and 1982. However, LUCELEC was able to offset esca- lating operating costs with periodic tariff increases (Table 3.3), except in 1980 and 1981 when losses were incurred. Nevertheless, tariff increases were not sufficient to keep the company in a healthy financial condition. By 1982 retained earnings had dropped to about 40% of their 1979 level. Table 3.3: LUCELEC OPERATING EXPENSES AND AVERAGE REVENUES (ECC/kWh) Operating Expenses Average Revenue 1976 19.4 19.5 1977 20.4 21.9 1978 20.9 21.6 1979 26.7 26.7 1980 37.1 36.7 1981 44.8 43.7 1982 48.5 49.3 Z increase p.a. 16.5 16.7 Source: St. Lucia Electricity Services. 3.8 Tariffs are uniform in both the northern and southern systems. The Public Utilities Commission (PUC) was established in 1973 to indepen- dentLy regulate and restructure tariffs. In order to claim an increase, LUCELEC first must publish an advertisement in a newspaper at Least 28 22/ Fuel consumed by LUCELEC is noE subject to consumption tax. - 18 - days before submitting a claim. Public hearings then are arranged by the PUC where interested parties may state their objections before increases are allowed. The tariff structure for LUCELEC (Table 3.4) distinguishes between four consumer categories: domestic, commercial, industrial and street lighting. The domestic tariff consists of a minimum monthly charge of EC$5.0, a first block rate of EC$0.20/kWh for the first 180 kWh each month, and EC$0.21/kWh for alL additional units. Commercial users (including the Government) pay a minimum monthly charge of EC$25.00, EC$0.50/kWh for the first 75 kWh and EC$0.237/kWh for all additional units. The Government pays EC$0.365/kWh for electricity used for street lighting and enjoys a 1OX discount on all its bills. Industrial con- sumers pay a fixed monthly charge of EC$100 with all units costing EC$0.232/kWh. They also have to pay EC$5.00 per kW of instaLled capacity of electrical equipment. 3.9 In 1974, a fuel surcharge was introduced to meet the rapid increases in fuel costs. This surcharge is calculated on a per kWh basis by dividing the total cost of fuel in that month over the basic price (EC$0.2977 per imperial gailon) by the total number of kWh sold per month. In 1983 this surcharge averaged EC$0.25 per kWh. It should be noted that although several large consumers are primary metered, this is not reflected in their tariff, and the energy charge to industrial users is 10-15% higher than that to domestic consumers. These charges bear no relation to the long-run marginal costs (LRMC) of supply to different consumer categories. Another important issue identified by the mission was that some large industrial electricity users concerned about the level of the industrial tariff are considering purchasing their own diesel units for self-generation. The present level of this tariff appears to be close to the point where autogeneration could become cheaper for these large users. The consequences of any significant move in this direction would be quite serious for LUCELEC, so it is essential that this issue be assessed by LUCELEC and the PUC. 3.10 Industrial and commercial consumers are cross-subsidizing the domestic users. Table 3.5 shows that only 2% of residential customers use more than 400 kWh/month aLthough they account for 18% of total resi- dential electricity use. However, there is little basis for extending a subsidy to all domestic consumption. Indeed on equity grounds it would be justified onLy for the lowest income and consumption group where monthly use wouLd seldom exceed 25 kWh. Far fewer distortions are introduced into the tariff if the cross-subsidy to this group is provided from the larger domestic consumers rather than the productive industrial and commercial users, thereby avoiding distortions in the productive sector's input prices. Given the skewed character of residential. elec- tricity use, a ECC2/kWh reduction in the tariff for all domestic con- sumption between 0-25 kWh/month could be recovered, for example, by a ECC3/kWh surcharge on those 2Z of consumers using more than 400 kWh/month. - 19 - Table 3.4: LUCELEC ELECTRICITY TARIFFS a/ (October 1983) Category Monthly Charge (ECS/kWh) Domestic Minimum charge (0-25 units) 5.00 Block 1 0-180 units 0.20 Block if Above 180 units 0.21 Conmercial Minimum charge (0-50 units) 25.00 Block 1 0-75 units 0.50 Block II Above 75 units 0,237 Industrial Minimum charge ;0i.°° All units energy cnarge 0.232 Demand charge o/ 3.00/kW Street Lignting All units 0.365 a! Excludes fuel surcnarge, wnich in 1983 averaged ECf25/kWh. b/ Based on the installed horseDower rating of connected motors and appliances. Table 3.5: LUCELEC - STRUCTURE OF DOMESTIC ELECTRICITY MONTHLY USE, 1983 Consumption Range Number of Total Monthly Monthly Average Consumption Per Month Customers Consumption Per Customer (kWh) ('000 kWh) (kWh) 0 - !00 '0,277 431.8 42 101 - 200 3,113 421.4 135 201 - 300 733 177.9 243 301 - 400 249 85.7 344 401 - 500 124 55.9 451 501 - t,O00 i153 101.0 660 Above 1,001 55 82.5 1,499 Power Demand Forecasts 3.11 After reviewing the underlying assumptions of energy sales and peak demand used by LUCELEC and the CDC, the mission has developed inde- pendent estimates of future sales, generation and demand (1983-90). The mission's forecast was developed in three steps: - 20 - (a) a base case 23/ with losses at current levels and no new energy conservation measures to be implemented at the end-user leveL; (b) adjusting billed sales upwards to reflect a reduction in non- technical losses resulting from the power loss reduction pro- gram and downwards to include the impact of a major energy conservation programme in the hotel, commercial and manu- facturing 24/ sectors; and, (c) reducing power demand and generation to reflect the effects of reduced technical losses. 3.12 The comparison of the mission's and LUCELEC's forecasts of electricity demand is shown in Table 3.6. The forecasts are in broad agreement, the di'ferences largely reflecting different assumptions about the rate of impact of the loss reduction and energy conservation pro- grams. The mission predicts sales growth for the northern and southern systems between 1982 and 1990 to be 4.4Z and 5.7% p.a., respectively, with total sales increasing at 4.7% p.a. Interconnection of the two systems is expected to occur in 1990 when total sales are projected to be 66 CWh. Table 3.6: ELECTRICITY SALES PROJECTIONS, 1983-90 (GWh) Actual Growth 1982 1983 1985 1987 1990 (% p.a.) mission NoHrth 35.5 38.3 41.6 44.3 50.0 4.4 South 10.3 11.5 12.5 13.5 16.0 5.7 Total 45.8 49.8 54.1 57.8 66.0 4.7 LUCELEC MfB787 45.8 48.3 53.2 58.6 - 5.1 Source: Mission estimates and LUCELEC. 3.13 A high level of electrical own-use on the northern system is expected to remain until 1985, after -which it should revert to the normal 5.4% of gross generation. This increase (about one-third over the last two years) is due to ventilation problems in the radiators on four of the units at the Union Station. Deposits on these radiators affect the 23/ Underlying this scenario was an assumed 4% p.a. growth rate in CDP. 24/ This is expected to amount to 4 GWh (about 5.5% of gross generation) at the end-use level by 1987. - 21 - capability of the station to handle the current peak load. To avoid overheating on hot days, these units have to operate at 400 kW below their normal output level of 2,600 kW. Therefore, an additional unit has to be brought on-line to meet demand and this increases auxiliary power use. Extensive cleaning and maintenance is needed to overcome this problem, but, because of reserve capacity restrictions, this cannot be undertaken until the new diesel unit (Union No. 6) is commissioned in late 1984. This problem wiLL cause a generation loss in 1983 and 1984 of about US$100,000. 3.14 Total generation is projected by the mission to rise at only 1.71 p.a. between 1982 and 1987 and at 4.2% p.a. between 1987 and 1990 (Table 3.7). The lower growth in che medium-term reflects the reduction in technical losses arising from the loss reduction program. Table 3.7: ELECTRICITY GENERATION PROJECTIONS, 1983-90 (CWh) Actual Growth 1982 1983 1985 1987 1990 (Z p.a.) Mission North 50.4 53.7 54.2 53.7 - South 13.4 14.2 15.0 15.7 - Interconnected - - - - 78.4 Total 63.8 67.9 69.2 69.4 78.4 2.6 LUCELEC 63.8 65.0 67.8 72.2 - 2.5 source: Mission estimates and LUCELEC. 3.15 LUCELEC's projections of peak demand for both the northern and southern systems are based on 3% p.a. increases between 1982 and 1987 (Table 3.8). The mission estimates that peak demand in che north will increase at 3.7% p.a. and in the south by 5.4% p.a. 25/ The effect of reduced technical Losses in slowing the growth rate of peak demand has been included in the mission's forecasts. However, the energy conserva- tion program at the end-use level is assumed to have only a small impact 25/ At the time of the mission (October 1983), the northern system registered a peak of 8,800 kW, about 5.4% above the 1982 level. Since the traditional peak month is December, it is likely that the 1983 peak would have exceeded the October level (i.e., was 8,900 kW in December, 1983). - 22 - on system peak demand because the commercial and industrial sectors are not major contributors to the evening peak. Any impact it would have on peak demand would arise largely from the hoteL sector. Table 3.8: PEAK DEMAND FORECASTS, 1983-90 (MW) Actual Growth 1982 1983 1985 1987 l990 (Z p.a.) Mission estimates North 8.35 8.90 9.40 10.00 11.50 4.1 South 2.62 2.83 3.10 3.40 3.87 5.0 LUCELEC esimates Worth 8.35 8.60 9.12 9.68 -- 3.0 South 2.62 2.75 2.92 3.04 -- 3.0 Source: Mission estimaces and LUCELEC. Power System Expansion 3.16 In 1980/81, CDB financed a generation expansion study. Al- though the study focused mainly on the 1981-86 period, plant requirements for the years 1981-90 also were evaluated. The generation plant types considered were diesel fueled high-speed four stroke, two stroke low- speed, and four stroke medium speed diesel units (residual fuel oil based). 26/ The expansion program recommended by this study was based on high demand forecasts. For example, peak demand on the northern and southern systems in 1986 was anticipated to be about 50% and 75Z above current estimates. The actual sequence and sizing of plant additions advocated in this study therefore must be reviewed, though the plant types seLected remain valid. 3.17 To develop a revised system expansion plan (1983-1990) based on the mission's demand and sales forecasts, the following issues and con- straints should be recognized: (a) Capacity constraint. The system is capacity- rather than energy-limited, with new plant additions being timed to cover peak demand rather than energy growth. 26/ Other conventional plant types such as steam, gas turbines and combined cycle units were excluded because of the better efficiencies of the diesel engine in the required unit size range. - 23 - (b) On-stream date of geothermal power. The prospects of economic geothermal power production appear good; the main issue is the timing of the first unit. Given the lead times involved for packaging and implementing an appropriate exploration and development program, the mission believes the first geothermal unit could be commissioned by mid-1990 (5 MW). (c) Vieux Fort power station (south). This station, located in the port area, is surrounded by buildings with no open land left for expansion in the station compound. No further major expan- sion can be undertaken at this site except for the addition of a small skid-mounted unit in 1985. (d) Union power station (north). There is sufficient land for the addition of one more unit (No. 6). Beyond this a new site would be required. (e) Retirement of plant at Vieux Fort station. The four diesel units at this station are due to be retired between 1987 and 1991 when they would have completed about 100,000 hours of operation (Annex 4, Table 5). Provided that spare parts are still available and maintenance costs have not become unten- able, closure of this station could be delayed until about 1990 when the two systems are interconnected and geothermal power becomes available. (f) Retirement of plant at Union power station. Units 2 and 3 (2,670 kW each) are due to be retired in 1990 when they would have run for 100,000 hours. The retirement schedule of these units could also be delayed, subject to the conditions in (e) above, until the second geothermal unit comes on-stream in the early 1990s. 3.18 The mission has not included wind-generated electricity in the system expansion plan to 1990. Some time will be-needed to assess the technical and economic performance of an interconnected wind farm. Such a farm is proposed for an island in the Eastern Caribbean by 1986. The pricing issues related to power sales from an interconnected wind farm are also to be resolved. It is unlikely that these could be accomplished before the late 1980s. The CMI resource survey has identified some sites in St. Lucia with good wind regimes and it is likely that wind could be a reliable source for a small system. 3.19 To meet the demand in the south, a 1,000 kW skid-mounted diesel unit is likely to be needed in 1985/86. This would be the last unit which could be added at the existing Vieux Fort Station site. The expan- sion issues between 1986-1990 are complex because of the following factors: (a) the northern system will need new capacity in 1987, which will require a new power station; - 24 - (b) both the northern and southern systems will call for additional plants in 199o. This corresponds to the time when units 2-4 at Vieux Fort station will face retirement as well as units 2 and 3 at Union station; (c) the timing and cost of interconnecting the two systems; and (d) a "yes or no" decision concerning geothermal development cannot be expected before 1986 (assuming the geothermal drilling pro- gramme has been completed and evaluated). 3.20 Regarding the first issue, since the first unit of the new thermal power station must oe commissioned by 1987 to meet demand in the north, a site must be selected by late 1984. Two possible locations have been identified for this station: a new site at Vieux Fort (south) and one at Cul-de-Sac (north). The development costs of the Cul-de-Sac site exceed those of the new site at Vieux Fort by about EC$750,000 (1983 prices). This cost disadvantage is offset by three factors: (a) the southern location will require the interconnection of two systems by 1987 and cost US$4.1 million (1983 prices). This interconnection shouLd be delayed until 1990. (3.22 and Annex 5); (b) the southern location would result in the need to transfer to the northern system roughly three times more energy a year than would occur for a northern site. The costs of transmission losses would be about EC$0.2 million p.a. lower for the northern than the southern site; and (c) in the event of transmission line failure (possibly twice a year) the net economic losses would be Larger for a southern location because the scale of economic activity in the north is larger tban in the south. 3.21 The mission concurs with the findings nf the 1980/81 generation expansion study tha: the new thermal station shouid be located at Cul-de- Sac in the north and that the new capacity should be based on either medium- or slow-speed diesel 27/ units with residual fuel oil. The choice of unit type would be made at the time of evaluating bids for both 27/ About US$450,000 a year in fuel costs couid be saved by using a medium-speed fuel oil-fired diesel unit with a base load of 4 MW over a high-speed diesel powered unit of a similar size and base load. The investment cost of the medium-speed fuel oil-fired unit would be about US$250/kW higher than the high-speed diesel unit (1983 prices). The investment cost of slow speed diesels is about 70X higher than that of medium speed diesels; the benefit of the slow speed diesel is its considerably lower forced outage rate. - 25 - types of pLant. In selecting the unit size, the objectives to balance are: maximizing savings in fuel cost and maximizing system security. In 1983 the peak and base loads on the northern system were 8.9 and 4.6 MW, respectively; they are projected to grow to 10.0 and 5.2 MW in 1987. The unit size on the northera system by 1987 should not exceed 5 MW. Analy- sis should be done to determine the optimum size for the northern system over the 1987-90 period. The analysis should be based on the lower de- mand forecasts as compared to those used in the 1980/81 generation study. 3.22 The issue of interconnecting ti two systems involves one of timing, i.e., whether to do it in 1987, or in 1990 closer to when the Vieux Fort station is de-commissioned and new capacity needs to be added to meet demand on both systems. There are several benefits to be had from interconnection: (a) reduced overhead costs in operating the Vieux Fort station if such interconnection leads to closure. Fixed operating costs at this station amount to about EC$100,000/a year; (b) economies of scale resulting from the utilization of larger generation units since system size would increase by about 30%; Cc) allowance for lower cost fuel generators in meeting the base load on the entire system. 3.23 In 1983, the peak and base loads on the southern system were 2.8 and 1.3 MW, respectively. These are expected to rise to some 3.4 and 1.7 MW each by 1987. To benefit from interconnection in 1987, the size of the Cul-de-Sac No. 1 unit would have to be about 7 MW, or about 50% of peak demand on the combined system. This would lower the cost of fuel to meet the southern base load demand. 3.24 A preliminary study conducted for St. Lucia estimates the length of 69-kv wood-poLe interconnection line between Cul-de-Sac and Vieux Fort to be 80 km. The cost of this interconnection is estimated at US$4.1 million (1983 prices). In the mission's view, the technical optimization, timing and investment cost of the interconnection should be reevaluated. A leasr-cost power study is also needed. Such a study would: (a) establish the optimal sequence, sizing and types of new generating plants (geothermal, slow or medium speed diesels) to meet demand; (b) review progress in the power loss reduction programme and its targets; (c) determine a schedule for retiring relevant units at Union and Vieux Fort power stations and for closing the Vieux Fort power station; - 26 - (d) develop a forecast of sales, demand, generation and losses; Ce) establish the routing, voltage level and operating charac- teristics of the incerconnector; and (f) prepare an investment programme for the optimal expansion scheme. 3.25 A 5-ffW medium- or sLow-speed diesel unit in 1987 at the new Cul-de-Sec station could cover peak demand requirements on the northern system up to 1990 (Annex Table 9). The precise nature of capacity addi- tions in 1990 would be determined by the least-cost expansion study. The mission has assumed, however, that the first geothermal unit (5 MW) would be commissioned by mid-1990 to do base load duty on the interconnected system. If the geothermal exploration programme proves unsuccessful, then a second 5-MW medium- or slow-speed diesel unit would have to be added at Cul-de-Sac in that year. In either case, the retirement of units 3 and 4 at the Vieux Fort station could be undertaken in 1990, with unit 1 being retired in 1991 when the station is closed and the 1 .W skid-mounted unit is transferred to Cul-de-Sac. Power Losses 3.26 Between 1975 and 1982, losses on both the northern and southern systems have shown an upward trend (Table 3.9). Table 3.9: POWER SYSTEM LOSSES, 1975-86 Cex-p-res-s-eaas a percentage of net generation) 1975 1976 1977 1978 1979 1980 1981 1982 North 17.5 17.0 18.3 18.9 16.1 20.1 22.5 25.5. South 18.3 16.3 16.8 17.0 14.9 7.5 21.2 19.6 Source: LUCELEC. 3.27 The low level of losses for the South in 1980, are an anomaly. In this year, a hurricane caused severe damage to distribution lines so supply was restricted to only those customers who were cLose to the Vieux Fort power station. This brought both the technical and non-technical losses down to the artifically low level of 7.5%. After 1980, losses increased significantly on boch systems; in 1982, they amounted to 25.5% of net generation in the north and 19.6% in the south. These increases are partly attributed to the damage caused by the hurricane. 3.28 Meters were among the items of physical plant which were affected. Some were complecely destroyed, while others were rendered inaccurate by water ingress. As a result of a meter shortage immediately - 27 - after the hurricane, some customers were given direct connections in order to restore supply quickly. Rowever, chis has since been rectified. 3.29 The need to reduce losses was addressed by a power loss reduc- tion study 28/ conducted in 1983. The objectives of the study were to: (a) identify and isolate the technical loss centers on the trans- mission and distribution systems; (b) estimate the levels and types of technical losses on the system and recommend measures to bring such losses down to an economic Level; (c) formulate a program of measures and standards to monitor and improve both technical and non-technical losses; (d) develop an investment program needed to bring losses down to an economic level; and (e) evaluate the financial benefits to LUCELEC and the economic benefits to St. Lucia of implementing the recommended program. Technical Losses 3.30 During the course of the loss reduction study a series of mea- surements were taken. With the aid of a portable microprocessor, 29/ technical losses on the northern and southern systems were estimated (Table 3.10). In addition, analysis is underway to determine optimum loss levels for both systems. Table 3.10 shows that the most significant technical losses on both systems occur in the primary and secondary dis- tribution systems. Total technical losses in the north are estimated at 13.5Z of net generation and in rhe south at 11.0%. These levels of losses are excessive for a system of this size and design. The optimum levels should be around 7-9%. 3.31 Power Factor. The system power factor on both the northern and southern systems was found co be lower than optimum. In the north, the power factor at the station busbars ranges from a low of 70% during low demand periods (midnight to 6:00 a.m.) to a high of 80% at peak periods (6:00 p.m. - 10:00 p.m.). This improvement in power factor with the evening peak is indicative of the effect of incandescant lighting on the evening. load, while the low power factor during the day is due to the 28/ Final report: "Report on Power Loss Reduction Study for LUCELEC" was completed in July, 1984, and financed by the CARICOM Secretariat under the CAESP. 29/ The software package was developed by Scott & Scott, Inc. of Missouri, USA. - 28 - influence of air-conditioning Loads. In the south, the power factors are somewhat better but still low. For example, in the mid-morning period it is abouc 72% at the station busbars, rising to 85% during the evening peak. Table 3.10: MAJOR SOURCES OF TECHNICAL LOSSES (X of net generation) Technical Loss Component North South Primary Feeders 6.5% 4.0% Distribution Transformers 2.0% 2.0% Secondary Systems 5.0X 5.0% Total 13.5% 11.0% 3.32 There are no capacitors on either the northern or southern sys- tems. LUCELEC's management is well aware of the need for reactive power planning and about 1,000 kVAR of fixed capacitors were installed by March, 1984, with a further 2,400 kVAR to be done by end 1984. The instaLlation of 4,650 kVAR of fixed capacitor banks on the four northern feeders and some 750 kVAR on the two southern feeders at a cost of US$60,000 would lower demand losses at peak by about 300 kW (equivalent to about eight months of forecast demand growth on the combined systems) and reduce energy Losses by about 1.2 GWh p.a. The annual savings from lower peak demand and energy losses would be about US$156,000. 3.33 Primary Feeders. Some sections of feeders 1, 2 and 3 in the north require capacicor additions and reconductoring. In the case of feeder 1, for example, about 90% of the total peak losses occurs in the first five sections (a distance of about 4.3 miles). Reconductoring of feeder 1 and 2 are in progress. Feeder 1 is estimated to cost about US$95,000, feeder 2 about US$70,000, and feeder 3 about US$170,000. 3.34 Voltage Upgrading and Distribution Transformers. Sections of Feeder 2 are energized at 2.3 kV; upgrading to 11 kV and replacing some transformers would reduce losses on this feeder at an investment cost of about US$100,000. In the case of distribution transformers, those on the LUCELEC system range from 5 kVA to 1,000 kVA in size and all have high impedances of between 4-5Z as well as high copper and iron losses. The investment required to replace the heavily loaded transformers with those operating at lower Loss levels is estimated to be about US$250,000. 3.35 Secondary Distribution Systems. The issue of standards needs to be examined and escablished when the loss reduction program is executed. - 29 - Non-Technical Losses 3.36 Non-technical losses are implied to be 12.0% of net generation in the north and 8.6% in che south. This level of non-technical losses amounced to about EC$1.5 million in foregone income to LUCELEC in 1982 compared to a net income in that year of some EC$343,O00. The company is currently pursuing an aggressive programma to capture this foregone revenue. The non-technical losses result from several factors: (a) un- metered supplies; (b) inaccurate metering because of improper installa- tion and defects or willful attempts to defraud; and (c) unread or improperly read meters. Most of the meters are bottom connected, well- mounted types which are more difficult to seal than plug-in socker meters. Many of them are old (15% are more than 30 years old). In March, 1983, a meter inspection and sealing programme was initiated, and a meter-testing workshop began functioning in July 1983. The results of the first chree months of this program 30/ are summarized in Table 3.11. Table 3.11: RESULTS OF METER INSPECTION PROGRAM, 1983 (first three months) Number Number Number Number Number of Meters Not with Links of Direct with Discs Examined Working Removed Connections Displaced North 3,225 188 246 118 82 South 1,690 54 49 27 20 Total 4,915 242 295 145 102 3.37 Defects in the meters were found at 16% of the locations examined. This escimate represents a lower limit of actual defects since che examiners relied solely on visual observation and made no checks on the accuracy of meters which appeared to be in good working order. This initial survey covered mainly Low demand residential consumers, so that the impact of rectifying defects would not be as significant as for com- mercial and industrial consumers. A further survey was done during the loss reduction study covering 40 large users in the south and 82 in the north. On the southern system, 23% of the meters checked were found to be defective and responsible for losses amounting to some 0.6% of net generation. In the north, about 29Z of the metering locations had some form of defect giving rise to identified losses of 1.9% of net genera- tion. Clearly, intensification of this program of meter testing and in- spection will go a long way toward reducing non-technical losses. 30/ The number of meters inspected in this program represented about one quarter of che total number on the system. - 30 - 3.38 Based on the provisional program of measures and investments proposed in the loss reduction study, LUCELEC should achieve significant reductions in losses (Table 3.12). The consultants' final report, was completed in July, 1984, and shows that the optimum technical losses on the northern and southern sytems were 9Z and 7%, respectively, and that non-technical losses should be reduced to 2%. The targets are shown in TabLe 3.12, and che investments needed to achieve this totaL about EC$7.0 million. Annex 2 outlines additional measures to reduce technical and non-technical losses over and above those summarized here. Table 3.12: PROJECTED REDUCTION IN BOTH TECHNICAL AND NON-TECHNICAL LOSSES (Z of net generation) 1982 1983 L984 1985 1986 1987 1988 (Actual) Technical Losses Nort-h 14.7 14.7 14.0 13.0 12.0 10.0 8.0 South 12.2 12.2 11.5 11.0 10.0 9.0 8.0 Non-Technical Losses North 10.8 8.0 7.0 6.0 4.0 2 0 1a 0 South 7.4 4.0 3.0 2.0 2.0 1:0 a 1:0 a a/ Based on the resuLts shown in the final report (Loss Reduction Study, 1984) a leveL close to 2% is more likely to be achievable. Ceothermal Development 3.39 The volcanic origin of St. Lucia makes it a natural candidate for potential geothermal resources. The major geothermal manifestation on St. Lucia is within the Qualibou-Caldera, east of the town of Soufriere on the southwestern coast. This prospect has been drilled, investigated and studied by various consultants and specialists CAnnex 3). The studies indicate a deep-brine holding reservoir with temperatures in the range of 200-250°C, and possibly as high as 350°C, deeper than 1,000 meters below the surface. Exploratory drilling into this reservoir is now required, and there is general agreement that at Least three production size expLoratory wells should be drilled to a depth of 1,500 meters. Future developmencs depend on the results of this drilling. However, all the studies seem to agree on a geothermal poten- tial in excess of 10 MW. The mission believes that the exploratory drilling program could start in late 1984 if adequate financing can be identified and firmed up before then. If successful, this would allow a geothermal generation plant to come on-stream by 1990. 3.40 A four-phased program is needed to develop the administrative, financial and technical aspeccs of the Soufriere geothermal field. The major activity at the preparation phase is to develop, provide and co- ordinate a financing package for an appropriate exploration program - 31 - involving three 1,500 meter wells. This phase could be started even after the receipt of the evaluation report by Los Alomos Laboratory which was financed by USAID. The work on this report was completed in May 1984 and the results support the earlier findings on the expected high reser- voir temperature. However, this report outlines a development which may lead to installation of 2.5 MW of weLl-head generator capacity by 1987. The mission does not consider that the Government should follow a path to install non-condensing well-head units to produce power at an earlier date. The well-head units may be appropriate for demonstration purposes, as temporary installation. The cost of drilling three exploratory wells (4,500 m), including mobilization and demobilization of drilling equip- ment is estimaced to be US$5.0 million. A consulting organization needs to be selected to supervise the work of the driLling concractor and implementation of the technical surveys, i.e., production tests, reser- voir studies, preliminary design of the power plant and the feasibility study for that plant. 31/ The preparatory activities should be completed by mid-1985. Drilling and Feasibility Study 3.41 The preparation of drilling specifications, tendering, bidding and the award of drilling contract is expecced to take 3-4 months. Dril- ling, therefore, could start towards the end of 1985, after mobilization of the drilling team and supplies. Drilling the three exploratory wells is expected to take about six months, so this work shouLd be finished by mid-1986. Preliminary design work on the plant can start as soon as the nature of the geothermal fluids is known. Once the design work and cost estimates for the first power unit and a technical/economic feasibility study are completed, a "yes or no" decision can be made with regard to developing commercial geothermal power. The mission believes a decision could be made by end 1986 at the latest. 3.42 The mission recommends that the first geothermal unit be designed to operate as a base load plant to maximize savings on petroleum imports. It should be a condensing unit to limit the specific steam con- sumption and hence drilling costs. 32/ A unit size of 5 MW probably would be optimal for the size of the rUCELEC system. Given increasing demand and the need to retire Units 1-3 at Union Station in the early 1990s, the second 5-MW geothermal unit may have to be commissioned between 1991 and L992, about 12-18 months after the first unit. 31/ These tasks are estimated to cost another US$1.0 million. 32/ Condensing units need about 10 kg steam/kWh, while non-condensing "well-head" units use about twice as much. - 32 - Intermediate Phase 3.43 At this stage financing of the plant construction has to be arranged (estimated cost -- US$10.6 million). Also, decisions to drill additional production wells, if needed, would have to be taken; two more wells would cost approximately US$3.0 million. A consulting firm should be selected to be in charge of engineering and supervision of plant con- struction. This stage shouLd be completed by mid-1987 at the latest. Plant Construction 3.44 The duration of this phase is primarily determined by the installation of electro-mechanical equipment at the plant, estimated as follows: Activities Time Needed Tendering, evaluation and contract award 2 months Manufacture of equipment 15 months Installation of equipment 10 months Test runs 3 months Completion of installations and commissioning 6 months 36 months If this schedule is adhered to, geothermal-based electricity should be available in St. Lucia by mid-1990. To achieve this, uninterrupted financing of the whole project should be arranged as a complete pack- age. In this, a donor agency could play an important role in putting this project together and assist in: (a) formulating Government strategy for developing this resource; Cb) organizing institutional arrangements; Cc) mobilizing and coordinating co-financing; and (d) ensuring efficient project implementation. 3.45 The mission recommends that the Bank discuss with the Govern- ment future plans for financing a possible geothermal project. The Government may also wish to explore the possibilities for total private sector involvement in the financing and development of this project. The LUCELEC then could purchase bulk power at competitive rates. If the first project proves to be successful, there also may be the possibility of third and fourth units following in the mid- to late-1990s as demand increases. If these schedules are adhered to, by 1990, geothermal would contribute some 18% of total power generation; this would rise to about 36% in 1991, the first full year of geothermal generation. - 33 - Hydropower Development 3.46 A desk study 33/, written in 1982, identified three rivers as potential sites for hydropower development - the Millet, Vieux Fort and Troumasse. These rivers are estimated to have possible firm potentials of 120, 260 and 160 kW, respectively. The study recommends further examination of the hydro potential of these rivers, as intensive defor- estation and cultivation in watershed areas has tended to reduce dry weather flows. Accelerated run-off during the rainy season also results in high sedimentation and lowering of potential firm hydro output. The mission believes that additional data is needed on the flows of the besc hydro potential rivers, as the combined potential is onLy about 450 kW firm output. The mission also recommends that a stream gauging network be established at least on these three rivers as a first step, and thac data be collected over a 2-3 year period before embarking on any addi- tional major investment. About US$45,000 would be required to escablish such a necwork. 3.47 A feasibility study for the rehabilitation of a small hydro- electric scheme on the Soufriere River was completed in 1983. This small station, 50 kW installed capacity, was damaged during a storm in 1977 and taken out of service. The output of this station two years before the storm was only about 24,000 kWh/year, 34/ while in the early years of the scheme (commissioned in 1952), it averaged 300,000 kWh/year. This reduc- tion was caused by changes in the river bed conditions near the intake and the major problem of siltation. No records of stream flow data exist for this river so the feasibility study had to be based on spot measure- ments made on four occasions. The study recommended that the plant be rehabilitated to operate 24 hours a day and 7 days a week. The invest- ment to achieve this was estimated to be EC$369,000 (1982 prices) for an average output of 34 kW (about USS4,000/kW). 3.48 There is considerable uncertainty regarding the average level of output in the proposed rehabilitation scheme due to: (a) inadequate stream flow records and the assumptions that had to be made; and (b) the severe siltation problems which could only be reduced by using pipelines in place of a canal. This option had to be rejected because of its high cost, so the consultants proposed 33/ "Desk Study - Potential for Hydro-electric Development - St. Lucia" - December 1982 (Wason Consultants Ltd.). 34/ At that time, the station was operated 8 hours a day for 5 days a week. - 34 - instead hiring a full-time laborer to clear away vegetative matter and silt from the rehabilitated canal on a daily basis. 3.49 The 34 kW average output of the rehabilitated scheme taken by the consultants with 10% down-time for maintenance (particularly of the hydraulic works) would yield an output of only about 270,000 kWh p.a. This would imply an annual savings in diesel oil of some EC$58,000. 35/ Assuming operations and maintenance costs of about EC$26,000 p.a. and annual capital costs of some EC$44,000 p.a., 36/ it is evident that the scheme is not attractive. The mission recommends that the development of this scheme not be pursued given: (a) the unattractive economics of the project; (b) that better projects exist in the power sector over the period under consideration (e.g., the loss reduction program); and (c) that the Soufriere River's hydro potential, at the site inves- tigated, is considered to be inferior to that of the Millet, Vieux Fort and Troumesse Rivers. 3.50 The mission further considers that only when a few years of stream flow data have been obtained for the three rivers in question would it be appropriate to undertake an in-depth study of developing the potential of those rivers. Power Sector Investment Program 3.51 The estimated investment in the power sector over the 1984-90 period is expected to be the largest ever in the sector's history on the island; the figures are outlined in Table 3.13. 3.52 Total investments of about US$30 miillion (1983 prices), exclud- ing physical and price contingencies, 37/ are needed to undertake the expansion program for the rest of this decade. Of this amount, the geo- therma'l xploration component represents about 18Z. In the event that it is decided in 1986 not to proceed with geothermal development, power sec- tor investment between 1984-90 would decline to about US$24 million (1983 prices) excluding physical and price contingencies. This lower invest- ment estimate includes the addition of Cul-de-Sac No. 2 unit (5-1W medium 35/ The cost of diesel oil to LUCELEC in 1982 was EC$3.47/IC and the average fuel consumption per unit generated was taken as 16 kWh/IC. 361 Based on an optimistic 15-year lifetime and 9% cost of capital. 37/ These could add another US$10 million. - 35 - speed diesel) in 1990 in the absence of geothermal No. 1. In the scen- ario of the geothermal option, the estimated total investment needs of about US$40 million, including physical and price contingencies, are quite sizeable. They are more than five times LUCELEC's total assets of US$8.1 million at end 1982. It is clear that if LUCELEC is to finance about lOX (US$3-4 million) 38/ of this programme while maintaining a reasonable debt/equity ratio, a sustained level of annual tariff increases and equity injection would be caLled for. In this context, the manner in which geothermal exploration is financed is of some relevance. Table 3.13: ESTIMATED POWER SECTOR INVESTMENT PROGRAM, 1984-90 Item Commissioning Date Investment (US$ Million, 1983) Union No. 6 Unit (2.7 MW) 1984 1.8 Vieux Fort 1 MW skid-mounted unit 1985 0.2 Cul-de-Sac site development 1986 0.5 5-MW medium speed dieseL (Cul-de-Sac) 1987 4.4 H-T line linking Cul-de-Sac to Castries 1987 0.5 On-going T&D expansion 1984-1990 1.5 Power Loss Reduction Program (including T&D upgrading, meter change out etc.) 1985-88 2.6 Least cost system expansion study & engineering study of interconnector 1986/87 0.3 North-South interconnector 69 kV to be determined Geothermal exploration 1985-86 6.0 5 MW Geothermal Unit No. 1 (Soufriere) 1990 10.6 Total approximately 30.00 Source: Mission estimates. Electricity Tariffs 3.53 In February, 1983, LUCELEC received an average tariff increase of approximately ECc4.2 per kWh from the PUC. It had, in fact, applied for an increase of ECc5.0 per kWh. In August, 1983 they applied to the PUc for a further ECc2.0 per kWh increase in basic rates to take effect from January, 1984. Their justification for the increase was that it was needed to meet the current level of operating and administrative expenses and repayment of debts, and to provide sufficient funds for investment in expanding the system. However, the current "accounting" approach to tariff-setting bears little relation to economic efficiency criteria for 38/ The lower limit refers to no geothermal development and the upper limit refers to the case of geothermal No. 1 unit being added by mid-1990. - 36 - allocating scarce resources. Tariffs ideally should be structured so that consumers pay the full economic cost of supply. In reality, other factors have to be considered, particularLy, social objectives and the financial viability of the utility company. The tariffs therefore should be structured to reflect not only the long run marginal costs but adjust- ments also should be made to incorporate other such objectives. 3.54 A review of the current tariff structure has identified a num- ber of features which need to be addressed: (a) Most of the cost of fuel should be included in the base tariff, with the fuel adjustment surcharge only covering marginal de- partures from the base fueL price. This would provide greater incentive to the utility to lower technical losses; (b) Kilovolt-ampere (kVA) demand metering is not practised for large consumers, so there is no incentive to improve power factors; and (c) The structure of the tariffs on high-voltage compared to lower- voltage consumers does not reflect relative economic costs of supply. Consequently, cross-subsidization is taking place which results in an inefficient allocation of resources. Any subsidies to low income domestic consumers shouLd be provided by higher income domestic consumers rather than industry or commercial consumers to avoid distorting further the input prices of the productive sectors. A long run marginal cost tariff study is planned for the second quarter of 1984 (financed by USAID and executed under the CAESP). These defi- ciencies in the tariff structure should be addressed at that time. 3.55 A further issue related to tariffs concerns their absolute level. LUCELEC experienced a disastrous financial performance between 1979 and 1981 when net income after tax collapsed from a meager EC$14,000 in 1979 to a sizeable EC$530,000 loss in 1981. This resulted from: (a) inadequate timing and size of tariff increases approved by the PUC; (b) hurricane damage in 1980; (c) an 8% decline in total sales between 1979 and 1981; and (d) an increase in total transmission and distribution Losses (especially non-technical losses) between 1979 and 1981. The financial position has improved somewhat since then as a result of insurance payments for hurricane damage, part of which has been carried over in the balance sheet as a capital surplus. In addition, the com- pany's income statement showed a net income after tax in 1982 of - 37 - EC$343,000, with further strengthening in 1983. Over the next several years, however, LUCELEC has to generate significant surpluses to contri- bute to the sizeable investment program on which it must embark, and it is critical that tariff Levels reflect this if the quality of electricity service is to improve. This will require sustained annual tariff increases between 1984 and the early 1990s and in some years these increases may have to be significant. Institutional Issues 3.56 LUCELEC has an authorized share capital of EC$5 million, divided into 260,000 non-voting and 740,000 ordinary shares of EC$5 each. The company has issued 3,446,990 fully paid shares (Table 3.14). LUCELEC's Board of Directors comprises five Directors, one of whom is appointed by the Government, one by the Castries City Council (CCC) and the other three, including the Chairman, by CDC. The agreement between CDC and LUCELEC provides for CDC to serve the company in the following areas: (a) Technical and other advice (other than normal consulting engineering services) as required. This includes ad-ice on accounting procedures, preparation of accounts, capital esti- mates and revenue needs. In addition, they ensure that an executive or engineer visits LUCELEC at least once a year to review company management and make recommendations. These services tend to reflect CDC's ownership roLe. (b) Personnel Agents. This provides for CDC to recruit senior management staff for LUCELEC. Cc) Buying Agents. Under this component, CDC procures plant, machinery and equipment on behalf of LUCELEC and examines all shipping documents related to purchases. Table 3.14: ALLOCATION OF LUCELEC SHARES Shareholding Shareholder Voting Non-Voting Total St. Lucia Government 402,560 (18.8Z) 1,300,000 1,702,560 Castries City Council 604,430 (28.1%) -- 604,430 CDC 1,140,000 (53.1%) -- 1,140,000 Total 2,146,990 (100%) 1,300,000 3,446,990 - 38 - 3.57 Separating the areas of the Agreement which pertain to CDC's role as a major shareholder from those which characterize it as a manage- ment service arrangement is difficult. For example, the services offered in the financial and training areas include: 39/ (a) accounting syscem design and impLementation; (b) assistance in financial planning; (c) alL Loans in the form of debentures; (d) guarantees of bank overdrafts; (e) accountanc/secretary hiring; and (f) training of some accounting personnel. In the technical areas the following services are provided: (g) trouble-shooting and maintenance advice; (h) purchasing services of most equipment and spare parts; (i) hiring of key senior technical staff; (j) engineering services through its London office; and (k) training of some technical personnel. 3.58 CDC has played, and continues to play, an important role in the development of LUCELEC. Almost all of the senior management positions are staffed by qualified St. Lucians. CDC has indicated, however, its intention of withdrawing from its ownership role in the power companies in St. Lucia and other eastern Caribbean states (Montserrat and St. Vincent). LUCELEC and the Government must begin preparing for this eventuality. There are three areas of CDC activity under the current agreement which are of vital importance to LUCELEC and in which special effort is needed to ensure that appropriate arrangements are made to cover the gap that CDC withdrawal wiLl create. These are: (a) Procurement services. A provision for contracting a procure- ment agent would be required, and considerable benefits could occur if this were done jointly with other utilities in the OECS. (b) Engineering services. The annual visits of a CDC engineer provide a useful independent opinion and review of current issues and an opportunity for referring matters if additional expertise is needed. Here too the possibility of establishing common services arrangements with other OECS utilities needs to be assessed. 39/ Study by Sha-ainig3n (1980). - 39 - (c) Training funecions. This has focussed principally on field personnel, linesmen, etc. It is best for technical training to be done locally by bringing in experts to work on che job with trainees. This does not deprive the company of staff during training (which would occur if they were sent abroad) and also enables the training to be better geared to local issues (such as metering and theft). 3.59 One problem for senior management is that little time is available to focus on system and operational planning issues, since day- to-day operational problems take priority, given the limited skilled personnel available to a small utility. To overcome this, LUCELEC has taken steps to create an Engineering Department with an Engineering Adviser made available through the Commonwealth Fund for Technical Cooperation (CFTC) for two years beginning end-1983. To determine whac mechanisms should be established after CDC's withdrawal, the mission endorses the proposal in the Caribbean REAP for a regional study to assess what common services and through what institutional mechanisms could these services be provided to the OECS power utilities (Annex 1-B). 3.60 As there is no geological or mineral exploration insticution in St. Lucia to take responsibility for the geothermal exploration and development stage, the mission believes that the responsibility for de- veloping and exploiting this resource should be assigned to the enter- prise generating and supplying electric energy (LUCELEC) which would organize a geothermal department or division. This arrangement has proven its worth in other developing countries in a similar position. Technical assistance would be required for training the national staff of this division, and a basic chemical laboratory for geothermal fluids (water and gases) should be developed as soon as development commences. The initial staff should include at a minimum: (a) one geologist with a university degree; (b) one chemist or chemical engineer with a university degree; (c) one production/reservoir engineer with a university degree. The cost of basic laboratory equipment and other instrumentation would be about US$250,000. 3.61 The mission recommends improved liaison at the working level between the engineering and planning staff at LUCELEC with staff of the Energy Unit at the Planning Ministry. This is important if the macro- economic implications of the power sector program are to be properly assessed. - 40 - IV. OTHER RENEWABLES Biomass Supply 4.1 Most of St. Lucia's wood resources are found in about 7,820 ha of primary forests and 12,500 ha of scrub forests (Table 4.1). About 4,980 ha of the rain forests are classified as reserves. Table 4.1: LAND AREA BY CLASS Class (ha) Primary Forest Rain Forest 6,779.5 Montane Thicket 607.5 Mangrove 54.5 Elfin Woodland 133.0 Plantations 246.0 Scrub Forests 12,509.5 Open Woodland 1,871.5 Mixed Agriculture Secondary Forest 29,873.0 Developed Agriculture 7,101.0 Urban Influences 1,676.0 Grassland 619.0 Total 61,470.5 Source: Government of St. Lucia Forest Division. 4.2 Assuming a mean annual increment of between 1 m3 to 4 m3 per hectare a year for the unmanaged rain forest, the theoreti cal sustainable supply is estimated to be between 20,000 and 80,000 m a year. The actual supply, however, is less because of the general inaccessibility of the primary forest areas. Most of the wood currently used as firewood or carbonized for charcoal is believed to be obtained from the scrublands. Besides stemwood from wood, unproductive coconut trees (senile, diseased and damaged by hurricane) in the 9,300 ha of coconut plantations are con- sidered a potential biomass fuel resource. At last count, 40/ these numbered around 25%, of a total 1,048,560 trees. On a ten-year exploita- tion ra_e, the mission estimates the stemwood resource potential to be equivalent to at least 2,200 tonnes of charcoal production per year 40/ Agricultural Census (1973/74). - 41 - (1,510 toe); this compares to a current annual charcoal consumption of about 5,000 toe. 4.3 Charcoal has been produced from coconut stemwood and used successfully in some countries, notably in the South Pacific. For St. Lucia, however, two factors may inhibit its use. First, the stemwood charcoal is less dense and more fragile than wood charcoal. Except in the case of an acute scarcity of wood charcoal, it is doubtful that charcoal from coconut Logs would ever be widely accepted among the country's discriminating users. Second, compared to the way wood charcoal is now produced, the economic production of charcoal from coconut stemwood requires a relatively large-scale organized operation: trees will have to be cut by chainsaw, pulled to a central point possibly by a tractor, cut into smaller pieces (to fit into metal kilns), and air- dried for a few months before carbonizing. The mission does not see within the near term any convergence of market demand with local capability for this undertaking. 4.4 Coconut processing residues (mainly shells) represent another biomass resource, but the amount is relatively small. Many of the shells currently produced are used in drying copra. Based on an annual copra production of about 5,200 tonnes, some 4,600 tonnes shells are generated, about half of which are used in the drying process. Discounting a por- tion of the excess shells that is used domestically by farm workers, about 1,900 tonnes would be available for carbonization. The total potential of excess shells is only about 285 of tonnes charcoal/year (196 toe). Consumption 4.5 According co a recent survey, 41/ about 88% of households use charcoal. on either a regular or occasional basis. These households con- sume, on average, 330 kg p.a. of charcoal, of which only 1.3% comes from coconut shell. Firewood, on the other hand, is used by 43% of house- holds, at 739 kg/household/year. At the national level, about 7,260 tonnes of charcoal and 7,920 tonnes of firewood are used a year. Total wood use for charcoal making and direct use in cooking stoves is esti- mated at about 80,000 tonnes (about 114,000m of solid wood equivalent p.a.). 4.6 Charcoal production is unregulated and is carried out in almost all parts of the island, usually in forest areas close to the road. After reserving a portion for own use, the remaining charcoal is sacked and brought to the roadside for transport to the main "coal market" at Castries and to other markets. At the time of the mission, charcoal in Castries sold for EC$30 per 90 lb sack (US$272/tonne) and in small tins 41/ National Household Energy Survey (NHES), 1981, Government of St. Lucia. - 42 - containing roughly 2 lbs for EC$1.25 (US$510/tonne). Pricing is highly notional but appeared to be fairly uniform in the various markets. Char- coal prices have not changed significantly in the last few years. 4.7 Firewood is not sold in the public markets. Users obtain their supplies by gathering from the forest or by purchase (in bundles) from non-market sources. The NHES survey estimates the average consumption of households using firewood at 1,625 lbs p.a. to be valued at EC$72.80 (US$27), or roughly ECC10/kg. 4.8 A comparison of cooking costs using normally available fuels is shown in Table 4.2. Based on purchases by the tin, charcoal is clearly one of the most expensive fuels, roughly even with electricity. However, when purchased by the bag, cooking costs with charcoal are cheaper and become comparable co LPG. There is no data on the proportion of house- holds that buy charcoal by the tin rather than by the bag. Kerosene and wood appear to be the cheapest cooking fuels, but kerosene is used mainly for lighting. Since -wood is usually not obtained commercially, it is the least-cost fuel; for most households, the economic cost of collection is still low. 4.9 There is a strong historical and cultural preference for char- coal as a cooking fuel; even higher income households who have "stepped up" to LPG still maincain charcoal burning pots in their kitchens for occasional use. Some househoLds use LPG for ceremoniaL cooi-ing only. Another important factor in the choice of cooking fuel is the investment required to purchase the stoves. While the widely used "coal pots" could be bought for only about EC$5 (US$1.85), kerosene, LPG and electric stoves are priced in the hundreds. LPG users, in addition, must pay a deposit on the gas bottles. Table 4.2: COMPARATIVE COSTS FOR COOKING FUELS Kcal/ End Use 3 Fuel Unit EC$/Unit Unit Efficiency (x) EC$/1o Kcal Charcoal kg 0.7-1.2 a/ 7,000 20 0.5-0.9 Wood kg 0.1 b/ 3,500 8 0.4 Kerosene lt 0.9 8,800 35 0.3 LPG kg 2.5 10,800 55 0.4 Electricity kWn 0.5 c/ 860 65 0.8 a/ Based on EC$30 per 90 lb bag and EC$1.25 per 1 kg tin. El Based on NHES average estimate of EC$72.80 annual expenditure. El Residential rate, above 100 kWh. Wood is also used in the commercial sector (bakeries, restaurants, etc.) but the volume is negligible compared to domestic use. - 43 - 4.10 The current estimate of total fuelwood demand (based on the NHES survey data) is several cimes that of past estimates. 42/ If this estimate is accurate, the annual fuelwood deficit, considering normal forest yields, could be around 60,000 m3 p.a. There are indications that the deficit is met by clearcutting of forest lands. Deforestation there- fore results from the need for new agricultural land, and cLearing of forests to meet fuelwood deficits. Official survey data 43/ indicate a 340 ha annual decrease in total forest and woodland areas between 1961 and 1973. Other estimates pLace che rate of forest removal at as much as 8%, or about 1,000 ha p.a. Biomass Issues 4.11 The principal biomass challenge is finding a way to meet the growing demand for fuelwood without causing destruction to the country's forests and concomitant environmental degradation in the long term. Since there are no other major biomass resources available in sufficient amouncs, the only way to increase fuelwood supplies is to establish plantations of fast-growing tree species and properly manage existing forests. 4.12 Some steps already have been taken to address this issue. In cooperation with the Forestry Division, CIDA experts have just completed a forest management plan which proposes a policy for optimum land use and a management system, based on sustained yields, for both public and private forest lands. The plan recommends an afforestation program for commercial timber at 100 ha p.a. up to 1993, and a smaller program for establishing short-rotation fuelwood plantations (mainly leucaena leucocephala) averaging 12 ha p.a. in the same period. 4.13 The mission endorses the plan and recommends that its execution be treated as a matter of high priority. Considering the magnitude of the fuelwood deficit, however, it may be necessary to expand the proposed fuelwood plantation component. if an average yield of 50 m3/ha p.a. is assumed for leucaena, L,400 ha would be needed by 1992 to provide even half of the fuelwood demand by that time. This translates to a yearly planting rate of 200 ha between 1985 and 1992. Given the various insti- tutional and resource constraints, however, a target of about 100 ha p.a. may be more realistic. The establishment of such fueLwood plantations is best carried out by private landhoLders, and the governmenc should try to generate this interest. The Forest Division has taken a few steps in this direction by providing leucaena seedlings and technical assistance to a few interested landowners. An educational campaign would be needed 42/ See, for example, World Bank Annex to Caribbean Energy Survey (1979), which cites 2,200 tonnes charcoal p.a., which is equLvalent to about 31,400m3 wood p.a. 43/ GOSL Annual Statistical Digest (1982). - 44 - to explain the benefits that could ba derived from a fuelwood plantation program. Survey data obtained by CARDI have shown that charcoal-making already contributes a significant portion of the income of most farmers today, indicating that a properly promoted plantation program geared toward charcoal production may be well received. A further push may be effected by enacting disincentives to owners of large tracts of land who allow their land to remain idle. 4.14 The mission supports the Forest Division's plan to establish five 5-acre experimental modules at separate sites along the Eastern coastline. Because of the need for separate supervision, fencing, fire protection measures, and the generally high cost of labor on the island, each module is estimated by the Forest Division to require a high invest- ment of about US$3,600 per hectare. 44/ The future expansion of such modules or the establishment of larger plantations by private farmers obviously would be justified only if unit costs could be substantially lowered. The feasibility of the long-term (beyond the demonstration modules) program needs to be studied in more detail. 4.15 Improving Efficiency. Efforts must be directed towards im- proving the efficiency of the major end-uses of fuelwood. The large quantities of wood -wasted during carbonization, coupled with the gener- ally short transport distances in the country, strongly argue against converting wood to charcoal. Preferences for charcoal as a cooking fuel, however, appear to be deeply rooted in local history and culture and, in the mission's view, would be difficult to change. A more useful approach would be to improve current methods of charcoal production and use. 4.16 The Forestry Division should begin co formally monitor the activities of charcoal makers, not only to control indiscriminate cutting of trees, but also to allow the introduction of less wasteful ways of carbonization. Increasing che efficiency of charcoal-making from about 10% using primitive earth kilns to 20-25% using metal kilns or modified earth kilns could save, at the national level, up to l0,000-L5,000 m of wood a year. This is equivalent to the amount of wood obtained from clearcutting 100-150 ha of forest a year. 4.17 Where a number of charcoal makers could be organized into a cooperative, charcoal may be jointly produced using portable metal kilns. Alternatively, simple modifications to the traditional earch kiln could be taught, e.g., the use of metal linings and chimney to conserve heat and regulate air flow. In contrast to other developing countries, these approaches may prove more workable in St. Lucia where, because of the small size of the country, most of the charcoal makers and their normal places of operation appear to be well known to the Forestry Division. 44/ This cost relates to a research lot which would have multiple uses. The average forestation cost is estimated at US$1,600 per module. - 45 - Finally, there is scope for gradually introducing improved "coal pots" in the market. Some progress in this area appears to have been made in Montserrat under the USAID-financed CAESP (executed by the CDB) project and should be investigated for possible crial in St. Lucia. 4.18 Institutional Issues. The important institutional recommen- dation is to strengthen the Forestry Division to enable it to implement the forest management plan and the fuelwood planting program. The mission strongly supports the recommendations made by CIDA which in- clude: (a) the reorganization of the Forestry Division into a Department headed by a Chief Forester; (b) an increase in the number of specialist staff positions; and (c) the implementation of a long-term program to train forestry staff by sending them for intensive forestry courses at the Caribbean Institute of Agriculture and Forestry, the Institute of Tropical Forestry in Puerto Rico, and similar institutions in the region and elsewhere. Biogas 4.19 The Government has considered the use of animaL wastes as a possible energy source in the form of biogas; however, the total number of livestock on the island is not large (Table 4.3) enough to generate more than about 53,000 wet tonnes of manure per year. 45/ Converted to biogas, the theoretical energy potential is only 34 toe. There are a few farms with large numbers of animals where the construction of digesters could be undertaken. A recent attempt to employ this technology at the Beausejour Farms near Vieux Fort, however, failed because of faulty design and construction. Redesigning could cost easily between US$100,000 and US$130,000 - which the mission does not consider worth pursuing at this time. Table 4.3: ESTIMATED MUMBER OF LIVESTOCK BY TYPE, 1982 Stock Type Heads Cattle L1,100 Pigs 10,500 Poultry 209,400 Sheep 13,700 Goats 10,600 Source: Agricultural Quarterly Digest (1982). 45/ Excluding manure from sheep and goats, for which there is little biogestion experience. -46- Solar Energy 4.20 The Caribbean Meteorological Institute (CMI) recently has com- pleted a year-long measurement exercise of solar insolation on selected parts of the island as part of the Eastern Caribbean Wind and Solar Energy Resource Assessment Project covering seven islands. 46/ Although the data is still being processed, it is apparent that St. Lucia has ade- quate sunshine for solar water heating applications. Currently, between 40 and 50 homes and at least one small hotel are equipped with solar water heaters. About half of the units were installed by a local manu- facturer and the rest privately imported from Barbados and other sources. The locally manufactured home units (mostly 50-gallon systems with two 3' x 5' panels) cost about EC$2,500 (US$926) installed and are estimated to have payback periods of about three years compared to the cost of using electric heaters. 4.21 With several large hotels on the island 47/ using LPG for water heating, the potential market for solar water heaters is considered adequate to support a modest local industry. The mission considers solar water heating a local industry that merits government support, not only for its energy conservation aspects but also because of its empLoyment generation potential. Some incentives, in fact, are already in place. For example, import duties are waived for materials that are to be used in making solar water heaters. To stimulate the market, a further incentive may be extended in the form of income tax credits to users, as is currently done in Barbados. Wind Energy 4.21 Wind regime data for St. Lucia and six other islands were col- lected in 1982 by CMI as part of the resource assessment project. These measurements are currently being processed by CMI. Once the results are available they will provide an estimate of the wind resource base and identify promising sites for wind energy applicatior.. 4.22 USAID is financing a project through the CDB to design and test a wind-powered chilL storage room at the Dennery fishing cooperative. Originally funded at US$44,800, the project has been delayed but is now in the procuremenc stage for major equipment. A vertical axis wind gen- erator with a swept area of 50.2 is expected to produce about 1.5 hp of power at wind speeds of 5-6 m/sec. and drive a compressor for the 8' x 46/ The project was funded by CDB from a USAID grant and executed by CMI. 471 In 1982, nine hotels had a total capacity of 1,043 rooms. - 47 - 12' x 7' capacity, package-type chill room. An induction motor or grid power would run the compressor when wind speeds fall below 5 m/sec. The system is intended for test and demonstration and future expansion will depend an its economic/technical viability. Ocean Thermal Energy Conversion (OTEC) 4.23 The Government has received proposals from at least two foreign groups on exploiting the thermal gradients off che country's coastline through OTEC plants. However, the mission views OTEC as a technology that is at least a decade away in terms of practical application in a developing coun'.y. Because of its limited resources, the extent of Gov- ernment participation in this high technology research work should be limited to providing access to a suitable offshore site and similar in- kind assistance. Institutional Issues 4.24 The mission sees a need to train one person from CPU's Energy Unit on new and renewable energy. This could be done through participa- tion in short-term courses offered by a number of institutions abroad. A certain degree of expertise in this area is required to enable the Unit to judge the suitability of renewable energy projects being proposed in increasing numbers to the country, to actively participate with consul- tants in projects directLy under CPU's supervision, and to effectively monitor those activities being conducted by other agencies. 4.25 The mission does not view the proposed Renewable Energy Demonstration Station (REDS) as a priority undertaking by the GOSL. Although the objective of creating a central facility for R&D in renew- ables has merits, the pressing need is to quickly and effectively imple- ment priority activities that have already been identified, such as the establishment of fuelwood plantations. The important R&D areas cited as primary concerns with respect to the proposed station can be addressed within the relevant ministries if the concerned units or divisions are sufficiently strengthened. This approach would obviate the need to make substantial investments in new infrastructure or create another large organization whose long-term functions and means of support are not satisfactorily defined. As envisioned, the REDS will be supported by local and external funds in its first four years of operation and then become self-supporting through consulting contracts from the fifth year onwards. This appears unrealistic. The Government should review the basis of this expectation in particular and the rationale for creating REDS in generaL before making any investment commitments. - 48 - V. ENERGY CONSERVkIOE 5.1 Table 5.1 summarizes the major end-users of energy in the country. This information was developed from a number of visits during the mission to large energy-consuming establishments in order to identify potential Energy Conservation Opportunities (ECOs). Tourist Sector 5.2 Hotels account for only 7% of commercial energy use, but 23% of electricity consumption. The seven largest hotels account for 80Z of electricity consumption in the tourist sector. Air conditioning and water heating are the major applications, followed by lighting, refrig- eration and cooking (LPG only). Table 5.1: IMPORTANCE OF ENERGY CONSUMPTION FOR DIFFERENT END-USES IN FIVE SECTORS Kanufac- Tourism turing Commercial Households Government Air conditioning b a Cooking a Lighting a a a Production b b Refrigeration a Water heating a a: Application consumes 20% or more of all primary energy in the sector. b: More than 50% of sector total. 5.3 A modest start has been made in implementing energy conserva- tion measures in the hotel sector. Table 5.2 shows the results of an energy conservation program at the St. Lucian Hotel (200 rooms) since 1980. While electricity rates have risen by 12.5% p.a., energy conserva- tion measures 48/ have resulted in a 10.4% p.a. reduction in consumption, keeping total costs roughly constant in current prices. These savings are impressive and could act as a stimulus to other hotels if the information were properly disseminated. 48/ These include improved monitoring and maintenance programs, education of staff, and installation of efficient lighting and air conditioning controLs (so thac units only operate when doors and windows are closed and reset button is activated). - 49 - Table 5.2: IMPACT OF ENERGY CONSERVATION AT ST. LUCIAN HOTEL ELECTRICITY COSTS 1980 1981 1982 1983 Growth (Z p.a.) Average unit cost (ECC/kWh) 34.2 39.5 46.1 48.7 12.5 Average electricity consumption per occupied room- day (kWh) 40.3 36.6 31.9 29.0 (10.4) Average cost per occupied room- day (EC$) 13.7 14.5 14.7 14.1 1.0 Source: Caribbean Hotel Management Services. 5.4 The mission has identified a number of attractive opportunities for energy conservation in the hotel sector for air conditioning and hot water supplies (Table 5.3). Investments range from EC$700-2,000 per hotel room, with paybacks between 1.0 and 4.7 years. An effective in- vestment program would cost about US$1.25 miLlion, 49/ and wouLd reduce electricity use by 25%, diesel by 25%, and LPG by 40%. Financing for this program could be provided from the Energy Conservation Revolving Loan Fund of US$5 million which the CDB proposes to establish under the REAP. Loans could be provided from the Fund to both the St. Lucia DeveLopment Bank and commercial banks for on-lending to borrowers for energy conservation projects. Commercial and Manufacturing Sectors 5.5 Energy conservation opportuntities in the manufacturing and commercial sectors are difficult to identify because of the diverse nature of energy consumption and the lack of data. To get a rough idea of energy consumption patterns in these sectors, about ten facilities were visited where previous energy audits had been done. 50/ In the commercial sector, energy saving activities have been limited to good housekeeping, such as switching off air conditioning in unoccupied 49/ Based on a 75% penetration (900 out of 1200 hotel rooms) in air conditioning and water heating end-uses. 50/ "Energy Conservation Assessment Report on St. Lucia", funded by CARICOM Secretariat (1981) under the USAID-financed CAESP. - 50 - rooms. Because of financial constraints, none of the facilities visited had taken any action on recommendations made by the energy audits. Nevertheless, potential energy savings do exist. Air conditioning and lighting account for more than half of electricity consumption in the sector and in many instances efficiency is lower than in the hotel sec- tor. However, because of diseconomies of scale, payback periods in this sector may be longer than in the hotel sector. Even so, a systematic approach to improve efficiency in air conditioning and lighting could give good results. Table 5.3: ESTIMATED COSTS, SAVINGS AND PAYBACK PERIODS FOR DIFFERENT ECO's IN THE HOTEL SECTOR Energy Conservation Costs Annual Savings Payback Appliance Opportunity per room a/ per room al period Air Conditioning Control units EC$ 800 EC$ 500 (20%) 1.6 years c/ Replacement of old air conditioners EC$2000 ECS 875 (35%) 2.3 years Insulation EC$ 800 ECS 875 (35%) 1 year Hot water Heat exchange on di air conditioners EC$ 700 EC$ 500 (100%) 1.4 years Solar heating EC$1650 e/ ECS 350 (70%) 4.7 years a/ including freight, import duties and other taxes, design and instal- lation. b/ percentage in relation to energy consumption for this particular ap- pliance. c/ energy savings include both electricity and diesel. a/ pipe insulation is not treated separately, but included in the other measures. e/ this average reflects a wide range because of necessary or desired differences in design; in some cases a much cheaper installation will be possible. 5.6 Table 5.4 estimates the effect of an investment program of US$0.75 million to reduce air conditioning and lighting energy use by 17%, or a total savings of electricity and diesel in this sector of 10%. Organizational aspects of the program are of critical importance in the commercial sector. Extensive contacts need to be established with a large number of facilities to motivate them and to give detailed infor- mation on ECO's. 5.7 In the manufacturing sector, little attention is paid to energy conservation because energy costs make up less than 5% of total costs (as opposed to 10-20% in the hotel sector). Energy is mainly used in produc- tion processes, where efficiency directly depends on the quality of the technical staff and machinery. In some facilities a considerable reduc- tion in energy consumption has been realized, mainly as a result of - 51 - improvements of production efficiency or by repairing/renewing energy equipment. The few ECO's identified by the energy audits were considered to be minor; therefore external support for energy conservation is not considered necessary. Table 5.4: ENERGY CONSERVATION RESULTS OF AN AIR-CONDITIONING AND LIGHTING PROGRAM IN THE COMMERCIAL SECTOR Savings on Savings on energy Penetration energy cost Average costs for lighting Energy Conservation rate of for ACL payback and air- Opportunity program per site period conditioning - Maintaining air-conditioning and cleaning dazzle lights 501 12% 0.5 years 50S x 12% = 6% - Replaceing old air condition- ing units and less efficIent bulbs and fluorescent lighting 20% 40% 3.0 years 20% x 40% = 8% - Insulation 10 30% 3.0 years 10% x 30% 2 3% Total 17% Government Sector 5.8 The Central Water Authority (CWA), the major energy consumer in the Government seccor, recently installed new pump sets, but an assess- ment of the energy conservation potential still needs to be undertaken. Energy consumption in Government buildings has never been monitored. This should be started immediately with a focus on air conditioning and lighting ECO's. It may be possible to make use of the results in the commercial sector program. Transport 5.9 The transport sector is the largest energy consumer in St. Lucia. Most energy conservation measures in transport are effective only in the medium- and long-term. In the longer term, infrastructural mea- sures (road maintenance, repairs and construction), transport planning and mode shifts (towards public transport) should be considered. In the medium term, attention should be paid to the stock of vehicles. One positive development is the growing preference for small, energy-effi- cient vehicles. Fuel taxation and import duties could reinforce this - 52 - trend. Finally, maintenance is of great importance. Obligatory inspec- tion and improved training of car mechanics are likely to be effective measures. An in-depth analysis of energy conservation options in this sector needs to be undertaken. A provision for such a study, estimated to cost US$40,000, is included in the Caribbean REAP. CDB and CARICOM are currently developing terms of reference for this study. Institutional Issues 5.10 A number of promising ECO's have been identified. Cost effec- tiveness by itself, however, does not guarantee that energy conservation efforts will be successful. The chances of a successfuL energy conserva- tion program are determined not only by the technical and economic feasi- bility of the separate energy saving measures, but also by the practical feasibility. Implementation in this case is limited by four factors: (a) lack of technical know-how; (b) lack of (access to) funding; (c) weak financial condition of several of the corporations in question; and (d) lack of organizational capability. 5.11 Assistance in these fields is a necessary condition for a suc- cessful energy conservation effort. There is an obvious need for tech- nical assistance when undertaking energy conservation efforts. Technical assistance should be made available in three areas: (a) The maintenance of energy equipment has to be improved. Grow- ing demand cannot be serviced by the available local resources; (b) The identification, design and preparation of energy conser- vation projects at the facility level are important bottle- necks. Energy audits should be made by consultants specialized in the particular appliance field; and (c) Assistance by independent experts in appraising energy conser- vation project proposals could facilitate the task of the St. Lucia Development Bank and commercial banks and speed up approval procedures. 5.12 The costs of energy audits, project preparation, and mainte- nance and the difficulties in securing financing are all constraints to the successful undertaking oi energy conservation activities. However, with the support of the CDB's Revolving Fund, some of the financing gaps will be closed at least for the first stage of the program. A consider- able level of technical assistance will be required to perform the energy - 53 - audits and to identify and prepare comprehensive conservation project proposals at the facility leve', to submit to the SLDB or commercial banks for financing. In addition, technical assistance will be needed by these banks in their appraisal of these projects. Under the proposed Revolving Fund, there will be additional resources to provide this technical support. For the program outlined above for St. Lucia, about US$125,000 in technical assistance would be required to launch this program. - 54 - Annex 1 Page 1 of 8 A. Regional Issues: Petroleum Supply Arrangements Regional Petroleum Study - Terms of Reference Title: A Regional Study of Petroleum Product Supplies, Tanker Size, Transportation and Storage in the Caribbean. Objective: To review the existing systems, and develop and recommend a least-cost 51/ regional strategy with regard to secu- rity and continuity of supplies, tanker size, transporta- tion logistics and storage facilities for petroleum products of appropriate quality over the medium and long term in the Caribbean. 52/ The study will be done in two phases. Cost: Phase I - Approximately US$50,000 Phase II - Approximately US$70,000 Funding: -bhase II - to be determined. Phase I - UNDP Caribbean Regional Petroleum Exploration Promotion Project Introduction 1. The current pattern of petroleum supply and distribution evolved during the pre-1973 era when oil companies competed for larger shares of an expanding petroleum product market. To meet the require- ments of this project scenario, large investments were made in refinery capacities, tankers and storage facilities. This was the appropriate strategy at that time because of the high profit margins associated with crude oil production. However, with crude production passing from the hands of the multinationals to the oil producing countries in 1973 and the oil price increases of 1973 and 1979, the outlook has changed radically. Many refineries are operating well below optimum capacity. The increased product demand growth pattern has changed, and marketing overhead costs have increased. The Caribbean Region has been no exception. Indeed, several features of the regional mode of operating exacerbate the situation: (a) refining capacity which is ill-adapted to present demand; (b) high freight costs as compared with world standards; 51/ Subject to security and continuity-of-supply objectives. 52/ A sub-option for the Eastern Caribbean CARICOM countries also needs to be evaluated. - 55 - Annex 1 Page 2 of 8 (c) inappropriate petroleum product pricing and taxation policies; and (d) high marketing costs in small country economies. Study Objective 2. The principal objective of the study is to develop a least-cost strategy for the supply and distribution of petroleum products of appr- opriate quality over the medium- and long- term in the oil-importing countries of the Region while maximizing the economic utilization of existing facilities and infrastructure and recognizing the need for security and continuity of supply. Nethodology 3. The consultants will be required to specify che methodology which they intend to use This should be justified based on its advan- tages over other methodologies. Weaknesses should also be clarified. The framework should include an analysis of the costs and benefits of the main study recommendations and should facilitate sensitivity analysis of the least-cost solution, both co variations in critical parameters and to adjustments reflecting other objectives such as security and continuity of supply, and political, social and economic factors within the various countries in the Region. These conditions are essential to developing a robust and realistic set of recommendations with regard to the least-cost strategy for the Region. Scope of Work 4. The consultants should develop a detailed picture of existing petroleum product supply and distribution in the Caribbean region, including in particular: (a) infrastructure refineries - review of configuration, capabilities, capa- city utilization and reliability; port facilities - review of draft limitations and tanker loading and unloading facilities and actual performance including documents; storage capacities - review of storage capacities by product (including crude), company and country, and of current fuel inventory management practices; and product handling facilities - review of product and crude pipelines, transfer pumps, utilities and related infrastucture. - 56 - Annex 1 Page 3 of 8 (b) transportation - review of tanker characteristics (including bunker con- sumption and cost), scheduling and actual performance; - review of role of chartered versus oil-company-owned vessels; - review of freight rates by product, tanker size, oil company, and country served; - estimate of freight costs based on current tanker schedul- ing, inventory practices and storage capabilities; and - in reviewing the existing transport system, the consul- tants should develop estimates of the freight costs for small cargoes being delivered on a single versus a multiple-destination basis. Since the current system operated by the companies is multiple-destination, the differential between these cost estimates and those for the single voyage mode would provide an indication of the savings of the present mode compared to the single country, single voyage option. (c) supply - review the existing petroleum product suppLy patterns to the market area in question from the refineries in the following terrritories: Aruba Curacao Trinidad (Port Fortin and Point-a-Pierre) Martinique Barbados Antigua Venezuela - this review should highlight: which petroleum products (in what amounts, at what frequencies and prices) are supplied from each of the above refineries to the individual demand centers; and associated risks of stockouts. (d) demand analysis of demand by product, company and country; review of marketing margin and description of distribution sys- tem; identification of interfuel competition; and review of petroleum taxation and supply security policies. - 57 - Annex I Page 4 of 8 5. In the light of the data gathered under 4, the consultants should examine each part of the regional product supply and distribution system to pinpoint areas where costs are unusually high and where inefficiencies appear to exist. 6. Regarding refineries in the Region, the consultants need not undertake an independent examination of their technical configuration, operational efficiency, or source of the crude supply, as these matters are outside the scope of this study. The consultants shouLd, however, include in their analysis potential efficiencies or cost savings in the export destination of refinery output, if any, in excess of domestic requirements. 7. Regarding product rransportation and storage, the consultants should examine the benefits/costs of constructing a centrally-situated product transshipment terminal to enable large cargoes to be moved from supply centers, with smaller tankers being routed from the terminal to their ultimate destination, particularly in the case of LPG where trans- portation costs amount to up to 40% of final product cost. The consul- tants should propose an efficient system of tanker scheduling to minimize freight coscs based on optimal inventory levels and associated storage capacities. The consultants should also examine ways to achieve ration- alization of marketing and distribution, particularly in the small island economies, in the light of freight rates for movement of crude and pro- ducts to the Region and between the countries of the Region. The consul- tants should indicate the potential savings from adopting their proposed least-cost mode of supply over the current system. In determining the optimal mode the consultants need to assess the costs/benefits of using larger tankers (given port limitations in certain destinations), moving larger cargoes to each island, on a multi-destination basis, more infre- quently, and hence maintaining higher inventories on each island. 8. Regarding market demand, the consultants should formulate appropriate petroleum pricing policies reflecting economic costs of supply, incorporating inter-fuel substitution and energy conservation objectives and including an assessment of the impact of petroleum product taxation and import duties and fees. 9. Based on che data gathered and analysis undertaken as above, the consultants should formulate the least-cost option for supply and distribution of petroleum products to each country in the Region con- sistent with security of suppLy. The study recommendations should con- sist of an action programme, on both a regional and individual country basis, to achieve the least-cost allocation objective, incorporating both short- and longer-term adjustments to the supply, transport, distribution systems and without threacening reliability of supplies to the area. Reports 10. The study is expected to take not more than 20 man-weeks over a period of 3 calendar months. - 58 - Annex 1 Page 5 of 8 11. Not later than one calendar month after commencement of the study, the consultants should submit to the Bank for comment an interim report summarizing the results of the data gathered by them under para. 4 above, the main issues identified to that point, and a preliminary indi- cation of the overall scope and contents of their final report. 12. Not later than two and one-half calendar months after commence- ment of the study, the consultants should submit to the Bank a draft final report for review with the Bank. The Final Study Report should be produced within two calendar weeks from concluding the review. 13. Throughout the study period, the consultants should maintain regular contact with Bank staff in Washington, D.C., and with Caribbean Development Bank staff in Barbados (where the consultants are expected to be based during the study period), submitting monthly progress reports to each. They should also ensure that all meetings with Government and oil company representatives are arranged by Bank or CDB staff on the basis of an agreed advance agenda. Composition of Study Team 14. The Study team should consist of two or three specialists, including a supply and transportation specialist, and a petroleum market- ing analyst. B. Common Services for OECS Utilities Title: Feasibility Study for Providing Common Services for LDC Power Utility Companies and Enhanced Cooperation Amongst CARICOM Utilities Objectives: The overall objectives of the study are: (a) to review current arrangements in the LDC power utility companies in the areas of operational, and financial system planning, training, technical and financial management and procurement services; (b) to propose how these requirements can best be met so that whatever corporate arrangements are recommended are self- financing; and (c) to assess the role, if any, which the larger utility companies in the region can play towards meeting these objectives, as well as in enhancing cooperation amongst CARICOM utility companies. Cost: Approximately US$80,000 - 100,000. - 59 - Annex I Page 6 of 8 Terms and Scope of Work: 15. There is a need for strengthening the areas of planning, train- ing, technical and financial management and establishing planned mainten- ance programs in the power utility companies in the region, especially in the Lesser Developed Countries 53/ (LDC's). In recent years, a deteri- oration of service, including electrical outages and extensive load shed- ding, has occurred due to financial, technical and managerial problems. Tariff increases have been prevented from keeping pace with increased operating and financial costs; as a result, maintenance programs and development plans have suffered. The very high incidence of power system losses (especially non-technical losses) is but another symptom of this decline. Some of the large utilicies in the region have enough tech- nical, financial and managerial resources to enable them to address some of these issues. This is, however, not the case in most of the smaller utility companies in the LDC's and the situation may worsen with the ex- pected disengagement of che Commonwealth Development Corporation (CDC) from their shareholding and management involvement in those Eastern Caribbean utilities 54/ where they operate at present. 16. In general, the agreements between CDC and the utilities in which it owns concrolling interest cover two main areas: (a) General Agent - under which CDC provides technical and other advice as needed and reviews the management of the company. In addition, important training functions of technical and finan- cial personnel are undertaken. (b) Buying Agent - CDC procures plant, machinery and equipment on behalf of the utility and examines all shipping documents re- lated to purchases. 17. The first cask of the study team therefore is to review current arrangements in each of the LDC utilities in the areas of operational, system and financial planning, training, technical and financial manage- ment and procurement services. Specifically, operations need to be re- viewed from the standpoint of che adequacy of current arrangements and then areas identified which are amenable to a common services approach, focusing on the costs and benefits of pursuing such a path. The study team in this context should focus on the following, inter-alia: (a) Training - especially of technicaL personnel; 53/ Antigua/Barbuda, Dominica, Grenada, Montserrat, St. Kitts/Nevis, St. Lucia, St. Vincent (the OECS countries), and Belize. 54/ Montserrat, St. Lucia and St. Vincent. - 60 - Annex 1 Page 7 of 8 (b) Engineering - the role of a small engineering service group; and (c) Procurement - possibility of common procurement agent. 18. The study team would need next to assess what role, if any, the Larger utility companies in the CARICOM region could play towards sup- porting the provision of common services. 19. The study team will work closely with the CARICOM utility com- panies and Governments in undertaking this work; the team should consist of about three specialists: a power engineer, financial analyst, and an organizational specialist. 20. The principal objective of the study is to propose how the requirements, defined, above can best be met so that the corporate arrangements recommended, if any, will be self-financing. Specific Tasks 21. In summary, some of the specific tasks to be undertaken -in the study include: Ca) Review of the corporate management control exercised and the common service provided by CDC in those utilities where it has equity interests and management control. Undertaking a similar review for those LDC utilities in which CDC does not operate. (b) Determine the degree to which these requirements will change after CDC's withdrawal. Cc) Review current management procedures, technical and accounting capabilities in those OECS utilities in which CDC does not hold equity interests and assess those areas in which capability needs to be strengthened. (d) Assess what actions and policies would need to be instituted to sL:mulate private sector interest in acquiring some equity in the power utility companies, as well as in any new regional common services corporation. (e) Assess the common services which any new regional corporate body would be expected to provide, inter-aLia: - appointment of agents for the supply of spare parts and other commodities from overseas suppliers; - provision of and arranging for engineering services as needed; - assistance for the utility companies in assessing their training needs, preparing programs to fulfill those needs, - 61 - Annex 1 Page 8 of 8 arranging training courses regionally and extra-regionally, and monitoring the results of such training; - advice on management, engineering, financial and accounting matters; and - assistance in preparing capital development programs. (f) Propose the type of regional organization required to cater to these requirements and recommend the measures needed to estab- lish such a body including its consitution, control, financing, staffing and contractual relationships with the power com- panies. (g) Prepare estimates of the operational budget for such an entity for the first two years of its existence. .h) Assess the extent to which the organization could solicit assistance, on a cost-of-service basis, from other, larger power companies in the region. C. Petroleum Pricing Specialist 22. One man-year of advice and assistance to the Eastern Caribbean Island Governments on a reginal basis to set up a petroleum pricing mechanism. Scope of Work: 23. Will work closely with the ministries/departments responsible for petroleum prices/policy. Main tasks would include review of domestic energy pricing structures, pricing policy in relation to development of indigenous energy resources, and preparation of guidelines and developing analytical ability in the ministries/departments establishing petroleum pricing policy and montoring systems. Tercs of reference cover: (a) development of strategy and guidelines for monitoring and reviewing domestic energy prices; (b) economic evaluation of energy project proposals or options; and (c) training of local counterparts in energy pricing and monitoring methods. - 62 - Annex 2 Page 1 of 2 Preliminary Measures and Investments Proposed in Loss Reduction Program 55/ A. Non-Technical Losses 1. Meter Test Equipment: LUCELEC's meter workshop is presently equipped with the most basic of test instruments. The purchase of a test bench to allow simultaneous testing of several meters, as well as pur- chase of precision instruments for calibration of meters and instruments is recommended. Estimated Cost: US$120,000. 2. Meters: Standardization of meters should be adopted, prefer- ably the plug-in socket type. If this is followed, LUCELEC could require new consumers to purchase sockets, with the utility meeting the cost of the meter only. For older installations, LUCELEC will have to bear the replacement cost. To phase out the older meters would require about US$200,000, based on the estimate that about 7,000 meters should be re- placed. Estimated Cost: US$200,000. 3. Meter Inspection: The program of meter inspection and sealing ought to be continued but modified in two important respects. A clip-on meter ought to be used to establish the accuracy of the meter being exam- ined. Clip-on kilowatt meters are available and obviate the need to guess at or measure independently the power-factor, as would be required with a clip-on ammeter. Priority ought to be given to inspecting the meters of the larger consumers. The total number of industrial and commercial consumers on both of LUCELEC's systems is less than 2000. This is a manageable quantity for individual investigations. After all consumers in these two categories have been investigated, attention couLd turn to the larger domestic consumers. Standards ought to be developed to indicate the consumption expected from each location. 4. Training of Meter Technicians: The services of an experienced meter tester for the training of LUCELEC staff in meter testing and in- stallation should be obtained. The training period should last about 4-5 months, and cost about US$15,000. B. Technical Losses 5. The measures highLighted below are additional to what was outlined in paras 3.31 - 3.36. 6. Transformer Load Management: Transformer load management programs relate transformer loading to the energy consumed by the customers connected to each specific transformer. The institution of a 55/ Draft report "Power Loss Reduction Study for St. Lucia" by W. Hay (October 1983). - 63 - Annex 2 Page 2 of 2 transformer load management program will allow monitoring of transformer loading and provide warning of impending overloads. It also will indicate discrepancies between consumption and billing, especially when such discrepancies are large. Further, it provides an opportunity for meters to be related to the feeders from which they are supplied, and thus show which feeders experience the greatest metering losses if the kilowatt meters for the feeders recommended in (3) above were to include integrators. Transformer load management programs are relatively easy to introduce on systems of LUCELEC's size and are easily expanded as the utility grows. They are much more difficult to implement on larger systems. It is recommended that a basic package program, tailored to LUCELEC's needs, be purchased and installed. Estimated Cost: US$30,000. 7. Power Factor and Kilowatt Meters: Feeders 1-4 in the north currently have no such instrumentation. To monitor power factors and active energy loading on all feeders, this instrumentation is required, especially after the capacitor installation. Estimated Cost: US$16,000. 8. Distribution Transformers - Phase Balancing: A drive to balance the phase-loading of distribution transformers, especially the more heavily loaded, must be undertaken promptly. Procedures should be developed and rigorously implemented to ensure a reasonable balance between phases as new consumers are added to, or loads increased for other reasons, on any given secondary distribution system. 9. Distribution Transformers - Load Tests: Although some load testing of distribution transformers is conducted, there is no regular cycle for such tests. Periodic checks ought to be formally instituted and diligently adhered to, whereby each transformer would be tested for loading at least once a year. 10. Distribution Transformers - Dual-Voltage: LUCELEC's long-term plans must include the phasing out of all 2.3 and 6.6 kV 3-phase distri- bution systems. When purchasing new transformers for these systems, it would be advisable to check the economics of dual-voltage units which could operate at 11 kV as well as for the primary voltage at which it would initially operate. In the case of the 6.6 kV system, the objective may be achieved by using three single-phase transformers, suitably con- nected, in place of a single 3-phase unit. 11. Distribution Line Records: Maps of the distribution system should be scrupulously kept up-to-date with regard to all information necessary to determine line performance. This applies to secondary as well as primary lines. 12. Power Station Meters: Because of their importance in deter- mining system performance, the kilowatt-hour, fuel-oil and power-factor meters in the power stations should be calibrated at least once a year. There are plans to replace the fuel-oil meters at Union power station. Those at Vieux Fort at least ought to be recalibrated. - 64 - Annex 3 Recent Investigations of St. Lucia's Geothermal Resources 1975-76 Merz and McLellan and the Institute of Geological Sciences dis- covered a shallow secondary steam bearing reservoir giving an energy equivalent of about 1000 kW from four producing wells out of seven drilled. 1982 Aquater S.p.a. carried out a thorough geoscientific investiga- tion (geology, geochemistry and geophysics), and developed a preliminary model of the geothermal system. They predicted that a saline primary reservoir existed below 1000m from the surface, with temperatures in the range of 200-2500C, and possibly 350C at a deeper level. They recommended drilling three production-size 1500m exploratory wells. 1983 Republic Geothermal Inc. reviewed the previous investigations and carried out limited studies of their own. They agreed with the main findings of Aquater, and recomended a similar program of exploratory drilling. 1983 Los Alamos National Laboratory reviewed existing studies, ac- cepted the principal conclusions of Aquater, and have under- taken to prepare a three-dimensional model of the geothermal system in order to select drilling sites for the exploratory wells with maximum probability of success. This study was completed in May 1984. - 65 - Annex 4 Page 1 of 8 Table 1: CDP TRENDS 1977-1982 (1977 PRICES) 1977 1978 1979 1980 1981 1982 GDP (Million EC$) 154.5 177.9 186.6 187.4 188.0 187.4 Annual Z Growth 15.1 4.9 0.4 0.3 (0.3) Z of GDP Agriculture 15.5 16.4 15.1 12.9 13.0 14.2 Manufacturing 10.6 10.4 8.7 10.2 10.2 11.5 Construction 6.9 10.0 10.7 11.2 11.8 8.3 Hotels & Restaurants 6.9 6.5 6.8 7.2 6.2 6.4 Source: St. Lucia Economic Review 1982, Ministry of Finance, Planning and Statistics. Table 2: ESTIMATION OF FUEL USE FOR TRANSPORTATION: NUMBER OF VEHICLES REGISTERED AND LICENSED IN 1982 Registered Licensed Mean Private Cars 4,940 3,319 4,130 Taxis 662 461 560 Mini-buses 863 632 750 Pick-ups 1,345 989 1,170 Vans 463 268 370 Land Rovers 225 79 150 Motor Cycles 351 181 270 Trucks 464 254 360 Other Classes 545 279 410 Source: Annual Statistical Digest, 1982. Due to disparities between the number of vehicles registered and licensed, the mean has been used to estimate energy use (Table 1). This is not unreasonable because registrations are likely to over-esti- mate the number of vehicles since some will have been scrapped or not run, while licenses will underestimate by excluding those vehicles which are operated illegally. Total fuel use for each category was calculated based on esti- mates of fuel efficiency (miles per imperial gallon) and annual mile- age. These are shown in Table 3. - 66 - Annex 4 Page 2 of 8 Table 3: ESTIMATION OF FUEL USE BY VEHICLE CATEGORY Fuel Annual Efficiency a/ Annual b/ Fuel Use Vehicle Type Number (mpg) Mileage ('000 IC) Private Cars 4,130 25 6,000 990 Taxis 560 20 12,000 340 Mini-buses 750 15 17,000 850 Pick-ups L,170 18 15,000 980 Vans 370 18 10 ,000 210 Land Rovers 150 18 10,000 80 Motor Cycles 270 100 6,000 20 Other Classes 410 18 6,000 140 Trucks 360 8 10,000 450 a/ Based on mission estimates and 'St. Lucia Energy Needs Assessment', C.F. Granger, CARICOM, 1982. -i Mission estimates. The largest consuming categories are private cars (24%), pick- ups used mainly for freight (24%), and mini-buses which constitute the public transport system (21Z). Table 4 shows fuel consumption by type of fuel and transport subsector. Table 4: FUEL CONSUMPTION BY TRANSPORT SUBSECTOR AND FUEL TYPE ('000 IG) Sector Gasoline Consumption Diesel Consumption Total Private a/ 1,290 1,290 Public b/ 1,190 1,190 Freight c/ 1,130 450 1,580 Total 3,610 450 4,060 a/ Private cars, land rovers, and motor cycles. bJ Taxis and mini-buses. c/ Pick-ups, vans and other vehicles use gasoline, while trucks use diesel. Based on these assumptions, freight is the largest consuming sector (44%), followed by public transport (29%), and private vehicles (27Z). Diesel accounts for 25% of freight fuel consumption and only 11% of total fuel consumption in the transportation sector. - 67 - Annex 4 Page 3 of 8 Table 5: ST. LUCIA ELECTRICITY SERVICES LIMITED GENERATION PLANT DATA AT DECEMBER 31, 1962 Economical Lifetime Year of Rating or Hours run Co.ls- Installed Continuous to Dec. 31, Unit Description sioning Capacity Capacity 1982 R.P.M. kW tNl41N 1 Allen VBCF 37F 1972 2,670 2,500 43,489 600 2 Alien VBCF V 1971 2,670 2,500 56,419 600 3 Allen VBCF 37F 1971 2,670 2,500 59,459 600 4 Allen VBCF 37F 1976 2,670 2,500 32,785 600 5 EnglIsh Electric 16 SVA 1970 1_425 1.250 22,806 750 12,105 11,250 VIEUX-FORT I English Electric 12 SVA 1971 1,040 1,000 54,866 750 2 English Electric 12 SVA 1971 1,040 1,000 58,960 750 3 English Electric 12 SAV 1964 1,020 1,000 69,531 750 4 English Electric 12 SAV 1965 10 I.o000 72,719 750 4,120 4,000 Annex 4 Page 4 of 8 Table 6: ELECTRICITY STATISTICS FOR NORTHERN SYSTEM, 1976-1982 1976 1977 1978 1979 1980 1981 1982 Electricity Genoration (GWh) 34,36 38,08 43,14 46,27 45,28 48,83 50.41 Fuel Consumption (000 IG) 2065,4 2291.5 2584,1 2874,0 2904,1 3000.3 3065.6 (kWh/lG) 16,64 16,62 16,69 16.10 15.59 16.28 16.44 Maximum Capacity (MW) 10,40 10,40 10,40 10,67 12,14 12.09 12.09 Maximum Demand (MW) 6,00 6,65 7,15 7,40 8,00 8,55 8,35 System Load Factor (5) 65,4 65.4 68.9 66,9 64,6 65.2 68,9 Own Use (GWh) 1,92 1,94 2,12 2,19 2,18 2,50 2,74 (5 Gross Generation) (5.6) (5.1) (4.9) (4,8) (4.8) (5.1) (5.4) Line Losses (GWh) 5.51 6.61 7,75 7,10 8.68 10.41 12,19 co (% Net Generatlon) 17.0 (18,3) (18.9) (16,1) (20,1) (22.5) (25,6) Final Sales (GWh) 26,93 29,53 33,26 36,98 34.42 35,92 35,48 Domestlc 7,52 7.87 9,24 10.32 9,88 11.05 11,42 Commercial 15.20 17.53 19,63 21,97 20.55 20.01 20,49 Industrial 3,69 3,60 3,82 4,04 3,31 4,13 2,82 Street Llghts 0,52 0.53 0,57 0,65 0,68 0.73 0.75 Source: LUCELEC Annex 4 Page 5 of 8 Table 7: ELECTRICITY STATISTICS FOR SOUTHERN SYSTEM, 1976-1982 1976 1977 1978 1979 1980 a/ 1981 1982 Electricity Generation (GWh) 10,49 11,80 13.52 14.48 13.09 13.13 13,44 Fuel Consumption (000 IG) 647.5 743.8 913.4 971,1 882,5 899.1 903.6 (kWh/10) 16,20 15,86 14,80 14,91 1483 14.60 14,87 Maximum Capacity (MW) 4.30 4.30 4,20 4.12 4,20 4,12 4,12 Maximum Demand (NW) 2,10 2,16 2,40 2,70 2,70 2.40 2,62 System Load Factor (%) 57.0 62.4 64.2 65.1 55.3 62.5 58.6 Own Use (GWh) 0.62 0,54 0.57 0.59 0,56 0,53 0.55 (S Gross Generation) (509) (496) (4.2) (3.8) (4.3) (3.9) (4.1) Line Losses (GWh) 1.61 1,89 2,21 2.20 0.94 2.67 2.53 '0 (% Net Generation) 16.3 16,8 17,1 14,9 7,5 21,2 19.6 Final Sales (GWh) 8.25 9.36 10.75 12.60 11.59 9.93 10,36 Domestic 1.70 1.78 2.08 2.66 2.23 2.46 2,88 Comerclal 3.79 4.23 4,55 5,79 5,23 3,76 3,88 Industrial 2,56 3,13 3,89 3,90 3.85 3,42 3,31 Street Lights 0,20 0.23 0,22 0,25 0,28 0,29 0.29 a/ Huricane year. Drop In line losses because only consumers close to station were served, Sourcet LUCELEC. - 70 - Annex 4 Page 6 of 8 Table 8: ELECTRICITY SALES, DEMAND AND GENERATION - 1982 ACTUAL AND FORECAST (1983-90) 1982 1983 1984 1985 1986 1987 1988 1989 1990 (Actual) SALES CGWh) North (Mission) 35.48 3828 40.26 41,56 43,27 44.34 45.89 47.61 50.00 South (Mission) 10,36 11.45 11.48 12.53 12,89 13.54 14.18 15.04 16.03 Total (Mission) 45.83 49.73 52.10 54.09 56.16 57.88 60.07 62.65 66.03 Total (LUCELEC) - 48.33 50.69 53.18 55.83 58.62 - - - OWN USE a/ (GWh) North 2.72 3.44 3.37 2.93 2.83 3.33 33,3 3,46 % (5.4) (6.4) (6.2) (5.4) (5.2) (6.2) (6.2) (6.2) 5.02 South 0.55 0.57 0.58 0.60 0.61 0.63 0.65 0.69 (6.4) % (4.1) (4.0) (4.0) (4,0) (4.0) (4.0) (4.0) (4.0) LOSSES b/ (GWh) Technical North 7.01 7,78 7.14 6.67 6,18 5.04 4.03 4.19 % (14.7) (14.7) (14.0) (13.0) (12.0) (10.0) (8.0) (8.0) South 1.57 1.67 1.59 1.59 1.47 1.35 1.25 1.32 6.60 S (12.2) (12.2) (11.5) (11) (10) (9) (8.0) (8.0) (9.0) Non-Technical b/ North 5.15 4.24 3.57 3.08 2.06 1.01 0.50 0.52 % (10.8) (8) (7) (6) (4) (2) 1.42 1.49 1.57 South 0.95 0.55 0.42 0.29 0.29 0.15 0.16 0.17 (1.0) % (7.4) (4) (3) (2) (2) (1) (1) (1) GENERATION (GWh ) North(Mission) 50.14 53,74 54.34 54.24 54,34 53.72 53.75 55.78 78.38 C/ South (Mission) 13.44 14.24 14.43 15.01 15,26 15.67 1624 17.22 -- Total (Mission) 63.85 67.98 68.77 69.25 69.60 69.39 69.99 73.C;; 78.38 Total tLUCELEC) - 65.04 65.58 67.77 69.34 72.17 - _ - PEAK DEMAND (kW) North (Mission) 8,350 8,900 9,200 9,400 9,600 10,000 10,500 11,000 11,500 (LUCELEC) - 8,600 8,858 9,124 9,398 9,680 - - - South (Mission) 2,620 2,830 2,970 3,100 3,250 3,400 3,600 3,780 3,870 (LUCELEC) -- 2,750 2,832 2,917 3,005 3,094 - - - Interconnected d/ - - - - - - - - 15,470 LOAD FACTOR % North (Mission) 68.9 68.9 67,4 65.9 64.6 61.3 58.4 57.9 - South (Mission) 58.6 57.4 55.5 55.3 53.6 52.6 51.5 52.0 - I nterconnected - - - - - - 57.8 a/ Own use expressed in GWh and as a % of gross generation. b/ Technical and non-technical losses in GWh and as a % of net generation. cl First 5,000 kW geothermal uniit assumed to come on stream in July 1990 at Soufriere and assumed to generate 14 GWh base load in the last half of 1990. d/ The North and South systems to be interconnected by 1988. - 71 - Annex 4 Page 7 of 8 Table 9: PROBABLE ELECTRICAL SYSTEM EXPANSION, 1982-90 Item/Year 1982 1983 1984 1985 1986 1987 1988 1989 1990 Actual Peak Demand (kW) North 8,350 8,900 9,2Mi 9,400 9,600 10,00 10,500 11,000 11,500 South 2,620 2,830 2,970 3,100 3,250 3,400 3,600 3,780 3,970 Interconnected - - - - - 15,470 Rated Capacity es (kW) North 12,105 12,105 14,775 14,775 14,775 19,775 19,775 19,775 19,775 South (Soufriere) - - - - - - - - 5,000 South (Vieux Fort) 4,120 4,120 4,120 5,120 5,120 5,120 5.120 4,120 2,040 Interconnected - - - - - - - - 26,615 Available Capacity (kW) North 11,300 11,300 13,900 14,100 14,100 19,100 19,100 19,100 19,100 South (Soufriere) - - - - - - - - 5,000 South (Vieux Fort) 4,000 4,000 4,000 5,000 5,000 5,000 5,000 5,000 2,000 Interconnected - - - - - - - - 26,100 Firm Capacity b/ (kY) North and Soufriere 8,800 8,800 10,000 10,200 10,200 11,500 11,500 11,500 - South (Vieux Fort) 3,000 3,000 3,000 4,000 4,000 4,000 4,000 4,000 - Interconnected - - - -- - - - - 16,100 3/ Capacit' additions: North - Union Station 1984 I x 2670 kW diesel South - Vieux Fort Station 1985 I x 1000 kW skid-mounted diesel. North - ul-de-Sec Station 1987 1 x 5000 kW medium speed diesel. South - loufriere Geothermal No. 1 1990 I x 5000 IW geothermal unit. North - 1000 kW skid-ounted unit transferred from Vieux Fort to Cul-de-Sac in 1991. a/ Capacity retirements: South - Vieux Fort Station 1990 retire Units Nos. 4, 2 and 3, (2 x 1020) and (1 x 1040 kW) South - Vieux Fort Station 1991 Close station and retire unit 1. b/ For southern system firm capacity defined as available capacity minus largest unit. For northern system firm capacity defined as: - up to 1983 available capacity minus largest unit; - 1984 to 1986 - available capacity minus largest unit and smallest unit; - 1987 to 1990 - available capacity minus two largest units; For interconnected system - 1990 available capacity minus geothermal unit and largest diesel unit on system. - 72 - Annex 4 Page 8 of 8 Table 10: MAJOR ENERGY CONSUMERS IN ST. LUCIA - 1982 Electricity Diesel LPG ('000 kWh) (gallon) (lbs) Hotels Halcyon Days 2,020 17,000 190,000 La Toc 2,927 6,900 125,000 St. Lucian 1,540 - 165,000 Halcyon Beach 827 - 186,000 Cariblue 950 1,500 71,300 Couples Malabar 640 7,200 43,000 Red Lions 260 2,300 21,000 ILnds Brewery) 1,030 91,500 a/ - Winera (Packaging) 580 c/ 103,000 Copra Manufacturing Ltd. b/ 350 80,000 at Commercial Cable and Wireless Ltd. 1,300 c/ 5,000 St. Lucia Cold Storage 350 c/ Canadian Imperial Bank of Commerce 160 c/ 500 Government Central Water Authority 2,860 c/ - Victoria Hospital 250 11,700 17,000 a/ Bunker 'C' included. b/ Estimates. c/ kWh derived from cost. IBRD 17612 aoso NOVE di IM ST. LUCIA POWER SYSTEM Cop Estate CosEn Bas uos Gras Islet UPower Stations Jt qIwwx Transmission Lines- * ~ 11 Iky. Circuit Castri eft /e° 1) 6.6 kLv. Circuit -- Bogus -5 6.35 kv. Circuit -1W00 7,Mrarchand *_ j J U P H N A Geothermal Potential dla Oil TrCshiprsnt Terminal z.ner 3mop-1 n Retail Gas oins Marigot 0Barre W_ Major Town S.-' (~~bMwc Dern~ere Riviere Roadcs LeonbM otco1 < --- Porish Boundrhie- Anse La Roye BaJptste anar /Ricke C oriesMlle a' ' St Joseh n ry _\ ~~I - - An# J * 'o' \ ~~~~~~~~~~~~~~~~ Pro slY Anse Chostanet P 2 A S L I N Soufrir s; DRI E E , Mhu L binte Molgretoute A t 9 Fond Si _ Lo Poate o , LjO ,2otcEstote" - K' nser Chaiseul ) 4~~~~~~~~~~~~~~N \ul ~~'~~~~~3rboan ~~~~~~CUBA MAILES * i 25 ICILOMETERS ~~Vme x~ GUSEOu3 rb.eu FAortgoW ~- W.o -~~~~~~~~~~~~~~~~~~~~~~6' coo1. _s w_-tvrlo r__ DKA"E -~ .- b-mg'w-.a.. 71, IbYM t,. I' cos8 88 0'72: U.S.A. BR AND 84AhAMA / 24 GREAr ABACO i NEW PROVIDENCE ELEUrHERA I -4 ANDROS IS CAT I SAN SALWON or Or EXZAMA t mm C4Ari u/G I LONG MSLAAO C ACYLhiM ISLUA M A4A i CA/COS and rURKs /S PINOS S Gr IASGUA I 0 CAYMAN IS HAITI ' DOMINICAN * REPUBUC . '-S.. JAMAICA t Com'rno ill.t 35, 500 -' 1 _ 'BELIZE /GUATEMALA B 4cOoj bCrmez r HONDURAS , L ,> , PtCubezcs SALVADOR) 1 ( - Isabel AR jA NICARAGUA ARUBA . bIonI,f,Idl 50nAndres . r___ /~~~~~~~~~~~~~~~ COSTA S P1 t-on J RICA ,. A 1 'x/ P ^ o , V E C 0 L 0 M B r'ls nw hoas beon ,orawr * rdby ThY. Wfd1bok ' .ai ..cA-.n* J. I,ho cr o-ronc. of se reds and s n,scks.e tok m. I.-rlm- us5 of Thre Wk.ld Bsank am h,o.Malhonai Fo,anco Cor,nraIo The demosoaf us.rd ard Nt, boudarms shoen on th1S oW, do not '"ely. orkm v.d of Thre Wlhd B..nu and m:, ln,-otal F-ce Cvo,alvn. anY mpdnse' on J- m,. siraru of any,- d-rrfly or *nv iewn,smnf o acceoI.,C of such bowudsOs 88 80so 72 I BRD 17800 712- 64 5JANUARY 1984 EASTERN 24- CARIBBEAN REFINERIES Vi. AND TRANSPORTATION ROUTES WAIM?DW I A48,000 REFINERIES WITH CAPACITIES IN BARRELS PER DAY TANKER SAILING DISTANCES IN MILES MA010A5S I --*---- INTERNATIONAL BOUNDARIES CAICOS and TURKS IS O I00 2D0 300 400 500 KILOMETERS HAITI DOMINICAN 2r a0 360 MtLES rAOMASt ANGUILLA I J REPUBLIC 1 48,000 Puerto SrTAARrfN Eo- La Ro.,na Rico k 12300 a4IIUDAI Dom-aw s7 CRo,IlxI sr K/ITrS I AfaVusRArz JCLO OMINCA A I- ., /MAlASrNXx1- ST LUCIA I sr. v1hNcfEr t { 42 3000 GAID ARIV8.4 I CLOWC401.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ATN0. B"W I~~~~~~~~~~~BAA0SI A36-2000 WRCiAlffrA TRINIDAD AND TOBAGO , 2000 MA RGARI TA / M.34000 JR 1,283 700 Pu-?eo la Cuz ) 0~~~~~~~~~~~~~~~~~~~~~~1 V E N E Z U E L A ' C E,w.u, Pmamor,bo StLaue.nt <~~~~~~ J rv . SURINAME L O ~M B I A t '=I/r] _/___ ~ ~-~ ~ I r B R A I I__, ',,. J- ~ 7Z° \ 6^° 56-~~~/