Report No. 6915-C;A Gabon: Issues and'Options in the Energy -Sector July 1988 .o 29> ' "' 'O r. Jg, H }/1'' > ; is JOINT URDPIVORLD BANK 8ENEGY SCWTOR ASSESSN3NT PROGANM Reports Already Issued Country Date Npmber Indonesia November 1981 3543 JD Mauritius December 1981 3510-MAS Kenya May 1982 3800-KE Sri Lanka May 1982 3792-CE Zimbabwe June 1482 3765-ZIM Haiti June 1982 3672-BA Papua New Guinea June 1982 3882-PNG Burundi June 1982 3778-BU Rwanda June 1982 3779-RW Malawi August 1982 3903-MAL Bangladesh October 1982 3873-BD Zambia January 1983 4110-ZA Turkey March 1983 3877-TU Bolivia April 1983 4213-BO Fiji June 1983 4462-FIJ Solomon Islands. June 1983 4404-SOL Senegal July 1983 4182-SE Sudan July 1983 4511-SU Uganda July 1983 4453-UC Nigeria August 1983 4440-UNI Nepal August 1983 4474-NEP The Gambia November 1983 4743-CM Peru January 1984 4677-PE Costa Rica January 1984 4655-CR Lesotho January 1984 4676-LSO Seychelles January 1984 - 4693-SEY Morocco March 1984 4157-MOR Portugal April 1984 4824-PO Niger May 1984 4642-NIR Ethiopia July 1984 4741-ET Cape Verde August 1984 5073-CV Guinea Bissau August 1984 5083-GUB Botswana September 1984 4998-BT St. Vincent and the Grenadines September 1984 5103-STV St. Lucia September 1984 5111-SLU Paraguay October 1984 5145-PA Tanzania November 1984 4969-TA Yemen Arab Republic December 1984 4892-YAR Liberia December 1984 5279-LBR Islamic Republic of Mauritania April 1985 5224-MAU Jamaica April 1985 5466-JM C8te d'Ivoire April 1985 5250-IVC Benin June 1985 5222-BEN Continued on inside back cover FOR OFFICIAL USE Report No. 6915-CA GABON ISSUES AND OPTIONS IN THE ENERGY SECTOR JULY 1988 This is one of a series of reports of the Joint UNDP/World Bank Energy Sector Assessment Program. Finance for this work has been provided, in part, by the UNDP Energy Account, and the work has been carried out by the World Bank. This report has a restricted distribution. Its contents may not be disclosed without authorization from the Government, the UNDP or the Vorld Bank. 3 Gabon possesses significant petroleum, natural gas, hydroelectric and forestry resourceso. The commercial energy consumption per capita (600 kgoe in 1985) is high compared to other countries of Sub- Saharan Africa. The mission preliminary estimates of the total fuelwood consumption per capita was about 390 kgoe, making the total per capita energy consumption per capita in 1985 990 kgoe. The mission reviewed energy sector development and investment plans following the drop in 1986 in international oil prices. As agreed with the government, the present report focuses mainly on petroleum and electricity subsectors which were the most affected by oil price decline. Utilization of natural gas has also become ' priority issue since the discovery of large resources. The report addresses other issues and evaluates options related to (a) optimization of oil production so as to sustain economic recovery; (b) a restricted power investment plan; and (c) development of coherent pricing policies to promote efficient energy supply and consumption. Finally, it recommends institutional reforms pertaining to energy sector planning, management and coordination. BEICIP Bureau d'8tudes Industrielles et de Cooperation de l'institut frangais du p6trole COGER Compagnie Gabon Elf de Raffinage DG8 Directorate General of Energy DCH Directorate General of Hydrocarbons GPP Groupement Professionnel des Pktrolidrs IMP International Monetary Fund MEER Ministry of Energy and Hydraulic Resources- - MHBP Ministry of Pinance, Budget and Participations MMH Ministry of Mines and Hydrocarbons MPg Ministry of Planning and Economy OPEC Organisation of Petroleum Exporting Countries Petrogeb Soci4te Nationale P6troli4re Gabwaaise 8ggG Soci6t6 d'Energie et d'Eau du Cabon SGEPP Soci6t6 Gabonaise d'Entreposage des Produits p6troliers SNgA Soci6t6 Nationale Elf Aquitaine SOBRAGA Soci6t6 des brasseries tu Gabon SOGARA Soci6t6 Cabonaise de Raffinage SPA!E Societe des P6troles 4e l'Afrique Equatoriale UNDP United Nations Development Programme bbl barrel b/d barrel(s) per day bly barrels(s) per year BSCV billion standard cubic feet BTU British Thermal Unit CIP cost, insurance, freight DER Directorate of Regional Exploitations PCV Franceville GOP gross domestic product GWh gigawatt-hour ha hectare hi hectoliter RV high voltage kcal kilocalorie kg kilogram kgoe kilograms of oil equivalent km kilometer km' square kilometer ktoo thousands tons of oil equivalent kVA kilovolt-ampere kY kilovolt kV kilowatt kWh kilowatt-hour 1 liter LIV Libreville LPC liquefied petroleum gas LV low voltage m meter 23 cubic meter NCP thousand cubic feet NHBTU million British Thermal Units WYA megavolt-ampere NV medium voltage M3 megawatt jjm3 nortal cubic meter MR! Northwest Europe POC Port-Gentil toe tons of oil equivalent ton metric ton yr year aURUC D AMF EQUnIVALUS Currency Unit - CPA Franc (CFAF) Lichange PAte: 350 CFAF/US$ 1 a/ Fuel Calorific Velue too (million kcal/ton) Crude Oil 10.2 1 LPB (Butaer) 10.8 1.059 Gasollne 10.5 1.029 Jet Fuel 10.4 1.020 Kweosene 10.3 1.007 Gas ol1 10,2 1 Fuel 011 9.7 0.951 Firewood 3.5 0.343 Charcoal 7.0 0.6863 Natural gas 253.0 k/ 22.84 S/ Elect&rcitX 4000 kWh a 1 toe for hydroelectrlc supply on a thermal replacement basis (thermal officlency 34.04). 1 GMh u 86 toe (thermal replacement value). a/ Exchange rate at tl.e of mission. Rate used In the roport, unless otherI se noted . bl MIIIIon kcal W6f ;/ tce/W4MF TAML Or COUT11111 Page SUMMARY AND RECOIMONDATIONS..........*.......................... i I. THE KERGY SECTOR IN G ... 1 The goog.............. ......... .e.e ceeco....c c .e.c......... 1 Initial Impact of the Oil Price Decline................ 2 Energy 2esources ..................ecc..... 2 Energy Consumption4 ......... ...... ;c.......... ..... 4 II. HYDROCARRON EXPLORATION AND DEVEL0PMHKT..**................. 8 Background .... * .....................................0*6 8 Geology of the Region .......... .. e8.e.c..... c cec- 8 Exploration and Production History........o...........e.. 9 Past Activities..oeeocoo..oocoe..o.t.o.eceooe. e.ccc.eo 9 Current Activities.................................... 10 Future Petroleum Production Prospects*.***..*..**o*.****. 11 Development of Proven Reserves... ..-.-..... 11. Oil Production Scenarios.o ...c.e....... 12 Legal and Fiscal Framework ......................... *...... 13 Sector Organization... ..o.oo............... *.e.c.... . 15 Potential for Natural Gas Development.*o0 ......... .... 16 III. PETROLEUM SUPPLY AND DISTRIBUTION ... 19 Petroleum Product Demando. ....................o.......... 19 Petroleum Refiningz.eo.o....o. o......e. *e oo.....o..e.co 20 Supply Arrangements for Crude Oilile.ce.ccceceeo..e.e.. 21 Product Marketing and Distribution ....................... 22 Marketing Ar rang anntgements................... 22 Financial Difficulties of PIZO. I ZO...............000.. 22 Product Distribution Strategy...........to............. 24 Institutional Issueso..o........... .soo .c e..oc.oe.e..00.0 26 Petroleum Product Pricing.c. 28 Ex-Refinery Prices...eo....o.o...o.o ......... ..-.oo... 28 Retail Price Structuresoo..... *oe ......cc....c.c...co.. 32 IV. ELECTRIC .Oge................. .. ............. 37 Introductior...... #&..... **oo9O**....a as .eeaa ..s***eae 37 Main System Characteristics.............. .... .... *..... 37 Generation and Tran s mi ssion.............................. 38 Distribution........................ee...........e..... 40 Demand Characteristic. 40 Demand P isf i l e s 40 Demand Forecasts r e c a s ts..........................e.... 41 Medium-Term System tievelopment: 1987-19957............... 42 Long-Term System Development 45 Interconnection of LBV and POG 45 Other Subsector Isus*.......*49 Electricity Tari ffs 49 Reform of Public Service Regulations................... 53 S8EG's Financial Si tia t i o n 55 TABLES 1.1: Gabon - Indicators of Commercial Energy Consumption 1978 - 1 6 1.2: Gabon Energy Balance, 1985 7 2.1: Annual Petroleum Production by Operator, 1976-1986....... 10 2.2: Projected Annual Output of Fields Currently in Productionoo*ee**ooooeo*******ooo.ooooosoo*ooo*oo*****# 11 2.3: Projected Oil Production, 1986-l992.*$o.................. 13 2.4: Projected Development Expenditures, 1986-1991,......... 14 3.1: Domestic Petroleum Product Sales, 1980-1985...........*. 19 3.2: SOCARA Refinery Characteristics ......................... 21 3.3: Domestic Market Shares of the Distribution Companies by Product, 1985 23 3.4: Retail Market Indicators for Petroleum Products, 1985....... .......... g.e...... e.g.................. .... 26 3.5: Suggested Investment Program 1987-1991.7-1991*0006*060600 27 3.6: Comparison of Ex-Refinery Prices and Import Parity, 1986 30 3.7: Major Components of the Petroleum Froduct Price S t r u c t u re................. ........... ................. 33 3.8: Evolution of Taxes and Subsidies on Petroleum Product Prices 35 4.1: Main SEEG System Characteristics, 1985....9 8 S............ 38 4.2: Cabon Electricity Sales - 1985.... 41 4.3: Revised Electricity Demand Forecasts: 1986-1995.......... 43 4.4: Potential Hydroelectric Plants near Libreville........... 46 4.5: Projected Investment Program for Electricity Subsector 1987-1995 48 4.6: SEEG Tariff Study - Low Voltage.......................... 51 4.7: SEWG Tariff Study - Transmission and Medium Voltage...... 52 4.8: Arrears Payable on SEEG Accounts...............o........ 55 1 Gabon: Commercial Energy Consumption..................... 58 2 Investment Expenditures for Petroleum Exploration, 1977-1985 .......S . 9 3 Gabon - Well Drilling History, 1976-1985................. 60 4 Investment Expenditures for Petroleum Development, 1 9 7 6 - 1 9 85............ Ge...... ........ CC G#O***9O** CCC *00 61 5 Natural Gas Utilization Feasibility Study - Draft Terms of Reference . ..................... 62 6 Gabon: SOGARA Production 1975-1985....................... 65 7 BEICIP Scenarios for Petroleum Product Demand*........... 66 8 Petroleum Product Demand and Investment Requirements ..... 67 9 Regional Petroleum Product Price Structure .............. 69 10 Petroleum Product Transport Costs........................ 74 11 Price Structure for Butane sold in Libreville and Port-Gentil, March 18,1985......................... 77 12 Electricity System Data . ................ .. eee. 78 13 Electricity Demand: l9801985...e...... .... .eee 81 14 Characteristics of Instalied Hydro and Thermal Plante.... 82 15 Electricity Consumption and Sales by Voltage and Type of Consumer, 1985.... ... ...... ..... 83 16 BERG Demand Forecast - 1984L8 17 H ydraulic Potential.......e .....e.....ea 88 18 BUG-Personnel ......................e.. 89 19 8EEG Customers - l975l9BSe................ ..e 90 20 SREG Operational Expenditures.........................****.. 91 21 SBEG: Past Investments . .e. ee. 92 22 SEEG Organization Chart....... * ..... ...... 94 23 SBEG Tariffs ......................... .... .. 9e..e 95 24 Household Energy Draft Terms of Reference ........ .e.. 99 S8_MAY MD Scope of Inquiry 1. This Energy Assessment Report summarizes the findings of a mission fielded in October/November 1986. 1/ The mission coincided with a period of marked uncertainty for the Gaboneose authorittes. its various economic development and investment plans were being revised following a severe drop in international oil prices. Although a comprohensive review of the entire energy sector had been planned, the anticipated macro- economic repercussions of the oil price decline (para. 1.6-1.7) modified Government priorities, as well as those of the mission. Consequently, the mission chose, with the agreement of the Government, to highlight, issues whose key parameters had been altered by 'the oil price decline, thereby affecting short- and medium-term decisions. 2. As a result, this report Ifocuses mainly on the petroleum and electricity subsectors. Utilization of natural gas as a long-term option of electricity generation (para. 4.27-4.31) has also bocome a priority issue since the discovery of large reserves which will allow for the supply of natural gas to the Socisto d'Energie et d'Eau du Gabon (SERG) at competitive costs. A decision regarding natural gas is important in the short term. Terms of Reference for an in-depth gea fesibility sLudy, to be undertaken immediately, are given in Annex 5. 3. The remaining issues addressed by the mission fall into the following general groupings: (a) the best strategy to simultaneously maximize the present value of remaining petroleum reserves and optimize current crude oil production so as to sustain economic recovery, with emphasis on contractual arrangements to provide incentives for exploration and development; (b) competitivity and efficiency of petroleum product supply to the domestic market, including arrangements for procuring crude oil 1/ Members of the assessment team were: Abderreazak Ferroukhi (Mission Leader, Senior Energy Economist), Lori A. Perine (Economist), P. Vernet (Energy Economist, Consultant), G.R. Rhoury-Haddad (Consultant, Petroleum Exploration and Production), L. Ceccaldi (Consultant, Petroleum Refining and Distribution), and D. Dufrenoy (Consultant, Electric Power). Ms. Wline Talon assisted in translating sections of the report and was responsible for report processing. Ms. Perine was the principal author of the report. - ii - and refined products, and product distribution and storage requirementsg (c) priorities for revising and scheduling electric power investment requirements in the short- to medium-term, as well as long-term considerations; (d) development of coherent pricing structures and policies te promte efficient energy supply and consumption; and (e) requirements for institutional reform to enhance sector coordination and planning, and to address various financial management problems. 4. Several other issues normally found in an energy assessment report were excluded from this exercise. These include: household energy; supply and demand of woodfuelsl; ad utilization of agricultur&l residuei and other non-conventional energy resources. Gabon has very little information on these areas at present. The Ministry of Energy and Hydraulic Resources (MEMR) has commissioned a study of household energy, and its results were expected in late 1987. Based on a review of the terms of reference, it seems that the study will give a rough estimate of global household demand. It will not, however, categorize the extent to which particular fuels are consumed, or the purposes for which they are used. Nor will there be a systematic examination of the supply networks for household fuels (most importantly woodfuels). The mission has annexed to this report (Annex 24) draft Terms of Reference for a house- hold energy survey which would provide such information. In order to round out its energy data base, ths Government should consider launching similar inquiries within the agriculture sector and among small indus- trial consumers to gather information on the use of non-conventional fuels in other sectors. Both surveys can be postponed for the medium term. Overview of Energy and the Economy 5. The Gabonese Republic possesses significant petroleum, natural gas, hydroelectric, and forestry resources. Proven petroleum reserves, at present, are almost 961 million barrels (bbls) (para. 1.9). Associated natural gas production was estimated at 2.0 billion Nm in 1985. It will substantially increase after the development of the discoveries, confirmed in 1987: Rabi and Coucal particularly. The Ogoou4 River and its tributaries provide the country with a hydroelectric potential of 5OOOO Clh/yr, only 1X of which is developed. Dense tropical rain forests cover over 22 million hectares (ha), or 80X of Gabonese territory. 6. Per capita commercial energy consumption was estimated as 600 kilograms of oil equivalent (kgoe) in 1985. The addition of mission - iii - estimates of fuelwood consumption among the rural populace (less than half the total population) increases this figure to almost 990 kgoe, which is high compared to the neighboring countries of West Africa. Petroleum products account for over 73% of net domestic consumption (excluding primary consumption of crude oil and natural gas by the petroleum industry), while woodfuels -snd electricity account for 161 and 10 respectively. Natural gas is used exclusively for the production of secondary energy (electricity) or in petroleum production, and so does not enter the national energy accounts under net domestic consumption (Table 1.2). The petroleum industry is the largest energy consuming sector in Gabon, although most of its consumption is in the form of primary energy (associated natural gas reinjected ror crude production and crude oil consumed in refining operations). The structure of final demand is 33X households, 281 nonoil industry and 171 transport, 81 petroleum industry, and 111 public sector/civil works. 7. The energy sector has played a crucial role in the development of Gabon since the early 1970s, when petroleum output emerged as the major determinant of national economic activity. Following a rapid expansion resulting from accelerated oil production and increasing oil prices, heavy external borrowing in the late 1970s to support an ambitious public investment program led to an external debt and liquidity crisis. The crisis lasted for about two years (1977-78) before the second *.nternational oil price increase helped fuel economic recovery from 1530 to 1984. The petroleum sector represented 45X of GDP and petroleum revenues made up 661 of total government receipts. 8. The economy grew sluggish in early 1985, then was shaken considerably by the drop in oil prices at the end of the year. Although short-term projections to 1990 indicate continued economic difficulties, the picture is likely to improve substantially by the mi4-1990s, fundamentally due to increased oil production and improved oil prices. In the short run, however, oil revenues could top 200 billion CFAF (constant 1985 prices), but this is still only about 551 of 1985 levels. The potential for significant increases in government revenues from other sectors during this period is limited. Thus the Government will be forced to curtail recurrent expenditures and all but essential investments. Priority Petroleum Subsector Issues Optimizing Production of Crude Oil 9. Most petroleum fields currently in production have been fully developed and now are undergoing a natural decline in output. Their combined annual output will not be enough to sustain current production levels (8 million tons) until 1990 (Table 2.2). The development of crucial new discoveries, such as the Rabi field (para. 2.10-2.11), as well as the Coucal field (para. 2.12), also would be necessary to sustain - iv - production. The projections of annual oil production .n Table 2.3 indicate that development of Rabi will be essential to maintaining production levels above the 8 million tons/yr threshold after 1990. These projections do not. take into account the possibility that fields other than Rabi and Coucal could be developed and brought into production. However, they do emphasize the importance of Rabils output for the short- to medium-term recovery of the e^onomys without this production, oil revenues have little chance of regaining pre-1905 levels. 10. The strategy adopted by the Government in order to simultaneously approach these two goals should consist principally of providing the proper fiscal and legal framework for encouraging development, especially during periods of oil price uncertainty such as occurred in late 1985/early 1986. The Government should take advantage of its expanded role under newly adopted production-sharing contracts '(para. 2.18-2.21) to: (a) improve monitoring of upstream petroleum activities; and (b) develop relevant fiscal and investment policies (para. 2.21). 11. The Directorate General of Hydrocarbons (DGH) has been the beneficiary of long-term technical assistance by well-qualified international experts who should design and implement an intensive training program in this area (para. 2.23). A review and possible revision of the experts' terms of reference should ensure that they are instructed to: (a) advise the DGU on the best arrangements to systematically monitor petroleum operations; (b) provide on-the-job training for the senior professional DGH staff selected for this function; (c) advise the DGH, as the need arises, on specific monitoring issues requiring inputs from technical specialists; and (d) train DGH staff to audit the oil company accounts under both types of exploration contracts (para. 2.17-2.20). 12. In the short term, the Government should establish the petroleum production profile for Gabon based on reserve/production ratio and oil export revenues. It would serve as the principal element in long-term planning for the national economy, antd should be updated regularly. Supply Arrangements for Crude Oil 13. Gabon' s oil refinery, the Socidt6 Gabonaise de Raffinage (SOCARA), is the principal supplier of finished products to the domestic market. It is obligated by statute to refine the locally produced crude, and all companies producing in Gabon must sell a fraction of their (after tax) production to the refinery. The crude is purchased from Elf-Gabon at a set price (para. 19), but up until 1984, payments were made through Petrogab, the national oil company (para. 2.24). Petrogab was liquidated in late 1987 (para. 2.26). As a result, direct invoicing by tlf-Gabon could be re-established. The transaction could be monitored periodically by the DGH (para. 3.8). Product Distribution StrategS 14. Gabon's infrastructure requirements and associated investments in the storage and transport of petroleum products were the subject of a study in early 1983 (para. 3.13-3.14). Taking into account lower activity scenarios following the oil price declinet the mission modified the study's recommendations in two areas, First, Gabon should minimise its storage investments by adopting a commercial inventory of less than 45 days, 25 days being the proposed reserve level. The Government may choose a slightly higher levelt if 25 days is considered inadequate for strategic reasons (para. 3.14). Second, the recommended establishment of additional service stations in the interior does not appear to be the most economic interim strategy. Other solutions, such as using drum supply in conjunction with hand pumps, should be considered (para. 3.17). 15. The study by the French Petroleum Institute's Bureau d'8tudeg Industrielles et de Coop6ration (BBICIP) recommended that two 2,000 e butane spheres be installed at Owendo in order to improve the supply costs of butane. The mission agrees that one of these s)heres should be installed immediately, on condition that the payback period is less than two years. In the short term, the Government should undertake a full analysis of butane demand and supply. This analysis could be included as part of the development of a household energy strategy, and should take into account the conclusions of the petroleum pricing study (para. 3.16). Petroleum Subsector Institutiocis 16. Of the six petroleum product marketing companies operating in Gabon until 1987, all were private companies (Government share: 101), with the exception of the national marketing company, PIZO. PIZO (Government shareS 50%) was created to ensure that all regions of the country have access to petroleum products and, as recently as 1985, was the market leader for inland product sales (para. 3.9). As a result of its public service mandate and its high proportion of public sector customers, PIZO found itself saddled with numerous financial problems (para. 3.10-3.11). The Government decided that these problems would best be resolved by liquidating the company and selling its assets. The final liquidation plans, which will shortly go into effect, should include clear provisions for the payment and/or cancellation of PIZO's debts and accounts payable by clients before it is implemented. 17. There are two key institutions involved in the supervision of operations, investments, planning and pricing in the petroleum sub- sectors the Ministry of Finance, Budget and Participations (MPBP), and the Ministry of Planning and Economy (MPH) (para. 2.23-2.26; and 3.18- 3.22). Although their responsibilities are defined in legal texts, there is considerable duplication in these documents. A "de facto" division of responsibilities permits the subsector to operate without major difficulties. However, lack of clear distinction of responsibilities restricts coordination between the ministries and leaves gaps in the exercise of supervisory functions. - vi - 18. A comprehensive institutional study has been recommended for the subsector to confirm the proper roles of the DGH, MEHR, MPBP and MPE and develop recommendations to strengthen them in these roles. The principal tasks to be undertaken in the study are: (a) fully assess the effectiveness of each institution in its current "de facto" roles; (b) make a thorough accounting of major operational and supervisory responsi- bilities which are not exercised or poorly executed under the current system; (c) evaluate the capabilities and resources of the various institutions relative to (a) and (b); (d) identify appropriate divisions of responsibilities and modify legal texts accordingly; and (e) determine new staffing, training, and resource requirements where needed and develop a plan to implement proposed changes (para. 3.22). Product Pricing 19. Under the current system, ex-refinery prices are set by the MFBP. The price is based on the NPBP's assessed value of crude oil plus a margin calculated to both cover SOGARA's costs and provide a small profit (para. 3.24-3.251 3.28). The price at which SOGARA actually purchases the crude, the official price of the Organisation of Petroleum Exporting Countries (OPEC) at the time of pumping, can differ substantially from the MFBP assessed value (para. 3.26). That final ex- refinery prices are substantially higher than import parity indicates that local refining might not be the most economic source of petroleum product supply. In fact, the cost-plus system of determining ex-refinery prices offers little incentive to reduce costs (para. 3.29-3.30; Table 3.5). In ordcr to encourage a more economic supply of products through local refining, the Government should return to import parity pricing (as was the case prior to 1981) as the basis for ex-refinery prices (para. 3.31). 20. The MPBP sets prices at the retail level, also. Prices are calculated according to a complex structure which includes the ex- refinery price, transport costs, distributors' renumeration, financial costs, retail margins, and various taxes and subsidies (para. 3.33- 3.38). The structure should be simplified to five major cost components (para. 3.43). Adjustments made to retail prices in April 1986 reflect the lower cost of crude oil and changes to fiscal policy (para. 3.39- 3.40). The mission recommends that, as a first phase, the retail price of gas oil be increased (possibly by applying a larger "taxe complementaire") so that all retail prices more closely approximate their relative economic costs (para. 3.41-3.42). The advantage of that solution is also its fiscal implications. 21. In the second phase, all the mechanisms for pricing petroleum products from the refinery to the final customer are in need of review. Price adjustments are infrequent, and it does not appear that regular consultations are held with all relevant parties to ensure that prices reflect economic costs (para. 3.25-3.27; 3.34). The reforms to the pricing system should be precisely defined within the context of a refining and product pricing srudy, which would include three main - vii - components: (a) the examination of the systems and the costs of supplying crude oil and petroleum products to the country; (b) a diagnostic evaluation of refinery operations and a management audit of SOCARA; and (c) a review of the product dis'cribution strategy and of the pricing system (para. 3.31). Institutional arrangements for product pricing should be consistent with the recommendations of the subsector institutional study (para. 18). Priority Electricity Subsector Issues 8lectricity Demand Forecasts 22. In 1984, Societ6 d'Energie et d'Eau du Gabon (SEG) calculated a detailed long-term forecast of electricity consumption throughout the system (Annex 16), upon which it based its long-term development plan (para. 24). The forecasts were revised in early 1986 to reflect more moderate growth after the oil price decline (para. 4.17-4.18; Table 4.3). The mission felt that neither forecast was adequate for input to the long-term system development plan, however, as they were calculated using demand trend assessment methods (para. 4.19). Thus, it was recommended that BEEG revise its demand forecasts (particularly those for low voltage consumption) according to a more appropriate methodology, to include: (a) a disaggregated market survey of each major class of consumer (in addition to surveys of large industrial individual consumers) for each of the subsystems; and (b) a macroeconomic consistency check, based on the most recent macroeconomic projections to be provided by the MPE. A new scenario, which predicts a recession in the electricity subsector, was constructed in early 1987, using a synthetic analytic approach (para. 4.20). These forecasts should be used to define the least-cost long-term development plan (para. 4.27). Medium-Term System Development to 1995 23. The revised 1987 forecasts for electricity demand confirm the conclusion that the existing generating capacity in the three large load centers (Libreville, Port-Gentil, and Franceville) will be sufficient to meet demand until t.he early 1990s (para. 4.21). A complementary 12 MS gas turbine could prove necessary in Franceville after 1992 to decrease the risks of shortages in dry years. The final decision should be made in 1988-1989 (para. 4.22). Previous plans for installation of gas turbines at Port-Gentil in 1992-1994 (para. 4.23) should be reviewed, once a scenario including the Libreville-Port-Gentil interconnection (para. 4.28-4.29) is re-evaluated. No new generating capacity will be needed for either of these subsystems before 1996, in any case. 24. In early 1986, SEEC reduced its original development program for the isolated centers (DER) from 24 to 15 target load centers (para. 4.23). After decreasing the scope of the planned program once more, the Government finalized the conditions for executing the - viii - readjusted program in 1987, with financing provided by the Canadians. The Government is still negotiating with the French Government for equipment for centers not included in the Canadian program. 8130 should subject each project remaining in the development program to a full economic and financial analysis so that they can be prioritised and the program continued according to an extended schedule (para. 4.25). Long-Term System Development 25. The interconnection of the Libreville-Port-Gentil subsystems was the principal element of the initial long-term development plan formulated by SEEG in 1984. The interconnection was to be put in service in 1990-1991, and would have been followed by the installation of two 21 KW gas turbines at Port-Gentil. The third element of the plan included development of a hydroelectric site near Libreville, to be commissioned in the mid-1990s (para. 4.28-4.30). The plan was revised in 1987 to take into account SBEG's new demand forecasts and uncertainties concerning the availability of natural gas and financial resources. The revised strategy consists of separate development of the LBV and the POG networks (para. 4.23; 4.27). 26. SERG should begin imediately to examine again its long-term development plan. New scenarios will have to be evaluated under revised assumptions for key parameters, including: (a) demand forecasts and anticipated consumption growth rates (para. 22); (b) projected consumption of natural gas, natural gas availability and natural gas prices; (c) trends in fuel prices; and (d) discount rates. Complementary soil investigations for potential hydro sites should be completed immediately so that full information will be available for taking a decision regarding the first major investment by late 1989. This date is crucial, as the lead times are six years for the hydroelectric options and four years for the interconnection. If the interconnection is found to still be the optimal first stage in the development plan, construction should begin in 1992, but no later than 1994 (para. 4.31). 27. The timing for deciding on the appropriate sequence for system development is less crucial for the other subsystems. In Franceville, a decision concerning the timing of new hydroelectric capacity, possibly in 1996 or 1997, will be needed by 1992 (para. 4132). The projected econo- mic conditions up to mid-1995 should constrain any return to full-scale development of DIR until 1996, as investments required in other sub- systems will take priority over these. The Government should take advan- tage of the period of slowed development to: (a) clearly define its development strategy for the DER; (b) re-assess the energy needs in tar- geted load centers; (c) identify economic interim solutions; and (d) seek alternatives for financing these solutions (para. 4.33). Other Issues 28. Tariffs. The 8ERG undertook a detailed tariff study in 1984 to complement itsinvestment plans. The proposed tariffs are based on the - ix - long-run marginal costs of supply (under the old development plan), sub- ject to the constraints of: (a) public service policies, much as geogra- phic cross-subsidies; and (b) revenue generation requirements, to ensure a sufficient gross margin to support the financing of future invest- ments. The study appears to be methodologically sound (para. 4.39). The tariffs will have to be updated to incorporates (a) the re-optimized system development plans and (b) modifications to the load curve and consumption patterns envisaged following the economic slowdown and during the recovery period (para. 4.42). In the interim, the proposed tariff structure should be implemented, although tariff levels will need to be adjusted after the study has been updated. 29. Public Service Reform. The MERR has considered a proposal to reform the public service arrangements for electricity and water. Under this reform, SEEG would be converted from a parastatal enterprise (Government share: 63X) to a completely public enterprise. Upon conversion, all buildings and equipment owned or used by SEEG would become state property, and SEEG's only retained responsibility would be managing system operations (para. 4.44-4.45). The mission identified several disadvantages to this proposal (para. 4.46), and recommends that private shareholders remain active in SEEG ownership in the short term (para. 4.47). Investment by other entities or individuals should also be encouraged. If some private participation in ownership is maintained, preferential tariffs for large consumers who are also shareholders should be reviewed; instead, shareholders should be the beneficiaries of any profit realized from 888G operations (para. 4.47). In the interim, all proposals for reforming or restructuring the subsector should be reviewed, preferably within the contest of an in-depth examination of SEEG's financial situation and a management audit of the electricity subsector. 30. Financial Status. Like many parastatal enterprises in developing countries with a public service mandate, SEEG has a severe cash balance problem caused by 4 months arrears and/or non-payments (about FCFA 15 billion in 1985). The structure of the arrears-85X of outstanding billings attributable to public sector bodies--is such that even vigorous collection programs are not sufficient to tackle the problem (para. 4.49-4.51). A full examination of SEEG's financial situation and of subsector management should be undertaken immediately, with the ultimate objective being the scope for financial and organizational restructuring of SEE1 vis-A-vis the Government. The transfer of assets, or a debt-to-equity exchange, would clear up Government debt and give SEW1 more financial autonomy (para. 4.52). A review of operating costs may also yield some potential for cost reductions (para. 4.53). The company is pursuing all efforts to bring its operating costs under control. Summary of Priority Recommendations 31. The key recommendations of the previous sections are presented below according to their priority for implementation. Core Program for Public Investment 32. The following projects should -ieceive absolute priority in future investment budgets: (a) investments for butane and reduced storage investments for other petroleum products (Table 3.5): 1.86 million CFAF; (b) improvements to electricity distribution in Libreville and Pranceville (Table 4.5): 6 billion CPA?t and (c) the first phase of a scaled-down program for developing the DEB subsystem (Table 4.5)s 4.5 billion CPAP; 33. Investments in transmission at Libreville, including the Bissegue substation transformation capacity (2 billion CFAP) and a new 225 kV overhead line connecting Kinguele to Libreville (5 billion CFAF) can be deferred to 1990. Further investments in the DER subsystem are anticipated at an annual rate of 1.5 billion CPAP until 1990. Priority Investigations and Studies 34. The following studies are set for, or should be launched in, 1987/1988: (a) natural gas feasibility study, to be launched immediately (Annex 5): cost to be determined; (b) least-cost system development plan, including the results of the gas utilization study: 1 billion CPAP; (c) scope for financial restructuring of SIEG, and 8EUG's status vis-&-vis the Government (para. 4.52): US$150,000 - 40 staff weeks (1985 US$); (d) revisions to the electricity tariff study (para. 4.42); and (e) a diagnostic evaluation of refinery operations and management audit of SOGARA; 35. The following studies should be scheduled after 1988, to be completed no later than 19911 (a) comprehensive institutional review of the petroleum subsector (para. 3.22): cost to be determined; - xi - (b) second and third phases of petroleum product refining and pricing study (para. 3.31); and (c) revised development policy and irvestment plans for DWR (para. 4.33): cost to be determined; 36. Further surveys of household energy and non-conventional fuels could also be carried out during this period, as funding permits. Institutional and Policy Reforms 37. The following reforms should be implemented immediately, or as soon as the studies upon which they are based are completeds Petroleum Subsector (a) the "taxe compl6mertaire" should be applied to gas oil prices so that all retail prices more closely approximate their relative economic costs (para. 3.42); (b) the terms of reference of in-house experts should be reviewed/revised to ensure proper intensive training of national counterparts in monitoring upstream petroleum operations (para. 2.22); (c) the retail price structure should be revised to include about five components, rather than the 30-plus components of the current structure (para. 3.43); and (d) ex-refinery prices shQuld be established on the basis of import parity (para. 3.31). Electricity Subsector (e) private shareholders should remain active in SEEG ownership, and preferential tariffs should be eliminated. All proposals for institutional restructuring should be reviewed, following a full examination of subsector finances and management; and General (f) revision of legal texts following petroleum subsector institutional review to eliminate duplication/ambiguities and fill in the gaps. Manpower Planning and Training 38. In addition to training requirements identified in the reconmended studies, the following activities should be launched as soon - ,ii - as possible: (a) an intensive training program in the DGU, supervised by foreigp expertg already in-house, to develop the DCH's capacity to monitor petroleum operations, and usefully utilize annual accounting audits submitted to the DGH by operating oil companies (para. 2.23-2.26); (b) technical assistance and training to the DCE for (i) collection of energy data, (ii) analysis of energy/economy links, and (iii) constructing and maintaining national energy balances; (c) after 1992, technical assistance and training to the DCE for the consolidation of energy demand projections, and the elaboration of detailed five-year plans for energy demand and supply. I. TIIFN8GY SE1CTOI III GAl Overview 1.1 The Gabonese Republic (Gabon) lies astride the equator alog 800 km of the west African coast. The country extends over 267,000 km', three quarters of which is covered by tropical rain forests. The Ogoou6 River and its tributaries traditionally have provided the major transportation link to the interior. 1.2 Estimates place the total population of Gabon at about one million in 1985, including Europeans and non-Gabonese Africans. Wore than half of the population is estimated to live in urban areas. The urban population growth rate is twice that of the total population (2.32/yr). By contrast, rural population growth is only O.9S/yr, due to the relatively high pace of rural-to-urban migration (1.31/yr). The Econoum 1.3 Since independence in 1960, economic giowth in Gabon has been heavily dependent on the output of its extractive industries: petroleum, msanganese, uranium, and forestry. Forestry and mining, exclusive of petroleum, were the mainstays of the Gabonese ecowomy in the early 1970s (301 of GDP). By 1984, these two sectors accounted for only 4.31 of CDP. Petroleum, on the other hand, represented 451 of GDP and 661 of total government revenues. 1.4 Agriculture's share of CDP has remained relatively constant at around 4.51 for the past decade. Manufacturing and construction represented 13.3Z of GDP in 1985, and public administration and taxes another 151. The contribution of other sectors include 7.61 for non- government services, 6.61 for trade, and 3.81 for transport. 1.5 Petroleum output emerged in the early 1970s as the major determinant of Gabon's GDP. Economic development became highly dependent on the evolution of international petroleum markets. This linkage is evident in the three distinct periods of economic growth between 1970 and 1983. From 1970 to 1976, the economy expanded rapidly (14.1X/yr on average) in conjunction with the increase in both oil production and international oil prices. Then in 1976-1979, heavy external borrowing to support an ambitious public investment program, coupled with stagnating oil revenues contributed to an external debt and liquidity crisis. Consequently, the economy experienced a sharp contraction as real GDP fell by an annual rate of -12.61. In 1979, an IMF stabilization program was adopted to diversify the economic structure, create conditions for non-inflationary growth and reduce external debt. Its efficacy was enhanced by the second international oil price increase. The otherwise -2- spectacular econome recovery which resulted during the period 1980-1984 was sharply undercut by high rates of inflation. Although the economy exhibited strong growth in current terms (16.13Z/yr), annual real growth averaged only 1.542. Initial Impact of the Oil Price Decline 1.6 The economy grew sluggish in early 1985 and then was es 'ken considerably by the sharp drop in international oil prices at the et of that year. Oil production declined slightly (-1.21) and the apprecia"ion of the CFAP vis-&-vis the U.S. dollar failed to keep pace with the rapidly decreasing dollar price per barrel. As a result, oil revenues declined by more than 102. There was no accompanying moderation of domestic investment and consumption, which in fact grew by 17.3Z and 6.92, respectively. As a consequence, GDP registered its first negative real growth in a number of years (-2.52). The full impact on the Gabonese economy will be felt in early 1987, when GDP is expected to drop to almost half its 1985 level. I/ Oil revenues are expected to drop from 632 to 231 of total government revepues, causing the budget to also be halved and bringing about the curtailment of government expenditures and all-but-essential investments. 1.7 Short-term projections of economic growth indicate a very slow recovery. The most conservative hypothesis assumes that oil prices will rise very slowly to only $16/bbl in 1990. This hypothesis has already been surpassed, oil prices having rebound to $20/bbl by mid-1987. Should prices continue at this level, government oil revenues- could reach over 200 billion CFAP (constant 1985 prices) in 1990. This is still only about SS of its 1985 level. Real GDP will grow only marginally, aot to regain previous levels until well into the 19909. 8nergy Resources 1.8 Gabon has a number of indigenous energy resources, including petroleum, natural gas, hydroelectricity, wood, uranium and solar. Only part of potentially exploitable resources have been developed for energy use, both for domestic consumption and for export. To date, the Gabonese have been quite prudent in developing their energy resources. As a result, the country largely is self-sufficient in energy, with the exception of some petroleum product imports. 1/ This one year delay occurs because petroleum sector revenues in any given year are accrued by the Government in the following year. -3- 1.9 In 1987, Cabon's proven petroleum reserves amounted to 133.4 million tons (961 million bbls). This quantity reflected the increase in reserves following new discoveries in 1986 and 1987 (para. 2.10-2.11). 1.10 Natural gas pro 4uction in association with petroleum was estimated at 2.0 billion Mm in 1985. Only a raction of this production is consumed for electricity generation and petroleum production and the rest is flared. Official estimates place total proven reserves, between 40 and 45 billion Nm . Most of these reserves are associated, although there have been minor non-associated discoveries. Economic recovery of natural gas on a large-scale basis poses a number of difficulties, as the gas in found in numerous offshore reservoirs scattered along 400 km of coastline. This situation has improved recently, thanks to Shell's discovery of additional gas reserves. Shell is proposing a conservation policy (reinjection) in the development plans submitted to the Government. 1.11 The total exploitable potential of Gabon's hydraulic resources has been estimated at 50,000 GWh/yr. Slightly more than 1X of this potential is developed; annual hydroelectric production in 1985 was 668 CUh. This quantity accounts for just under 80% of total electricity generation in the country. Total installed hydroelectric capacity now stands at 161 MV (para. 4.3; Table 4.1). 1.12 Over 22 million ha, 801 of the Gabonese territory, is covered by rain forests. Approximately 8 million ha if forest cover is exploited for an annual production of 1.5 million m of industrial wood. An estimated 3 million ml (720 ktoe) of unutilized wood wastes is generated annually as a by-product of forestry operations and wood processing industries. 1.13 As there is a relative abundance of economic energy resources, low priority has been given to exploiting the potential for nuclear and solar energy. Gabon has the capacity to produce up to 1,500 tons/yr of yellow cake uranium. Produciion in 1985 was only 900 tons, and is expected to decrease to 700 tons in the next few years as a result of the international economic slowdown. Authorities at one time considered using this potential for producing electricity, but the utilization of nuclear energy remains limited to small technological applications. The country's high degree of insolation would make it an ideal candidate for solar applications, especially in remote rural areas. To date, there has been only minor research to adapt current solar technologies to local needs and conditions. -4- Snergy Consumption 1.14 Total energy consumption in Gabon is difficult to estimate because of the total lack of information on consumption patterns of fuelvood, charcoal, and other non-commercial fuels. Rough estimates place the per capita consumption of coimercial energy marketed in Gabon (petroleum products, natural gas, and electricity) at 600 ktoe in 1983. If use of natural gas and crude oil in petroleum production is included, this figure increases to over 870 ktoe. 2/ By contrast, the commercial energy consumption in Cbte d'lvoire is only 170 ktoe, and in the Congo, it is 150 ktoe. This is exceptionally high for sub-Saharan Africa and indicative of Gabon's relative prosperity. With the addition of fuelwood consumption among the rural populace, total energy consumption per capita is almost 990 kgoe, according to mission estimates. 1.15 The historic consumption of commercial energy is presented in Table 1.1. Consumption grew at an average annual rate of almost 6.0X between 1978 and 1985, before dropping sharply in the aftermath of the oil price drop. Per capita consumption also displayed steady growth of S8X/yr. Annual fluctuations in the growth rates during this period reflect the relative weight of petroleum products, which account for 862 of commercial energy consumption. The demand for petroleum products is, in turn, closely linked to the economic situation. 1.16 The 1985 energy balance for Gabon (Table 1.2) shows the current structure of energy demand. The consumption of traditional woodfuels by the rural population has been very conservatively estimated at just over 76 ktoe annually; other statistics show a moderate consumption of fuelwood by sawmills for industrial heat and electricity generation (24.7 ktoe/yr). When these figures are taken into account, as well as primary consumption of natural gas and crude oil by the petroleum industry, the three largest energy consuming sectors are the petroleum industry (342), households (242), and other industries including mining (202). Transport and public sector/civil works follow, with 12X and 8X respectively. 3/ Petroleum products represent 532 of the net domestic consumption, natural gas 242, fuelwood 122, and electricity only 82. 2/ Since these quantities do not enter the domestic retail market, they are not usually counted among the Government's domestic consumption figures. 3/ Vell over 502 of the energy demand in the public sector/civil works sector is attributable to construction of the Transgaboneso railroad. 1.17 It should be noted that exclusion of natural gas and crude oil consumption totally changes the ranking of sectors according to energy demand. Households (331), other industry (281), and transport (17X) become the top consumers in this case, with the petroleum industry relegated to fifth place (8X), just behind public sector/civil works (liz). Table 1.1: GAON - INDICATORS OF COMERCIAL 0EM6Y COONSUITION 1978 - 1986 Idicateor 1978 1979 1980 1981 1982 1983 1984 196S 1966 a/ Total Commerclal Energy ConsumptIon ('000 toe) 350.79 352.93 400.17 437.74 443.77 459.83 489.27 523.29 474.56 Electricity 42.24 45.99 48.72 52.61 57.36 62.69 68.36 74.07 75.08 Petroleum Products 308.55 306.94 351.45 385.12 386.39 397.13 420.89 449.22 399.48 6; Commercial Energy Growth Rate (%/yr) 0.61 13.39 9.39 1.38 3.62 6.40 6.96 -9.31 1 Per Capita Consumption (kgoe) 473.03 465.21 515.62 S51.34 546.38 553.42 575.61 601.80 533.48 Electricity 56.96 60.62 62.77 66.27 70.65 75.45 80.45 85.18 84.40 Petroleum Produets 416.06 404.58 452.85 485.07 475.73 477.96 495.16 516.61 449.08 Growth of Per Capita Consumption (%/yr) -1.65 10.84 6.93 -0.90 1.29 4.01 4.55 -11.35 Energy Intensity (kgoe per CFAF) b/ 0.29 0.28 0.25 0.28 0.27 0.28 0.29 0.32 0.38 Energy Coefficient c/ 0.12 0.55 49.69 0.44 -2.38 1.44 -2.80 0.38 a/ Preliminary estimates. b/ GMR In 1985 CFAF. c/ Ratio of GOP growth to growth of commercial energy. Sources Mission estimates, WIP, MEP. Table 1.2t cam0l c BaLICE. 1965 (000 TMO) Primary Bner Pagoleo Uatural Crad Ilctetl- Gao- Karo- Jot Ca Fuel Tot. Pet. Fuelgod Ga" Hfdro Oil clity 1II a Ful on 0t1 AOlal LPG Other Produts TOAU. Gauss Supply Produato. 821.20 1,382.40 166.90 8,626.00 10,996.50 reports 13.U5 10.75 1.80 26.38 26.38 PrImary Zapasts (7,984.79) (7,984.9) Priary Cons. bi (207.56) (28.00) (235.56) Unut lied cl (720.00) (1.114.21) (1,834.21) Stock Cbnges di 1.26 1.26 Tot. Avail. Supply 101.20 60.83 166.90 614.47 13.85 10.75 1.80 26.38 969.77 Beff"fjo (614.47) 63.53 88.07 228.19 15U.92 2.61 7.75 21.46 5"S 52 (18.96) .1 Semal GC. (60.83) 16.45 (11.34) (11.U0) (s5.n) *1 Hydro Cen. (166.90) 57.41 (109.49) of Aunoproductiom f 0.20 (0.99) (0.99) (0.79) of Trans. and Dist. Loses g/ (8.97) (b.97) of Stock Chsnes hi 2.96 (2.80) 14.49 i5.98 0.00 (0.10) 40.51 40.31 Net Supply 101.20 65.09 66.47 99.12 241.09 209.90 2.61 9.45 21.46 650.09 816.57 _ ---------------------- ----- ---------------- --------- - Secondary mports (1.17) (1.06) (124.35) (0.75) (15.97) (143.30) (143.30) Bunker Sales (5.55) (48.63) ($3.96) (53.96) …………---- - --------- ---- ---- ---- --- ……--- -- --------- - - net Dmestlc Cmen. 101.20 65.09 65.50 15." 83.13 234.70 56.92 1.86 9.43 5.49 452.82 619.11 HouseholdlCm 76.50 24.g9 59.42 10.87 30.51 100.81 202.50 Transprt 0.12 83.13 17.84 1.86 103.55 103.55 Petrolems End. 0.26 51.63 51.90 51.90 Other Industry 24.70 34.89 2.55 0.80 55.8s 36.92 9.43 5.49 11.98 171.57 Agriculture 0.39 18.07 18.46 18.46 Publiclcivil IIo*a 5.21 1.96 4.32 59.85 66.12 n.33 *J 3ydraalaettic supply oc _erted oen a thermal replasemet b is, asuaLag 34.41 efflioscy. bi Couuption of natural ga reinjected for petrlam productoin, and cGude oil ud is ref inin. Although consuad on natLonal territory, tbea quantities to not reach the domastic market. cl For fuelvood, quntties of wood wastes generated aally which go utilised, but could be tapped as a potential eneg resoure. For natul gS", quantitles of gS asiated with annual petrolai production which currently are flard, but potentially -uld be tapped in part for consption. dl Additions to (negative) or wlthdrawal. from (positive) SOGAR stocks. *I ConersLxo lo0ses asolated with tramfrxstio frm primary to secondary nergy. fl Purases frm Sh1LL-1anbe for tbe national grid. g/ Differsece bet Swe8 net productin and SM sales. hi Additions to (negative) or withdrawals from (positlve) distributio stooks. il Assumes ru&al population comes an average 200 kgoeicapitalyr. stimate sbold be vy low, given the high oisrture eontnt of wood. Source: mission estimtes, SW, DGB, Sogera, MB. II. Wn5l"SluSDo IA3ATRIOC AND D slOw'HUET Background 2.1 The medium-term evolution of Gabon's economy will depend primarily upon the evolutiwn of oil prices, the prospects for continued investment in the oil sector, and the exploitation pattern of recently discovered oil deposits. This heavy reliance of the economy on oil activities underscores the key issues facing the sector: (a) the optimum petroleum production profile which will ensure the maximization of the present value of remaining reserves; (b) the level at which investments should be maintained in both exploration and development activities to offset declining oil production and expand the hydrocarbon reserve Uase; ond (c) the modifications needed to the fiscal and legal framework governing the activities of the petroleum copanies in Gabon to encourage new investment. Geology of the Region 2.2 Gabon's sedimentary basins cover a total area of 200 000 km2, which is divided between a small eastern basin (45,000 km) and a coastal/offshore basin (155,000 ki2). The coastal/of shore basin is further subdivided into a continental shelf (3,500 tm) with a water depth of le'ls than 200 m and a deep water (200-300 m) offshore area (120,000 kmn). The continental shelf contains all known commercial hydrocarbon accumulations. 2.3 The sedimentary basins consist of sequential layers ranging from mesozone to recent (predominantly shale/sand) formations, with some carbonate intervals and a thick evaporate section. Reservoirs have been found at depths of 1,000-3,000 m and are mainly constituted by sands and sandstones of various ages and origins. The majority of hydrocarbon bearing traps in Gabon are salt-induced structures, although pre-salt reservoirs are generally tied to basement controlled structures. -9- Exploration and Production History Past Activities 2.4 intermittent oil exploration began in 1928, but the first discovery was not made until 1956 by the SociUt6 des Petroles de l'Afrique Equatoriale (SPAPE), an affiliate of the French Elf Group. Output from the three 'newly discovered fields (Osouri, Pointe Clairette, and Port-Gentil) averaged 3,500 barrels per day (b/d) in 1957, equivalent to an annual rate of 177,000 tons. In 1959, Mobil and Shell joined SPAPE, nq, known as Elf-Gabon, in a series of joint ventures in a 25,000 bm area extending south to the Congo. As a result of these efforts, 16 new fields had been discovered and brought on stream by 1964, pushing production to 20,000 b/d (1 million tons/yr). 2.5 From 1965 to 1969, exploration slowed perceptibly as the oil companies concentrated their investments in development. Annual production increased five-fold during this period. Renewed exploration from 1970 to 1977 led to 15 new discoveties. Annual production soared to over 11 million tons in 1974, where it remained for over three years before declining. Output dropped below 8 million tons/yr in the early 1980s, but since has been maintained above that threshold as new fields have been put into production. Table 2.1 shows the evolution of production since 1976. 2.6 The high prospectivity of Gabon's sedimentary basin, coupled with progressive Government policies in the oil sector, encouraged substantial exploration activity during the past decade. Investment expenditures for research and exploration were particularly large between 1979 and 1982 (Annex 2), primarily due to the attractive terms offered in production contracts for that period. By the end of 1983, more than 205,000 km of seismic lines were recorded and about 411 wildcat wells had been drilled, totalling more than 925,000 m (Annex 3). The addition of two new discoveries brought into production at that time raised the estimate of remaining proven reserves to 467 million bbl (65 million tons). - 10o- Table 2.1s ANNUAL PETROLEUM PRDOUCTION BY OPERATOR, 1976-1986 ('000 tons) ELF SHELL AMOCO Year MandJI a/ camb" a/ Lucius I/ OguendJo a/ TOTAL 1976 8,930 1,894 510 11,334 1977 9,254 1,5"9 414 11,267 1978 8,872 1,392 356 10,620 1979 8,318 1,196 282 9,796 1980 7,509 989 389 8,887 1981 6,300 886 421 7,607 1982 6,299 923 570 7,792 1963 6,270 797 538 237 7,842 1984 6,277 814 663 977 8,731 1085 6,199 734 656 1,037 8,626 1966 6,248 637 614 794 8,293 a/ Sabonese crude oIl Is clessifled In four cotegorles according to Its density, which ranges from 31t to 39 API. The four types and their barrels per ton equIvalent are: MandjI - 7.221 Oguendjo - 7.45 Samba - 7,259 Lucina - 7,596 Source: DONG Current Activities 2.7 There are now 27 interjational oil companies 2xploring in Gabon with permits covering 68,000 km', including 32,000 kmf onshore. Seven companies (Elf4Cabon, Shell, Mobil, Amoco, Conoco, Tenneco, and Exxon) act as operators on behalf of the others. Elf-Gabon and Shell control over 801 of the permit area and account f5r 75X and 152 respectively of total production. Approximately 30,000 km remain free areas, excluding offshore areas with depths over 1,500 a. Of the 45 fields discovered and put into production since 1956, 30 are currently being operated. All but three are operated by Elf-Gabon, primarily under concession agreements (para. 2.17). Amoco's only field in production, Oguendjo, produces under a production sharing contract (para. 2.19), as does the Konsi field operated by Elf-Gabon. 2.8 Commitments for exploration investment in 1986 remained relatively high at 31 billion CFAF (US$91.2 million). Expenditures by Elf and Shell amounted to 90X of the total. Following the sharp decline of oil prices at the end of 1985, Elf and Shell are expected to postpone - 11 - some exploration expenditures and concentrate on developing their new discoveries (para. 2.10-2.12). Exploration investments in 1987 and 1988 are expected to be around US$120 million and US$150 million respectively, approximately half of which will be by smaller operators who have only recently begun prospecting in Cabon (Conoco, Agip, Tenneco and Sunoco)* Companies, especially those who have recently signed production sharing contracts, have presented a very encouraging work program to the Government. Future Petroleum Production Prospects Development of Proven Reserves 2.9 Most fields currently in production have been fully developed and now are undergoing a natural decline in output. As a result, total annual production is expected to drop below 8 million tons in 1987. The anticipated addition to output from fields to be brought into production by Tenneco and Amoco during 1987 and 1988 will be sufficient to sustain total production at this level (Table 2.2). Tuble 2.2: PROJECTED ANNUAL OUTPUT OF FIELDS CURIENTLY IN PROOUCTION ('000 tons) Operotors 1986 1987 1988 1989 1990 1991 1992 (actual) Elf-Gabon 6.248 5,836 5,450 5,183 4,709 4,521 3,907 SholI 1,251 1,157 958 795 659 546 455 Amoco 794 682 922 719 562 440 344 Tenneco a/ 169 707 749 5 78 224 Total 8,293 7,846 8,037 7,446 6,485 5,893 4,930 nJ Developmsnt expenditures already toultted to bring three sualI fields Into productlon In the second half of 1987. Peak productlon anticipated In 1989. Source: G, mission estimates. 2.10 The Rabi field, discovered by Shell in August 1985, constitutes a crucial element to sustaining short- to medium-term production levels. Vith recoverable reserves estimated at about 374 million barrels, 299 million proven, Rabi is the largest discovery ever made in Gabon. It is located onshore in the northern section of the Sette Cama block of the Ogoou6 exploration permit, which is operated by Shell (42.5X) in association with Elf-Gabon (25.51), the Societe Vationale Elf-Aquitaine - 12 - (513*) (171) and the State (1S5). The southern section of the Rabi field is well defined and conceivably could be put into production two years after a decision is made to invest in production facilities and infrastructure. Negotiations with the Government have advanced sufficiently for production to begin by early 1989. The northern extension to the field has been confirmed and wilt require further development expenditures. Total costs for developing Aabi, 4/ including drilling, infrastructure, pipelines and modifications to Shell's Gamba terminal for evacuating the crude, were estimated at U8495 million in June 1987. These investments would be phased over a six year period. 2.11 Shell's proposal for phased development of Rabi would start in the southern section, with approximately 25 wells producing in successive phases 20,000 b/d, 60,000 b/d, and 80,000 b/d. The production level would build rapidly to a plateau of 10Q,000 b/d (4 million tons/yr) by the first quarter of 1990 through the Gevelopment of other wells, for a total of 58. The plateau could be maintained for approzimately four years. 2.12 Two other fields which could be developed are the Rousette field and the Coucal field, operated by Elf-Cabon. Development of these fields could be deferred if Blf-Cabon chooses not to support development investments for this field simulttAneously with its participation in the Rabi development. Oil Production Scenarios 2.13 The mission's estimates for future oil production are presented in Table 2.3. The scenario assumes that Rabi and Coucal will be developed and brought into production. It should be stressed that the projections in Table 2.3 are merely indicative. They do not include the possibility that new fields other than Rabi and Coucal could be developed and brought into production. Seventy-five to 114 exploration wells are expected to be drilled between 1987 and 1991, and some of these are likely to yield successful results. I 0 2.14 The mission has taken a conservative position in its projections to emphasize the importance of Rabi's output for the short- to medium-term. It cannot be automatically assoumed that maintaining production above the 8 million tons/yr threshold will prove to be the best strategy for maximizing the present value of all production from the new discoveriest current and future. Still, it is essential to the recovery of the Gabonese economy that high levels of production be maintained. In order to meet both of these objectives, the Government's medium-term strategy should consist principally of providing the proper environment for encouraging ezploration and development, especially 4/ The project financing would include a government participation in addition to investments by Shell, Elf-Gabon and 511A. - 13 - during periods of oil price uncertainty. The implications of this role are discussed in the following section. 2.15 In the short term, the mission recommends that a profile of optimum petroleum production for Gabon be developed, based on oil price projections and estimates of remaining reserves, in order to maximize the present value of the country's petroleum reserves. This profile will serve as the principal slement in long-term planning of the national economy (by providing projections of petroleum revenues), and should be updated regularly. Table 2.3: PRJEC1I0 OIL PRCOUCTION, 1987-1992 ('000 tons) ELF SHELL Present Prsent Year Fields Ooucal Fields Robi AMO TENECO Total 1987 5,836 1,157 682 169 7,846 1988 5,450 958 922 707 8,037 1989 5,1S3 795 1,060 719 749 8,526 1990 4,709 659 3,712 562. 555 10,197 1991 4,527 1,247 548 3,712 440 378 10,852 1992 3,907 1,995 45S 3,953 344 224 10,878 Soure: 0OH, Oil companIes, mission estimlates. Legal and Fiscal Framework 2.16 Two types of petroleum exploration and production contracts currently are used in Gabon. Under the first type, the concession contract, oil companies are granted the exploration and exploitation rights to a particular concession for a certain period. The maximum period is five years for exploration, three-times renewable in blocks of up to five years. Sxploitati9n rights are granted for 75 year periods, renewable in blocks of 25 years. Four companies operate under this typq of contracj, including Elf-Gabon and Shell. Approximately 29,500 km' (22,000 km' onshore) of the area currently under exploration is governed by concessionary agreements, most of which are due to expire in mid-1991. 2.17 The Government and the oil companies sign a "convention d'6tablissement" (establishment agreement) governing the administrative, legal, fiscal and technical scope of company activities. As an OPEC country, Gabon normally employs the fiscal provisions recommended by the organization. The Government receives an after-tax profit equivalent to - 14 - its share in the capital of every producing company that operates under a concessionary agreement. This share can reach 252 and can be taken in kind. 2.18 In line with a new policy, the Government signed its first production-sharing contract in March 1977; pro-existing concessionary agreements remained in force. Under these new agreements, the company has a "work and financial obligation" for exploration, valid for a maximum period of five years. Exploration risk is assumed entirely by the oil company; exploration costo are reimbursed only it there is a comercial discovery. Companies recover their costs by taking up to 40X or 50Z of production ("cost oil"), while the remaining 501 to 601 ("profit oil") is split between the Government and the company on a sliding scale basis linked to field output. The company pays no taxes and is free to export its production share with minimal restriction. SI The company's financial situation is audited each year by independent accountants hired by the Government. 2.19 The Government initially awarded eight areas under production- sharing contracts to Elf-Gabon and several newly-created associations. Of the three discoveries made to date in these areas, two are currently in production (Konsi for Elf and Oguendjo operated by Amoco on behalf of a consortium). A third, Obando marin (operated by Tenneco on bUhalf of a consortium) came on-stream September 3, 1987t. Production-sharing contracts account for about 26S of the total areas covered by exploration permits and licenses, and about 151 of annual oil production. 2.20 Although existing permits granted to the oil companies remain valid, the Government is expected to assume a greater role under the new production-sharing agreements. It currently is negotiating with a number of companies to ensure maximum uniformity and cohesiveness in the fiscal conditions applied under its various contracts. Another round of bids took place between spring and Vovember 1987. 2.21 The Government should continue to exercise sound judgement in negotiating under the provisions of the new contractual arrangements, and that it act with the same prudence in its negotiations to ensure that the climate of confidence, which traditionally has characterized exploration activity in Gabon, is maintained. Specifically, the Government should take advantage of the expanded role permitted under production sharing contracts, which it has implemented, to: (a) improve the monitoring of upstream petroleum activities; and 5/ Companies are required to sell a small fraction of their output to the local refinery (para. 3.6). - 1S - (b) develop relevant fiscal policies which simultaneously (i) serve as incentives for continued exploration efforts by international concerns and (ii) optimise the conditions for government take. 2.22 The team currently assigned to moni$or exploration activities within the Directorate General of HydrocarboLa (DGH) is working in this direction. The mission recommends that their terms of reference be reviewed and amended to give them official responsibility and accountability for (a) formulating appropriate policy and (b) identifying possible mechanisms for its implementation. The specific provisions to be included should be determined in the context of the petroleum sub- sector institutional review recommended in Chapter III (para. 3.22). The institutional review should also define the requirements for additional training in this area. Sector Organization 2.23 The Ministry of Mines & Hydrocarbons (HMM), through the DCI, monitors petroleum exploration and production activity in Gabon, as well as domestic refining activities. The DCI also negotiates with the oil companies and represents the government interest in the companies' executive boards. The DCH's responsibilities are subdivided among three main functions: technical, financial, and documentation. At the time of the mission, the DCI was being restructured with the help of long-term technical assistance from international experts. The mission recommends that the DCI take advantage of the presence of these international experts to design and implement an intensive training program in order tot (a) increase its ability to monitor exploration and development activities; and (b) more importantly, take full responsibility for developing and managing petroleum sector fiscal and investment policies. 2.24 The Covernment created the national oil company Petrogab in 1979 in order to coordinate more effectively its interest in the petroleum sector. Petrogab's statutes were very broad, covering all aspects of hydrocarbon exploration and development, as well as product and crude transport and storage. Until 1983, Petrogab's primary duty was to market 25S of the government share of Elf-Cabon's production. (The rest was marketed directly by the DCH.) Petrogab also served as an unremunerated intermediary between Elf-Gabon and the SOCARA refinery, for the invoicing of purchases of crude oil (para. 3.7). This activity seemed to be redundant, as the refinery can be supplied directly by the companies. - 16 - 2.25 Following an agreement between MMH and the oil companies in 1983, Petrogab undertook a limited active role in exploration by acquiring a minor share in the Oguendjo and Olende fields. It has also secured an exploration permit through Gaborep (40X Petrogab, 601 Perrodo Group), with work obligation of US$7 million in three years. This permit includes an area relinquished by Shell (two wells tested, but the discovery was not considered economical by Shell) and subsequently allocated to Gaborep. 2.26 Petrogab's role in the petroleum sub-sector has long been poorly defined. It was questionnable even if Petrogab need exercise some of the responsibilities it had been granted in official statutes, given that many were already performed quite satisfactorily by the DCH and other petroleum sector institutions (para. 3.18-3.21). Consequently, the Government decided in 1987 to liquidate Petrogab, a step which the mission approves. The mission recommends that Petrogable former activities and responsi"bilities be thoroughly examined and revised within the context of an institutional review of the entire petroleum subsector, as defined in para. 3.22, and that the scope of these activities be precisely attributed to other sub-sector institutions in amendments to official statutes. Potential for Natural Gas Development 2.27 The Government has been investigating gas utilization since 1968, when it formed its Gas Committee ("comite gas") (para. 2.19). There have been a number of limited studies since then to ascertain the magnitude of reserves and the feasibility of production for certain projects. One such project was the production of ammonia, studied by Pierre-Fite-Auby in 1973 and again by Voest Alpine in 1978; the project was scrapped in mid-construction after the latter study did not confirm its economic feasibility. Two important studies were conducted in the early 1980s, one by Elf-Gabon (1981) and the other by Degolyer and Maciaughton/Sechtel (1984) to determine the feasibility of recovering gas from the Torpille (301 of remaining gas reserves) and Anguille fields, extracting the liquids and then storing the gas in the old Lopes Nord oil field to be used at a later date. Elf-Gabon concluded that the project was not economic and that any attempt to exploit gas reserves for com_ercial use could not be justified economically. Degolyer and NacNaughton/Bechtel, on the other hand, found the project marginally economic at a price of US$1.56/MMBTU, if the gas is used mainly for power geneeation. 2.28 There are three distinct points of view expressed by the principals involved in the development and utilization of natural gas. From the consumer side, the electric companyt SEEG, appears for the moment to be the only major potential user if gas is developed. SEW6 would be interested in gas only if it could be delivered at a price competitive with planned hydroelectric developments (para. 4.27-4.30), - 17 - and if the supply could be assured over the long term. From the producer side, the oil companies want to be assured that the gas price will cover their coses of development and exploitation. Many are convinced at this point that tbere is no way to economically develop the quantities of gas needed by 3EEG at prices required for thermal generation to be competitive with hydroelectric power. The third view is held by the promoters, who counsel that by use of their exploitation techniques, extracting the gas from certain fields and storing it in empty reservoirs for later use would be marginally economic. 2.29 The Government has formed a Gas Committee to initiate and review the studies and proposals for gas development and utilization, and to decide upon gas development priorities. Committee mmbers include representatives from the MMH (both directorates), the Ministry of Energy and Hydraulic Resources (MERO), the Ministry of Planning and Economy (MPE), the Ministry of Pinance, Budget and Participations (MFBP) and the Presidence. The major conclusions drawn by the Committee in earlier discussions were that: (a) The oil companies are not interested in gas development, since the price of gas will not cover their exploitation costs. To meet S33G's criteria, it is most likely that the "pris de cession" would have to be fixed on a political basis, and not by the market. (b) The results of recent studies are biased by the apparent conflicts of interest of the groups conducting them, and thus the reliability of their findings is questionable. (c) Although it would be impossible to develop all available reserves due to the nature of the reservoirs (par&. 1.10), there are some fields which could be developed economically under certain conditions. (4) The only viable consumer for the gas is 9S33, which is very skeptical about plans committing it to develop large, gas-based thermal generating capacity. The Government would be willing to "encourage" development of marginally economic fields if 9330 could guarantee that it would consume the quantities produced. 2.30 In the aftermath of the 1985 oil price drop, natural gas development was accorded a low priority in national energy planning. The only major market identified to date, S33,, totally revised its investment plans to take into account new demand forecasts and limited availability of natural gas (para. 4.17-4.19). The discovery of new hydrocarbon reserves call once again for the re-evaluation of gas utilization scenarios. Major reserves of natural gas-an estimated 385 billion standard cubic feet (BSCF) of associated and 490 BSCF free gas-in-place- are associated with Shell's Rabi field (para. 2.10-2.12). Shell has already presented the Government with plans to conserve this - 18 - gas for future development through a reinjection program (5,150 million CPAP). In addition, Tenneco has mwde proposals for development of natural gas associated with its Obando Marin field. Approzimately 75 BYSP could be made available to 93KG at an estimated cost of 12 CFAI'/m (about US(1.5/NBTU), based on jemand projections supplied by 833C. S33C currently pays about 24 CPAF/tm for its purchases of natural gas. 2.31 The availability of competitively priced natural gas in sufficient quantities substantially changes the options for medium- and long-term electricity syutem development in the late 1990s and after. for this reason, the mission recommends that the options -for exploiting and developing natural gas be fulli. determined with minimal delay. A feasibility study should be undertaken which will include: (a) an evaluation of reserves using presently available data; (b) a preliminary assessment of potential conventional markets (power, industrial, , residential and coumercial) and unconventional markets (tr4nsport, agriculture); (c) an estimate of the investment costs to produce and transmit the gas to the main local markets; (d) a preliminary analysis of pricing issues with respect to gas; and (e) recommendations for future action. The feasibility study would decermine whether it is justifiable to undertake an intensive utilization study aimed at optimization of the use of projected supplies, further analysis and comparison of investment and conversion and consideration of contract provisions (pricing and taxation) which direct the interest of the Government's commercial partners in the development of reserves. Detailed Terms of Reference for the feasibility study are presented in Annex 5. -19 - III. SB"]LUI -SUPPLY AIM DizsuBTo Petroleum Product Demand 3.1 The total domestic 'market for petroleum products in Gabon (1985) amounted to about 464,000 tons (Table 3.1). Gas oil comprises more than half of total sales; however, only 11 of total gas oil sales are made through retail outlets while the largest 11 customers account for half the sales. Jet fuel is the second most important product in terms of sales volume (182); an estimated 572 is consumed by the national airline and the air force, with foreign airlines accounting for the remainder. Gasoline, which accounted for about 142 of total sales is predominantly sold through the 99 petroleum product retail outlets across the country. Fuel oil accounts for only about 82 of sales, and is entirely accounted for by two consumers - Cinents du Gabon (92Z) and the SOBRAGA Brewery (8%). Kerosene and butane, which account for only 22 and 31 respectively of sales, are primarily household fuels. Kerosene i8 sold through the petroleum companies' retail outlets and by peddlers in outlying areas, while butane is predominantly an urban middle class- cooking fuel. Table 3.1: OWESTIC PETRILEUM PRODUCT SALES, 1960-1985 a/ ('000 tons) Average Annual Growth Rote Product 1960 1961 1962 1963 1964 1965 1960-196 (in %) Butane 6.1 6.7 7.3 863 8.9 8.9 7.8 Aviation Gasoline 2.9 2.6 2.2 1.7 1.6 I.6 -9.1 6asollne 51.2 53.5 56.8 61 7 62.2 65.3 5.0 Kerosene 9.7 10.0 10.7 12,0 14.7 15.6 10.2 Jet Fuel 68.6 75.6 74.8 70.5 78.3 81.5 3.5 Gas Oil 176.9 204.3 207.2 215,3 221.6 234.7 5.6 Fuel 011 33.7 29.5 24.3 24.5 30.4 38.1 2.5 Asphalt 6.8 5.4 8.4 _ 9.9 9.9 8.3 4.1 Total 355.9 367.6 391.7 403,9 427.6 454.4 5.0 at Excluding lubricants. Source: OHM OPP, 1EHR - 20 - 3.2 The consumption of petroleum products is regionally skewed. Three of the country's nine provinces-Iutuaire (the Libreville region), Haut Ogooue (the upland mining region), and Ogoou6 Maritime (the oil producing regiov)-accounted for 882 of gasoline consumption, 732 of the gas oil consumption, and 682 of the kerosene consumption. All the fuel oil and butane consumption also occurred in these regions. 3.3 Overall petroleum product sales averaged 52 volume growth between 1980 and 1985, with growth in 1984-85 amounting to 6.3Z. The fastest growing fuels have been household energy. fuelo--kerosene and butane-which averaged 102 and 82 growth respectively over the 1980-85 period, but these products still only account for 52 of total sales. The consumption of gasoline and gas oil averaged relatively steady growth of 5X and 62 per annum respectively. Sales of Jet fuel grew at a somewhat lower rate of 42 per annum over the period., but year-to-year sales have fluctuated considerably, reflecting the tendency of international airlines to base their purchases on relative prices vis-a-vis neighboring countries' airports. Petroleum Refining 3.4 Gabon's oil refinery, the Soci6t6 Gabonaise de Raffinage (SOGARA), is the principal supplier of finished products to the domestic market. SOGARA is structured as a private company with national priority status. The nine shareholders include the Government and various marketing companies operating in the country (para. 3.9). 6/ Its activities are heavily regulated by the DGH, within the MMB. 3.5 SOGARA's installations were integrated with those of the former COG B refinery in 1985, 7/ leaving it with a nominal distillation capacity of 1.2 million tons annually. Cracking and reforming capacities limit its efficient production capacity to 700-75O,OOO tons/yr, however. In 1986, the refinery was operated at about 650,000 tons throughput, which sufficed to meet domestic demand for gasoline, kerosene, gas oil, and fuel oil. However, some imbalance remains between domestic demand and refinery output. About 100,000 tons of excess fuel oil are sold on the international market, as well as occasional batches 6/ Government: 25.002, Elf: 18.752, Total: 18.75Z, Mobil: 11.62, Shell: 11.392, Texaco: 5.62, Fina: 3.31, BP: 3.10X and Agips 2.502. The Governmnt has the option of increasing Ats share to 51.002. 7/ The Compagnie Gabon Elf de Raffinage (COGER) was owned by the Government (302) and Elf Gabon (702) and was operated as an export- oriented refinery from late 1976 until 1985. Part of COGER's 1 million ton/yr capacity was leased to SOGARA before the installations were merged. - 21 - of naphtha. It is also necessary to import butane on a regular basisp as refinery output meets only about two-thirds of total demand. Butane imports currently amount to about 3,000 tons annually; because of limited butane storage capacity, these additional requirements must be imported in small lots, at very high unit costs (para. 3.16). Table 3.2: SO¢ARA REFINERY CHARACTERISTICS Facilities Capacity Processing Units (Tons/day) Atmospheric distillation 2,800 Hydrotreatmoent 680 Catalytic reformer 180 Thermal cracking and visbreaker 1,300 Storaes Capacity (03) Butane 300 asoline 12,000 Jet Fuel/Kerosene 5,500 Gas Oil 28,000 Fuel Oil 29,400 Crude 19,940 Source: SOARM. Supply Arrangements for Crude Oil 3.6 SOGABA is obligated by government statute to refine the Gabonese crude, Mandji (29' API). All companies producing in Gabonese territory are required to supply a portion of their (after tax) production to meet SOCARA's needs. Elf-Gabon consolidates the production an4 delivers it to SOCARA in batches of 65,000 bbls via a 17 km pipeline from its terminal at Cap Lopez. 3.7 The crude is purchased from Elf-Gabon at a 'price set by the Ministry of Finance, Budget and Participations (MPBP) on a quarterly basis; this is generally the official OPEC price (para. 3.26). Payments were made through Petrogab, the national oil company (para. 2.32), on a 90 day basis. The purchase was billed in dollars, but the currency of payment was CFA francs (CPAP) at the exchange rate in effect at the end of pumping. Petrogab received no remuneration for this intermediary role, although one full-time engineer and three part-time administrative workers are allocated to this transaction, at cost to the company of an estimated 100 million CFAP/yr (US$333,000). - 22 - 3.8 In view of the fact that Petrogab has been liquidated (para. 2.26) direct invoicing by Elf-Gabon could be re-established. Such direct arrangements have operated efficiently in the past. The transaction could be subject to periodic, unannounced audits by the DCH as part of its monitoring activities throughout the petroleum subsector. Product Marketing and Distribution Marketing Arrangements 3.9 Products deatined for the domestic market are delivered to storage depots outside Port-Centil by the marketing companies and the SociAt& Gabonaise d'Kntreposage des Produits P6troliers (SGBPP). SG8PP is owned Jointly by the marketing companies operating in Gabon in 1986: BP, Agip, Mobil, Totalp Texaco and PIZO. The first five are affiliates of major international petroleum companies, with the Government holding 101 of their stock. PIZO, which because of financial difficulties was liquidated by the end of 1987, (para. 3.12) was the national marketing company. It was owned by the Government (501), Shell (201), Elf (20X) and Agip (10Z) and was created to ensure that all regions oE the country have access to petroleum products. PIZO was the market leader in 1985, with 361 of the total inland product sales (Table 3.3). financial Difficulties for PIZO 3.10 Almost all of the marketing companies service the interior of the country to some extent. The burden of supplying these (generally) low-volume demand centers has fallen disproportionately to PIZO because of its official mandate to supply the entire territory. Until 1986, PIZO operated almost half of the retail outlets outside of Libreville and Port-Centil. The figures in Table 3.4 give some indication of PIZO's retail market share relative to the number of its retail outlets, as compared with other marketing companies. - 23 - Table 3.3:s OVESTIC ARKMET SIARWS OF THE DISThI9EUTION OI"PANIES BY pRODUcT, 198S a/ COWANIES Products TOTAL MOBIL TEXACO BP PIZD ELF bl Retail Market c/ Oasollne d/ 24.0 18.9 6.9 13.9 36,3 - 91.0 Koeosene 24.5 20.1 14.1 19.7 21.6 - 68.0 as Oil 29.1 12.7 9*0 - 13*3 35*9 - 13.0 Jet Fuel 9.8 30,9 - - 38.7 10.2 - Fuel 011 20.3 19.5 4*0 14.9 41.3 -- LubrIcants 20.3 36,1 3*9 11.7 28.0 15.0 e/ Excluding sales to International bunkers and airIInes by Elf-Gabon and Shell. b/ Elf does not market ref med products within Gabon, except Jet fuel sold to the national airline. c/ The prce ntep of products sold on the retail market, as opposed to wholesale or bulk sales of produets to large customers, e.g. SEEG, Elf-Gabon, Transgabonals, the State. d/ CombIned regular and super. Source: 6PP, WER, mission estiomtes. Table 3.4: RETAIL ARKET INDICATORS FOR PETROLEUM PROOUCTS, 1985 TOTAL MOBIL TEXACO BP PIZD Number of retaiI outlets Total IbrevIlle nd Porl-GentlI 12 8 5 10 20 55 Interior 5 9 7 5 18 44 Total 17 17 12 1S 38 99 Percent of retall sales 6asollne a 21.3 20.9 7.4 14.5 35.8 Gos oIl 29.3 19.6 9.9 13.9 27.1 b/ Lubricants 26.8 41.8 11.5 9.3 10.7 Total Share of Retail Market 25.8 27.4 9.6 12.6 24.5 cl I/ Includes regular and super gasollnes. / Many of these sales are through the use of vouchers Issued for use by government employees or employees of parastatal and public enterprises. cX Note that many of PIZ's sales were to bulk and/or preferentlal customers who do not purchase products on the retall market. Source: GPP, WM. - 24 - 3.11 PIZO also handled most of the public sector market for products. Nearly 352 of PIZO's market in 1985 was comprised of the public administration and public sector enterprise. The Government did not pay PIZ0 until at least 180 days after billing, and PI20 found it difficult to recover the full amount billed even at that stage. Public sector arrears to PIZO were commonly between nine and twelve months, amounting to a total 4 billion CFAF (US$13.3 million) by the end of 1985. As a result, PIZO's average arrears were 120 days, as compared to 35-40 days for Total, 38-40 days for Mobil, and 37 days for BP. 3.12 The severity of PIZO's financial difficulties led the Government to convene a technical working group in 1986 to address the problem. The group, which is composed of representatives from the MMH, MUSK, M1P8, M8P and PIZ0, completed its evaluation in early 1987. Its main conelusion, based on a preliminary iecoomendation by the mission, was that PIZ0 should be liquidated and its assets sold to a private company. Shell has formed a new marketing company, with the Government as a minority shareholder, which has purchased PIZO's assets. A committee was appointed to oversee the implementation of the liquidation. The mission recommends that (a) the final liquidation plan include very clear provisions for the payment and/or cancellation of all or part of PIZO's debts and accounts payable before implementation is begun; and (b) the Government explore and identify economic interim solutions to ensure that remote areas are supplied followin; the liquidation of PIZ0 (para. 3.17). Product Distribution Strategy 3.13 In early 1983, the consulting firm BUICIP (France) assessed the national requirements for infrastructure investments in storage and transport of petroleum products at the request of the Government. BEICIP's final recommendations were based on a medium growth hypothesis for future demand, one of several alternative demand growth scenarios prepared in the report (Annex 7). The minimum investment strategy proposed by BEICIP is split almost evenly between additions to existing storage capacity (7.5 billion CFAF) and transport investments (8.3 billion CFAF). The volume of the recommended additions to storage was calculated on the basis of 45 days of consumption. 3.14 In light of the recent economic slowdown, the mission has adopted a lower growth scenario (BEICIP's "low scenario") for product demand, and modified BEICIP's proposal accordingly (Annex 8). The mission recommends that Gabon minimize its storage investments by adopting a commercial inventory reserve of less than 45 days. An adequate reserve level could be 25 days, although the Government may choose to increase this level, if it is considered inadequate for strategic reasons. - 25 - 3.15 The mission believes that a 25 day reserve would be adequate since Gabon is an oil producer, has a refinery which is located near the oil fields, and has good storage capacity at the refinery. There is also very good product supply availability on the West African coast, which would present alternative sources of supply. 8/ Adopting a 25 day reserve inventory, along with the low growth scenario for product demand, would imply total additional investment in product storage through 1992 of 22tSOO m. at a cost of 1.5 billion CFAP. This would represept a substantial potential savings over a 30 day i4ventory (32,000 m at 2.1 billion CIA?) or a 45 day inventory (55,200 m? at 3.0 billion CPA?). 3.16 Regardless of the overall inventory level decided upon, there is a need for major investment in butant storage facilities at Owendo. 8UICIP has recommended that two 2,000 ml spheres be installed. These would establish the required reserve inventory and be sufficient to handle anticipated growth in butane demand, while also permitting a savings of up to 4150/ton due to the ability to purchase butane in more economical volumes. for a demand of 3,000 tons per year, the annual savings would amount to about $450,000. This would have a significant beneficial impact on the current deficit in the equalization fund used to subsidise butane imports (para 3.22). The mission therefore recommends that one butane sphere be installed immediately but only if the nvestment can be justified by showing a payback period of less than two years. With such justification, the project woulA prove to be the best short-term strategy for meeting the current butane demand. In the meantime, an analysis of butane demand growth and the options for meeting this growth should be undertaken. This analysis could be included as a component of the household energy study proposed by the mission; in addition, it should incorporate the conclusions of the petroleum pricing study (para. 3.43-3.44). The need to install a second sphere should be examined around 1992, depending upon the growth in butane demand. A timetable for these and the other storage investments is given in Table 3.4 below. 3.17 The BRICIP study also recommended the establishment of additional service stations. While the mission supports the need to ensure that fuels are supplied to remote areas, it also feels that more economic interim solutions-e.g., using drum supply in conjunction with hand pumps-should be considered. S/ BRICIP's analysis indicates that additional imports represent a less costly alternative to augmenting domestic supplies during supply interruptions (due to planned refinery shutdowns, for instance) than does additional storage. - 26 - Table 3.5: SUGGESlED INVESTIENT PROOSAM 1967-1991 (millon CPAF) 1987 1968 1989 1990 1991 TANKAGE Owendo Gasoline 200 200 - Kerosse/Jot 232 - Gasol I - 200 232 Lmbarene OsolIno & Kerosene -- 67 Gasol I - - 133 Noanda Gasol I - - - 200 - Jet - 34 - GUTANE sphere 1,50 - ,600 Battles - 150 150 100 100' ETAIL OUTLETS 20 20 20 20 20 Total T1520 602 637 586 1,853 Source: Mission estimates. Institutional Issues 3.18 The Ministry of Energy and Hydraulic Resources (MEHR), through its Directorate General of Energy (DGE), is nominally the ministry which oversees petroleum product marketing and distribution and ensures the domestic supply of refined products. However, several governent ministries intervene te monitor product imports and total supplies, fix prices, and participate in various downstream activities. Although the responsibilities of the various ministries within the Government are defined by statutet there is a tendency for them to overlap. 3.19 Legal texts give authority to supervise refinery operations to both the DCH and the DCB. The DCG is also given authority to supervise "investment, marketing, policy land] prices'p, activities which are equally under the mandate of the MPBP and the 1P4. 3 - 27 - 3.20 In practice, the DCH supervises and monitors crude supply to the refinery and refinery operations, while the DGt supervises all petroleum sector operations not related to production. Both ministries act only in an advisory capacity, however, to the MPBP and the MPH on matters concerning annual investment and operating budgets (for SOGARA, PIZ0, SCEPP), the price at which crude oil is purchased by the refinery, ex-refinery prices and market prices for refined products. 3.21 While this "de facto" division of responsibilities permits the system to operate without major difficulties, it is not clear that it is conducive to the most efficient operation of the marketing and distribution system. Under these arrangements, the MIHR's real authority is effectively limited to the approval of new depots or retail outlets. Altbough there is some communication of data and statiatics from the marketing companies through the Groupement Professionnel des P6troliers (C??), it does not appear that the MEHR is kept regularly informed of product imports. Their documentation of refined product supply is incomplete, at best. Nor does the MEOR participate directly in the process to establish retail prices (para. 3.32). In effect, the lack of clear distinction of responsibilities not only restricts the coordination of policy between the ministries, but also leaves gaps in the exercise of supervisory functions. 3.22 1We mission recommends that the Government review the existing legislation to amend all duplication of responsibility among the institutions of the sub-sector. This review should take place following a more extensive institutional review for the subsector to determine the proper roles for the DCHI, MIR, NIBP and MPH in product marketing and distribution. The extensive review should include, but not be limited to, the following tasks: (a) fully assess the "de facto" roles of the various institutions and their effectiveness in fulfilling said roles; (b) make a thorough accounting of the major areas of operational and supervisory responsibilities (some of which may already be accounted for in the legal texts) which are not exercised or are ineffectively carried out under the current system; (c) evaluate the capabilities and resources of the various institutions relative to Mi) the tasks which they currently exercise, and (ii) those tasks for which they are legally responsible; (d) identify the appropriate division of responsibilities among the various institutions based on the evaluations in (a), (b), and (c); and (e) determine new staffing, training, and resource requirements where needed and develop a plan to implement proposed changes. - 28 - Petroleum Product Pricing 3.23 The Government of Gabon intervenes heavily in the pricing of petroleum products at both the ex-refinery and retail levels. Its principal objective is to ensure relatively stable prices for petroleum products in the domestic market. Provision is also made through flexible fiscal policies to cover costs while allowing a reasonable profit margin for the refinery and the marketing and distribution companies. Changes in prices consequently take place only when there have been major international price shifts. Ex-Refinery Prices 3.24 Until 1981, ex-refinery prices were established according to import parity (Caribbean) prices. Under the current system, the MFDP estimates the price at which crude oil will be purchased by SOCARA, then calculates a margin which will both cover costs and provide a small profit to SOGARA. The margin is determined on the basis of a budget presented by SOCARA. 3.25 The MFBP's assessed value of crude oil is a reference price based on estimates of the average official OPEC price. Although it normally is adjusted quarterly, adjustments were made monthly during the fi'rst two quarters of 1986 because of the rapid evolution in OPEC quotes following the 1985 price drop. 9/ The MFBP's assessed value for the third quarter 1986 crude price was fixed at $10.50/bbl. 3.26 The price at which SOCARA actually purchases the crude, the official OPEC price for Mandji, can differ substantially from the MFP assessed value. 10/ For example, the MFPl assessed value of crude used in the price structure for the second quarter of 1986 (April 10, 1986) was $15/bbl at an exchange rate of 370 CFAE/UB$. The actual OPEC quote for April was $13/bbl. During the first half of 1986, such differentials resulted in a windfall profit for the refinery. For the month of April, the windfall would have-been equivalent to US$130,000 for delivery of one 65,000 bbl batch (para. 3.6), or about US$1.3 million annually for a $2 differential maintained throughout the year, not including the benefits arising from fluctuations in the exchange rate. 9/ The OPEC price moved as follows during this period: January - $21/bbls February - $15/bbl; March - $14/bbl; April - $13/bbl; May - $13/bbl; and June - $12/bbl. 10/ As noted in para. 3.7, SOCARA's purchase price is billed in US dollars, payable in CPA francs using the exchange rate in effect at the time of pumping. - 29 - 3.27 The windfall profit to the refinery only occurs when the MFBP underestimates the OPEC price. More commonly before the oil price drop, the quarterly price used by the MFBP in the pricing structure underestimated crude costs. This, combined with margins inadequate to cover SOCAaA's actual operating costs, has led to losses which must be absorbed by the refinery, seriously reducing its working capital for improving operations. 3.28 The added margin covers operating costs, fixed and financial charges and profit. Forecasts of annual product sales and exports are prepared by SOGARA and submitted for review with an associate operational budget to the MPBP. The per unit costs projected for 1986 (at an exchange rate of 340 CPAP/US$) were comprised of US$20.3/ton in variable costs (including fuel), US$7.35/ton for transport, US$34/ton in overhead costs-a total of US$61.50/ton for operating costs-plus US$5.20/ton and US$8.60/ton for financial costs and depreciation, respectively. 11/ Both operating and financial costs appear unusually high compared to industry standards in West Africa. 3.29 The resulting ex-refinery prices. are considerably higher than the economic costs of refined products, which are represented by import parity prices in Table 3.5. Clearly, the differential between the actual cost of crude and the NFBP's assessed valEie contributes substantially to the distortion of ex-refinery prices relative to import parity. Yet even when adjusted for this differential, ex-refinert prices are 26X-52X greater than import parity. Civen that the ex-refinery prices presumably reflect the actual costs of refining, SOCARA may not be the most economic source of supp for the country. However, the mission was not able to determine during its brief assessment the scope for bringing the costs of local refining more in line with the economic costs of supply, and a full economic analysis of the refinery was outside of its mandate. 3.30 The cost-plus system of determining ex-refinery prices, based on an assessed value of crude, offers little incentive for least cost supply of refined products. The problems inherent to the system would not be alleviated simply by modifying the frequency of adjustments to MFBP's assessed value, as this appears to be only one of many factors contributing to high ex-refinery prices. 11/ SOCARA's financial costs for 1986 total almost 20 billion CPAP. This can be broken down into debt burden (14.4 billion CFAP) plus the net difference between receivables (16.8 billion CFAP) and accounts payable (11.4 billion CPAP). The high figure for receivables is primarily due to PIZO's outstanding debts (9 billion ClAP) to SOGARA. - 30 - Table 3.6: COMPARISON Of EX-EFINERY PRICES AND IMPORT PARITY, 198 CUSS/ton) lst Quarter 1986 4th Quarter 1986 cl Imwport Import Adjusted Products Ex-Reftinory a/ ParIty 1/ Ratio Parity e/ Ratio Ratlo ft Premium Gasoline 255 213 1.2 173.5 1.47 1.3 Regular Gesollne 265 198 1,34 156.5 1.67 1.52 Kerosene 239 244 0.96 170.0 1.41 1.26 Gas Oil 225 212 1,06 142.0 1.58 1.41 / Ex-refinery prices In price structure f fective April 10, 1986 (Annex 9). Exchange rate: 340 CFAF/SI.00. b/ As of Apil 1, 1986, before nea price structure, Average spot value of KandJi - S15.50/bb.- c@ As of October 23, 1986. M/ E April 1966 plus Insurance and freight. gl tNiE October 1986 plus Insurance and freight. 7/ Adjusted for "windfall codponent" In the ex-refInery price due to tho differenc between the assessed value for MandJi In the ApriI 10 price structure (still In effect In October) - S15hbbl - --*9iot market value of WandJt In late October 196 IS11 .5fbb1 ). Source: WEBP, mission estimates. 3.31 A restructuring committee has been formed to review the structure of ex-refinery prices. Nonetheless, the mission recomsends that the Government return to import parity pricing as the basis for determining ex-refinery prices in order to encourage more economic supply of products. The exact nature of the picing system should be define4 in the context of an in-depth refining and product pricing diagnostic study. The three main objectives of this study will be to (a) undertake a diagnostic evaluation of refinery operations and a management audit of SOGARA; (b) examine the arrangements and costs for supplying crude oil and refined products to the country; and (c) review the petroleum product distribution strategy and pricing system. The study, which will follow- up a financial audit of SOGABA planned for the beginning of 1988 under the MPE's supervision, should examine, but not be limited to, the following: (a) the efficiency and full costs of refining at SOGARA's facilities, including (i) a thorough evaluation and breakdown of all operational and financial costs and (ii) review of management practices which may affect refining costs; - 31 - (b) the scope for reducing refinery operating costs through financial restructuring (e.g, debt to government equity) and improving the technical, financial, marketing and managerial factors as identified in (a), so as to ensure sustained economic and financial viability; (c) the optimal combination of cost reduction measures which would bring SOARA's costs closer to import parity costs; (d) the costs of importing products from alternative sources (including other West African refineries) versus local refining under a scenario of cost reduction; the economic cost to the Gabonese economy of choosing to supply itself from SOCARA rather than from alternative sources; (e) the levels for ex-refinery prices, using import parity as the base, which will serve as an incentive for both (i) the implementation of cost reduction measures by SOAMA, and (ii) economically efficient operation of refining facilities in the future. The import supply alternative which is leaot costly to the economy (determinated in (4)) should be used as reference. An appropriate formula for calculating the ex- refinery prices should include componnts representing the costs of supplying the country from the next best supply source; 12/ Cf) the appropriate institutional arrangements for monitoring and adjusting ex-refinery prices and the frequency with which they should be adjusted; and Cg) the reforms necessary to simplify the retail price structure, and to institute a formal mechanism for regular consultation and revision of retail prices, as specified below (pare. 3.42- 3.44). 3.32 SOCAM would be required to deliver products at the ex-refinery prices calculated under the import parity formula; its profit would be determined by the degree to which it can reduce its costs below this level. 12/ Principal elements of the formula thus defined would be: (a) freight and insurance; (b) terminalling, maintenance cost and operator profit; (c) port costs; and (d) capital recovery for investments required to allow efficient handling of products. - 32 - Retail Price Structure 3.33 The prices for all petroleum products in GabonT (except lubricants) are set officially. The MPBP calculates the prices according to a complex structure which includes the ex-refinery price, transport costs, distributors' remuneration, financial costs, retail margins, various taxes and the requirements for various policy-based funds. The main features of the resulting price structure are: (a) cross-subsidization among products to benefit those considered "socially sensitive", either through ea-refinery price levels (butane) or through various taxes and levies (kerosene); (b) stabilization of consumer prices over time with the objective to avoid frequent adjustments; and (c) geographic cross-subsidization to minimize the differences in the price of a given product throughout the nation. 3.34 The retail price structure has been adjusted infrequently and only twize in the past three years. When the marketing companies consider a price adjustment is required, they make a request through the OPP. The request is made to the MBPIP, which reviews the merits of the proposal. For the most part, requests are kept under advisement until there is need to modify one of the major components of the structure. 3.35 Table 3.7 below shows the major structural elements of the prices in Libreville and Port-Gentil for the four main products: premium gasoline, regular gasoline, gas oil and kerosene. The price structures for products sold in other localities (Annex 9) include additional elements for transport, storage, and (further) geographic equalization (para. 3.32). The transport component is fixed by decree, with foreimburseme.t" to the distribution companies according to the type and quantity of products delivered and the distance travelled (Annex 10). The price of locally refined butane also is constructed according to a rather complicated structure (Annex 11). The prices of other products, including fuel oil, jet fuel and asphalt, are set by decree. 5 - 33 - Table 3.7: MAJOR COMPONENTS OF THE PETROLEUM PRODUCT PRICE STRUCTURE u/ (CFAF per 100 lIters) Gasollne Cmwponent Premium Regular Keroene Gan Oil Ex-refInery 6,436.4 6,433.6 6,44B.7 6,451.3 Stabilizatlon Fund Tax 1,029.0 624.7 -2,860.4 37n.7 "Stabilized" cost 7,46$.4 7,256.3 3,568.3 6,629.0 Taxe Compl6mentalre 14,700.0 14,700.0 700.0 3,500.0 Equalization Fund Tax 1,700.0 1,700.0 1,700.0 1,700.0 Other Taxes, Chorges, Margins 4,134.6 3,841.7 2,611.7 2,871.0 Retail Price 26,000.0 27,500.0 8,800.0 14,900.0 Retail Price per liter 280.0 275.0 68.0 149,0 It/ Libroevil and Port-entil, as of AprWi 10, tg96. Source: Directeur GOn6ral des Calsses de StabiIlsation et de ibr6quatlon. 3.36 Two of the most important components of the price structure are the Stabilization and Equalization Funds, both administered by the MFBP. The Stabilization Fund was established in 1972 to ensure the stability of petroleum prices, at the distribution stage, over time. Originally, only gasoline was taxed to support the prices of kerosene and gas oil. In 1986, the gas oil subsidy was ended and now gas oil sales also contribute to the fund. The Stabilization Fund covers the differential between the price of imported butane and the price of locally refined butane. Until 1986, contributions to this fund amounted to 321 of the retail price of super gasoline and 33X for regular gasoline. The stabilization component is considerably less in the price structure put into effect in April 1986t 4X for super, 3X for regular and 31 for gas oil. This dramatic shift is the result of policy changes which favor the "taxe compl6mentaire" (para. 3.39). 3.37 The Equalization Fund was created in 1968 (the current structure was put into effect in 1971) to minimise the difference in the selling prices of products throughout the nation. The objective of the fund is to keep prices of products sold in the outlying regions low enough to (a) not represent a constraint on consumption and - 34 - (b) discourage black market trade with the Congo and Cameroon. A levy of 17 CPAP per liter is collected on all clean products. This amount has more than doubled since 1983, when it varied from 5 CPA? per liter of kerosene to 8.75 CPAF per liter of gas oil. It is now uniform for all products. 3.38 In 1985, both the Stabilization Fund and the Equalization Fund carried deficits of about 1.5 billion CFAF each. In the case of the Stabilization Fund, this was attributed in part to the large subsidies on gas oil until 1986. These subsidies encouraged rapid and wideosprad substitution for the more costly gasoline, the sales of which were needed to support the subsidy. For the Equalization Fund, the old levies simply were not sufficient to meet subsidization needs. In both cases, the MPFP estimated that under revised forecasts of petroleum product demand, the levies carried in the new structure will permit the funds to recover their deficits and break even within the next two years. Since then, the situation has improvedt the Stabilization Fund now has a surplus of almost 17 millioli CFAF, as a result of the increase in the taea complhentaire. The Equalization Fund still carries a deficit, but it has decreased to 500 million CFAP. 3.39 The current price structure was put into effect in April 1986. 13/ It implements certain adjustments to reflect falling crude oil prices--including a minimal adjustment to retail prices (from 2-5 CPAP per liter depending on the product) in order to pass some savings on to the consumer-and reflects some policy changes in the- utilization of taxes and subsidies. The principal adjustments were made in three areas: (a) ex-refinery prices were reduced by nearly 501 to adjust for lower crude prices; (b) the "taxe compl6mentaire" was increased radically to recoup for the national treasury the rent which previously had been absorbed by the refinery; and (c) the major subsidies, the Stabilization Fund and the Squalization Fund (paras. 3.36-3.37) were modified to correct for deficits and to drop the subsidy on gas oil. 13/ The price adjustments made in April 1986 affected only the three main products. Price levels and pricing structures for butane, fuel oil and Jet fuel remain the same as in March 1985. Table 3.8: EVOLUTION CF TAXES AND SUMSIDIES ON PETROLEUM PFR00UC PRICES a1 (CFAF per 100 liters) PREMIUN_ REGULAR KEROSENE GAS OIL 1983 1985 1986 1983 1965 1986 t983 1965 1986 1983. 1985 1986 RetalI Price b/ 24,500 28,500 28,000 24,000 28,000 27,500 7,500 9,000 8,000 13,700 15,200 14,900 Taxe oomplimentalre 100 100 14,700 100 100 14,700 10p 100 700 100 100 3,500 Stabilization Fund c/ 7,783 9,179 1,029 7,773 9,232 825 (8,562) (9,885) (2,860) (1,688) (2,557) 378 Equalization FundC/ 775 1,390 1,700 775 1,390 1,700 5O0 1,390 1,700 875 1,390 1,700 Oter Direct Texesd/ 397 401 430 407 411 430 226 230 400 166 170 407 Taxes and subsidy contributions as percent of retall prlce 37% 39% 64% 38% 40% 64% - - - - - 40% Taxes as percent of retail price o/ 2.0% 1.8% 54% 2.1% 1.8% 55% 4.3% 3*7% 12.5% 1.9% 1,8% 26.2% I- 1!, Based on price structures for Libreville dated Sept. 1, 1963, March 18, 1985 and April 10, 1986. For 1986, price structure Is also applicable to Port-Centi I.. b/ For Libreville and Port-Gentil. Level of subsidies differs between the two In 1983 and 1985. c/ Positive value Indicates levy to finance the fund. Negative value-In parenthesis-is subsidy provided by the fund. d/ Includes port taxes, municipal taxes on distribution and storage charge,. eJ Including the toxn copld.entalre. Source: WOP, mIssion estimates. - 36 - 3.40 The net result of these changes is a dramatic shift in the relative weights of taxes and subsidies in the price structure (Table 3.7). There is more emphasis on income generation through a more aggressive fiscal policy (increased "taxe compl6mentaire") and less emphasis on cross-subsidization among products. The Government can expect to receive up to 167 million CPAP (US$0.5 million) from the "taxe compl6mentaire". 3.41 These shifts in policy are encouraging, as they indicate a willingness on the part of the Government to make more effective use of taxes and subsidies. The mission believes, however, that there io further scope to simplify the system of taxes and subsidies, and to make their application more economically efficient. The case of gas oil is a good example. Although the product is no longer subsidized through the Stabilization Fund, the final retail price is maintained at half the price of premium gasoline by keeping the tax burden relatively low (26X of the retail price, versus 551 for gasoline). Thus price discrimination in favor of gas oil continues. The objective of keeping the price of gas oil low is to assist small entrepreneurs, industries and transporters. However, given that a dozen large consumers account for almost half of total gas oil consumption, the policy of maintaining an artificially low price is a highly inefficient way of achieving this objective. 3.42 The mission recommends that, as a first phase, the official retail price of gas oil be ad3usted (possibly by increasing the "taze compl&mentaire" to match that of gasoline) in order that retail prices more closely reflect the relative economic costs of the products. Other mechanisms, such as special vouchers or fiscal measures, be explored to target the intended beneficiaries of any preferential pricing of gas oil. The former action will allow the ratio of the retail prices for gas oil and for gasoline to more closely approximate their relative economic costs, thus siding demand management of the two products. It should also provide a source of additional government revenues. The mechanisms used to benefit smaller users should be designed to complement the price increase. 3.43 As a second phase, and most !Lzportantly, the mission recommends that the Government simplify the current pricing structure, which is unnecessarily complex. This could be done by establishing five major cost categories: ex-refinery price, fiscal levies, freight and Equalization Fund adjustments, Stabilization Fund adjustments, and marketing margins. These items should all be examined under the petroleum product pricing study recommended by the mission (para. 3.31). 3.44 The mission further reco.mends that the pricing system be improved by instituting a formal mechanism to permit regular consultation and revision of product prices. In the process, the marketing companies should be more directly involved, through the GPP, to provide information on the current marketing and distribution situation and their costs. - 37 - IV. 8LCIC POE Introduction 4.1 The monopoly for generating and distributing electric power in Gabon is held by the 8ociete d'8nergie et dEau du Gabon (SilG), which is also responsible for water distribution. The bulk of BERG's activities, coats and revenues are related to electric power. The exact proportion is difficult to calculate as the management and operation of the dual water/electricity systems are highly integrated within SERG. 4.2 SEG's operations are grouped according to four physically independent transmission and distribution subsystems (para. 4.4-4.11)s Librevillet Port-Centil, Franceville and the various isolated centers. In addition to the BERG system, there are a number of individual and/or semi-collective generating facilities in remote villages and on some larger farms. Most of these are relatively small in capacity, although at leapt one sugar mill has installed a large combined process heat and power generation plant. The contribution of these facilities to total electricity generation in the country is minimal, however. Main System Characteristics 4.3 The SBEG power system boasts a total installed capacity of 285 MV. Hydroelectric plants account for 56X of this capacity. Total net generation of the system in 1985 amounted to 861 GCh, 78X of which originated from hydroelectric plants. The proportion of hydro to thermal capacity and generation varies markedly among the system's four subsystems. The net generation in each subsystem, for all practical purposes, could be considered either totally hydroelectric or thermal (para. 4.4-4.10). Table 4.1 presents a summary of the main characteristics of the total system and each subsystem. - 38 - Table 4.1: MAIN SEEG SYSTEM CARACTERISTICS, 1985 Subsystem ISV POG FCV DER Total Available Capacity a/ (MW) Total 168 57 48 15 285 H4ydro 126 0 38 0 161 Thermal 42 57 10 15 124 Peak Load OV) 87 26 25 8 146 b/ Net GeneratIon (GWh) Total 531 158 137 35 861 Hydro 530 0 137 0 668 Thermal 0 158 0 35 194 192/1985 Averaee -oand Oro"t (S/year) 10,2 4,0 7,4 20,8 8,9 a/ In October 1986, y/ Sum of separated peak loads, Irrespective of any colncidence factor. Source: SEES. Generation and Transmission 4.4 The Libreville subsystem (LBV) accounts for approximately 602 of both the total installed capacity and the power generated by 8NUG. Two hydroelectri¶ generating plants on the Mbei river form the bulk of installed capacity: Tchimbele, with a 220 million mJ reservoir, is equipped with three units of 22,800 kV each; Kinguele, downstream, has a negligible reservoir capacity and is equipped with two units of 9,600 kW and two units of 19,200 kW. The diesel-fired gas turbines (2 x 21 M4) have been installed at the Owendo port in Libreville and were brought on- line in 1986. 4.5 The transmission network from the hydro plants consists of three main components. A 225 kV overhead line connects Tchimbele to Kinguele (40 km) and then to the Bissegue substation (Kinguele-Bissegue: 104 km) on the outskirts of the capital. Kinguele is also connnected to the Bissegue substation via N'Toum (Kinguele-N'Toum: 70 ki; N'Toum- Bissegue: 35 km) by means of a 90 kV overhead line. Finally, a 105 MVA transformer bank (3 x 35 MVA single phase, plus 35 AWA standy) at Bissegue feeds the 90 kV Libreville subtransmission system. - 39 - 4.6 The maximum total output from Tchimbele and Kinguele combined is 126 HU under normal conditions, and 108 NW during dry years (assuming a return period of at least 20 years). The average total energy generated annually is 670 GWh, 490 GMh during dry years. 4,7 Under 1985/86 levels of demand (para. 4.13), the gas turbines at Owendo would not be used unless there is a shortage of hydraulically generated energy due to an extremely dry year, or there is need for backup to cover a shortfall in hydroelectric capacity. A capacity shortfall technically could arise from electromechanical outages at one of the hydro plants, or in the unlikely event that one of the 220 kV overhead lines is tripped. In the latter case, LBV's emergency supply capacity would be about 82 NW (40 NW through the 90 kV overhead line and 42 NW from the gas turbines), which is nearly equivalent to the present peak demand. 4.8 SEG uses a simulation program, Mogador, for managing the operation of the LBV hydro plants. Mogador features a medium-term component for handling the yearly optimization of water use, and a short- term component with a time horizon of several hours for synchronizing the outflows at Tchimbele with the inflows at Kinguele. Management of the reservoirs using Mogador has contributed to the high reliability of the LaV subsystem, and also to avoiding the use of expensive thermal generation. 4.9 The Port-Centil subsystem (POG) supplies the port city which houses the petroleum industry. Power is generated primarily by two 20.9 NW gas turbines fired with natural gas piped in from offshore oil fields. This capacity easily covers the current peak demand (Table 4.1). An old 5 x 3 MW diesel plant is kept as backup. The generating plant is located on the edge of the city, and thus there is no transmission network. 4.10 The Franceville subsystem (FCV) serves the major urban center in the interior, Pranceville, and the mining industry at nearby Moanda. The generating plant consists primarily of the Poubara hydro plants, which include four units of 4,64 NW and two 9.6 MW units. The Moyabi diesel plant (5 x 2.2 NW) has been used only as backup since 1984, when the last of the Poubara units was commissioned. The FCV subsystem has a 63 kV transmission network connecting Poubara to Franceville (21 km) and to Noanda (54 kn) via intermediary substations at Mvengue and Moyabi. 4.11 The isolated centers (DER) represent BERG's administrative and operational grouping of 22 small, physically independent load centers scattered throughout the Gabonese territory. Distances between load centers are usually over 100 km. SERG is responsible for power supply to all of these centers with the exception of one, which is supplied by Shell Gabon. Installed capacity at each point of the DER subsystem ranges from a mere 120 kW to 1,800 ki; total installed capacity amounts to 10 MW. - 40 - Distribution 4.12 S11G has a total 620 km of 20 kY medium voltage (NV) lines in its distribution systems, 190 km of which are underground. In the DIB and FCV subsystems, about 200 km of 5.5 kV overhead lines are also used. The low voltage (LV) lines total 720 km in length, of which 50 km are underground. There are 1,230 NV/LV substations, with total capacity of 363 NVA. All services are equipped with breakers. Demand Characteristics Demand Profiles 4.13 Total electricity sales in the 8L90 system amounted to 757 GIh in 1985. The LBV subsystem accounts for nearly 601 of total consumption, the DIR subsystem for only 71, and the balance is split evenly between PO0 and FCV. Systemwide, NV sales account for Just over half of total sales. The proportion of HV sales varies widely among the subsystems, however, ranging from a high 881 of consumption in the PCV subsystem to a low 441 in both the LBV and DER subsystems; in the POG, the proportion is only slightly higher than this latter figure, 521. The largest MV customers include the mining sector, the Pr6sidence" and the oil industry (Table 4.2). Consumption of LV electricity is predominantly in the residential sector, although there is some usage by BERG itself and in industry. From 1980 until 1986, electricity consumption increased at an average rate of almost 91/yr (Annex 13). LV customers registered the highest growth rates, 14.5X/yr compared with 4.71/yr for NV customers. 4.14 Load Curve. In the LBV subsystem, the yearly load factor is 0.69. The daily load curve features an evening peak between 7:00 p.m. and 11:00 p.m. which is 201-401 higher than the average daytime consumption. There is almost no variation in the daytime load until the evening peak. In the winter months, there is a noticeable post-peak reduction in the night loadt which falls to about 751 of the daytime average. Seasonal modulation is small, although there is a load reduction in the ummer; a 151 decline is recorded during the month of August when many residential customers go on vacation. 4.15 In the POC and PCV subsystems, the daily load curves have the same general shape, but fluctuate over a smaller range. The summer load is reduced in proportions equal to that in LBV. Yearly load factors, are 0.69 and 0.63, respectively. 4.16 The yearly load factor of operating plant in the DIR subsystem ranges from 0.25 to 0.60. As a general rule, the larger the load center, the higher the load factor. - 41 - Table 4.2s GABON ELECTRICITY SALES - 1985 Llbreville Port-Osntil Franceville DER Total (01h) (S) / (0G1h) (S) a/ (Gb) CS) I/ (6Wh) (C) I/ (SGO) (5) i/ NMdlu voltgp 211 28 75 10 104 14 7 1 396 53 Low voltap 250 33 70 9 14 2 24 3 356 47 Total 461 81 145 19 116 16 31 4 756 100 Number of Percent of Low Voltae Categorles Customers Total Consumption Rassdential 54,490 38.4 Pubtlc Llghting 550 1.4 Industrial 1,040 3.2 Internal Use (Water) 210 2.1 SEEG Personnel 1,660 2.3 a/ Percent of total sales. Source: SEES, Annex 12, Annex 15. Demand Forecasts 4.17 In 1984U, SlG calculated a detailed long-term forecast of electricity consumption throughout the system using several demand trend assessment methods (Annex 16). These forecat.s were revised in early 1986 following the oil price drop at the end of 1985 (Table 4.3). The new forecasts indicated a stabilization of the demand in L8V, FCV and P0, followed by moderate growth after 1990. An actual decrease in demand in 1987-88 was possible, especially in the case of POG, where electricity consumption is closely linked to the oil industry, and in LBV, due to the induced macroeconomic effects of the oil price drop. Stag ation of electricity demand in ICV also was anticipated, even though demand in this subsystem is more directly linked to the mining sector than to petroleum. The commissioning of the Transgabonese Railroad would have the most direct impact in this subsystems the electric cableway which transports 2 million tons of ore annually will no longer be operated, thus redu-cing the power demand by 10 GMh/yr. 4.18 The S13G forecast for DER was based on the assumption that there will be no constraints placed on the introduction of new generating capacity in these areas. Under this assumption, electricity demand in DER would grow at about 15X annually (high scenario). The mission adopted the more realistic assumption that further development of - 42 - generating capacity would be reduced or halted in the medium term (low scenario). Thus DU consumption would tend towards the maximum energy and demand which could be generated by existing equipment. It is evident from these scenarios that the actual electricity consumption in DER may be constrained, depending on the policy adopted by the Government for introducing new generating capacity (para. 4.38-4.40). 4.19 The mission was of the opinion that the demand trend assessment methods used by SBEG in its demand forecasts were not adequate for projecting future demand. This is because past economic performance, and therefore electricity demand, have been heavily influenced by the evolution of the international petroleum market. The vagaries of international oil prices in the past decade, including two dramatic price increases and the more recent crash, do not represent gross macro- economic/energy demand trends which are likely to repeat themselves in the future. The mission therefore recommended that the BERG revise its deman forecasts according to a more appropriate methodology, to includet (a) a 5isaggregated market survey of each major class of consumer, (in addition to the surveys of large industrial individual consumers) for esch of the subsystems; and (b) a macroeconomic consistency check, based on the most recent macroeconomic projections to be provided by the NEP. 4.20 A new scenario, which predicts a recession in the electricity subsector, was constructed in early 1987 using a synthetic approach which excludes use of tendencial models, the latter deemed ineffective in the context of Gabon's economic crisis. Nevertheless, BEIG would find it difficult to implement the methodology recomuended by the mission. This is due, firstly, to the lack of analytic data on market segments; and secondly, to the fact that the sector operators feel that the MPE's long term economic projections are not made accessible to them. 8UG believes furthermore that macroeconomic models are very difficult to elaborate because of lack of reliable data. A new investment plan, based on the revised (downward) growth scenario, takes into account the modification of the major parameters (para. 4.23; 4.27). Medium-Term System Development: 1987-1995 4.21 New Generating Capacitr. Taking into account the forecasts for electricity demand used by the mission and presented in Table 4.3, the existing generating capacity in the three large load centers (POG, LBV, and FCV) will be sufficient in the medium term to meet electricity needs. SUG's 1987 revisions are even lower, and thus the conclusion remains valid. The available margin of power and energy for existing hydroelectric capacity in the LBV and PCV subsystems now stands at 26S Table 4.3: REVISED ELECTRICITY E(KAND FCRECASTS: 1986-1995 1986 1967 1988 1969 1990 1991 1992 1993 1994 1995 (actual) Librevi lIe Net Consumption (0Kb) 511 481 481 485 515 545 560 610 650 690 Peak Demand0 ) 8S 60 60 61 86 91 97 102 109 116 Port-Gent I Not Consumption (0Kh) 169 158 158 160 165 170 180 190 I9 200 Peak Demond () 28 26.5 26.5 27 28 28.5 30 32 33 34 Franceville Net Consumption (6Oh) 143 140 140 140 150 160 175 190 205 220 Z Peak Demand ONS) 26 25.4 25.4 25.4 27.3 29.0 31.5 34.5 37.2 40.0 DER High Scenario (Gob) 8/ 63 63 64 68 76 86 95 110 .120 135 Low Scenario (6hb) 63 55 55 55 58 60 61 63 64 64 a/ Assuming soe addition to generating capacity is possible. bJ Assuming constrained consumption due to limits on generating capacity. Source: SEEG, mission estimates. - 44 - and 201 respectively. With these margins, thermal generation is needed only if there is a disturbance in generation or transmission, or under extremely poor hydrological conditions. Once the available margins have been utilised, it still would be possible to meet electricity demnd in these subsystems through incremental use of existing thermal capacity. The maximum peak which thus could be accommodated would be 126 MS at LIV and 32 NW at FCV. 4.22 A complementary 12 MS gas turbine (1.2 billion CFAF) could prove necessary for FCV after 1992 to decrease the risks of shortages in dry years. Still, any significant new generating capacity will not be required until after these dates. A final decision on this can be delayed until 1988-89. 4.23 SEBG's 1985 system development plan called for the installation of two new 21 MW turbines in 1992-1994 for Port-Gentil. This reserve was to constitute the second phase in a project to establish an inter- connection between the LBV and POC subsystems (para. 4.27). Under the revised 1987 forecasts, the interconnection was scrapped, and a new strategy retained which foresaw separate development of the LBV and POG subsystems. This strategy reflected the uncertainties in 1986/87 about the price of natural gas and its availability at Port-Gentil. Recent natural gas discoveries (para. 2.28-2.31) have made this strategy questionable, and the mission advises that a new optimization of the investment plan be undertaken to incorporate this information (4.27- 4.33). 4.24 A 32 billion CPAP development program for the DER subsystem, co-financed by Canada (C$ 32 million), France (4.5 billion CPAF) and the SEG (20 billion CPAP), had been initiated in 1985. The program included development of the electric power and water supply systems in 24 isolated centers. The scope of the project was reduced to 15 centers in early 1986, to include either electric power or water at each target point, but not both. 4.25 After decreasing the scope of the planned program once more, the Government finalised the conditions for executing the readjusted program in 1987, with financing provided by the Canadians. The Government is still negotiating with the French Government for equipment for centers not included in the Canadian program. The mission recoaends nonetheless that the program be prioritized and continued according to an extended schedule. A full economic and financial analysis of the various projects which comprise the program should be undertaken 14/ and the energy demand in targeted load centers re-evaluated (para. 4.J§) in order to rank the projects accordingly for completion. 14/ Many of the projects contained in the program are significantly different one another. Some are merely extension projects; others, such as Lebams, are small hydro projects which would displace diesel stations. Thus the analyses must be undertaken project b prect. - 45 - 4.26 Transmission and Distribution. The principal investments to consider in short-torm system development are in transmission and distribution for the LBV subsystem. The Bissegue substation transformation capacity at Libreville requires strengthening (2 billion CPAP). A new 225 kV overhead line connecting Kinguele to Libreville is also needed (5 billion CIA?). These investments are intended primarily to improve the reliability of supply. Since system reliability is already quite high, the mission believes that they can be postponed without incurring significant risks to subsystem operations. Long-Term System Development 4.27 SUEG's initial long-term system development plans were based on the original 1984 demand forecasts (Annex 16). The plan was revised in 1987 to take into account changes in the key parameters and, in particular, uncertainties surrounding availability of natural gas. Since many of the key parameters have changet substantially yet again in the past 12 months, with the-discovery of major natural gas reserves, this plan is not likely to be the best solution for system development. SEDG will therefore have to review and re-optimize its existing plans to reflect new gas discoveries, economic constraints, and a new timing. Interconnection of LIV and POG 4.28 Long-term development of the LBV and POO subsystems should once again be examined simultaneously, as the interconnection between the two is still an option, given the availability of natural gas at Port- Centil. The interconnection would follow an in-land route, for a total of 407 km of overhead lines (225 WV). The substations would be developed in two stages, allowing a transmission capacity of 40 MS during the first stage and 80 MN during the second. Total cost of the project is 36 billion CPAF (US$102.9 million). 4.29 The studies previously conducted during the planning stages included detailed operation simulations under various scenarios of developing generating equipment. On the Libreville end, this incorporated possible development of hydro sites along the M'Bei, Komo and Abanga rivers. The potential and costs associated with the three most (economically) interesting sites are presented in Table 4.4. On the Port-Gentil end, the addition of two 21 NW gas turbines immediately following construction of the interconnection was considered in some of the scenarios. 15/ The simulations showed that the interconnection 15/ Generating costs at Port-Centil were estimated at 15.5 CPAP/kWh in the simulations, given a gas price of 30 CIA?. The total cost rises to between 20 and 25 CFAF/kVh once capital, operating and maintenance costs are added, depending on the discount rate and plant factor used in the calculations. - 46 - would be used to transmit power in both directions, thereby delaying the need for larger additions to capacity. Table 4.4: POTENTIAL HYDROELECTRIC PLANTS NEAR LI9REVILLE Kinguele Kinguele downstresm upstrem Ngoul msendJis River M'SEI M'DEI KOmG Installed capacity (NW) 30 40 100 investmnt costs a/ (maillon CFAF) 50,000 U5,000 130.000 Nean energy (GWh/yr) 210 280 610 Firm energy (GBh/yr) 160 230 5Z/ Energy cost b/ (CFAF/kWh) 37.5 44.4 30.0 Energy cost cl (CFAF/kWh) 28.6 36.4 25.6 a/ Including an Interest rate of 10%/year during constructlon. b/ On the basis of the firm energy and calculated with ywarly capital and operation and malntenance costs equal to 12% of Investments costs, but without price nor taxes and duties. c' The same as b/ but on the basIs of the men ergy. Sources SEEG. 4.30 The principal parameters in these previous simulations and their evolution have been modified significantly. With regard to the growth of consumption, the new demand forecasts indicate that the importance of the POC subsystem relative to LBV has decreased. However, future trends for gas prices, another major parameter, are more certain than before, thanks to the oil companies' analyses giving estimates of the cost of supplying gas to SENG from the new discoveries. Purthermore, it has been shown that, once a timing for the interconnection has been establishld, gas will be available in the quantities needed (up to 2 billion m /yr) for a sufficient period of time (at least 15 years). - 47 - 4.31 Demand in Port-Gentil can be met with exioting capacity until almost 2000. However, demand forecasts indicate that new capacity will be needed in the LBV subsystem by 1996/1997. Without the inter- connection, major investments in hydroelectric capacity would be needed in Libreville. The mission therefore recommends that S$EC re-optimize its development plan to account for the availability of gas at Port- Gentil, in order to take a decision by 1989 on the first major investment to be undertaken for system development. This date is crucial, as the lead times are six years for Kinguele downstream and Ngoulmendjim and four years for the interconnection and Kinguele upstream. The lower price of fuel could make the possibility of thermal alternatives more attractive, also, and this should be taken into consideration in the revised plan. If the interconnection is found to still be the optimal first stage for developing the LBV/POC subsystems, construction should begin preferably in 1992, but no later than 1994. In the interim, complementary soil investigations for the hydro sites will have to be completed immediately, so that full information is available for taking an optimal decision. 4.32 For the other subsystems, the timing for deciding on the appropriate sequence for system development is less crucial. The optimum foreseeable development in the FCV subsystem would include (a) a gas turbine operational around 1992 to provide back-up during dry years and/or during hydro/thermo-mechanical equipment outages, and (b) new hydro capacity (possibly Poubara 3) in 1996 or 1997. A decision for the latter would be needed, at the latest, by 1992. In the case of the DER subsystem, development will be a matter of general policy for electrification of isolated centers. Projected economic and financial conditions in the medium- to long-term would prohibit return to any full- scale development of this subsystem before 1991. The investments needed in the other subsystems may push this date back to 1996. 4.33 The mission recommends that the Government review and clearly define its development strategy for isolated centers in the long-term within a sector-wide framework of investment priorities for electrification. The Government should take advantage of this period of slowed development to thoroughly re-assess the energy needs in targeted isolated centers, in conjunction with a full economic and financial analysis of proposed projects in order to set development priorities (para. 4.25). 4.34 The mission estimated in Table 4.5 the investment program for the electricity subsector with or without the Libreville/Port-Gentil interconnection, plus the additional investments needed for developing the isolated centers. Investments for the sector will be reduced significantly in the short-term, but will increase rapidly in the first half of the next decade as existing generating capacity becomes saturated. Table 4.5: PROJECTED INVESTRENT PI06RAN FOR ELECTRICITY SUBSECTOR 1987-1995 (billIon 1986 CFAF) Total 1987 1988 1989 1g 1991 1992 1993 1994 1995 Investment Generation and Transmission Total with Intereonnectlon: 0 O.S 0.5 0 0 5 8 8 26 S8 LBV and P06 - Special studies - O.S 0.5 - - - - - - 1 - Interconnection overhead lines S substations - - - - - 2 8 8 6 a/ 36 - Next hydro plant - - - - - - - - 20b/ - FCV - 6as turbine - - - - 1 2 - - - 3 Total without Interconnection: 0 O.S 0*5 0 5.5 13 10 1S 30 74.5 - Special studies - 0.5 O.S - - - - - - 1 o - Kinjuele downstream - - - - 5.5 10 10 10 10 S/ SO - Nebt hydro plant - - - - 5 20 d/ - FCV - Gas turbine - - - - 1 2 - - - 3 Distribution 2.0 2.0 2.0 2.0 2.0 2.5 2.5 2.5 2.5 20 Libreville 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.S 13.5 Port-centi I 0 0 0 0 0 0.5 0.5 0.5 0.5 2.0 Franceville 0.5 0.5 0.5 O.S 0.5 0.5 0.5 0.5 0.5 4.5 Isolated eenters 1.5 1.5 1.S 1.5 4.0 4.4 4.8 5.3 5.9 30.4 a/ Complementary substatlon equlpment In 1996. b/ Timing assumes co.missioning In 1999 (gas turbine at Port-eentil to be comissioned beforehand, with first investments beginning after 1995). c/ Last part of electromechanical ot lissioned In 1996. d/ In the development without interconnection, the next hydro plant would probably be other than Kinguele downstream. Source: SEES, mission estimates. - 49 - Other Subsector Issues Electricity Tariffs 4.35 The tariff structure currently used by 583G is characterized by a declining block rate structure which varies according to the subsystem. One constant LV tariff throughout the BUKG system is the social" residential tariff, a two block rate for consumers with low demand. The range of the initial block in this tariff was doubled in April 1986 (from 120 kVh to 240 kVh) in an effort to reduce electricity costs of smaller residential consumers. The two NW tariffs include a "subscribed demand capacity" charge for all subsystems except LBV, which instead has peak and off-peak rates. 4.36 Tariff levels are the same in PCV and DEI, and generally higher in those subsystems than the tariff levels in LBV and POG. The average price per kWh in 1985, excluding all taxes and other contributions (para. 4.38) came to 42 ClAP. This increases to 43.5 CPAP/kWh if equipment costs are included. By August 19860, the average price per kWh had increased to 46 C8AP. 4.37 Annex 23 describes in detail the tariff structure and levels in use at the time of the mission. 4.38 Although tariff levels are set to reflect the general costs of electricity supply in each subsystem, there is a certain amount of cross- subsidization and a number of specialized costs incorporated into electricity billing. In the LBV and POC subsystems, two line items are added to the basic price of electricity. A "contribution d'6quipement" (equipment contribution) covers the capital costs related to the electricity and water distribution networks, which are owned by the municipalities. The "contribution speciale d'dquipement" (special equipment contribution) is used to reimburse the municipality's expenses for use of electricity, particularly public lighting. The customers of the LBV subsystem also are billed for a contribution to an 5E3G equipment fund used to cover debt service and investments. This contribution is calculated on the basis of hydro-generation at Kinguele (6.47 ClAP/kWh) and service charges of miscellaneous loans. Income from LV electricity sales in All subsystems except DU is allocated to the "fonds de p6r6quation" (equalization fund) and "fonde de compensation" (coupensation fund) to subsidize the costs of electricity supply in the DER subsystem. Both funds are managed by the Caisse Autonome d'Amortissement. Tariffs in all subsystems include an 8Z sales tax (taze sur le chiffre d'affaires) on consumption. 4.39 Tariff Reform. In 1984* S33G began a detailed tariff study to complement its 1984-1988 investment plan and further plans for system development into the early 1990.. For LBV-POC, this included the commissioning of the interconnection and two gas turbines during the investment period, plus development of one hydro plant (the timing of - so - which had not been determined) after 1988. Poubara 3 was planned for FCV, but no major generation projects were envisaged in the Dui. The tariff structure which resulted from the study represents a vast simpli- fication of the current tariff structure. Tariff levels incorporate the principles of economic efficiency, subjeet to the constraints of (a) imposed public service policies, such as geographic cross-subsidies; and (b) revenue generation requirements, to ensure a sufficient gross margin to support the financing of future investments. The study appears to be methodologically sound. 4.40 The final general structure has two principal components, a fixed demand capacity charge (prime mensuelle fixe A la puissance) and a proportional price (prix proportionel de l'energie consommee) for each unit of energy consumed. The structure is further distinguished according to the following criteria: (a) the voltage category - HV transmission, MV distribution or LV distribution; (b) the period of consumption, or time-of-use. This distinction is limited to MV customers, and corresponds to periods determined as peak and off-peak; (c) the duration of usage of the subscribed demand capacity, by definition the ratio of the energy consumed during a certain period and the contracted demand capacity. In the Lv tariffs, this is retained only for customers subscribing ,6 demand capacities of 18 kV or higher; (d) the subscribed demand capacity (la puissance active souscrite), which is "monitored" through the use of single-setting load limiters, set at the maximum demand requested by the customer. This charge is used as an incentive for more efficient utilization of the customers electric appliances; and (e) the actual energy consumed. This is the only tariff criteria applied to LV customers who subscribe under the "social tariff", with demand capacities of less than one kW. 4.41 Tables 4.6 and 4.7 present the proposed tariffs and the related LV marginal costs, as presented in the final report of the study (May 1985). Geographic cross-subsidization is maintained for LV tariffs, but eliminated for NV and RV. This action represents a practical compromise between economic and social objectives: the high long-run marginal costs of supply in the DER and FCV are covered by NV and RV customers (who are generally the larger consumers) and large consumers of LV electricity in LBV and POG-yet electricity remains accessible to smaller consumers throughout the country. Once the long-run marginal costs were dstermined, the basic tariff levels were adjusted according to a factor (le p6age) which takes into account the elements of the policy for financing investments. The values in Tables 4.6 and 4.7 assume that this factor is equal to one. Table 4.6: SM TARIFY STUDY - LO V0LTA¢Z at 3etlO.*l Tariff bI I LOng-1un Marginal Costs o I - …PO K D I L_________ _____ _____ -__ __ __ Dmand d ergy of I emnd di nergy el D_ed *! d Enery el Demand 4/ Suerg el (CFAF1kM) (C1*1tb1h) I (CF*lkW) (C1*11bJh) (1AP*1W) (lCAMh) (C01/Ik) (C0F1*/kh) Small ant Medium Capacity I Social (1 kW) -- 60.i3 I -- 55.6 -- 70.13 -- 123.84 Comfort (3 or 6 kU) 1719 48.46 1 1650 43.87 2612 51.59 2204 108.22 Creat Comfort (9 or 12 2309 44.26 1 2222 39.83 3511 45.20 2958 102.82 1 Large Cpaity flI I I Short duration 81 1418 51.67 1 1369 46.96 2161 56.48 1821 112.33 I General hi 2309 44.26 1 2222 39.83 3511 45.20 2958 102.82 I Long duration it 3315 40.07 1 3187 35.79 5042 38.82 4258 97.43 a* Marh 1985. bi New tariff reulting from the study, to be applied nationally. Based oan the long-run marginal costs calculated In the study, equalized geographically and taking into account the S lGovezramnt capaeity to finance investment plan versus cash generation from from nev tariffs. Excludes the Governments share In certaln investment In the DER, the consumption tax (TCA) and contributions to the special municipal funds. of As calculated by SEEG according to the long-te generatim development plan for each subsystem. d1 Monthly premium in 'CAFIkV of subscribed demand capacity. el Proportional price in CFAF per kWh consumed. fl Subscribed demand capacity s 18, 24, 30, 36 k or more. gI Frie 0 to 120 hourslmonth usage of the subscrLbed demad capacity. h/ From 120 to 240 hours/month usage of the subscribed demand capacity. if Over 240 hoursimonth usage of the subscribed demend capacity. source: SEEN. Table 4.7s SFF TARUFF STUDY - IRA*USSZION AND MEDUK VOLTAGE aIbl ----- (CFUA) Transmissioa Teriffs MdLua Voltage W-mG ICY Dm I LlV-Il0 iCt Don Very Short Duratlon (TCU) el I Demnd Charge (per kY) 33899 36742 37710 1 40500 51199 42738 Prsortional price (per khh) Peak (7 - 11 p.m.) 90.68 95.78 251.08 1 107.27 133.4 280.45 Off-peak 26.42 19.16 56.85 1 26.42 26.70 60.3s Short duration (CU) d1 / Demo Charte (per kI) 50730 55238 59650 f 60606 76971 67603 ProportLonal price (per khh) I Peak (7 - 11 p.m.) 49.36 46.56 151.27 J 57.68 64.87 167.34 Off-peak 16.5S 9.31 56.85 1 18.91 12.98 60.33 General el 1 De d Charg (per kI) 63518 68952 72028 1 75884 96081 81633 ProportiLonal price (per khh) I Peak (7 - 11 p.m.) 34.47 28.90 115.45 1 39.89 40.27 126.74 Off-peak 12." 5.79 56.85 I 14.68 8.06 60.33 Lane duration (LU) f /I Dem_d Charge (per hI) 77853 84247 86489 1 93011 117392 96207 Proportional price (per hbh) I Peak (7 - 11 p.m.) 25.85 16.67 94.72 I 29.60 26.02 103.26 Off-peak 10.93 3.96 56.85 I 12.22 5.20 60.33 a1 March 1985. b/ Does not include consunption tax (TCA) or contributions to the special mmicipal fLau. These prices re not eqalie erdlly reflect the long amnrinia costs supplying electricty. Excludes the Go_veinsnt' she s certain Invstmts in the DBR. o1 Prom 0 to 1000 eourslyear. d/ Froz 1000 to 2500 helrslyear. e/ From 2500 to 5000 hours/year. f£ Over 5000 eourslyear. Scurce: SE=. - 53 - 4.42 With demand forecasts now adjusted downward (para. 4.17-4.10), most of SEBG's system development plans will have to be re-optimized (para. 4.31-4.33). The mission recomends that the tariff study be updated: (a) to incorporate (i) the re-optimized system development plans (particularly as this relates to the calculation of short-run and long-run marginsal costs of supply) and (ii) modifications to the load curve and consumption patterns envisaged following the 1986 economic slowdown; and (b) to ensure adequate cash generation. Reform of Public Service Reaulations 4.43 9HBG's present legal ststus is that of concessionaire for the operation of the power system. The concession grantors are the municipality, in the cases of LBV and PDG, and the state for the other subsystems. The generating plant of the system is owned directly by the Government, which normally assumes responsibility for financing and constructing the infrastructure needed by SBEG's operations, as well as partially reimbursable loans. SEEG is a parastatal enterprise, with the Government holding 63X of its shares, and large private or semi-private companies holding the remainder. No return is realized on BERG's capital, although some large consumers who are also shareholders (¢OMUP, COMILOG) are beneficiaries of preferential (low) tariffs. The mission has recommended that this situation be reversed, so that shareholder benefits are realized through return on capital rather than through tariffs (para. 4.47). 4.44 The major advantage of the current public service arrangements is that the Libreville and Port-Gentil municipalities are able to monitor the development of the electricity and water distribution networks within their jurisdictions. The major disadvantages stem from the overly complicated billing and accounting systems needed by 8BEG under these arrangements. In general, customer bills are difficult to read. Charges intended to cover investments are not easily decipherable, especially in LBV and POG, where the various funds complicate the billing. The accounting system adopted to keep track of subsystem disparities is characterized by (a) numerous circular inflows and outflows, and (b) imprecise valuation of assets, making it difficult to define the economic return on investments and debt servicing capacity. 4.45 In early 1986, the MOM1 considered a proposal to reform the public service arrangements for electricity and water. The primary objectives of the reform are to (a) further unify the electricity subsector, and (b) transform 5EeG into an enterprise which will operate with neither loss nor profit. The KKR1's proposal is comprised of three main components: - 54 - (a) SEBG will be converted into a public enterprise with 100X of capital held by the Government. (b) Upon this conversion, all buildings and equipment owned or used by SERG will become state property. (c) SEEG will be responsible only for, managing the system. The legal difficulties inherent to these arrangements can be easily accommodated within the framework of the Gabonese law. 4.46 This proposal meets the objective for subsector unification, and should result in simplified accounting and billing of electricity throughout the country. Several major difficulties could arise, however, from the transformation of BERG into a management company owned entirely by the national Government. (a) There is a risk that regional/load center-specific inputs needed for efficient management and planning of subsystem distribution will be lost if the municipalities are totally excluded. (b) There is a risk that the creation of a publicly-owned monopoly for electricity supply will not lend itself to efficient and least-cost supply of power throughout the country. In fact, experience in other countries in Africa and elsewhere shows that total nationalization of public utilities tends to distort incentives for efficient supply. (c) Electricity investment is likely to become a heavy burden on the Government budget, when some elements should be financed from other sources, especially by consumers. (d) 8REG will become subject even further to Government administrative rules (e.g., on staff-related issues) that may not be appropriate to a commercial, revenue generating enterprise. 4.47 In light of this, the mission recommends that all proposal for public service reforms within the electricity subsector be revised, preferably following a thorough examination of SEEG's financial situation and a management audit of subsector operations (para. 4.52). In the meantime, the mission advises that SEEG's parastatal status be maintained. Shareholders other than the national government could include the current shareholders, but should most certainly include the Libreville and Port-Gentil municipalities to insure their continued participation in distribution issues. Investment by other entities or individuals, private or public, could also be encouraged. If this status is maintained, preferential tariffs for shareholders should be eliminated; instead, shareholders should be the beneficiaries of any profit realized from BEEG operations. - 55 - 8OEG's Finmacial Situation 4.48 A severe cash balance problem caused by arrears and/or non- payment is the most important financial issue for the 8EEG in the short term. More than 852 of outstanding billings are attributable to national and local services and the national administration (Table 4.8). Although this is not a recent phenomenon, the problem has mushroomed dramatically since 1981; by mid-1986, arrears amounted to almost 502 of the yearly billing. As a result, SK3G's cash flow has decreased from about 40X of the .eombined electricity and water turnover in 1980/81 to only 27S in 1985. The situation probably is much worse than it appears, since 8BEG owns no capital and pays no depreciation. The expected decrease in electricity demand coupled with short-term difficulties for the national economy can only cause the situation to worsen. Table 4.8: ARREARS PAYABLE ON SEES ACCOUNTS (ml IlIon CFAF) Cusftos 1981 1982 1983 1984 1985 VIP 548 67g. 1,181 1,950 2,152 Oter private 2,250 1,741 1,3t3 t,375 2,046 Admlnlstrstlons under the state budget 2,550 4,207 5,006 3,190 6,442 Other eminalstratlons 1,959 2,547. 3,093 3,390 3,381 -allpaeli[tles l Wommunitles (LIbr villo & Port-Gentil excluded) 452 700 298 589 935 Total 7,759 9,874 10,891 10,494 14,956 tS of yearly billing) (36.4) (38.5) (36.7) (29.6) (32.9) Source: SEES. 4.49 There are certain structural and operational problems inbirent to the system which contribute to SEEG's financial difficulties. The demand on the generating system is relatively small and dispersed; thus distribution costs, even in the cities, are quite high. The low generating costs of the hydroelectric plants are offset by the high investment costs of these plants, arising from difficult-access to the sites. The isolated centers represent a disproportionate fraction of the overall SEW budget, relative to the size of installed capacity. Because it is entirely thermal and highly decentralized, the generating costs of this subsystem are more than three times those of the next most expensive subsystem. It would be difficult, if not impossible, for BUKG to correct these factors. - 56 - 4.50 Several options are available to 83G to tackle its firtancial problems. It has already launched a vigorous collection program for recovering non-payments from small, private customers. This is only a fraction of the problem however, as most of the arrears are attributable to governmental or parastatal bodies. Owing to the structure of the arrearages, the Government could opt to resorb some of the debt. This would be the most politically expedient solution, but could leave S8tC iC an untenable position of financial instability. 4.51 Given the limitations inherent to undertaking a comprehensiv- review of the electricity subsector within a short period of time, the mission was not able to explore this problem in more depth. The problems seem to stem primarily from the financial structuring of SEUG relative to the Government. It is an issue which should be given a high priority by Gabonese authorities, as many questions remain unanswered in this assessment. The mission recommends that a full examination of SUNG's financial situation ani a management audit of subsector operations be undertaken immediately, the key areas of immediate concern being: (a) to determine the net finAncial position of SEUG vis-&-vis the Government, taking into account direct and hidden subsidies, including Government-financed investments, operational subsidies, and preferential tariffs; and (b) to define a plan for financial and managerial restructuring of the subsector (the former possibly by debt-to-equity exchanges or transfer of assets), with the objective of Mi) rectifying the financial situation, (ii) strengthening sNUG's accounting system to ensure that its accounts totally reflect the rate of return on subsector investments and the economic costs of generation, transmission and distribution, and (iii) optimizing the level of autonomy exercised by SUNG in order to promote efficient management and operation of the electricity supply system. 4.52 There does appear to be scope also for SNUG to improve its immediate cash balance through the reduction of some operating costs. Personnel costs, for instance, represent 451 of SNGC's operating expenses. This is a high percentage but can be explained by the capital intensive nature of SNUG's operations (small outlays for fuel, linked to heavy use of hydroelectric generation) and also by the many non-connected distribution points scattered throughowut the system. The mission estimates that 500 MS are sold and 39 customers are served per employee. 16/ The managerial and supervisory staff account for 401 of 16/ These figures cannot be calculated precisely since employees cover both water and electricity operations, The mission's estimates are %ade using the assumption that 3/4 of personnel's activities are devoted to electricity. - 57 - the total 2,040. This is partly due to the double staffing of about 50 key positions with an expatriate and a national undergoing training. The expatriate staff (80 -regular employees) is paid according to the same scale as the nationals, but receives additional benefits for housing, home leave, etc. The additional cost represents about 5 of the total personnel costs. The number of expatriates is being progressively reduced, which will produce savings in this area. 4.53 The mission recommends that in addition, all operating costs be reviewed to ascertain their scope for reduction. Other costs should also be examined: maintenance costs are relatively high, but in return the reliability of service in the 83G system is excellent. Some reduction in maintenance costs could be achieved without substantially lowering the supply reliability. Miscellaneous costs included in Salm's budget such as training (5) and public relations and missions (41) could also be reviewed to determine the scope, if any, for possible reduction. The company is pursuing all effort to bring its operating costs under control. Tabl Is GABM8 0-MrCA EIIB; oasup -- -- - -------------------------- - ---- - - -- - - --oo -s 1978 1979 190 191 1982 1983 1984 1985 1966 aI PETMXRLEM PRODUCTS (000 tons) LPG 5.25 5.57 6.09 6.75 7.29 8.30 8.90 8.90 9.80 TOR equivalent 5.56 5.90 6.45 7.13 7.72 8.79 9.43 9.43 10.38 Growth rate (X) 6.10 9.34 10.51 6.29 13.89 7.23 0.00 10.11 *vWs 4.81 4.21 2.91 2.60 2.20 1.70 1.60 1.80 1.30 ToR equivalent 4.98 4.36 3.02 2.69 2.28 1.76 1.00 1.86 1.35 Growth rate (X) -12.56 -30.71 -10.84 -15.32 -22.73 -5.68 12.50 -27.78 Jet Al 73.00 69.02 68.58 75.02 74.83 70.50 76.30 81.50 73.40 TOR equivalent 74.46 70.40 69.95 ".13 76.33 n.91 79.87 83.13 74.87 Growth rate (X) -5.46 -0.63 10.25 -1.05 -5.79 11.06 4.09 -9.94 Gasoli. 44.93 45.69 51.17 55.55 56.83 61.70 62.20 65.50 64.70 TM0 equivalent 46.23 47.01 52.66 55.10 58.47 63.49 04.00 67.19 00.S8 Growth gate (X) 1.69 12.01 4.64 6.12 8.58 0.81 4.99 -0.92. Kerosene 10.03 8.97 9.68 10.05 10.71 12.00 14.70 15.80 16.60 SOg equlialent 10.15 9.08 9.79 10.17 10.83 12.14 14.88 15.99 16.80 Growth rgate (X) -10.55 7.80 3.79 6.S8 12.09 22.50 7.48 5.06 Gas oil 161.28 160.28 176.88 204.32 207.20 215.30 221.60 254.70 201.60 1 TOE equivalent 161.28 160.28 176.88 204.32 207.20 21S.30 221.60 234.70 201.80 Growth rate (X) -0.61 10.35 15.51 1.41 3.91 2.93 5.91 -14.02 us Fuel oil 6.08 10.22 33.74 29.51 24.31 24.50 30.40 38.10 28.60 1 TOR equlvalent 5.89 9.91 32.70 28.59 23.56 23.74 29.46 36.92 27.71 Grofth rate (X) 08.27 230.11 -12.56 -17.00 0.78 24.08 25.33 -24.9 TOTAL 305.37 303.96 349.06 382.36 383.36 394.00 417.70 446.10 396.20 TOe equivalent 308.55 306.94 351.45 385.12 386.39 397.13 420.89 449.22 399.48 Growth rate (S) -0.46 14.84 9.54 0.26 2.77 6.02 6.80 -11.19 BLRenCTBZZ COWh) Total to Internl System 491.20 534.80 506.50 611.80 667.20 729.00 79.10 861.00 875.00 TOR equivlent 42.24 45.99 48.72 52.61 57.38 62.69 68.38 74.05 75.08 Growth rate (S) 13.91 8.88 5.93 8.00 9.06 9.26 9.07 8.29 1.39 TOTAL CO 005I (000 TOR) 350.79 352.93 400.17 457.74 44S.77 459.8 489.27 523.27 474.56 percent chane 0.61 13.59 9.39 1.3# 3.42 6.40 6.95 -9.31 aI Prelimiary estiotes. Source: Mlislsi estimtes, DoE, SE, Table 2s AlUll AJIAL CROT -( per year) 76-61 79-82 80-63 81-84 82-85 78- 79-85 sled 9.18 7.96 8.06 6.85 8.92 9.05 8.22 Pet Prod 7.97 6.04 6.85 4.05 3.96 5.08 5.39 Total 7.79 6.19 0.94 5.20 4.59 5.96 5.68 _______________---- - - - - - -- - - ______ ____________ 59 - bnu Annex 2 INWESTMENT EXPENDITURES FOR PETRDLEUM EXPLORATION, 1977-1985 (In a I IIon CfAF) GULF VAULAR ELF SHELL INA BP BUNRAH AMOCO TENNECO ASIP CONOWO TOTAL 1977 15,260 2,258 17,518 1978 699 13,482 2,290 164 590 17,225 1979 2,487 18,612 924 3,845 766 3,266 29,900 1960 1,49 125 21,465 1,644 3,197 3,700 3D,600 i961 1,013 33,056 700 4,0Q7 7,852 6,524 33 53,152 1982 58 43,799 1,943 2,962 7,623 268 2,404 59,057 1983 369 36,330 3,906 2,512 1,824 1,385 123 46,451 1984 32,733 13,006 3,816 11,239 8,952 1,104 70,850 1965 33,290 12,700 1,611 7,454 36,794 467 92,316 Sources DO. < - 60 - AuLe: 3 6A90N - WELL CRILLINW HISTORY, 1976-1985 WeiIs drliled _Htor IrIllIed Dry Holes Year Exploration Davelop.ant Exploration Development Total Exploratlon Deveolopmnt 1976 16 24 36,117 65,452 101,569 12 2 1977 17 13 40,132 39,239 79,362 1S 1 1978 15 15 35,155 33,160 68,315 10 2 1919 21 16 50,141 43,036 -93,177 13 2 1980 16 24 35,543 52,485 88,028 8 2 1981 27 41 69,113 90,262 159,375 20 7 1982 20 40 43,702 85,937 129,639 11 5 1983 18 33 36,716 70,062 106,798 10 1 1984 22 20 53,026 42,366 95,392 18 2 1985 31 16 77.279 40.191 117.470 27 2 Total 203 22 476,924 562,201 1,039,125 144 26 RATIO 71% 11% Source: 0GH. - 61 - INVESlNENT EXPENDITURES FOR PETROLEUM OEVELOPfENT, 1976-1965 (ml I Ion CFAF) I/ ELF SHELL ANOCO TOTAL 1976 10,708 314 11,022 1977 6,642 537 7,179 1978 19,105 1,769 20,874 1979 16,941 8,000 24,941 1960 34,271 15,662 49,933 1981 84,060 10,767 94,827 1982 76,497 t0r18ss 7,462 94,117 1963 65,515 22,346 33,460 141,321 1984 51,625 17,533 20,421 89,579 1985 46,954 32,896 8,962 88,832 a/ Averag y.p*jy exchange rates: 1980 $1 3 211 CFAF 1961 S1 a 272 CFAF 192 51 * 326 CAF 1963 51 a 380 FAF 1984 S1 - 436 CFAF 1985 S1 a 450 CFAf Source: 06H - 62 - Annex 5 PaSe 1 of 3 NATURAL GA8 UTILIZATION VEASIBILITY SUWDY DAFT TlIM OF REFIREIC I. Reserve Evaluation A. Review existing data to estimate the size of reserves by field. B. Estimate investment requirements to appraise and develop those reserves under different scenarios of reserve and production levels. (Alternatively, this could be undertaken in the engineering study under Part III.) {I. Cas Market and Pricing Study A. Market Survey 1. Industrial-Power Market Investigate the present fuel consumption of the large industrial consumers within the supply zone. (Large industrial consumer is defined as a consumer with annual fuel consumption of about 2 million liters of fuel oil equivalent per year or more.) The following information and data should be investigated and gathered from the large industrial consumerst (a) name, location, ownership; (b) raw material and product; type and quantity; (c) present fuel: heating value, price (specify any excise taxes); (d) storage capacity; (e) type and general technical specification of the fuel consuming equipment, i.e., boilers kiln, diesel engine, turbine, etc; (f) fuel consumption: yearly, average daily, maximum daily, maximum hourly; (g) specify the seasonal consumers, such as sugar factories and period of work; (h) future expansion plan. - 63 - Annex 5 Page 2 of 3 For medium sise and small industrial consumers, the above information should be provided for each category of consumer, such as brick kiln, foundries, workshops, etc. 2. Commercial and Household Sectors (a) identify cities and townships within the supply sone, by location, population, general layout, type of houses and commercial units and development plante (b) temperatureS mean maximum, mean minimumt seasonal changes, degree days of heating and cooling; (c) type of fuel and consumption of each sector; specify LPG; (d) breakdown of household consumption, i.e., space heating, water heating and cooling; (e) determine the number of potential commercial gas consumers by group, such as bakeries, hotels, etc; and (f) number of LPG consumers. B. Consumption Estimates 1. Using the data from the market study and considering the techucial feasibility, conversion costs, time required for conversion, the value of gas ("net back"), and minimum reserves to cover project or plant life, estimate the potential for gas consumption (a) for present industrial/power consumption and (b) industrial expansion and potential commercial and household consumption. 2. Also investigate the scope for use and the value of natural gas as a transport fuel or feedstock for production of ammonia/fertilizers and petrochemicals, including preliminary estimates of attending investments required. C. Pricins 1. Review the existing pricing structure for natural gas and competing energy resources. 2. Upon completion of the engineering study, recommend in broad terms a natural gas pricing structure, taking into account development and delivery costs, costs of conversion, service connection and costs of competing --A* 01MPW.I._ a - 64 - Annex 5 Page 3 of 3 III. Preliminary Engineering Design and Cost Estimates A. Prepare a broad description and cost estimates of natural gas gathering, transmission, processing and separation and major distribution systems (i.e., pipeline to industrial grid and spurlines to city gate station(s)), consistent with reserve scenarios proposed in the reserve study and the market survey. B. Estimate the unit and, if possible, marginal costs of producing, transmitting and distributing the gas for various scenarios of reserves. s C. Outline the steps required in implementing such investments. IV. Feasibility Analysis and Recommendations A. Evaluate the impact of the gas as a new source of energy in the overall energy supply-demand context. B. Analyze the petroleum products supply-demand situation before and after gas substitution and present a solution, i.e., by axporting the excess petroleum products and/or changing the refinery's product pattern. C. If justified, recommend an action plan for developing the gas, including an analysis of provisions concerning gas and condensate in existing production sharing contracts and appropriate price levels for the gas to induce a commercial oil company to develop and produce the gas resources. @mOU a 60A PET? 1*73-1965 ----- -- ---- … ------ - ----- -…------------------- 1975 1976 1977 1978 1979 1980 1961 1982 1983 19S4 1985 V 000 tos) 906.27 980.97 644.64 970.72 743.20 794.36 689.63 616.88 519.91 580.65 642.47 1R3.BW P0OWCTS ('000 uS) LPG ('000 tons) 4.99 5.S6 3.97 5.80 S.14 4.69 4.5S 5.25 3.n9 5.64 7.30 Ton equivalent 5.29 5.68 4.20 .14 3.32 4.96 4.82 5.56 4.16 5.97 7.73 Gasoline - Rgular 12.11 119.26 100.29 103.97 72.75 37.06 32.26 24.99 13.75 15.40 10.94 Ton equival.nt 88.08 63.96 70.61 73.19 51.22 26.09 22.71 17.59 9.66 10.84 7.70 TMN equivalent 90.63 66.39 72.65 75.32 52.70 26.84 23.37 18.10 9.96 11.15 7.92 Gasoline - PZMde 53.92 70.78 63.46 78.12 68.30 67.14 67.02 57.51 59.54 64.37 74.03 Ton equivalent 39.S6 51.67 46.33 57.03 49.86 49.01 48.92 41.98 43.46 46.99 54.04 TOR equivalent 40.50 3S.17 47.67 58.68 51.31 50.44 50.34 43.20 44.72 48.35 55.61 werose 121.26 130.94 108.97 131.06 113.40 101.60 110.93 113.73 85.51 102.62 109.87 Ton equivalent f .52 104.23 86.74 104.S3 90.26 80.87 88.30 90.53 68.06 81.68 87.45 TOE equlvalent 97.20 104.96 87.35 105.06 90.90 81.44 88.92 91.17 6.854 82.26 88.07 Jet A Ton lequvalent 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 ' 0.00 TOR equivalet 0.00 0.0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00°.° Eaptba 0.88 15.71 11.45 12.27 17.69 Ton eSivalent 0.00 0.00 0.00 0.00 0.00 0.00 0.64 11.42 8.32 8.92 12.86 603 equvalent 0.00 0.00 0.00 0.00 0.00 0.00 0.66 11.76 8.57 9.18 13.23 0a 011 271.51 291.00 263.52 304.33 214.26 222.21 268.57 23O.70 212.65 229.47 265.34 TM equivalent 233.50 250.26 226.63 261.72 184.26 191.10 230.97 198.40 182.88 197.34 226.19 TO equivalent 23S.50 250.26 226.63 261.72 184.26 191.10 230.97 196.40 182.88 197.34 228.19 11 0au 391.45 480.64 361.31 395.3S 325.92 321.25 261.50 220.39 17.22 193.61 210.90 Ton equvalent S52.31 432.58 325.17 355.62 293.33 289.13 23.35 19S.35 154.10 174.24 189.81 TM3 equIvalent 341.39 419.17 315.09 S44.60 *84.23 280.16 228.05 192.20 149.32 168.84 183.92 8It ('000 taOn) 0.52 5.36 13.03 7.44 3.74 7.66 5.70 10.91 12.25 10.54 8.23 STE equivaLen Ten equivalent 615.28 9S3.42 772.47 865.13 675.81 648.57 437.15 574.43 482.68 536.21 595.58 TON equivale 808.50 919.63 753.59 851.52 666.72 634.95 627.13 560.38 468.1S 523.10 584.68 IN r OSWWT!ON ('000 taO) 51.'2 39.03 50.02 35.74 37.42 26.32 23.14 22.47 27.67 28.00 LOM83 ('000 tons) 39.2* 47.55 33.15 55.56 S1.66 108.37 26.17 19.32 14.76 16.97 18.89 in percent of tlxousbput 4.33 4.85. 3.92 5.72 4.26 13.64 3.79 3.13 2.84 2.92 2.94 aI To Ausuat 31, 1986 Sour8e, misson estunte, Ml:, DOB. - 66 - Annex 7 BEICIP SCENRIWOS FOR PETROLEUM PROCUCr DEMAND Table 1 DENMA PROJECTIONS FOR PETROLEUM PRIOUCTS - HIGH AND LOW GROWfi 3CENARIOS 1988 1995 Product Unit 1963 Hlgh Low High Low LPG t 8,313 12,200 10,940 19,600 15,510 Resular 4 Premlum Gasoline .) 81,777 110,000 93,500 130,000 103,000 Aviation Gas .3 2,422 2,000 2,000 1,500 1,500 Jet Fuel M3 88,180 97,000 86,000 122,000 88,000 Kerosene .3 16,000 17,850 18,450 16,000 16,350 Gas o1 .3 254,500 286,600 234,600 385,400 294,800 .Fuel OfI t 24,463 40,800 31,400 53,000 40,000 Bitumens t 9,894 15,000 12,000 21,000 17,000 Lubrifeicants t 8,935 10,000 8,500 12,000 10,040 Source: EEICIP. Table 2: OEMAND PROJECTIONS FOR PETROLEUM PROUCTS MEDIUM GROWTH SCENARIO Product Unit 1983 1965 1988 1990 1992 1995 LPG t 8,313 9,700 12,200 13,600 15,200 17,560 Regular and Premium gasolIne .3 81,777 92,000 110,000 114,500 119,100 126,500 Aviation Oas *3 2,422 2,250 2,000 1,850 1,700 1,500 Jet Fuel .3 88,180 91,600 97,000 99,200 101,500 105,000 Kersesne 3 16,000 16,700 17,850 17,350 16,900 16,200 Gas OfI .3 254,500 258,050 288,600 302,500 317,000 340,100 Fuel OfI t 24,463 30,000 40,800 42,600 44,500. 47,900 Bltumens t 9,894 11,700 15,000 16,050 17,200 19,000 Lubriflcants 1 8,395 9,000 10,000 10,300 10,600 11,000 Source: BEICIP. - 67 - Annex 8 Page 1 of 2 PETLEUM PRWJCT DEMAND AND INVESTMENT REQU I REMNTS Table I- DEND EPrAJECTIMNS FOR PETROLEUM PRIFUCTS LOW GROWTH SCENMARIO Prodct Unit 1988 1990 1992 1995 LPG t 10,940 12,100 13,350 15,510 R"ular and Premium gasolIne 02 93,500 96,100 98,600 103,000 Aviation On .3 2,000 1,850 1,700 1,500 Jt Fuel M. 86,000 86,600 87,100 88,000 Kerosene .3 18,450 17,800 17,200 -6,350 on owI .3 234,600 246,750 264,300 294,800 Fuel Oil t 31,400 33,650 36,050 40,000 Bitummns t 12,000 13,250 14,600 17,000 Lubr ficfnts t 8,500 8,900 9.,300 10,000 Sourcet BEICIP. Table 2: ESTIMATED STORAGE REUIIETS FOR SECtRITy INVENTOty AND RESERVE INVENTORY aquired Daily Practical Needed Extra Extra Storap Extra Straep Swe ity Peak Security Avallable Storage for 30 dap needed for 25 days needed for Inventory V*oIm Invntoy Capacity Security Inv. Inventory 30 doa lnventory 25 (day) (.3/da) (a') Ce') (a) (MP) Cm') (GP) cm) G6sol Iees 16 305.0 4,010 2,435 2,445 9,150 7,386 7,675 5,964 Kerosene 16 50.0 600 - - 1,5 - - - Jet 16 426.0 6,.$48 760 - 12.840 6.116 10,700 3.487 Gas oil 16 472.0 7,5S2 5,925 - 14,160 9.03 11,800 6.S52 Fuel 011 21 125.5 2,635 3,000 - 3,M75 841 3,125 137 iarm Gasol Ines 9 25.5 229 255 - 765 561 637 420 Kerosene 9 18.5 166 125 47 555 473 462 370 Gas 01I 9 119.5 1,075 1,190 - 3,565 2,634 2,98 1,976 Ni'diol GasolInes 10 31.4 314 1,305 - 942 - 765 - Kerosene 10 21.6 216 535 - 648 124 540 - en Gas Ol 10 113.0 1,130 6,715 - 3,390 - 540 - Nosada Gasolin s 9 37.4 336 1,435 - 1.122 - 935 - Kerosene 9 14.4 129 - - 432 - 360 - Jet 9 22.1 199 475 - 663 - 552 - ans Oi 9 174,7 1,572 1,935 - 5,241 3,636 4,367 2,675 Gas OfI 25 8.1 202 250 - 243 - 202 - Port-Gentl I I l Gasoli Ines 9 106.0 954 1,435 - - - - - OS Kerex"3n 9.5 48,4 460 ----:__a Jet 9.5 36.3 344 2,660 - - 4! Gosn o 7 653.0 4.571 7,645 - - - - - i'S 60 3t00 0 1,600 300 2, 17,30 - - Source: Nisslon estleates, iEICIP, DON. - 69 - Annew 9 Page i of 5 RESIOAL PETROLEUM PROUCT PRICE STRUCTtR Table 1: PRICE STRUCTURE FOR PROOUCTS PASSING THROUGH THE GAMBA DEPOT April 10, 1986 (CFAF/hI) Premium Regular Kerosone Gas O1I 1. Base Price Ex-Port-Gentil 26,607.00 26,307.00 7,607.00 13,707.00 2, Port-Geetil Hfrbor Fee 225.00 45.00 45.00 45.00 3. Tax on f2 (8%) 18.00 3.60 3.60 3.60 4. Port Tax 100.0Pi 100.00 100.00 100.00 So Transport P4-Gaiba 1,408.00 1,408.00 1,408.00 1,406.00 6. Tax on 15 (6%) 112.64 112,64 112.64 112.64 7. User Fee - Gamb depot 354.00 354.00 354.00 354.00 6. Tax on 17 (8%) 26.32 26.32 26.32 26.32 9. Discharge/unloading 50.00 50.00 50.00 50.00 10. Equalization Subsidy/rax (1,495.96) (I.291.56) (1,401.56) (1,207.56) iI. Price ex-amba Depot 27,607.00 27,117.00 8,307,00 14,607.00 12. Delivory charge 225.00 225.00 225.00 225.00 13. Tax on 112 (6S) 18.00 18.00 48.00 18.00 14. Retall margin 6850.00 850.00 6 50.00 15. Retail price 26,700.00 26,210.00 9,400.00 15,700.00 16. Price per lIter 287.00 262.00 94.00 157.00 Source: Directlon 08n6rale des Caisses de Stabillsation et de Pbr6quation. - 70 - Annex 9 Page 2 0f 5 Tale 's PRICE STRUCTUE FOR PRODUCTS PASSING THROUGH TE SECONDARY DEPOT OF LANBAMNE AprIl 10, 1986 (CFAF/hI) Premium Regular Kerosene GM f11 1. Base Price Ex-LBV/POB 26,607.00 26,307.00 7,607.00 13,707.00 2. Port-Gentil Harbor Fee -223.00 45.00 45.00 45.00 3. Tax on f2 (8O) 18.i0 3.60 3.60 3.60 4. Po"t Tax 100.00 100.00 100.00 100.00 So Rlver Transport 1,072.50 1,072.50 1,072.30 1,072.50 6. Tax on J5 (8$) 8.080 83.60 86.80 85.80 7. CNI Tax on J5 & 16 (2%) 23.16 23,16 23.16 23.16 8. User Fee - Lsmbar6n6 303.88 303.U8 303.88 303.88 9. Tax on J8 (8%) 24.31 24.31 24.31 24.31 10. Discharge/unloading SO.OO 50.00 50.00 50.00 11. Equalization Subsidy/Tax (1.202.65) (1,148.25) (1,208.25) 1008! 2S) 12. Price ex-Lambar6n6 depot 27,307.00 26,817.00 8,107.00 14,407.00 13. Delivery charges (to city) 223.00 225.00 225.00 225.00 14. Tax on J13 (8%) 18.00 18.00 18.00 18.00 15. MunicIpal Tax 250.00 250.00 2SO.00 250.00 16. Retail margin 850.00 85000 859icO 17. Retail price 28,850.00 28,160.00 99,500.00 15,800.00 18. PrIce per liter 288.00 282.00 94.50 138.00 Source: Direction G&6hrale des Cesies de Stabilisatlon et de P6r6quatlon. - 71 - Annex 9 Pag8 3 of S Table 3: PRICE STRCTWE FOR PRPDCT PASSIN TROM T MAYIJIA DEPOT ApIl 10, 1986 (CFAFAIl) Premlum agular Kerosene an off 1. a Pric Ex-Pbort-Gotil 26,807.00 26,307.00 7,607.00 13,707.00 2. Plort Awtil Harbor Fee 225.00 45.00 45.00 45.00 3. Tax on 12 (8S) 18.00 3o00 3.60 3.60 4. Pnrt Tax 100.00 100.00 100.00 100.00 S. Transpot PiB-Msyubat 1,408.00 1,408.00 1,408.00 1,408.00 6. Tax on nS (8O) 112.64 112.64 112.64 112.64 7. User Fee - Nayuwba depot 553.12 553.12 553.12 553.12 8. Tax on f7 (8S) 44.24 44.24 44.24 44.24 9. Dischwr/unloadIng 50.00 50.00 50.00 50.00 10. EqualizatIon Subsidy/Tax Naysab (1.711.00) (I .La.A5 (1,516.60) (1,516.60) il. Price Ex-NsayubM Depot 27,607?e0 27,017.00 8,407.00 14,50?.00 12. Delilery charges to cIty 225.00 225.00 225.00 225.00 13. Tax an #12 (8S) 18.00 18.00 18.00 18.00 14. Retall margin 850.00 850.00 - 850.00 850.00 15. Retall price 28,700.00 28,110.00 9,500.00 15,600.00 16. Price per lIter 287.00 281.00 95.00 156.00 Souros Direction Gb6Arale des Calses de Stabillsatlon et de Pir6quatlon. - 72 - Annex 9 Page 4 of 5 Table 4: PRICE SlRUClEM FOR PRCCUCTS PASSING THFOUSO THE NDJOLE MEPOT April 10, 1986 (CFAFAIi) Premium Rsgular Kerosene Gas 01I 1. Base Price Ex-Port-Gentil 26,807.00 26,307.00 7,607.00 13,707,00 2. Port-Geatil Harbor Fee 223.00 4S.00 45.00 45.00 3. Tax on f2 (6%) 18.00 3.60 3.60 3.60 4. Port Tax 100.00 100.00 100.00 100.00 5. Rlver Transport 1,518.00 1,518.00 1,518.00 1,516.00 6. Tax on nS (8%) 121.44 121.44 121.44 121.44 7. CNI Tax on J5 + J6 (2%) 32.79 32.79 32.79 32.79 6. User Fee - NdJol6 303.88 30388 303.88 303.86 9. Tax on Os (6%) 24.31 24.31 24.31 24.31 10. Dlscharge/unloading 50.00 50.00 50.00 SO.OO 11. River Equalizatlon Subsidy/Tax (1.593.42) (1.589.02) (1,599.02) (1,399.02) 12. Price Ex-NdJol6 depot 27,607.00 26,917.00 8,207.00 14,507.00 13. DOelivery chargs 225.00 225.00 225.00 225.00 14. Tax on J13 (8%) 18.00 16.00 16.00 16.00 15. Retail margin 865000 850.00 850.00 650.00 16. Retall prIce 28,700.00 26,010.00 9,300.00 15,600.00 17. Price Wer Itter 287.00 280.00 93.00 156.00 Source: Direction 06n6rale des Calses de Stebillsetlon et de P6r6quation. - 73 - Annex 9 Page 5 of 5 Table si PRICE SlRWTUSE FOR PACDUCTS FROM MHANDA DEPOT THROUBH NDJOLE April 10, 1986 (Cf0A/hI) Premium Regular Kerosene Gas Oil 1. Cost Price (Ndjo*1) 27,607.00 26,917.00 8,207.00 14,507.00 2. TranspGrt NdJoi1-6oande 4,403.00 4,403.00 4,403.00 4,403.00 3. Tax on J2 (8O) 352.24 352.24 352.24 352.24 4. Losses In transit (on 01+2+3) 293.19 286.54 100.22 100.31 5. Financlal charge on security stocks 13U t 60 JHT 566.24 550.92 213.30 349.94 6. Customs credit tax (5s) 10.02 10.02 3.34 7. User Fee - Moanda depot 400.90 400.90 400.90 8. Tax on J6 (8$) 32.07 32.07 32.07 32.07 9. Retail margln 850.00 850.00 850.00 850.00 10. EqualIzatlon Subsidy/lax (6.157.46) (5.935.69) (5.505.07) (5.740.13) 11. Price ex-Moande depot 28,357.00 27,847.00 9,057.00 15,257.00 12. Transport (depot to city) 225.00 225.00 225,00 225.00 13. Tax on Jll (8S) 16.00 18.00 18.00 18.00 14. Municipal Tax 2SOtO0 250.00 250.00 250.00 15. Retall price 28,850.00 28,360.00 9,550.00 15,757.00 16. Price per liter 289.00 283.00 95.50 158.00 Souree: Direction O6nerale des Calsses de Stabillsation et de P&r6quatlon, 74 - Annex 10 Page I of 3 PETROLEUM PROCDUCT TRANSPORt COSTS Table 1: REIMJRSBEM NT fROM THE NDJOLE DEPOT (CFAF/ lIter) Transport costs Resimburseoent Towards: Dlstance (T.T.C.) Premium Regular Kerosene Gas OfI (Km) Akleni 623 62.44 60.01 58.01 58.51 60.01 Aye 113 11.29 7.86 7.86 7.36 8.86 Site. 383 38.26 34.83 34.63 34.33 35.83 saue 247 24.68 21.25 21.25 20.75 22.25 Franceville 536 53,53 51.12 49.12 49.62 51.12 Koulamoutou 364 38.36 36.93 36.93 34.43 35.93 Lastourville 353 35.26 32.63 30.83 31.33 32.3 Makokou 351 35.06 31.63 31.63 31.13 32.63 Mekambo 526 52.S5 49.12 49.12 48.62 50.12 MInvoul 423 42.26 37.83 38.63 38.33 39.63 mltzlc 190 18.98 13.5S 13.5S 15.05 16.55 Moends 476 47,55 60.75 58.53 54.25 S6.66 Mougnue 462 46.15 43.72 41.72 42.22 43.72 OYeM 308 30.77 27.34 27.34 26,84 28.34 Source: WFBP. Table 2: REIIMJRSEMENT FROM THE MAYUMBA DEPOT (CAF/I Iter) Transport costs Reimbursement Towards: Distance (T.T.C.) Premium Regular Kerosene Gas Off (Km) Mibombe 239 23.88 21.45 21.45 21.45 21.45 Mblgou 325 32.47 30.04 30.04 30.04 30.04 Mimongo 347 34.67 32.34 32.34 32.34 32.34 Noabi 204 20.38 17.95 17.95 17.95 17.95 Moulla 280 27.97 25.54 25.54 25.54 25.54 Ndende 204 20.38 17.95 17.95 17.95 17.95 Tchlbanga 114 11.39 8.96 8.96 8.96 8.96 Source: WSP. - 75 - Annex 10 Paa-e 2 o f 3 Table 3: REINFURSEtT FOR TRANSPORT FROM THE OEPOTS AT MBINDA AND NOANDA (CPAF/I iter) Transport From MBINDA costs ReimburseMent towardst Distance (T.T.C.) Premium Regular Keroseno Gas Oil (Km) otanda 104 10,39 t8.06 18.05 14.62 15.95 Cami log 104 10.39 6.79 6.09 6.89 6.89 From NOANDA towards: Akieni 149 14.89 11.46 11.46 10.98 11.46 Sakumbe 53 5.49 2.06 2.06 2.06 2.06 Somacngo 169 16.C8 13.45 13.45 12.95 13.05 Fronceville 60 5.99 2.65 2.65 2.15 2.65 KoouIamutow 193 19.28 15.8s 15.85 15.35 15.85 'astourvI I Io 123 12.29 8.86 8.66 6.36 8,36 Lekonu IB 15.78 12.35 12.35 11.85 12.35 Soasbo SO 5.59 2.16 2.16 1.66 2.10 oMunano 20 2.00 (1.43) (1.43) (1.93) (1.43) "vengue 45 4.50 1.07 1.07 0.57 1.07 OkoudJa 248 24.77 21.34 zt .34 20.84 21.34 Pane 283 28.?? 24.84 24.84 24.34 24.84 Soureet WBP. - 76 - Annex 10 Page 3 of 3 Table 4: REINBURSEMENT FROM THE LNMAENE DEPOT (CFAF/IIter) Transport costs RAembursement Towards Distance IT.T.C.) Preuium Regular Kerosene Gas Oil (Km) Foegamom 92 9.19 5.76 4.76 3.76 5.76 Mebamba 310 30.97 27.54 26.54 25.54 27.54 MandJI 170 16.98 13.55 12.55 11.55 13.55 Mayumbs 477 47.65 44.22 43.22 42.22 44.22 Mblgou 397 39.66 36.23 S5.23 34.23 36.23 Mimongo Yeno 419 41.86 38.43 37.43 36.43 38.43 Mlocngo Mbigou 475 47.45 44.02 43.02 42.02 44.02 Moabl 291 29.07 25.04 24.ei4 23.64 25.64 Moula 200 19.98 16,55 15.55 14.55 16.55 Ndende 273 27.27 23.84 22.84 21.04 23.84 Slndare 97 9.69 6.26 5.26 4.26 6.26 Tchibanga 363 36.26 32.83 31.83 30.83 32.83 Source: IIBP. Table 5: REIMBURSBENT FROM THE LIBESVILLE DEPOT (CFAF/liter) Transport costs Relmbur_sat Towards: Distance (T.T.C.) Premlum Regular Kerosene Gas Off (K) Lambardn6 235 23.48 20.26 22.16 21.96 20.56 Medouneu 218 21.78 10.85 10.75 9.55 10.15 NdJol6 224 22.38 18.16 20.06 19.86 18.46 Source: WBHP. -77-. Annex 11 PRICE STRUCTEIRE .R BUTANE SOLD IN LIEEVILLE AND PORT-GENTIL "ercb 18, 1985 (CFAF/l) 1. Ex-reflnery price 99,000 2. LandIng Tax l,000 3. Dishehwr fie (2% of 1 + 2) 2,000 4. Entry duty (25% of 91) 24,730 5. Tax 10% of 91 and f4 12,375 6. "Taxe ocmpl6mentalren 5% of 11 4,950 ?. Customs tax 0.8% of #1 792 8. Tresury tax 2% of 4, 5, 6 nd 7 86 9. Depot Users Fees 25,378 10. Tax S%ot f 9 2.030 11. Exit price at 46p8t 172,361 12. Bottle malntenance 34,363 13. Amortization of bottle oosts 34,320 14. Transport to city 9,781 15. Tax on transport to city 8% of 114 782 16. General charges 18,405 17. Financlot charges 1.2% of #4, 5, 6, 7 end 8 515 18. Profit 17,500 19. StabiIlzatIon subsidy 5,953 20. Wholesale price 294,000 21. RetaIl margin 26,000 22. RetaIl price per ton 320,000 23. Retail price per 12.5 kg bottle 4,000 Source: WBP, -78 - Ann" 12 Page~ 1 of 3 ELECTRICITY SYSTEM DATA Table Iv SIJSARY Of BASIC DATA 1975 1980 1985 Installed capeclty (14) 101.1 209.0 251.9 Hydro 47.7 121.8 163.6 Thermal 53,4 67. 88.1 osneration (0Mb) 253*0 566.5 461.3 Hydro 143.3 415,l 667.7 Thermal a/ 109*7 150.7 193.6 Losses 36.6 6864 104.4 Sales (MAPi) 216.4 498.1 756.9 NV and WV 122.2 309.5 398.4 LV 94.2 188.6 358.5 Custneurs 19,390 33,100 58,506 N and MV 172 310 360 LV (Total) 19,218 32,790 58,146 Residential 18,425 31,860 56,652 Public Lighting 157 185 536 Industrial 636 76'. 956 a/ Including purchases from Shell 6ambs (2.3 GNh In 1985). Source: SEEG. Table 2: MAIN POdER SYSTM CHARACTERISTICS, 1985 LIbreville Port-4entil FrancevIlle centers Total AvIleable capacity 1' 0W) 168 57 48 5 285 Hydro 126 b/ 0 38 0 161 Thermal 42 57 10 15 124 1985 Peak Load ON) 87 26 25 8 cS - Not Generation COMh) 531 158 137 35 861 Hydro 530 0 137 0 668 Thermal 0 158 0 35.d/ 194 Sales (COh) 461 e/ 146 119 31 _/ 757 HV & Y 211 75 104 7 398 LV 250 70 14 24 358 Number of customers 37,968 8,845 3,059 8,633 59,56 HYSNW 252 44 42 21 360 LV 37,716 8,801 3,017 8,612 58,146 Average Oemand Growth 1982 to 1985 (S/yr) 10.2 4.0 7.4 20.8 8.9 a/ In October 1986. b/ Only 108 MM are available In dry yars. c/ Sum of Individual peak loads; not occuring simultaneously. d/ Including 2 GMh purchased from SHELL. !/ Figures for N'Toum Included under Libreville totals. Source: SEES. Io Table 3: INSTALLED CAPACITY AND GEtERATION 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 Total InstalIId CapacIty OW) 101.1 106.1 162.4 167.0 167.6 209.0 219.2 221.0 228.4 239.5 251.9 Hydro 47.7 52.3 57.0 76.2 76.2 121.8 121.8 121.6 131.4 141.0 163,8 Thermal 53.4 53.8 105.4 90.8 91.4 87.2 97.4 99.2 97.0 98.5 88.1 Total o.n.ration (GWh) 253.0 327.8 431.2 491.2 534.8 566.5 6t1.8 667.2 729.0 795.1 861.3 Hydro 143.3 161.8 299.4 348.0 369.5 415.8 459.5 502.9 546.5 612.9 667.7 Thermal 109.7 166.0 131.8 143.2 135.3 150.7 152.3 164.3 182.5 162.2 193.6 UBV Installed Capacity 05) 50.8 50.8 50.8 70.0 70.0 115.6 115.6 113.2 113.2 113.2 129.4 Hydro 38.4 38.4 38.4 57.6 57.6 103.3 103.2 103.2 103.2 103.2 126.0 Therami 12.4 12.4 12.4 12.4 12.4 12.4 12.4 10.0 10.0 10.0 3.4 LEV Generation (OWh) 131.8 164.4 250.5 293.9 313.4 328.7 367.2 396.2 434.9 483.2 442.3 Hydro 128.2 161.3 241.2 283.5 309.6 326.7 356.4 396.0 4315 482.9 530.4 Thermal 3.6 3.1 8.6 10.4 3.8 2.0 1.8 0.2 3.4 0.3 0.3 P06 Instel led Capacity a;/ ON) - - - 56.8 59.8 62.8 62.8 62.8 62.8 61.3 59.8 Generation b/ (6Wh) 98.0 104.0 114.0 117.8 111.7 123.8 128.4 140.2 148.5 151.9 157.8 FCY Install d CapacIty 0NV) - - - - - - 31.2 33.8 42.0 51.6 47.8 Hydra 9.3 18.6 18.6 18.6 18.6 18.6 18.6 18.6 28.2 37.8 37.8 Thermal - - - - - - 12.6 15.2 13.8 13.8 10.0 FCV GeneratIon (CWh) - - - - - - 99.2 110.6 121.3 130.7 137.3 Hydro 14.8 51.9 58.1 64.5 79.9 89,0 94.2 106.9 115.0 129.9 137.3 Thermal (2) (2) (2) (2) (2) (2) 5.0 3.7 6.3 0.6 0.0 DER Install d Capacity a/ 0(N) - - - - - - 8.6 8.6 10.7 13.4 14.9 Generation (GWh) 6.2 6.8 8.2 11.5 12.9 14.3 16.2 19.2 23.0 27.2 33.3 a/ All thermal. bJ Included In DER. Source: SEE8. CHARACTERISTICS OF INSTALLED HYDRO AND THERNAL iPLANT Number Total Unavailability rates u/ of Unit Installed Cammissioning Main- Forced System Name Type of Units Units rating capacity Years tauance Outages Total 0N) Oi) (S) (S) (S) lUY KINGELE ilydro 2 9.6 19.2 72 - 73 4.4 0.7 5.1 2 19.2 38.4 75 - 78 3.7 0.6 4.3 TCHlIRLE Hydro 3 22.8 68.4 80 - 85 3.6 1.6 5.2 OSANDA S.T. 2 20.8 41.6 86 - - - POO Q 6.T. 2 20.9 41.8 77 7.2 0.6 6.0 co - Diesel S b/ 3.0 15.0 69 - 76 2.7 2.7 5.41 FCV POUBARA I Hydro 4 4.64 18.56 75 - 76 3.9 O.S 4.3 POUBARA 2 Hydro 2 9A6 19.2 83 - 84 2.0 5.3 7.3 NOYABI Diesel 5 2.2 11.0 77 - - - Dlesel 2 1.4 2.8 65 - 66 - - - DER - Diesel - - 15 - - - - a/ Neon value from ocumissioning to end of 1965 for hydro plants and meen value for 1985 for therml pisants. b/ Six twin units out of which two have only one motor left avaltable, Source: SEES. ELECTRICITY EMEAPO: 1960-1965 (oh) Average Annual Srowtb 1980 1981 1962 1963 1984 1985 80-85 82-85 84-85 (S) (M) (O Total 496 533 S6u 639 697 757 8.7 8.9 8.6 MV 309 332 347 367 383 399 5.2 4.8 4.2 LV 189 201 229 273 314 358 13.6 16.1 14.0 Libreville 274 296 325 359 400 442 14.6 10.8 10.5 mV 141 158 164 173 185 196 6.8 6.1 5.9 LV 133 137 161 187 215 246 13.1 15.2 14.4 Port-Soothl 114 117 129 133 140 146 5.1 4.2 4.3 co NV 76 14 75 76 75 75 -0.3 -0.1 0.6 LV 38 43 53 57 65 70 13.4 9.8 7.7 Francevile 81 91 100 110 114 119 6.0 5.7 3.7 NV 74 83 91 100 103 104 7.2 4.5, 1.4 LV 7 a 9 10 11 14 11.0 16.1 24.5 Isolated Cnteis 29 30 33 37 43 50 11.5 15.4 16.6 MV 18 17 17 18 20 22 4.3 9.6 10.3 LV 11 13 16 19 23 26 20.2 21.0 23.0 Source SEES,. ELECTRICITY COIRlWPTICN ANO SALES BY VOLTAIE AND TYPE 'f W4UIMR, 1985 ! Nor Averago of consupt lon Averae Voltae Category Tortff cusoe b/ Sales per customer Invoicing KWh rate (billion (1Knh) (S) (klh/year) CFAF) (S) (CFAF/kWh) General tariff E4 305 93,145 12.3 306,400 5,042 15.9 54.1 WY Special tariffs - 50 288,433 38.1 5,769,000 7,485 23.6 26.0 Internal sales - 5 16,916 2.2 3,383,000 - - - Total - 360 398,497 52.6 1,106,900 12,527 39.6 31.4 Social residential ES 4,655 5,357 0.7 1,151 250 0.8 46.7 Residential El*E2+E3*E9 49,835 285,031 37.7 5,719 17,129 54.1 60.1 Public lighting E64E7 S45 10,720 1.4 19,670 504 1.6 47.1 LV Industrial E5.E8 1,040 24,352 3.2 23,415 1,189 3.8 48.8 Internal sales - 215 15,555 2.1 72,349 - - - SEES Personnel - 1,860 17,462 2.3 9,388 65 0.2 3.7 Total - 58,145 358,475 47.4 6,165 19,137 60.4 53.4 TOTAL General Total - 58,505 756,972 100.0 12,940 31,664 100.0 41.8 a/ Taxes ond "contrlbutlonsn excluded. b/ Rounded to the narest multiples of 5. Sowrco SEEG. VI -84 Annex 16 Page 1 of 4 -1 DIP3 FO SD - 1984 In SRGC's 1984 demand foreca,tte several demand trend assessment methods were used. Al - Logarithmic extrapolation of past trends A2 - Linear axtrapolation of past trends A3 - Exponential extrapolation of past trends a -Use of a log function, taking as a basis past trends, final` assessed consumption per consuesr and the forecasted trend of tbQ total class of consumers involved, actual and projected C - Specific market surveys of large consumers Three forecasts were worked out using different scenarios based on the length of the recorded period used for the extrapolation, or the type of extrapolation selected (Al, A2, or A3). The tables in this annex present the general features of the forecasts based on the "average" scenario. The phrase "service rate" means the number of service per one hundred inhabitants; "SEEG use" means both the consumption by SEEG personnel and the SERG- own con;umption for tis operations (water service). -85- Annex 16 Page 2 of 4 Table 1: S£EQ FORCAST FOR LIERVILLE, 1984 Trend estimate 1988 1990 199 Population (103) - 273 295 359 ServIco rate - 10.8 11.5 13.0 Residential speclfic consumption Mbh/yoer) - 9.4 9.7 10.6 Total consumPtion (GIh) - 548 628 856 LV Consumption (Sb) - 321 381 559 Residential B 276 330 494 SEEG use A2 21 24 32 Public llghting Al 8 8 9 industrial A2 17 19 24 WV ConsumPtlon (0Mb) - 227 247 296 Private use A2 214 233 281 SEE use C 13 14 15 Source: SEEG, - 86 - Annex 16 Pape 3 of 4 TbIe 2: SEEG FOlCAST FOR PORT4ENTIL, 1984 Trend estimate 19B 1990 199S Populatlon (105) - 97 104 122 Service rate - 10.1 10.7 11.9 Rasidential swcific consumption (M/"r) - 9.4 9.6 10.6 Total onmptlon ) - 173 191 242 LV Consumption (lnh) - 97 114 169 Resldential 8 92 109 15 SEEG use Al 3 3 3 Public lightlg Al 1 1 1 Industrial A2 1 1 1 Consumption (Wh) - 76 78 62 Genral prIvato Al 15 16 19 3 large onpan Is C so so 58 SEEG use C 3 4 5 Source: SEEC. - 87 - Annex 16 age 4 of 4 Tble S $EG FOREAST FOR FRANCEVILLIL, 194 Trend ntl1oto 1988 1990 1995 Totel conamtlon (0M1h) - 139.2 145.3 163.0 LV Conwwtlen (0h) - 13.6 15.2 19.1 buldetletll A2 9.0 10.1 12.6 SEEua A2 2.2 2.4 3.0 PublC fighting Al 0.9 1.0 1.3 Industrial A2 1. 1.7 2.2 -IV Consolo (Ih) - 125.6 130.1 143.9 Suwal private Al 21.9 23.9 29.3 3 lage coweles C 103.7 106. 114.6 Source: SEES. Table 4: SEEG FOlCAST FOR ISOLATED CER, 1964 Trend ..tJ.t. 1966 1990 1995 Total consumption In centers (O11) A3 67.2 97.8 246.3 Sources SEEG. - 88 - Anne 17 synAvuC 1onITh The hydraulic potential of Gabon presently is assessed to be 4,900 MN and 33,500 CWhlyear of which less than 200 MM and 1,000 GUb/year currently are harnessed (less than 5S). - A very large range of sites are available, from ones convenient for micro or mini-power plants, up to sites khere several hundreds of MW power plants can be installed. The following tsble displays the most important sites where some studies have been undertaken. Number of main sits Powr Enwe (W) (h/yer) Llbrev lo Realon 13 763 4,640 River M9EI 3 121 610 River NMO 5 312 1,980 River ABANA 3 245 1,510 Olers 2 85 540 South East qI a 638 47t0 High "001£ 4 322 2,335 Others 4 316 2,435 Other regions b/ 8 3,325 9,540 I/ Region of Francpel I le, South East of Lstourvi le. y/ MaInly In the center of the omuntry. Source: SEES. - 89 - Annex 18 SEES PERSOMEL Table 1: SEES PERSONNEL BY FUNCTION a/ Mbnagertal Supwvlsory Staff Staff Labour Total Total 231 530 1,279 20040 E* ectrlclty 49 151 535 735 water 13 35 206 254 Both 169 344 538 1,051 Electricity Subsectoe 49 151 535 735 Qeneration 33 98 179 310 rFstrtbutlon 2 43 171 216 l Ah 14 10 165 209 I/ September 1986 #urces SEE6. Table 2: GEOGRHIC SREAKOOIIN OF SEED PERSONNEL Managerial Supervisory Staff Staff Labour Total total 231 530 1,279 2,040 Head offices 181 286 468 935 Libreville 14 83 291 388 Port-dent I 13 so 175 238 Franceville 10 35 90 135 Isolated Centers 13 76 255 344 Source: SEES. - 90 - Annex 19 SEEG CUSTONERS: 1975-1965 Table 1: NUM9ER OF MV CUSTOERS: 1975-1985 1975 1976 1977 1976 1979 1980 1981 1982 1963 19U4 1965 Llbreville 99 110 147 - 198 212 210 216 223 243 249 Part-osntl l 45 46 47 - 44 42 39 39 36 43 44 Freanceville - - - - - 34 42 41 42 55 59 solated Centers - - - - - 28 22 24 25 Total - - - - - 310 308. 318 323 351 360 Source: SEEQ. Table 2: KUIUER OF LV CUSTOERS: 1975-1985 (thwoeands) 1975 1976 1977 1978 1979 1980 1981 1982 1983 1964 1965 Librevl I I 12.0 14.6 18.9 - 19.8 21.7 23.2 26.8 30.9 34.5 37.7 PoCt-4satl l 3.6 3.8 4.2 - 4.4 4.8 5.4 6.3 7.4 8.1 8.8 Fracewi I le - - - - - 1.8 2.0 2.4 3.0 6.3 6.9 laolated COters - - - - - 5.08 6.5 7.5 8.6 Total - - - - - 32.8 35.6 40.7 46.8 52.4 58.1 Source: SEEG. 91 - muex 20 SEEI OPERATIOtL EWKNDITUIES a/ (ml l Ion ClF) 1964 1985 illIng (without tam) 36.764 49,027 Electricity and water sales 31,594 37,83S Equipont contributions 2,633 4,478 special contributions 1,701 2,439 Nisoel lan works 1,690 2,923 lecI laneou actIvities 904 1,304 Oeational oxnses 28,129 34,301 Procurement (Including fuel) 9,087 10,731 Transportation 736 615 Pers8onl 10,877 12,645 sIC 332 412 aeintenenco under the equipment contribution 327 564 Naintenance and consumption under th special contribution 1,701 2,439 Miscellaneous services 3,272 4,138 Insurances end mIscellaneous contributions 515 691 Taxes 600 674 Interests 676 1,186 Bo "th water and eioctriclty. Sorcs SEES. - 92 - Annex 21 Page 1'of 2 The figures given in the tables below cover 93KG's investments for both electricity and water supply. The mission estimates that electricity represents approximately 752 of total investments. Table 1 show past investments undertaken by concession (outside the private ownership of SEW). Since these figures vary considerably from year to year, a running four-year average is given so that general trends can be more easily noted. Table 1: PAST INVESTMENTS - CONCESSIONS (billIon CFAF) 1975 1976 1977 1978 1979 1980 1981 1962 1963 1984 1985 Current Value of Investment 7.7 8.3 4.1 21.4 5.3 22.6 7.3 3.3 6.6 8.8 7.6 Present Value 17.6 18.5 8.4 42.3 9.3 36.9 10.9 4.3 8.0 9.4 7.6 (1965 CFAF) Average for Four Preceeding 9.8 13.6 11.6 21.7 19.6 24.2 24.8 15.4 15.0 6.1 7.3 Years (1985 CFAF) - Source: SEEG, mission estimates. At the end of 1985, Sl8G's own assets (as opposed to those operated by SE33 under concession arrangements) amounted to 39 billion CPAP. Major capital investments in the past 10 years include the installation of a gas turbine plant at Port-Gentil (the only large generating facility privately owned by SEWG) in 1976-1977 (10 billion CPAF), and construction of new headquarters in Libreville and miscellaneous office buildings in other towns in 1985 (18 billion CPAF). Table 2: ELECTRICITY SUtCTOR INVESTlENT PROGRAM - 1987-199M (bl lI ton CFAF) Total Investuent 1987 1968 1989 1990 1991 1992 1993 1994 199S GENERATION AM TRSMISSICN With lnter_onmetion 0 0.5 0.5 0 0 5 8 a 26 Llbreville and Poct-entll Special studles 1 - 0.5 0.5 - - - - - - InteroonnectIon overhead I [mes and substet-ons 26 - 2 8 8 6 . Next hydro plat - - - - - - - - - 20 Franceov I le es turbine 3 - - - - - 3 -- - wltout ltwecoanectlon 0 0.5 O.S 0 5.5 13 10 15 30 Libreville and Fort-Sentil Speclal studles I - 0.5 0.5 - - - - - Kilguo downstrm so - - - - 5.5 10 10 10 10 cJ Nbt hdro plI nt - - - - - - - - 5 20 i/ Francevo le Ss turblne 3 _ _ _ _ _ 3 _ _ _ DlSTRIDUTIONi 2.0 2.0 2.0 2.0 2.0 2.5 2.5 2.5 2,5 Libreville - 1.5 1.S 1.S 1.5 1.5 1.5 1.5 1.5 1,S Port-Gentil - 0 0 0 0 0 0.5 0.5 0.5 O.S Franeeville - O.5 0,5 0.S 0.5 0.5 0.5 0.5 0.5 0.5 ISOLATED CENTERS - 1.S 1.S 1.5 1.5 4.0 4.4 4.8 5.3 5.9 a/ Co.plem_ntary substation equipment In 1996. o kX Assumption for commissioning In 1999 (ST at Port-Gentil to be commlsslaned beforehand, with first Investments beyond 1995). 0 ' c/ Last part of electromechanical commissioned In 1996. i/ Assumptlon. In the development without InterconnectIon, the next hydro plant would probably be another than Kinguale downstreem. SO,urce Mission estimates. - 94 - Anon 22 BU CRGANIZTIW CMT The following organization chart displays past and peseat situation. The figures on the right are the number of personnel, as of September 1986. De Dliectlon g6n6rale (Gnal Maagment) 171 _ Etudes gnh6rales (Development studles) 7 - Oontrle de gestln (Monagnt suwprvislns) a - Service Juridique (Lawer questions) 25 m so60 D DI I Direction de I 'informetique 42 (Data ProcessIng) Dlrectlon Tochnique de I'Equlpeuent t (Project Department) r OAC | Direction Administrative, Ccmptable at Financlre 38 (Administration, accounting, fInance) T DIC-7 Direction Commercialo (Saies) 271 r l DP, QDirection du Personnel 54 I OEX | Direction de I'Explotatlon (Operatlon) - Common sorvices 209 Libroville 365 - Port-4snti I238 FrancevIlle 135 Isolated centers 3U 2.040 - 95 - Annex 23 Page 1 of 4 BuG TARIM1 (mid-1986) "Tarif Social" (Social Tariff) This LV tariff referred to as "85", applicable up to 4 kVA, is the same all over the country. It features two blocks: 0 to 240 kWh/month .............. 37.04 CFAF/kVh Over 240 kVh/month .............. 76.39 CVAF/kWh The bills are charged with the 8X TCA (income tax). Other LV Residential Tariffs in Libreville In Libreville, four other LV residential tariffs are used: 31, 32, £3 and 39. Tariff E9 is for air conditioning only, and is used by consumers who also have tariff 31 for the other applications (in these cases, the consumers have two meters). This system is being replaced progressively by tariff E3 (with only one meter per consumer). Another tariff, 32, also being phased out, is applicable for all domestic usages. Tariffs 1, 2 and 3 are block tariffs, each block being defined by a number of hours of utilization of the subscribed demand (limited by the breaker setting). The kWh prices are as f4llows: Block Basic tCA on basic Equipmant Special price price contrlbution contribution Total El 0 - 40 h 75.27 6.02 4.01 - 85.30 40 - 130 h 69.66 5.57 - 5.33 80.58 over 130 h 49.31 3.91 - 5.35 36.60 E2 0 - 40e 75.27 6.02 4.01 - B5.30 40 - 130 h 69.66 5.57 - 8.03 83.26 over 130 h 41.40 3.91 - 8.03 52.74 E3 Sam prices as for E2, but with blocks 0-20h, 20-50h and over SOh. E9 Single block 41.40 3.31 - 8.03 52.74 - 96 - Annex 23 Page 2 of 4 Other LV Residential Tariffs in Port-Gentil In Port-Gentil, there is only one LV residential tariff other than the social tariff, tariff El, with two blocks onlys Block Besic TCA on basic Equipment Speclal price price contribution contributlon Total El 0 - 125 h 08.13 7.05 5.76 - 100.94 Over 125 h 39.65 3.17 5.76 5.76 54.34 Other LV Residential Tariffs in Pranceville and the Isolated Centers Here also, tariff E1 is the only LV tariff other than the social tariff. The blocks are the same as in Port-Gentil, and there is no contribution. The prices are the same in Pranceville and the isolated centers: for the first block, 98.30 CFAP/kWh and for the second block, 72.70 CPAP/kfh. The 82 slaes tax is added in the billing. LV Industrial Use This tariff "5" is a single block tariff with the following prices (in CVAF/kIh): Basic TCA on basic Equipment Special price price contributlon contribution Total LIbrevi Ile 50.18 4J01 4.01 - 58.20 Fort-OentiI 59.26 4.74 5.76 - 69.78 In Libreville and Port-Centil, there is no contribution, and the common price is 84.80 CVAP/kVh. 97 Anrex 23 Page 3 of 4 Specifie.L-Tariffr The two following tariffs also are found, although they are being phased out. In Port-Centil, tariff "87" for private settlements: basic price 66.10 CPAP/kVh, sales tax: 5.29 CFAF/kPgh, equipment contribution: 5.76 CPAF/kWh, special contribution: 5.76 CFAP/kWh, for a total of 82.91 CFAF/kWh. In Franceville and the isolated centers, tariff "18", for the food industry, has a single block at 50 CPAC/Ikh. NV General Tariff in Libreville This tariff "14" is a time of the day tariff, without demand charge. The prices are as follows: Basic TCA on basic Equlpmnt Secial price price contrlbutIon contribution Total P-ak 62.18 2.49 3.05 3.05 70.77 Out of peak 41.46 1.66 3.05 3.05 49.22 MV General Tariff in Port-Centil, Libreville and the Isolated Centers Also referred to as "14", this tariff is a subscribed demand charge tariff with single kWh price. The prices are as follows: port4nt II Francoville and Isolated centers Subscribed doend chrge 20,067.6 + 02.7 sales tax 20,756 CFAFkWh/year a 20,870.3 kilh price (CFAF) 50.18 + 2.01 sales tax 75.40 + 0.87 specilo contribution 3 53.06 - 98 - Annex 23 Page 4 of 4 MV Special Tariffs These tariffs (the most important in WV by the sold energy) are negotiated case by case. - 99 - Annex 24 Page I of 4 um*r 18e or U These Terms of Reference are presented by the mission as information. A final version tailored to the characteristics of Gabon's energy sector will have to be defined. I. The household energy economist shouldt (a) collect available and relevant economic data, evaluate existing energy pricing policies, and advise the socio-economic surveyor on economic data to be gathered via the household survey; (b) determine the economic and financial cost of demand-supply scenarios for electricity, LPG, kerosene, charcoal, firewood, agricultural residues, etc; (e) assess the economic price of the various fuels and recommend appropriate and phased measures to adjust prices to promote substitution and conservation; (d) recommend pricing for the substitute fuels, evaluate the pricing of their required cooking equipment (including possible subsidies) and its impact of fuel demand, and determine the cost for each fuel on a per useful.NJ basis; (e) analyze the likely impact of new prices (including subsidies) on disaggregated energy supply, demand, the family budget, foreign exchange, and government budget; (f) determine the comparative economic benefits of local versus foreign manufacture of new cooking equipment; (g) prepare economic and financial analyses of all recommended options and policies, rank the options according to their relative economic and financial internal rates of return and net present values, and determine the impact of the proposed policy (or package of policies) on government expenditure, revenues and balance of payments; and (h) identify support required to ensure successful implementation of the household energy strategy. - 100 - Annex 24 Page 2 of 4 II. The petroleum products/distribution specialist should: (a) review existing and ongoing studies on LPG and kerosene for the household sector; (b) assess, in collaboration with the stove technologist and the marketing specialist, present supply, storage, distribution and marketing arrangements for LPG and kerosene, and advise on the range and relative priority of technical options (separate as well as in packages) to be considered in developing a program of substitution for LPG, and assess their costs and likely benefits. Special attention should be given to reliability and appropriateness of the distribution system in relation to consumers' fuel purchasing behavior; (c) determine a phased investment plan required for procurement, processing, handling and distributing LPG and kerosene for the household market, the size of which will be estimated in collaboration with the marketing specialist and the energy economist; and (d) provide a description and cost estimate for any technical assistance required for program implementation, including supervision of engineering, training of operators and distributors. III. The marketing specialist should: (a) identify, in consultation with the stove technologist and local staff, the survey sample and design a consumer acceptability study for improved cookstoves; (b) train and supervise surveyors, carry out the survey, test social acceptability, and analyse results. Repeat the survey, if adaptations in stove design are indicated; (c) select, in collaboration with the stove technologist and local staff, the stove designs for dissemination; (d) evaluate, together with the energy economist, the least-cost financial and economic solutions for meeting cooking needs as well as assess the inherent risks of each option; (e) recommend, in collaboration with the energy economist, the means of promoting the sale and use of substitute fuels and define their likely consumption area; (f) evaluate the size, segmentation and location of the market for each fuel; and - 101 - Annex 24 Page 3 of 4 (g) implement the recommended program, training and other technical assistance as needed to establish and maintain dissemination. IV. The stove technologist should: (a) advise on the range and relative ranking of appropriate stoves for each fuel, as well as determine the need for adaptatiou of existing equipment or the development of new equipment. If teed be, develop in collaboration with local staff such adapted or new stoves; (b) determine the efficiency and durability of improved three-stone stoves and develop quality controls for construction and use; (c) identify a small sample of appropriate stoves (based on items (b) and (c)), which will be field-tested in a small control group of consumers to ascertain fuel consumption, time saving, safety, stability, and other consumer (male and female) reactions. The results of this survey will provide inputs of modifying the stove design, if need be, and for narrowing down the range for the final selection of the most appropriate stoves. This survey may have to be repeated more than once; (d) recommend means of production, procurement of construction materials, provision of training and incentives to artisans/factory if local production is preferable. On the other hand, advise why import or assemblage of stoves is the least-cost solution; and (e) work in close consultation with the marketing specialist, as well as local staff in the selection, adaptation, and/or development, quality control, market testing, and maintenance of stoves. V. The soci-economic surveyor should: (a) review existing studies on household energy consumption and supply, and prepare, in consultation with relevant team members, a detailed list of data requirements; (b) assist local experts in design of the representative statistical samples for the supply and demand surveys; (c) design draft questionnaires, in consultation with local experts and team members, for each survey; (d) advise on the training aid supervision of interviewers; - 102 - Annex 24 Fagie4 of 4 (e) monitor pilot testing and recommend modifications for the large-scale survey; (f) assist in the design of machine tabulation requests and data compilation; Cg) analyse the results of each survey and supervise preparation of final reports on household energy consumption and supply systems (h) develop an information system to keep track of the results of the studies and quality control by means of consumer control groups and permanent monitoring of stove manufacturing; and (i) evaluate the actual impact of the program and its effect on improving efficiency. VI. The enerpy forester should: (a) identify and describe any present de facto forestry and/or fiscal policy, institutional and planning arrangements drawing upon the material available in studies and from field investigations; (b) examine the organization of fuelwood supply for each large city in the country. This examination should include: (i) delimitation and mapping of areas for exploitation and those to be protected, including access routes, within a 100- 150 km radius about the cities; (ii) quotas for annual exploitation and an exploWtation schedule for each area, based -on local fuelwood demand and the availability of dead wood; (iii) exploitation specifications for each type of forestry formation, giving priority to collection of dead wood; (iv) potential organization of retailers: village associations, co-ops consisting of several villages, private companies, etc.; (v) placement and management of markets in each area, as well as quotas for each market; (vi) organization of transport between the collection or cutting point and the city markets; and (vii) the potential for- improving fuelwood marketing in cities; (c) design and implement pilot projects among the rural population for promoting rational exploitation of wood resources in the bush; and (d) calculate the revenues that will accrue as a result of these activities to the government and the village comunity and suggest mechanisms for the possible use of these revenues to- improve the ovurall performance of the proposed management system. Continued from inside front cover Reports Already Issued Togo June 1985 5221-TO Vanuatu June 1985 5577-VA Tonga June 1985 5498-TON Western Samoa June 1985 5497-WSO Burma June 1985 5416-BA Thailand September 1985 5793-TH Sao Tome and Principe October 1985 5803-STP Ecuador Decemtkpr 1985 5865-EC Somalia December 1985 5796-SO Burkina January 1986 5730-BUR Zaire May 1986 5837-ZR Syria May 1986 5822-SYR Ghana November 1986 6234-GH Guinea November 1986 6137-GUI Madagastar January 1987 5700-MAG Mozambique January 1987 6128-MOZ Swaziland Pebruary-1987 6262-SW Honduras August 1987 6476-HO Sierra Leone October 1987 6597-SL Comoros January 1988 7104-CON Congo January 1988 6420-COB Energy Assessment Status Reports Papua New Guinea Julyt 1983 Mauritius October, 1983 Sri Lanka January, 1984 Malawi January, 1984 Burundi February, 1984 Bangladesh April, 1984 Kenya May, 1984 Rwanda May, 1984 Zimbabwe August, 1984 Uganda August, 1984 Indonesia September, 1984 Senegal October, 1984 Sudan November, 1984 Nepal January, 1985 Zambia August, 1985 Peru August, 1985 Haiti August, 1985 Paraguay September, 1985 Morocco January, 1986 Niger February, 1986