ivory coast: issues and options in the energy...
TRANSCRIPT
Report No. 5250-IVC
Ivory Coast: Issues and Optionsin the Energy Sector
April 1985
LIHL_.Report of the joint UNDP/World Bank Energy Sector Assessment ProgramThis document has a restnicted distribution. Its contents may not be disclosedwithout authorization from the Govemment, the UNDP or the World Bank.
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JOINT UNDP/WORLD BANK ENERGY SECTOR ASSESSMENT PROGRAMREPORTS ALREADY ISSUFD
Countrv Date Number
indonesia November 1981 3543-INDMauritius December 1981 3510-MASKenva May 1982 3800-KESri Lanka Ma" 1982 3792-CEZimbabwe June 1982 3765-ZMHaiti June 1982 3672-HAPapua New Guinea June 1982 3882-PNGBurundi June 1982 3778-RURwanda June 1982 3779-RWMalawi August 1,982 3903-MALBangladesh October 1982 3873-BDZambia Januarv 1983 'i'0-7ATurkey M<arch 1983 3877--UBoLivia April 1953 4213-80F:ji _ne 1983 4462-F1JSolsomon . sLands june 1983 4,04-SOLSenegal JuLy 1983 8'-RSESudan! JU 1983 '5;'-SUUganda July :983 "a53-UG
iger a ;zuaust 1933 'SL0-UN'
NeDal Auiust 1983 447-'-NEPGaambia November 1933 7 ' 33-GM?e-u Januarv 19 3 467 7-PECos-ta Rica ,:anuarv 19342 4-655-CRLesothc J.3nuarv 1984 4'676-1.SOSe vchiei s ,a,!uZarI 198 '9o3-SEYMorocco Ma I984 -'57-MORPortugal Anril 1984 482-PONi- ger May 1984 '642-NIR
Caee Verde August 8198 50,3-CVuiner 3 ssau Au gust 198. 5083-CUBi
30 tsw-naS S-otemoer 1i)34 9n?
St. ii.ne. ancthe ,renr.ad.ise:3 Scr- embe r 5I4 5103-STY
S. ucta Seotember 1 5111-SLuParagua- 0ctober *934 5145-PA.a nian November i934 :969-TAYemen Arab Re^ubiic December 1934' 43892-YARLiberi.a December 13 52 79-LSBR
siamnc ReDub'C Jc
Mauri ania 'priL '1935 5224-MAdU;ama ca Apri 198.5 5466-JM
FOR OFFICIAL USE
Report No. 5250-IVC
IVORY COAST
ISSUES AND OPTIONS IN THE ENERGY SECTOR
APRIL 1985
This is one of a series of reports of the Joint UNDP/World Bank Energy SectorAssessment Program. Finance for this work has been provided, in part, by theUNDP Energy Account; and the Canadian International Development Agency throughthe UNDP; and the work has been carried out by the World Bank. This reporthas a restricted distribution. Its contents may not be disclosed withoutauthorization from the Government, the UNDP or the World Bank.
ABSTRACT
The Ivory Coast has a large and diversified indigenous energyresource base, including hydropower, petroleum, recently discoverednatural gas, forest reserves and biomass residues. Exploitation and useof these resources is constrained by tight financial conditions andlimited coordination of subsector planning and policy. Efficientdevelopment of the country's energy potential will have to take intoaccount recent financial constraints and new energy resource potential,particularly in the power and hydrocarbons subsectors. The pricingpolicies of the public enterprises in these subsectors are being revisedwith the goal of improving financial difficulties and better reflectingeconomic costs. New institutional arrangements are needed to furthercoordinate subsector management and define priorities for more efficientuse of energy resources.
In the short to medium term, specific actions are needed toaddress energy sector problems. Measures are needed to stimulate furtherexploration of hydrocarbon resources, plans to expand power generationcapacity will have to be revised, and programs are needed to augment thesupply and increase efficient utilization of traditional fuels (fuelwood,charcoal, biomass residues). This report focuses on the various factorscontributing to these and related issues and proposes strategies to dealwith energy sector difficulties.
ACRONYMS
CIDA Canadian International Development AgencyCTFT Centre Technique Forestier TropicalDEC Direction d'Etudes GeneralesEDC Export Development CorporationEdF Electricite de FranceEECI Energie Electrique C6te d'IvoireGPP Groupement Professionnel PetrolierIBRD International Bank for Reconstruction and Development
(World Bank)I2T Societe Ivoirienne de Technologie TropicaleLBTP Laboratoire du Batiment et des Travaux PublicsPetroci Societe Nationale d'Operations Petrolieres de la
C6te d'IvoireRAN Regie Abidjan-NigerSAP Socieee Africaine des PetrolesSIR Societe Ivorienne de RaffinageSodefor Societe pour le D6veloppement des Plantations
ForestieresUNDP United Nations Development ProgrammeUNIDO United Nations Industrial Development Organization
ABBREVIATIONS
bbl barrelBCF billion cubic feetBD barrels per dayBtu British thermal unitDDO distilllate diesel oilFO fuel oilcJ gigajoulesCWh gigawatt hourha hectareHFO heavy fuel oilHV high voltagekcal kilocalorieskg kilogramkgoe kilograms of oil equivalentkm kilometerkVA kilovolt-ampereLV low voltageLPC liquified petroleum gasm3 cubic metermcwb moisture content (wet basis)MCF thousand cubic feetMMCFD million cubic feet per dayMMsc'd million standard cubic feet per daymmtpa million metric tons per annumMV medium voltageMW megawattTJ terajoule (106 joules)TOE metric ton of oil equivalentton metric ton
CURRENCY AND FUEL EQUIVALENTS
Currency Unit - CFA Franc (CFAF)US$ 1 = 405 CFAF a/
Fuel Calorific Value Toe(million kcal/ton)
Crude Oil 13.2 1LPG (Butane) 10.8 1.059Gasoline 10.5 1.029Jet Fuel 10.4 1.020Kerosene 10.3 1.007Gas Oil 10.2 1.01Diesel Oil 10.2 1Fuel Oil 9.7 0.951Fuelwood 3.5 0.343Charcoal 7.0 0.6863Sawdust 2.0 0.196Green wood 2.2 0.216
(bulk wastes)
Natural Gas 233 b/ 22.84 c/
Electricity4000 kWh = 1 TOE for hydroelectric supply on a thermal replacementbasis (thermal efficiency 34.4Z)
11,628 kWh = 1 TOE (end-use calorific value)
a/ Exchange rate at time of mission. Rate used in the report, unlessotherwise stated.
b/ million kcal/MMCFc/ TOE/MMCF
This report is based on the findings of an energy assessment missionwhich visited the Ivory Coast in January 1984. The mission memberswere: Abderrezzak Ferroukhi (Mission Leader, Senior Energy Planner),Lori A. Perine (Researcher), Chakib Khelil (Petroleum Engineer), YvesAlbouy (Power Economist), Daniel Dufrenoy (Power Engineer, Consultant),John A. Philpot (Gas Expert, Consultant), Mohsen Shirazi, (GasSpecialist), Kathleen Stephenson (Financial Analyst), Fernando Manibog(Biomass Energy Specialist), Sayuri Carbonnier (Forestry and FuelwoodSpecialist, Consultant), and Jean-Marie Chevalier (Energy Economist,Consultant). David Hughart (Economist) joined the mission to assist inthe mid-mission review and the wrap-up meetings with the Government.L. Perine and A. Ferroukhi were the principal authors of the report.
TABLE OF CONTENTS
SUNKARY AND RECON MNDATIONS ............................... i-xxi
I. ENERGY AND TME ECONOMY ................... 1Overview ........................................................... 1Recent Economic Developments ........................... ... 1Energy Demand .............. ... 2Historical Consumption Trends ... ..... ..... .......... 2
Biomass Energyve*.*.*..e9.e ......................... o ... 9...o.e... 4Commercial Energy ............... .. ....... 4Petroleum Products .................................... 4Gasoline ............. 5Electricity ........................................................ 7
Present Energy Demand Structure ......................... 7International Comparisons .. 8Projections into 1990 ... . 10
II. HYDROCARBONS SUBSECTOR .. 13Geology of the Region.......... ........................ 13Exploration Activities and Pr3duction History . . 13Petroleum Production Prospects . . . 15Gas Production and Prospects .. . 16Options for Oil and Gas Supply Expansion . . 17Potential Markets for the Gas . . . 19Electric Power Generation . . . 21Refinery Fuel .......................................... . 21
Industrial Market ........... . . 22Urea Production . ... 24Residential/Commercial U s e s ......................... 26Transport ... ............................................ 26Other Potential Uses ... 27
Potential Gas Supply .. 27Strategy for Gas Development ............................ 28Possible Role for the Bank in a Gas Project ............. 30
SIR (Societe Ivoirienne de Raffinage) ..................... 30Main Issues ............................................. 32
Financial Difficulties .. 32Operational Difficulties .............................. 33Managerial Difficulties ..... 34
Rehabilitation Strategy ................................. 34
III. ELECTRICITY.. ............................ ... 36Overview ........ ...... 36EECI System Characteristics .. 37Generating System ....... 37Transmission and Distribution . . 38Demand Characteristics ........ ..... 39Demand Profiles ....................... 39Load Curve ........ 0T....... 0 ...... ....... 39
Demand Forecasts ................... 39Hydraulic Resources .................. 43Thermal Power .............. ................ 45Heat Recovery and Unit Repowering ......................... 45Additional Combined Cycle Units ......................... 46
Fuel Supply Considerations ................................ 46Captive Power ............................................. 46Main Issues and Recommendations ........................... 47Short-Term Issues ....................................... 47
Energy Shortages ...................................... 47Network Bottlenecks ................................... 48
Medium- and Long-Term Issues .............................. 49Review of System Ratings ............................................ . 49Revising Expansion Plans .................................. 50The Case of Gas Turbine Repowering ........................ 51Gas Based Alternatives .................................... 51
Recommendations ......................................... 53
IV. FUEIMOOD AND OTHER BIOMASS SOURCES . . ...................... 54Fuelwood .................................................. 54Overview ................................................ 54Current and Projected Consumption . . . . 55Potential Fuelwood Supply Sources . . . . 56Rural Areas ........................................... 56Urban Areas ........................................... 57
Supply/Demand Balance .... 58Policy Strategy for Closing Supply/Demand Caps .... 59Rational Management of Forest Reserves .... 59Recommendation ........................................ 59Lack of Information .... 60Recommendation ........................................ 60Integrated Policy .... 60Recommendation . .................. 61Regional Planning .... 61Recommendations ....................................... 61
Short-Term Issues and Options .... 61Supply Shortages in Korhogo Province .... 61Energy Efficiency of Cooking Stoves .... 62Recommendations ....................................... 62Charcoal in Abidjan .... 63
Recommendation .......................................... 66Other Biomass Sources .... 67Overview ... 67
Agro-Industrial Residues .... 67Palm Oil Wastes ......................................... 67Supply ................................................ 67Current Use ........................................... 69Unused Energy Potential .... 69Development Options .... 71Recommendations .... 72
Coffee Residues ......................................... 73Supply ................................................ 73Current Uses and SurpLus Wastes . . 73
Options .......................................... 74Recommendations .................................. . . 75
Bagasse from the Sugar Industry ......................... 75Sawmill Wastes .......................................... 76
Supply and Current Uses .. ............................. 76Substitution Options . . ................................ 78Constraints ...................................... . 79Recommendation ... ............ ........................ 80
V. SECTOR MANAGEMENT ISSUES .................................. 81Planning and Organization . . ............................... 81
Sector Planning .. ..................................... 83Energy Pricing . . ..................................... 85Electricity Tariffs .................... ................... 86Petroleum Prices ....................................... 88Residential Interfuel Substitution . . . 91
Conservation ....................................... 93Investment Requirement . . .................................. 95Hydrocarbons .... .............................. ...... 95Electricity ......................... 97Biomass and Fuelwood .................................... 97
ANflnES
1. Commercial Energy Consumption in Ivory Coast .............. 99Average Annual Growth Rates for Energy Demand ... 99Demand Forecasts for Petroleum Products . . . 100
2. Power Demand in the "Mauve Scenario" ..................... .. 101Power Demand for Grey and Mauve Scenarios ... 102
3. Hydroelectirc Master Plan .... 1034. Repowering the Gas Turbines at VRIDI . . . 1055. Switching VRIDI to Gas . . . 1086. Thermal Alternatives . . .................................... 1097. Postponement of All Hydro Projects Firm
Energy Balance .......................................... 110Postponement of All Hydro Projects FuelRequirements . . .1............... ll
8. Demographic Projections by Region . . . 112Projected Demand for Fuelwood . . . 113
9. Availability of Potential Fuelwood Sources .. . 11410. Terms of Reference for an Improved Stove
Promotion Project . ...................................... 115
MAPS
IBRD 14699R2: Country MapIBRD 18077R1: Gas Development SystemIBRD 18305R: Petroleum Exploration and Development PermitsIBRD 18562: Ivory Coast Power System
SUMMARY AND RECOMMENDATIONS
Introduction
1. The Ivory Coast is a country of 9.3 million people (growing atabout 4.2% per annum), covering an area of 322,500 square kilometers.Its political framework, established upon independence in 1960, haspromoted an open and stable economy and encouraged the development of astrong transportation infrastructure to support economic development.
2. Economic growth during the first two decades of independencewas impressive. Overall, the Ivory Coast experienced an average 7% perannum real growth rate, with GDP per capita increasing from US $145 in1960 to US $1200 in 1981, the second highest in sub-Saharan AFrica.Profitable exploitation and diversification of the agricultural sector,based mainly in the southern coastal areas, and commercial development oftimber resources were the main sources of export earnings, income genera-tion and public savings used to finance public investment and capitalexpenditures.
3. Since 1980, the program of major capital investments begun inthe late 1970's has been greatly reduced and general economic developmenthas slowed dramatically. The worldwide recession in 1980, which impededthe growth of exports, and a precipitous drop in the prices of cocoa andcoffee, the primary export crops, have led to a sharp decrease ingovernment revenues provided by the tariffs levied on external trade.For the first time in twenty years, the country has experienced threeyears of zero or negative real GDP growth, leading to a 20% decrease inreal GDP per capita between 1980 and 1983. By 1983, external debt hadreached the level of GDP.
4. At the end of 1980, the Government embarked upon a traditionalstabilization program to rectify medium-term and structural problemswhich were contributing to the financial crisis. Two structural adjust-ment loans were signed with the Bank in 1981 and 1983 to support theGovernment's efforts and intensify the adjustment process. In January1984, a number of austerity measures were announced to improve theimmediate financial situation of the public sector and to stabilize thedebt service payments as a ratio of exports in the medium term. A newinvestment code, aimed at promoting private investments and exports, andat improving resource allocation in the industrial sector withoutpenalizing the export sector, will become effective in October 1984.
5. Despite the corrective measures taken under the stabilizationprograms and under new government austerity measures, the Ivory Coastwill be subject to relatively tight financial conditions in the short tomedium term. The 1983 drought has affected agro-industrial productionmore severely than had been anticipated, thereby affecting exportearnings. The effects of the drought (especially the heavy dependence on
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imported petroleum products for electricity production and the increasein oil product prices) led to financial problems for EECI (EnergieElectrique de la C6te d'Ivoire). The financial difficulties of the twomajor public enterprises in the energy sector, EECI (because of fuel oil)and SIR (essentially due to structrual problems within the SocieteIvoirienne de Raffinage), account for a major portion of the deficit ofthe consolidated accounts of the public sector. The financial problems ofEECI and SIR have been exacerbated by the drought and the subsequentreturn to heavy dependence on imported fuel oil for electricitygeneration. Although this financial burden has begun to decline due torecently implemented rehabilitation measures, further reductions in thepublic investment program, including those planned in the energy sector,are expected. This is likely to result in a decline of real GDP for thefourth consecutive year rather than the modest increase initiallyprojected.
6. Authorities will have to continue to devote substantialinvestment funds to the energy sector, however, especially in light ofthe sectorial difficulties identified by the energy assessment mission inthis report. Given the nature of the financial situation within thesector and the economy as a whole, energy sector investments will have tobe carefully prioritized.
Energy Resources
7. The Ivory Coast's diversified energy base provides a number ofoptions for energy development and use. Indigenous energy resourcesinclude hydraulic resources, agricultural residues and animal wastes,significant though depleting forest resources and modest known reservesof crude oil and natural gas. The river systems offer a technicallyexploitable hydroelectric potential estimated at 12,400 GWh in an averageyear. At present, about 20Z of this potential is harnessed.Approximately 500,000 TOE of biomass residues are generated annually byagro-industries and sawmills only half of which is tappped for energyuse.
8. Abundant forestry reserves have traditionally been the majorindigenous energy source. However, due to rapid deforestation, theestimated annual potential fuelwood productivit of the remaining foresistock is expected to decrease from 13 million m in 1980 to 8 million min 1985. Discoveries in the past decade of modest crude oil and naturalgas reserves have increased the country's energy base. Current crude oilproduction averages 20,500 BD; since the ratio of producion-to reservesis relatively high, it is uncertain that this production level will bemaintained in the medium term. Natural gas has only recently beendiscovered and has not yet been developed. Reserves of both associatedand non-associated gas proven to date should significantly influence thefuture developemnt of the Ivorian energy sector.
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9. Other, non-traditional energy sources could come into use inthe long term through advances in new energy technologies. Research iscurrently underway to develop the country's vast soLar energy potentialand to harness ocean-thermal energy. Experimental projects to gasifyanimal wastes have had promising results. More technical research anlfield testing is needed, however, bef re these non-conventional resourcescan be used economically in the Ivorian environment.
Energy Sector Development
Historical Energy Development
10. The general evolution of energy demand has followed the courseof economic development. Economic expansion from 1960 to 1980 shaped thedemand patterns for both imported and indigenous energy resources andgenerated increased energy consumption. CommerciaL energy consumptiongrew at an estimated rate of 8% annually from 1972 to 1982, slightlyoutpacing annuaL CDP growth. Total energy consumption more than doubledduring the same ten year period, increasing from 1.0 million TOE to 2.5million TOE.
11. The pace of growth in the energy sector has slowed recentlyalong with economic growth. The economic recession and a series ofdrought years (1972-1978 and 1982-1983) have affected both consumptionpatterns and the availability of electric energy. Electricity growth hasslowed from an average 13%/yr between 1960 and 1980 to about 5.4%/yr inthe last three years. Demand for petroleum products (including regularlycontracted exports to Mali and Burkina-Faso) has stagnated; consumptionof individual products, especially gas oil and gasoline, has dropped atan average rate of 4X since 1979.
Current Energy Supply and Demand
12. Current energy consumption in the Ivory Coast is based on threesupply sources: hydroelectricity, petroleum products and biomassresources. These supply sources accounted respectively for 17Z, 34% and48Z of the net domestic energy consumption in 1982. Additionalelectricity requirements are met by thermal generation using heavy fueloil and distillate diesel oil.
13. Electricity. All facilities for commerciaL power generationare managed by EECI, which produces 95Z of the electricity consumed inthe Ivory Coast, mainly using hydroelectric facilities. Pjwer demand wasalmost evenly split between MV and LV customers (about 47:) in 1983, withHV customers consuming the remaining 6%. LV consumption is relativelyhigh for a developing country in Africa, mostly because residentialdemand in the Abidjan area is itself quite high.
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14. EECI's policy for managing its generating stations is based onrational use of hydroelectric resources given that all reservoirs arerefilled annually except Kossou, which has never attained its maximumstorage levels. Since 1980, energy generation at hydro plants hasaccounted for up to 92% (80X on average) of the commercial electricitysupply. Extensive use of the existing hydroelectric reservoir storagehas been a feature of EECI's operating policy, which must balanceimmediate fuel savings against the risk of diminished protection ofguaranteed supply.
15. A series of drought years and reservoir depletion have reducedthe availability of reliable hydroelectric supply and underminedmaintenance programs for the generators at Vridi, reducing availablethermal capacity by 15Z. Power outages plagued the country from December1983 to March 1984. EECI was forced to use all means of thermalproduction, even the most costly, to meet electric energy demand. EECIforesees a greater use of thermal production in the years to come inorder to build-up hydraulic reserves, notably Kossou.
16. Petroleum Products. Domestic demand for petroleum products ismet primarily by production at the SIR refinery, which uses bothdomestically produced and imported crude. About 60% of Ivorian crudeproduction, estimated at 1.2 million tons in 1983, is used by SIR; therest is exported by the oil consortia and the national oil company,Petroci. Additional crude and small quantities of refined products(200,000 TOE in 1982) must be imported to meet both domestic requirements(750,000 TOE in 1983, down from 850,000 TOE in 1982) and local exports toMali and Burkina-Faso. Since 1981, local exports and bunker sales haveaccounted for more than 50% of the refinery's annual production,amounting to over 900,000 TOE in 1983.
17. Consumption patterns of petroleum products have fluctuatedconsiderably since 1980 due to changes in the thermal/hydro mix of powergeneration at EECI. In the 1970's, electricity generation accounted foran average 33% of the domestic demand for petroleum products. This sharedropped to about 6% in 1981-1982, but rose sharply again in 1983 to 34%as reservoir depletion limited hydroelectric energy availability.
18. The transportation sector is the other major consumer ofpetroleum products (53% of the net domestic consumption of petroleumproducts in 1983). Total demand in this sector has decreased by about 4%in the past three years due to the recession. Consumption by industry isrelatively small (12% of the total supply), reflecting the limited numberof energy intensive industries in the Ivory Coast relative to other WestAfrican countries.
19. Biomass Resources. Fuelwood, charcoal and biomass residuesgenerated by agro-industrial and wood processing plants account for abouthalf of the net domestic energy consumption in the Ivory Coast. Fuelwoodremains by far the primary energy source in the country, accounting forat least 85% (1.2 million TOE) of the basic household energy consumption.
The rural population (about 55Z of the total population) relies mainly onfuelwood, while a great majority of the urban population depends oncharcoal (105,000 TOE). Fuelwood has been increasingly substituted bycharcoal, mainly in urban areas.
20. Most of the fuelwood consumed in the Ivory Coast is the by-product of shifting cultivation. The land-use patterns engendered byagricultural and timber exploitation policies have led to a deforestationrate that is higher than the rate of annual sustained forest product-ivity. Current and planned rates of reforestation are not sufficient formeeting future fuel needs; shortages are already evident in urban areas.
21. Other biomass sources, mainly residues generated by agro-industries and the wood transformation industry, represent a significant,untapped energy potential. Of the 340,000 TOE produced annually by agro-industries, over 40Z is currently utilized. Within the sugar industry,structural problems preclude the exploitation of bagasse beyond thecaptive requirements of the sugar mills up to the medium term. Most ofthe residues generated by sawmills (70X) are already used for in-plantpower and steam generation, as well as charcoal production and themanufacture of small wood products.
Main Subsector Issues and Recommendations
22. The mission identified and studied ten main issues affectingthe three major supply subsectors (hydrocarbons, electricity andbiomass). They are summarized under the following headings:
1. Oil Exploration and Production2. Development of Natural Gas Reserves3. Rehabilitation of the SIR Refinery4. Short-Term Power Shortages and Reservoir Management5. Future Power Generation Facilities6. Deforestation and Non-Commercial Fuelwood7. Charcoal Shortages in Urban Areas8. Utilization of Other Biomass Sources9. Energy Pricing Policies
ElectricityPetroleum Pricing
10. Conservation Potential and Interfuel Substitution
The mission's recommendations follow the summary description of eachissue. The mission examined only major, high-priority issues. Theenergy potential of other sources, especially animal biomass, peat, urbanwastes and solar energy, should be studied for possible development.
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Oil Exploration and Production
23. After intensive exploration efforts during the last ten years,the oil companies have appreciably slowed the rate of drilling in theIvory Coast's offshore basins. Plans for new drilling activities beyond1985 are not known at this time. The small size of oil reservesdiscovered to date (joint production of the Belier and Espoir fields haspeaked at 20,500 BD in 1983 and is expected to decline by 20% annually ifthere are no new investments in the subsector), the high cost of fielddevelopment at great water depths, and the higher cost ofexploration/development of new fields in offshore Ivory Coast mostprobably will continue to prevail in the future as petroleum activitiesmove to deeper waters.
24. Recommendations. The Government should take all possiblemeasures to expand the country's hydrocarbon reserve base. The missionrecommends the following actions:
Ca) Encourage continued exploration efforts by the consortia.Exploration and development activities should be stimulated byintroducing more flexible contractual provisions for the oilcompanies (seismic option contracts, tax incentives). Theattractiveness of the current environment must be reviewed todetermine other incentives to strengthening explorationactivities.
(b) Provide Petroci with the technical assistance it would need to
Si) implement Government hydrocarbon policy in assessingexploration prospects in the medium term; and
(ii) orient exploration efforts by oil companies.
(c) Continue technical training programs which have been alreadyimplemented to further strengthen the technical skills ofPetroci employees.
Development of Natural Gas Reserves
25. Oil exploration in the Ivory Coast during the past two yearshas led to offshore discoveries of non-associated gas in the B1production block, in addition to gas associated with present oilproduction in the Espoir and Belier fields. Total recoverable reserveshave been estimated in the range of 350-400 BCF, sufficient to sustain an.annual production averaging up to 55 MMCFD (equivalent to more than450,000 TOE/yr, or 18% of current domestic energy consumption) for 20years. Although reserves are not currently sufficient to justify gasexport projects, they could be developed as a substitute for asubstantial fraction of the national demand for petroleum products.
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26. Three potential gas markets were identified by the missionwhere projected gas production can competitively substitute for petroleumfuels: power generation (41%), use at the SIR refinery (45%) andindustrial uses in the Vridi industrial zone (14%). Sensitivity analysestesting the effect of variation in reserves estimates and potentialproduction levels provided estimates of the economic costs of gasdelivered onshore at Vridi to meet the demand of these markets. Theestimates were in the range of US$ 1.9 - 2.2/MCF delivered at the citygate station. This does not include a depletion value, which would beabout US$ 1.0/MCF.
27. The average total projected gas demand for the three marketswas estimated at 40 MMCFD. With an estimated production potential of 55MMCFD, additional quantities of gas would be available, up to 15 MMCFD,for expanded use in any of the three markets. Since the incremental costis bound to be less, this excess supply could be used for additionalpower generation (para. 39).
28. The precise relationship between gas supply arrangements andthe optimum gas share in thermal generation has not yet been clearlydefined. Flexibility in the supply of gas is a key factor in determiningits role in thermal generation. Thermal generation in a predominantlyhydroelectric system is erratic: the daily fuel intake, if freelyoptimized, would vary from several times the yearly average to zero,especially in the rainy season. To some extent though, reservoiroperation can accommodate a more rigid supply pattern, at the expense ofadditional fuel requirements and increased risks of water spillage.
29. Recommendations. The mission has recommended that theCovernment take the following actions to quickly advance the prospectsfor gas development:
(a) Institute a steering committee of top government officials,including the Ministers of Mines and of Industry and themanaging directors of EECI and Petroci, to coordinate allaspects of gas development and to develop policy directives;
(b) Institute a gas project unit, the responsibilities of whichwould include:
(i) undertake a detailed market survey to establishquantities and appropriate pricing for the gas;
(ii) with the support of technical advisors, estimate costsand develop a detailed design of gas productionfacilities; and
(iii) perform the economic and financial analyses required asinputs to negotiations for purchase and salesagreements.
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It is essential that the unit's studies and strategies developprice-quantity estimates for gas and integrate the plans for bothgas development and new electricity generation developments so thatgas demand patterns can be identified which will make full economicuse of gas production facilities.
(c) Hire consultants with relevant contractual, commercial andtechnical skills to support the gas unit;
(d) Negotiate with the consortium for supply and with EECI, SIR,and industrial consumers for sales. During negotiations,encourage the consortion to undertake additional delineationdrilling according to an agreed program t., evaluate further theprospects for oil production at the field and to confirmfurther gas reserves;
(e) Promote a long-term drilling/exploration program to securefuture supplies and ensure market growth.
30. The Ministry of Mines has already formed a gas task forcewithin Petroci to begin preparing for negotiations with the oilcompanies. With the participation of appropriate staff from both Petrociand EECI, this task force could be expanded to take up theresponsibilities of the gas project unit, as outlined above. The missionbelieves that it is essential for EECI to take an active role in theprojecr unit's activities so that potential use of gas facilities ismaximized.
31. A possible design which the gas project unit may wish toconsider for the production and distribution network would involve:
(a) piping the gas from an onshore delivery point to Vridi via anonshore pipeline; and
(b) distributing the gas to the Vridi industrial zone by means of adistribution grid, tnereby supplying the EECI thermal plant,the refinery and other industries.
This strategy, meant to deliver gas from the Bi production field, wouldalso accomodate associated gas from the Espoir field, which could bepiped directly to the onshore pipeline. The transmission anddistribution system and the onshore pipeline could be managed andoperated by either:
(a) a national operating company or gas utility, which could evolvefrom the gas project unit if it is reinforced with theappropriate technical expertise. The operating company wouldpurchase the gas from the consortium at the city gate stationand then negotiate the terms of sale to the primary consumers;or
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(b) a joint venture with the consortium, with Petroci as a majorshareholder. In this case, the consortium would develop theentire production and distribution system, and negotiate salesdirectly with the consumers.
The flexibility of gas supply patterns needed for gas consumption by EECIwill be possible using either option.
Rehabilitation of the SIR Refinery
32. The SIR refinery in Abidjan has been confronted with seriousproblems which may jeopardise the effectiveness of the petroleumsector. The refinery's nomimal capacity was recently expanded to 3.7million tons/yr, far exceeding local demand, as part of a major revampingproject which involved the addition of a hydroskimming unit and ahydrocracker. The project, just completed in 1982, suffered seriousdelays and cost overruns. The projected increase in demand for light andmedium distillates, which had justified installing the hydrocracker, didnot materialize because of the economic slump. SIR's problems werefurther exacerbated by start-up difficulties, weak and fragmentedmanagement, and high operating costs which exceed world standards by awide margin.
33. In recent years, the large financial Losses incurred by therefinery have become a major drain on the national budget. Since1979/80, SIR has operated at a loss, and it has been unable to generatesufficient cash flow even to service its debts. Several short-termmeasures were implemented by the Government in early 1984 to improve therefinery's profitability, including revision of both input and outputprices to reflect border prices and increasing the rate of capacityutilization through exports and/or processing contracts. Although theseare crucial initial steps towards restoring the economic and financialviability of the refinery, more guidelines must be developed fordecreasing costs and rehabilitating general financial management.
34. Recommendations. As the result of the recommendations of aBank mission which visited the Ivory Coast in December 1983, SIR hasintroduced a number of measures aimed at reducing operating costs, and ithas been able to increase the refinery's utilizaion capacity with aprocessing contract of 400,000 tons in 1984. Further changes will beneeded in the management system if full financial rehabilitation is to besuccessful. Thus the Government has agreed to retain the services ofindependent consultants to implement an in-depth management audit whichwill simultaneously:
(a) Establish the economic viabiity of the refinery and identifythe main parameters that constrain its viability; and
(b) Assess the options for restructuring all aspects of therefinery, including the need to restructure the company's
management, organization, financial and accounting methods,production, and marketing activities.
35. Bids for the audit, which will be financed by the Bank'sTechnical Assistance Loan, are being taken. The audit results shouldallow the Government to take a final decision regarding the future of therefinery.
Short-Term Power Shortages and Reservoir Management
36. Prolonged drought followed by premature depletion of theminimum reservoir storage needed to support peak loads reduced energyavailability in the EECI system and undermined the peaking capacity aswell. The thermal generators at Vridi were insufficient by themselves tocover electricity consumption needs, despite increased usage. Four gasturbines, with a total installed capacity of 88 MW (100 MW iso), had tobe installed to meet energy deficits. EECI is making arrangements toprevent the recurrence of similar situations.
37. Recommendation. The mission encourages EECI to continue theimplementation, already in progress, of strategies and arrangements foravoiding future energy shortages of the magnitude of those occurring fromDecember 1983 to March 1984. The mission believes that EECI should studythe economic and technical conditions for purchasing electricity fromcaptive power producers, which may prove to be an additional source ofthermal back-up capacity. Up to 94 GWh/yr of surplus power could begenerated from unexploited palm oil residues alone. The impact of thiscontribution to the grid, however, will not modify EECI's main productionplans.
Future Power Generation Facilities
38. Even under very pessimistic lower growth assumptions, newgenerating capacity will be needed in the early 1990's. Exactly whatform this capacity should take is marked by uncertainty about demand,rated supply capability of existing hydro plants and the competitiveposition of gas-fired thermal power and hydro resources. Decisionsregarding the next step for developing new capacity will have to takeinto account these factors, and EECI is currently studying the situation.
39. The options provided by gas development could significantlyenhance the alternatives available to EECI. If gas reserves aredeveloped and made available at competitive prices, gas could displace upto 75Z of liquid fuel requirements for thermal backup, corresponding to agas demand of about 17 MMCFD on average over the next 20 years. Theestimated difference between the demand of identified gas markets and themaximum gas production potential (para. 27) could be used to runadditional thermal capacity, in the form of a new combined cycle unit, inbase load. Using the excess supply in this manner would translate into aslightly accelerated depletion of existing gas reserves, but initially
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developed gas facilities would be utilized to the full economic extentbefore committing the country to major new investments.
40. Recommendations. Based on the mission's analysis of existingplans for hydroelectric development and possible thermal alternativesunder present financial and economic conditions, the following course ofaction is recommended for EECI:
(a) Revise and update hydrological data so that both existing andplanned hydroelectric plants can be rerated and their economicscompared with other power generation options.
(b) Study the optimal share of future hydro and thermal generationbased on the prospect of gas availability. This should includea detailed study of the precise reLationship between gas supplyarrangements and the optimum gas share in thermal generation.This ideally should be done in conjunction with the studies tobe undertaken within the gas project unit (para. 29).
(c) Investigate the feasibility of dual firing by oil and gas atthe existing steam units at Vridi. If the economics arefavorable, then conversion should proceed.
(d) Evaluate the technical feasibility and economic costs ofadditional thermal generation, including heat recovery units atthe existing gas turbine plant at Vridi and dual-fired steam orcombined cycle units at a site west of Abidjan.
(e) Ascertain the conditions under which confirmed gas reserves canbe used to postpone the commissioning date of the nexthydroelectric projects with the aim of maximizing the use ofthe gas facilities before engaging in other heavy investments.
Deforestation and Non-Commercial Fuelwood
41. Much of the fuelwood consumed in the Ivory Coast is gathered inrural areas as a free good, and is usually the by-product of landclearings associated with agricultural expansion. Forest resources arebeing depleted due to the combined effects of over-exploitation ofsources for timber extraction and land requirements for agriculturalexpansion. The future prospects of supply sources for non-commercialfuelwood, especially in urban regions is directly related to the long-term outlook of the timber industry. If the Government maintains currenttimber extraction rates, the natural dense forest is not protected, andcurrent rates of reafforestaiion are not increased, forest productivitywill drop to only 500,000 m /yr by the end of the decade. Projectedsurpluses in some of the less densely-populated rural areas will be toocostly to process and transport as fuel to offset projected shortages inother regions. Changes in policy and implementation of long termstrategies are needed to ensure that non-commercial fuel needs are met,
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while taking into account competing land uses for timber production,continued agricultural expansion, and charcoal production.
42. Recommendations. The mission recommends the following changesto ensure adequate supply sources to meet current and future fuel needsthrough proper resource management and planning, field projects andstrengthening of subsector management:
(a) Develop an integrated fuelwood/forestry policy which takes intoaccount oil competing land uses. The policy should:
(i) create strategies on a regional basis in accordance withprojected demand/supply imbalances to permit appropriateexploitation and use of regional forestry resources;
(ii) stress regional management to facilitate strategyimplementation.
(iii) allow for the means to conduct and monitor nationalforestry inventories and localized surveys of woodybiomass sources and consumption trends to update theinformation needed co evaluate demand patterns and theextent of remaining resources.
(b) Fast-growing industrial plantations should be established inareas of projected shortage to meet demand for commercial woodenergy. This and other field projects could be linked toprograms for rationalizing the Abidjan charcoal market (para.44) and otherwise increasing the efficiency of woodfuel use.
gc) Establish improved forestry extension programs to teach forestprotection to rural populations and promote increased use ofpotential woody biomass wastes which are currently destroyed.l/
Charcoal Shortages in Urban Areas
43. In the short term, the problems concerning imminent andprojected charcoal shortages in the Korhogo and Abidjan regions and thoseconcerning general improvements in the efficiency of fuelwood andcharcoal consumption must be addressed. Due to increasing demographicpressures in the Korhogo region, the productivity level of remainingnatural vegetation now falls far below the fuelwood requirements forlocal consumption and competing needs for charcoal production to meetdemand in nearby Korhogo city. Villagers have started to use fruit treesformerly reserved for food production as fuel. In other urban regions,
1/ Of the 23 million m3/yr destroyed by agricultural expansion, only about 7million m3 are used as fuelwood. The rest is burned on site to free theland for planting.
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Abidjan in particular, the existing charcoal pr-duction and distributionsystems accelerate the drawdown of already scarce locaL forest reservesand exacerbates the problem of irrational and escalating charcoalprices. Overall, efficiency of fuelwood consumption is very Low (5 to15% useful energy yield with existing cooking methods); improved end-useefficiencies would lessen the demand for fuelwood resources to meetenergy needs.
44. Recommendations. As short-term strategy for managing imminentshortages, the mission recommends that the Government:
(a) Set up an industrial energy plantation and rural woodlots inthe Korhogo zone to alleviate the shortages in the area;
(b) In Abidjan, survey charcoal production, distribution andconsumption as a prerequisite to identifying alternativecharcoal sources and more efficient conversion technologies;
(c) Evaluate and take action, where appropriate, to:
(i) use surplus sawmill wastes and/or wastes from Sodeforclearing/thinning operations as alternative sources ofwood for charcoal production;
(ii) rationalize the charcoal market as a means ofestablishing more efficient charcoal production,pricing, and utilization policies. This could beaccomplished by unifying and monitoring existing andpotential charcoal production networks, possibly througha co-operative which would register and issue permitsamong charcoal producers, wholesalers and retailers;
(iii) improve charcoal conversion technologies to lowerproduction costs and encourage the participation ofartisanal producers in a formal production anddistribution network; and
(iv) develop additional incentives to producers in theinformal sector monopoly, who currently control over 90%of the market, co join the formal market network.
(d) Formulate a program to promote and disseminate improved woo'1
and charcoal stoves. An organization or agency will have to Ledesignated to monitor and coordinate the program and to assessits long-term viability. A pre-investment trial program wouldbe needed, as well as vigorous publicity campaign aimed at bothconsumers and artisinal producers. The Government shouldevaluate the feasibility of improved stove production as asmall industry activity and investigate its own role inproviding incentives to encourage it.
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45. Previous studies have indicated that exporting charcoal toBurkina-Faso would be profitable. There may be several drawbacks topromoting exports at the expense of domestic markets, however. Since theproduction and distribution of exported charcoal must be a highlyorganized commerical activity, exports would effectively remove the twomajor sources of incremental supply for domestic consumption: sawmillwastes and wastes from Sodefor's cutting and thinning operations. Exportpromotion may also precipitate further incursions into forest reserves byitinerant producers, which could be catatrophic if producers concentrateon the northern savanna regions in order to minimize transport costs toOuagadougou. Given these potential difficulties, the mission believesthat priority should be given to meeting projected gaps in domesticcharcoal demand before export markets are tapped.
Utilization of Other Biomass Sources
46. At least 150,000 TOE of unexploited biomass residues could beused economically to generate surplus power in palm oil extraction plantsand to displace diesel-based power and process steam generation in thecoffee industry. Unused residues generated by sawmills (about 30% oftotal residues) should be considered as an additional source for charcoalproduction. Additional use of wood wastes must take into account thepessimistic resource outlook for the industry, as well as its currentfinancial health.
47. Recommendations. The mission's analysis of the energypotential of unused residues and possible development options for theiruse, led to the following recommendations:
(a) For the palm-oil industry, a pre-investment study isrecommended to establish the economic and technical viabilityof power generation options. The study should
(i) Analyze the impact of predicted decreases in palm oilplantation productivity over time on the waste resourcesupply, surplus generation prospects and cost recovery.
(ii) Determine the technical feasibility of gasification ofpalm oil wastes under Ivorian conditions.
(iii) Determine the costs of connecting to the EECI grid,conditioning and storing residues, additional labor andD*aintenance, boiler efficiency improvements, andadditional generating capacity necessary for surpluspower generation.
(iv) Determine if the selling price for PALMINDUSTRIE thatwill recover the costs of producing surplus electricitycan compete with EECI's marginal cost of alternativepower generation for the grid.
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(v) Examine and establish legal provisions for sale andpurchase of electricity. No such provisions currentlyexist.
(b) In the coffee industry, actions should be taken to determinethe technical feasibility of coffee residue gasification in theIvory Coast. For the coffee decortication plants for whichresidue gasification is technically and economically viable,prepare a conversion program using gasifier systems tosubstitute for DDO. Technical and economic performance underfield conditions of the available small direct combustionsystems should also be evaluated as an alternative togasification.
(c) Wood waste utilization for energy purposes is complex and needsto be selective. Studies must be undertaken to determine:
(i) the outlook for timber and wood wastes for each majorwood processing plants and the economic and technicalrequirements for exploiting the energy potential ofunused wastes. Four of the largest sawmills havealready requested technical assistance to study thesefactors and have expressed interest in converting towood-fired direct combustion/steam cycle systems if theprospects are favorable;
(ii) the economics of wood-waste gasification, drying,preparation and storage facilities for the wastes, andthe impact of wood waste diversion for energy use onlocal sources of livelihood; and
(iii) the technical performance, compatibility in combinationwith existing engines, and potential cost savingsattributable to direct-heat and engine gasifiersoperating on wood.
Energy Pricing Policies
48. Electricity. Electricity pricing is based on long run marginalcosts (LRMC) of supply established in 1981 and thus reflects the costs ofa predominantly hydroelectric system. Tariffs are generally set higherthan LRMC to meet revenue requirements. As a consequence of theoperational difficulties, short-run marginal generating costs have risensteeply. They are expected to decline as the balance of the generationmix is gradually restablished in favor of hydroelectricity in the longterm.
49. Tariffs were revised in early 1984 in an attempt to coverincreased operating costs and fuel expenditures. Even so, the rateincreases will be financially adequate only under optimistic assumptionson hydroelectric capability. In the short and medium terms, EECI will
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have to make rate adjustments which will balance two extreme solutions:reflect the steep hike and gradual decline in marginal generating costsor accept a smooth transition towards a long term target. The January1984 tariff increases reflect the latter course.
50. Recommendations. The major recommendations for revisingelectricity pricing and for covering temporarily increased costs include:
(a) Calculate new long run and short run marginal costs incoordination with the development of future power generationplans (para. 38-40);
(b) Initiate temporary rate increases for the most price-elastic HVand MV customers to cover increased fuel expenditures whilehydroelectric capability is being restored;
(c) Introduce cost-based rates for captive power purchases by EECIto serve as emergency backup.
51. Petroleum. The Government sets petroleum prices at each levelof sales activity. Final retail prices are obtained by adding fixeddistribution margins and various taxes and levies to ex-refineryprices. The pricing system was revised in January 1984 on therecommendaion of an IMF/World Bank mission. Under the new system, ex-refinery prices are based on CIF Abidjan prices and adjusted twicemonthly. Artificial transfer prices for heavy fuel sold to EECI by SIRand Petroci are eliminated.
52. The current price structure does not totally follow guidelinesthe new system. Part of the Compensation Fund tax, a levy used tocompensate the refinery for operating losses, has been incorporated intothe ex-refinery price. Retail prices continue to reflect heavygovernment taxation, especially on light products. The taxes provide theGovernment with an easy means of collecting revenues and are supposed toencourage energy conservation. However, the major determining factor fortax levels seems to be revenue requirements.
53. Recommendations. Because of the ongoing rehabilitation ofSIR's operational and financial management, any major changes in thepetroleum pricing system may be premature at this time. The missionrecommends only the following:
(a) Keep the ex-refinery prices and the partial Compensation Fundlevy separate once the refinery's financial situation hasimproved in order to encourage more efficient refineryoperation; and
(b) Evaluate the impact of tax policies on demand for lightproducts to determine the extent to which tax policy can beused as an effective demand management tool.
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Conservation Potential and Interfuel Substitution
54. There has been little done to officially promote energyconservation and to improve end-use efficiencies. EECI has conductedfield tests for household energy conservation. and the results have beenpromising. Areas identified by the mission for which conservationprograms would be effective include domestic energy consumption,commerical and industrial lighting and processes, and fuel use in thetransportation sector.
55. Recommendations. Among the steps which can be taken to promoteconservation and rational energy use are:
(a) Promote high-efficiency air conditioners to be used byresidential customers and use price incentives to induce moreconservative use of the equipment.
(b) Mount a program to promote and disseminate improved woodcharcoal stoves (para. 44).
Cc) Develop a program to improve the distribution of LPC suppliesand study the costs of household LPG conversion under varyingsupply constraints.
(d) Replace incandescent lights in commercial and industrialestablishments with fluorescent lights for immediate savings.
(e) Initiate a program to evaluate -ald to improve the energyefficiency of industrial processes and public lighting. TheGovernment has already asked their traditional lenders toassist them in the development of such a program.
(f) Study the scope and requirements for fuel Li-cerv.tion andsubstitution in the transportation sector, including:
(i) Current fuel use of major entities, future developmentof the sector and potential fuel requirements;
(ii) Fuel efficiency and the impact of price change on fuelconsumption within the sector;
(iii) Scope for conservation through maintenance, improveddriving and cargo dispatch, and interfuel substitution;
(iv) Policies, administrative and institutional measures, andinvestments required to increase energy efficiency.
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General Energy Sector Management
Organization and Planning
56. The energy sector in the Ivory Coast suffers from a weak andpoorly coordinated institutional infrastructure. No one institution hasbeen given primary responsibility for energy planning and policyformulation. Areas of responsibility are divided among variousministries. Institutional issues involving coordination among public andsemi-public enterprises need to be resolved, particularly in the keysubsectors, power and hydrocarbons.
57. The impact of the energy sector on the overall economy willlargely depend upon the successful achievements of the Government indefining and implementing policy objectives. This will require aninstitutional set-up based on coordinating the action plans of thevarious agencies operating in the sector and consistent with theGovernment's own broad energy and econmic development strategies.Sectorial coordination is essential, since immediate decisions concerninghydrocarbon exploration, possible development of natural gas reserves,adequate management and development of the electric power system, and theeffective use of biomass resources will affect not only individual sub-sectors, but also the total balance between energy supply and demand.
58. Recommendations. The mission proposes a two-tieredorganizational structure for coordination and planning of the energysector:
(a) A national energy committee authorized to formulate policy, toexamine the options and to recommend Government actions fordeveloping strategies within the national energy sector; and
(b) a technical agency to monitor the implementation of policy inthe various subsectors. The agency will have at least threecomplementary duties:
(i) Collect energy data and analyze the energy system;
(ii) Identify and integrate the objectives and constraints ofeach sub-sector; and
(iii) Define, in coordination with all parties concerned,courses of action to improve system efficiency and topromote efficient energy use.
59. The institutional structure for energy management anddevelopment at the subsector level is largely in place and theenterprises are already well staffed with technical personnel to takeresponsibility for promoting the Government's policies and objectives.
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However, the mission has identified the following actions which need tobe addressed on an priority basis:
(a) Petroci should:
(i) give top priority to hydrocarbon exploration anddevelopment activities in order to become a full-fledgedpartner of the oil companies in exploration/production;
(ii) strengthen its internal financial capabilities toevaluate projects and establish budget priorities.Introduction of computer services will be necessary toundertake these tasks without delay; and
(iii) continue training programs and identify technical needsto strengthen further the technical skills of thecompany's employees and design a program to meet tnem.
(b) EECI should:
'i) be included as a full member of the recently formed gascommittee and work in conjunction with Petroci andappropriate technical experts on all pertinent aspectsof gas development;
(ii) immediately strengthen the thermal department toexpedit:- repairs at Vridi; and
(iii) restructure its internal organization to accomodatefuture project development based on use of natural gas.
Cc) Sodefor should:
(i) gradually expand the new charcoal production unit withthe addition of a forester as head of the unit; oneengineer responsible for transport of wood and mobileequipment maintenance; one engineer responsible forsupervision of building operations; and one expertresponsible for charcoal marketing and distribution;
(ii) coordinate the activities of its unit for inventory anddelimitation of natural forests with the Inventory andConservation units which already exist in the Ministryof Agriculture, Water and Forests.
60. Other Government agencies responsible for the forestry sub-sector have recently been restructured to accomodate energy planning, andstudies to rehabilitate SIR's management are under way.
Sector Investment Priorities
61. The investment program for the Ivorian energy sector wilL benecessarily limited by the financial difficulties faced by the two major
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public enterprises in the sector, EECI and SIR. As the result of itsrecent operational difficulties, EECI's dependence on imported fuel hasincreased substantially, increasing the financial burden to both thecompany and the national economy. It is hoped that the proposedconservation measures for public lighting (para. 52) and the disincentiveeffects of the recent tariff increases will somewhat reduce imported fuelrequirements. SIR's deficit has continued to grow in spite of recentlyimplemented cost saving messuren.
62. The financial difficulties of EECI and SIR also effectPetroci's cash fico-e since Petroci is their major supplier of importedcrude and fuel. The Go:ernment intends to use part of the funds obtainedthrough recent loans b-, commercial banks to rectify the interrelatedarrearages of the three companies.
63. The mission has estimated the new investments for the sector,taking into account both the precarious financial situation of the majorenterprises in the sector and the nature of the sector's difficulties.These do not include ongoing projects, such as the EECI's ruralelectrification expansion programs and the rehabilitation measures forthe refinery. The major gas-related investments are listed below, alongwith their total estimated costs.
64. The mission believes that it is essential to find immediatefinancing for several of the recommended studies and surveys so that thepriority of further large investments (particularly for power generation)can be determined. Financing has been propJsed for some of these studiesby the Bank and other traditional lending agencies.
(a) EECI revision of hydrological data, demand projections,commissioning dates for hydroelectric projects, and marginalcosts analyses for future generation options, includingincreases in thermal generating capacity.
(b) EECI audit of existing thermal facilities.
(c) Joint EECI/PALMINDUSTRIE study of the conditions for purchaseof surplus power from palm oil extraction plants.PALMINDUSTRIE must also evaluate additional investment,operating and storage costs of connection with the grid.
(d) Pre-feasibility studies in other agro-industries for usingbiomass residues to substitute for petroleum products. Thetechnical assistance requests of the four largest sawmills tostudy the options for using their wood wastes should be givenpriority.
(e) Revised national forest inventory and fuelwood consumptionsurveys.
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TOTAL INVESTMENT COSTS OF MAJOR GAS-RELATED PROJECTS
A. Natural Gas Development and Distribution Million US$ (1984)
1. Consortium Investments
Platform and other facilities at BI 125.0Drilling and completson costs 27.014" pipeline to shore 12.0Subtotal for BI 164.0
Facilities at Espoirand pipeline to shore 24.0
Total initial cost of facilities 188.0
Additional wells drilled overproject life (10) 120.0
Recompression facilities 12.0
Total cost to consortium 320.0Cost to Petroci 53.0
2. Transmission/Distribution System
Pipeline to Vridi 24.0Industrial distribution 6.0
Total onshore system cost 30.0
Total Cost 350.0
B. EECI Investment Options for Use of Natural Gas
Conversion of units at Vridi 6.7
Repowering gas turbines at Vridi 35.0
Second combined cycle unitto use slack gas demand a/ 76.5
Total Cost 118.2
a/ Further study needed to justify this investment.
Source: Mission estimates, Gas Engineer Project - Initial Project Brief.
1. GEErY AND THE eCONOMr
Overview
1.1 The Ivory Coast is a country of slightly more than 9.3 million
people (growing at about 4.2% per annum) covering sn area of 322,500
square kilometers. It boasts a strong transportation infrastructure,
including a 46,414 km road network and deep water ports at the capital,
Abidjan, and at San Pedro. The political framework established following
independence in 1960 promoted an open and stable economy, attracting
skilled technicians and managers from Europe as well as unskilled labor
from poorer neighboring countries.
1.2 For nearly two decades, the Ivory Coast experienced impressive
economic growth. The Government' s economic policies concentrated on pro-
fitable exploitation of the country's agricultural sector, which is based
mainly in the southern coastal areas. In particular, production of
cocoa, coffee, and, until recently, timber, were the main sources of ex-
port earnings, income generation and public savings used to finance the
spreading infrastructure network. At the same time, public investment
programs pushed the economY towards further diversification by developing
the industrial sector, especially agro-industry, which has grown at an
average rate of 12%/yr. The contributions of the secondary and tertiary
sectors to GDP have both increased during this time from just over 50% in
1960 to more than 70% in 1981, demonstrating the effectiveness of the
Government's diversification efforts. Overall, the country experienced
an average 7% per annum real growth rate during this time, with GDP per
capita increasing from US $145 in 1960 to US $1200 in 1981, the second
highest in sub-Saharan Africa.
Recent Economic Developments
1.3 Following the large public finance gains arising from high
coffee and cocoa prices in 1976 and 1977, the Government embarked upon a
campaign of major capital investments. Public investment, 40% of which
was financed by external borrowing, rose to over 25% of GDP in 1978, but
did not generate new resources. Meanwhile, expenditures for crude oil
imports were increasing. By 1980, when domestic production of oil began,
gross imports of crude oil were more than 12% of total imports, as comr
pared to 5% in 1972. Petroleum imports accounted for 19% of export
earnings in 1980, more than double the 9% share in 1972.
1.4 The country was ill-prepared to withstand the effects of the
second oil crisis in 1979. The economy was badly shaken by a precipitous
drop in cocoa and coffee prices, which had fallen to 50% of tkn peak 1978
price by 1980. The worldwide recession in 1980, which impeded the growth
of exports, and the drop in the prices of the country's primary- export
crops led to a severe decrease in government revenues provided by thetariffs levied on external trade. In addition, the progress made inexploration for domestic oil production did not prove to be a major newgrowth factor for the economy, as had been anticipated. Economicrecovery has been further delayed by a series of regional droughts whichhave seriously affected electricity generation.
1.5 For the first time in twenty years, the country has experiencedthree years of zero or negative real GDP growth, leading to a 202 de-crease in real GDP per capita between 1980 and 1983. By 1983, externaldebt had reached the level of GDP. At the end of 1980, the Governmentrecognized the financial crisis as a reflection of medium term and struc-tural problems, and it embarked upon a traditional stabilization pro-gram. Two structural adjustment loans (SAL) were signed with the Bark in1981 and 1983 to ensure continuation of the stabilization program and tointensify the adjustment process.
1.6 The Government announced a number of austerity measures inJanuary 1984 which are expected to improve the immediate financial situ-ation of the public sector and to stabilize the debt service payments asa ratio of exports in the medium term. They included wage freeze pro-visions, cuts in government spending and restructuring various tariffsand prices, especially in the agricultural sector. Short term economicprospects should be favorably influenced by the latter, as well asexpected increases in industrial productivity and improvements in publicfinance towards the end of 1984. As a result, economic growth isexpected to resume progressively in late 1984 and should reach 2.5% in1985. Table 1.1 summarizes current and expected short term trends. Theprospects for coffee and cocoa exports are expected to improve, leadingto an increase in the revenues available to the Agricultural PriceStabilization Fund. The Government aims to reduce the public sectordeficit by freezing expenditures at their 1983 level. Increased revenuegeneration is expected to come from the anticipated higher profits of theStabilization Fund.
Energy Demand
Historical Consumption Trends
1.7 Energy demand and the general evolution of the energy sectorhave been shaped by the course of economic development. Domestic energyconsumption more than doubled in 10 years, growing from 1.0 million TOEin 1972 to 2.5 million TOE in 1982. Commercial energy demand tended tofollow the course of economic development, although growth of electricityconsumption and production since 1960 has been much more dramatic. Thiscan be attributed to the combined effects of increased demand due toeconomic development and the Government's rural electrification programs,which not only strengthened the infrastructure for agro-industrialdevelopment, but also increased the markets for residential electricityconsumption.
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Table 1.1: IVORY COAST - ECONOMIC INDICATORS
Population: 8.24 million (mid-1980)GNP per capita: US$1,150 (1980)
Annual Growth Rates (Z) atUS$ Constant Prices 1980
Million ACTUAL PROJECTEDINDICATOR 1980 1980 1981 1982 1983 1984 1985
National AccountsGross domesticproducts at Marketprices 10,514 6.3 -1.6 -1.8 2.2 1.8 2.5
Agriculture 2,708 11 4.6 -3.7 -1.7 1.9 2.4Industry (excludingCrude Oil) 2,458 3.9 -0.2 -3.6 -1.7 2.8 2.3
Services 5,329 4.8 -3.7 -1.6 -1.7 1.8 2.3Crude Oil - 410.1 87.6 97.7 -3.6 -2.9Consumption 9,185 3.4 2.8 -3.3 1.9 3.3 3.7Gross Investment 2,753 7.7 -11.7 9.9 -9.4 -6.3 -4.6Exports of GNFS 3,578 11.5 3.4 0.6 1.5 1.4 2.5Imports of GNFS 4,125 6.2 -6.3 -5.4 -5.5 0.2 2.0Gross NationalSavings 1,290 -4.6 -41.8 -31.2 8.9 2.1 -2.9
Debt Service Paymentsas Z Exports atCurrent Prices 855 23 27 27 25 26 27
Source: World Bank Second Structural Adjustment Loan to the IVC, StaffAppraisal Report, P - 3613-IVC, June 9, 1983. Mission estimates.
1.8 The Ivory Coast's domestic demand is met primarily by threesources: fuelwood (commercial and non-conmnercial firewood and charcoal),petroleum products and hydroelectricity. Until recently, firewood andcharcoal obtained from Ivorian forests were the only indigenous sourcesused. Petroleum imports provided the basis for meeting the energy demandwhich accompanied sustained economic growth, including electricitygeneration. The Ivory Coast's hydroelectric potential, estimated at2,500 MW and 12,400 GWh, was largeLy untapped until 1972, when theGovernment decided to launch a more aggressive program of hydroelectricdevelopment and energy self-sufficiency. Domestic production of crudeoil began in October 1980. About 60% of this production is used to meet
local petroleum requirements. Development of recently discovered naturalgas reserves may affect the consumption of these three primary sources inthe future.
1.9 Biomass Energy. Consumption of biomass energy sources 2/accounts for more than half of the total energy consumption in the IvoryCoast. Firewood and charcoal have been used traditionally to meet domes-tic needs, and combined demand for these sources has tended to parallelpopulation growth. Wood and agricultural wastes have also served asenergy sources for domestic uses, but until recently, there was littleuse within the industrial sector. Firewood remains the primary sourcefor cooking, but it is being progressively replaced by commercialcharcoal in urban areas. In 1970, for instance, only 20% of the house-holds in Abidjan without electricity used charcoal for cooking, themajority choosing to use firewood. By 1983, the figures were reversed,with 70% using charcoal and 30% using firewood. Among households withelectricity, 58% still prefer charcoal as the primary cooking fuel; therest use either electricity or gas. Recent attempts to encourage moresubstitution of kerosene and butane for charcoal and firewood have notmet with marked success. Substitution of wood energy has become a moreimportant issue recently as depletion of forest reserves has limited thefuelwood supply.
1.10 Commercial Energy. The evolution of total commercial energyhas been closely linked to economic growth (Table 1.2). Individually,however, demand for electricity and petroleum products have exhibitedcorpletely different growth trends (see Annex 1). Demand for petroleumproducts has been very sensitive to changes in economic activity. Bycontrast, electricity demand appears to be largely supply-accessoriented: any changes in electricity demand which may have been inducedby general economic conditions or tariff increases seem to be offset bydemand increases due to the expansion of the customer base.
1.11 Petroleum Products. Although global consumption of petroleumproducts is very sensitive to changes in CDP growth, consumption trendsdiffer from product to product (Table 1.3). Total consumption of petro-leum products began to decline after 1978 as thermal power generation wasgradually displaced by hydro generation. The drop in consumption becamemore precipitous during the years of economic stagnation and recession,and then stabilized as the effects of the prolonged drought required anincreased share of thermal power generation.
2/ Includes all charcoal, firewood, and other biomass residues.
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Table 1.2: COMMERCIAL ENERGY CONSUMPTION IN THE IVORY COAST
CommercialEnergy Energy Energy
GDP Consumption Consumption IntensityGrowth Rate Growth Rate Per Capita 1980
(Z per year) (Z per year) (Kgoe) (Kgoe per$ of GDP)
1974 104 0.0951975 7.0 12.1 112 0.0991976 12.0 14.4 124 0.1021977 4.7 10.9 132 0.1081978 9.9 14.1 146 0.1121979 2.0 10.2 155 0.1211980 6.3 4.8 158 0.1191981 0.2 -1.6 150 0.1171982 -4.0 -1.2 143 0.1201983 -4.3
Source: Annex 1, Mission estimates.
1.12 Among the individual products, consumption trends for heavyfuel, gasoline and gas oil are of particular interest. Heavy fuel(Fuel 380) is used almost exclusively for power generation at EECI'sthermal stations. Demand for this product is related to hydroelectricdevelopment and availability. Thus the consumption pattern for heavyfuel (as shown in Table 1.3 and Annex 1) reflects the demand forthermally generated electricity, which dropped sharply following thecommissioning of the 210 MW Taabo hydro plant in 1979 and the 180 MW Buyohydro plant in 1980. Fuel demand dropped accordingly from a maximum of318,000 tons in 1978 to 37,000 tons in 1981. Demand increased to 262,000tons in 1983 following an increase in thermal generation.
1.13 Gasoline consumption increased regularly and independently ofprice changes between 1974 and 1980. Average annual growth was 8%. Thedecrease in economic activity combined with the effect of higher pricesreversed this trend in 1981, leading to a 4% decline in consumption,after which consumption decreased substantially. Consumption of gas oil,on the other hand, was more sensitive to economic changes, with zerogrowth in 1979, then declining by 19% between 1980 and 1983. Both fuelsare consumed primarily by the transportation sector; the martked declinein consumption indicates the degree to which this sector has beeneffected by the recession.
Table 1,3: CONSUMPTION OF PETROLEUM PRODUCTS(Growth Rate 1974-83)
GDP GASOLINE GAS OIL KEROSENE BUTANE DIESEL OIL+FUEL 180 bl FUEL 380 c/Growth Growth Growth Growth Growth Growth GrowthRate Rate Coeffl- Rate Coeffl- Rate Coeffi- Rate Coeffl- Rate Coeffl- Rate Coeffi-(%/yr) (%/yr) clent a/ (%/yr) client a/ (%/yr) clent a/ (%/yr) clent a/ (%/yr) cient a/ (%/yr) clent a/
1974-78 8,4 9.6 1.14 16.9 2.0 6.9 0.82 16.9 2.0 11.1 1,32 27,1 3,22
1975-79 7,1 8.8 1,24 14,9 2.1 5.5 0,71 21,4 2,8 10,3 1,34 15,3 2,15
1976-80 5,7 7,7 1,35 8.0 1,4 9.0 1.58 17,0 2,9 8.7 1.53 -6.4 -
1977-81 4.6 4,9 1.06 1,2 0,26 10.6 2,3 15.6 3,4 6,2 1,35 -33,3 -
1978-82 1.1 0.1 0.09 -4,1 - 9.1 8.2 13,2 12 -0,7 - -16,0 -
1979-83 -0,4 -4,2 10,5 -5.8 13.7 3,1 - 10.0 - -4,3 - 100.4 -
a/ Coefficient Is the ratio of growth In energy demand to growth In GDP.b/ Diesel oil and fuel 180 used primarily by Industry for producing stem, process heat, and for captive power requirements.c/ Used exclusively by EECI for thermal generation,
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1.14 Electricity. Demand for electricity grew at an average rate of13% per year between 1972 and 1980. Growth in low voltage consumptionwas aided by various rural electrification programs which increased thenumber of customers with access to the EECI interconnected system. Highand medium voltage consumption grew more rapidly during this period,averaging 14.5% per annum. Since the 1977-1978 fiscal year, the totalnumber of customers in rural divisions has exceeded the number ofcustomers in the Abidjan urban area. However, the level of consumptionamong low voltage customers remains higher in the urban areas, reflectingthe higher per capita consumption of the urban users.
1.15 Electricity consumption has not been strongly affected by theeconomic situation until recently. This may be due to the combinedeffect of two factors. First, the share of thermal to hydro generationhas been reversed since the early 1970's, when the Government decided toembark upon a program to assure the country's energy independence. Sincethat time, almost 20% of the country's hydroelectric potential (estimatedat 2,500 MW and 12,500 GWh annually) has been developed, and by 1981, 80%of total electricity production came from hydro power, as compared with30% in 1972. The availability of generating capacity in the short termwas unaffected by the economic conditions, and thus had little effect onproduction capability for meeting demand. After reduced reservoir levelsbegan to limit the generating output of hydro plants and it was necessaryduring the recession to import more expensive fuel for thermal genera-tion, the pace of production and consumption growth lessened. There hasbeen no negative growth, however. Second, 60% of the total electricityproduced is consumed by households and services; domestic demand forenergy has been less severely affected by the fall in GDP than has demandin other sectors, especially transportation. This phenomena can also beseen by comparing the evolution of butane and kerosene demand as comparedto gasoline and gas oil demand, shown in Annex 1.
Present Energy Demand Structure
1.16 The energy balance for 1982 (Table 1.4) indicates the generaldemand structure for the country. Over half of the Ivory Coast's energydemand was consumed by households, mostly in the form of fuelwood orcharcoal. Petroleum products were used predominantly in the transporta-tion sector, although there was a moderate demand (estimated by the mis-sion of at least 93,000 TOE) for intermediate consumption of middle dis-tillates for electricity generation in industry (other than EECI). Morethan 50% of the petroleum products produced internally in 1982 weredestined for export or bunker sales, mostly to the neighboring countriesof Mali and Burkina. Net domestic consumption by industry was relativelysmall (12% of net supply), reflecting the limited number of energyintensive industries in the country.
1.17 It should be noted that any energy balance gives only a staticpicture of the interrelationships between supply, transformation andfinal use. In the case of the Ivory Coast, this picture has been knownto change substantially from year to year, especially as demand and sup-ply for petroleum products fluctuates. In 1982, for example, crude oil
Table 1.4: 1982 ENERGY BALANCE ('000 TOE)
Prlmary Energv Petrolmuu ProductsAgri. A Wood Natural Electri- Total Pet.
Fuelvood Wastes Hydro Crude Oil Gas Charcoal city Butane Gasollne Kerosene Dlesel Gas Oil Fuel EYoorts Products TOTAL
Gross Supply
Production 2000 500 432 a/ 762.3 19 b/ 3713.3Imports 1354.1 11.8 77.4 63.8 4.5 48.4 5.7 211.6 1545.7Primary Exports 1236.1) (236.1)Unutilizod (266) (19) (285)Stock Changes 9.9 9.9
Total Available Supply 2000 234 432 1870.2 11.8 77.4 63.8 4.5 48.4 5.7 211.6 4747.8
ConversionPetroleum Refining (1870.2) 12.1 264.6 155.1 191.8 371.8 596.4 154.2 1746 (124.2) c/Charcoal Production (575) 105 (470) c2Comm. Thurmal Eloc, is (16) (49) (65) (471 c/Com. Hydro Gen. (432) 147 t2851 e/Transmisslon & Dis- (25)tributlon Losses (25) (1.9) (17.4) (17.6) (7.4) (19.0) (19.4) (4.6) (48.5) (48.5) 1
Stock Changes _ - _ - … … … … … …… -Net Supply 1425 234 105 140 22.0 324.6 201.3 172.9 401.2 566.6 155.3 144.1 3748.1 1
Secondary Exports I (2.4) 173.2) (31.7) (61.6) (28.7) (307.5) (99.4) (604.7) (604.7)Bunker Sales I ______ (102.1) (27.6) (75.8) (173.4) (378.9) (378.9)
Net Domestic Consumption 1425 234 105 140 19.6 251.4 67.5 83.5 296.7 85.9 55.9 860.5 2764.5
Industry 234 46.2 83.5 65.9 55.9 225.3 505.5Commerce/Services 33.6 33.6Transport 251.4 296.7 548.1 548.1Households 1425 105 42 19.6 67.5 87.1 1659.1Public 16.8 16.8Agriculture 1.4 1.4
/ Hydroelectric supply converted on a thermal replacement basis, assuminq 54.4 effIlelency.g Natural gas estimates based on quantities of gas currently flared which could otherwise be pumoed to the refIneryc/ Converslon losses.
Sources: EECI, Budgets * conomlques, mission estimatos.
production increased to 1.2 million tons, enabling higher exports andreducing imports. One year later, the effects of the drought reduced theshare of hydro generation to 20%, which substantially increased thedemand for imported fuel oil for commercial electricity generation.Industrial demand for other middle distillates for captive powergeneration has also fluctuated as more industries choose to produce someof their own power using both petroleum products and agriculturalresidues. These fluctuations indicate a certain flexibility in theenergy system, allowing for fuel substitution (especially in commercialand private electricity generation) and the development of new energysources. This flexibility will be crucial to the success of plans todevelop new natural gas reserves to replace fuel oil, and for the even-tual promotion of LPG to substitute for fuelwood and charcoal.
International Comparisons
1.18 Table 1.5 compares per capita energy consumption and GDP in theIvory Coast and other West African countries. Although per capita GDP isthe highest in the region, the Ivorian energy consumption and energyintensity are relatively moderate. This is due to limited commercialenergy consumption in the agricultural sector, still a major contributorto GDP, and the small number of energy intensive industries. Bycontrast, the industrial structure of other countries include very energyintensive mining subsectors: aluminum in Ghana and Guinea, iron ore inLiberia, and phosphates in Senegal.
Table 1.5: WEST AFRICA: COMMERCIAL ENERGY CONSUMPTION
Energy1980 Consumption Energy Energy
GDP/Capita Per Capita Impurts Intensity
(1980 US$) (kgoe) (Z of goods (TOE/millionexported) US$GDP)
Ivory Coast 1,275 158 11 120Ghana 400 183 n.a. 460Guinea 300 57 n.a. 190Liberia 520 344 25 660Mali 190 21 n.a. 110Niger 330 37 55 110Nigeria 870 116 1 130Senegal 430 242 55 560Upper Volta 240 23 52 90
Source: World Bank, Energy Indicators for Developing Countries.
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Projections into 1990
1.19 Long range projections of future energy demand are generallysubject to a wide margin of error. They are especially difficult in theIvory Coast since the economy and the energy sector are undergoing majortransitions. In order to take into account some of these transitions,the mission estimated energy demand based on two scenarios of economicgrowth and energy use (summarized in Table 1.6):
(a) Scenario 1: Optimistic Case - Economic recovery/substitution. In the optimistic case, real growth of GDP isexpected to be 0% in 1984, 2.5Z in 1985, and 4.5X in 1986 to1990. Butane and kerosene consumption are assumed to grow at10X/yr each during this period and are substituted for charcoaland firewood demand. There is a increased utilization of otherbiomass residues for in-house electricity and/or process heatrequirements. Electricity demand is based on the Grey Scenario(para. 3.10) and is met through a combination of hydro, fueloil- and natural gas-fired generation. These projections arevery optimistic when compared to more recent estimates of thegrowth in electricity demand in the Ivory Coast. The SIRrefinery also uses up to 18.5 MMCFD of natural gas to displacefuel oil. Demand for naturaL gas by industry is negligiblesince the gas distribution network will not be completed in1990.
(b) Scenario 2: Pessimistic Case - Slow growth/historical consump-tion. This scenario is based on the assumption that economicgrowth will continue to stagnate and prospects for exp.xdingpower generating facilities are limited. Real growth of GDPwas taken to be 0% in 1984, 1.52 in 1985, and 2.5% from 1986 to1990. There is minor substitution of charcoal for firewood,reflecting current patterns of fuelwood use, and demand forother biomass residues for energy production remains con-stant. Electricity demand lags behind the Grey Scenario by 600GWh in 1990 (para. 3.13). Newly discovered natura' gasreserves are not developed, so there is no substitute for moreexpensive liquid fuels.
Under Scenario 1, total net domestic energy demand will increase byalmost 13X from 1983 to 1990. A good portion of this increase will bedue to demand for petroleum products. Scenario 2 shows a much smallerincrease in total demand (9%). Demand for petroleum products (excludingEECI consumption) is less than in Scenario 1; but demand for non-commer-cial firewood increases substantially.
1.20 The major difference between the two scenarios lies in theimpacts of substituting of liquid fuels for fuelwood consumption and theeffect of gas availability on the power generation options to meetprojected dema3 d. Approximately 678,000 TOE of fuelwood (equivalent to2.8 million m of forest reserves) is conserved in Scenario 1 due to
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interfuel substitution. If most of this substitution takes place in theAbidjan area, it would more than make up for the expected shortages(about 1.6 million m3) in the region (see Chapter 4, Table 4.3). Thepower generation options of the new gas turbines installed in early 1984(para. 3.31) in conjuction with natural gas will allow EECI to meet thehigher demand in Scenario I (a total of about 600 GWh) withoutsubstantially increasing use of liquid fuels. Gas use for powergeneration in Scenario I will displace approximately 145,000 TOE ofliquid fuels which otherwise would have been needed to meet demand. 3/This is a savings in fuel oil costs worth more than US$26 million atcurrent (1984) prices.
Table 1.6: NET DOMESTIC ENERGY DEMAND: PROJECTIONS TO 1990(thousand TOE)
1983 Scenario 1 Scenario 2
Non-commercialFirewood 1,385 846 1,506Charcoal a/ 111 205 187Agri. & Wood Wastes 275 384 280
ComercialElectricity b/ 103 231 206EECI Pet. Prod. Demand 262 61 43Petroleum Products c/ 686 919 837Natural Gas - 581 -
Total 2,822 3,209 3,077
a/ End use calorific equivalent. Actual drawdown of wood supplies is 5times this figure.
b/ End use calorific equivalent of hydro generation. 1 TOE = 11.62 GWh.c/ Excluding EECI demand.
3/ This is assuming that no new generating station is commissionedbefore 1990. See para. 3.31-3.37.
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Table 1.7: CRUDE OIL IMPORT REQUIREMENTS, 1990(thousand tons)
Optimistic Case a/ Base Case a/Scenario 1 Scenario 2 Scenario 1 Scenario 2
Domestic Production 1,150 1,150 418 418Primary Exports b/ (460) (460) (167) (167)Domestic Demand 980 880 980 880
Primary ImportsNeeded to MeetDomestic Demand 290 190 729 629
Crude Import c/Expenditures(1984 million US$) 64 42 160 138
a/ Based on oil production projections in Table 2.1.b/ Petroci and the other oil companies will export about 40Z of the
crude produced in the Ivory Coast.c/ FOB Rotterdam price: US$220/ton.
Source: Mission estimates.
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II. HYDRCARBONS SUBSECTOR
Geology of the Region
2.1 The sedimentarl basins in the Ivory Cost cover an area ofapproximately 11,000 km onshore and 53,000 km offshore. Of theoffshore area, about 11,000 km2 represent the continental shelf area(water depth of less than 200 m); only about h_1lf of the eastern part ishighly prospective. The remaining 42,000 km of offshore basins areunder waters of up to 3,000 m deep. A large portion of the potentialoil-bearing areas lies beyond the reach of the current offshoreproduction technology. Thus, exploration has been concentrated along thecoastline, in shallow waters, and onshore.
Exploration Activities and Production History
2.2 Petroleum exploration activities in the Ivory Coast cover twomain periods. During the first period, 1952-1962, the Bureau deRecherches Petrolieres (BRP) and the Societe Africaine des Petroles (SAP)carried out geological/geophysical surveys on the sedimentary basinonshore, drilled ten dry wells and then withdrew. Onshore drilling wasnot resumed until 1978, when Petroci drilled three dry wells. During thesecond period, 1970-1983, Petroci joined other companies (Esso, Total,AGIP, Phillips) to carry out seismic surveys and to drill wells. Twocommercial discoveries were made: Belier in 1974 and Espoir in late1979. Two other discoveries in the B1 block, one oil and the othermainly gas, were made in 1982/83 and are still undergoing furtherevaluation drilling at this time.
2.3 The Esso-led consortium, comprising Shell and Petroci as aminority shareholder, put the Belier field into production in 1980, sixyears after its discovery and after drilling 25 delineation wells, manyof which were dry. 4/ Production reached 8,800 BD in 1982. A waterinjection program (13,000 BD) was implemented in early 1983 to maintainproduction levels. The effect has generally been positive; however, thedecline in production was not completely arrested and production fell to7,000 BD in 1983. At the same time, the consortium proposed to sell thegas associated with Belier's oil production to the SIR refinery as a sub-stitute for butane. However, the quantity of gas produced is small andwill be short-lived as oil production declines. Esso has relinquishedthe bulk of its concession, retaining a small area surrounding Belierfield (CEP1) and another area bordered by Ghana (APE 4) (Map IBRD 18305R).
4/ Production of Belier was delayed due to the extraordinary complexityof the geology of the field, which is characterized by considerablefaulting and rapid change in reservoir continuity.
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2.4 The Government signed a new production sharing contract in 1975with a consortium led by Phillips Petroleum Company. 5/ The explorationpermit (Blocks A and B) covered a 24,000 km2 area immediately south ofthe Esso concession, 20-30 km from the coast in water depths ranging from200 m to over 3,000 m. After carrying out seismic surveys, the consor-tium began exploration drilling in 1976, discovering the "Espoir" fieldin late 1979 at the northern edge of the permit. Since the Espoir fieldappeared to extend northward beyond the limit of the A-B blocks, the con-sortium bid for and was awarded exploration permits on two other tracts(Blocks BI and Cl) north of the discovery well. 6/ Through 1333, 30wells, including seven producing wells in the Espoir field (spanningblocks A-B and Cl) and two oil and two gas discovery wells have beendrilled by the consortium. More drilling is underway near the oil dis-covery wells. Exploration permits for all of these blocks expire in1986.
2.5 Initial production at Espoi- started in August 1982 with fivewells using temporary facilities; permanent facilities are expected to bein place by mid-1986 to permit continued production beyond 1990. Produc-tion declined rapidly, reaching its lowest level (60% of initial produc-tion) in December 1983 when two wells were shut down due to productionproblems because of sand and water intrusion. The tentative program forcontinued development of Espoir calls for production through nine wells.Due to the rapid decline of production levels, it is highly probable thatthe consortium would resort to water injection or other pressuremaintenance scheme, if economically feasible, by mid-1987.
2.6 The Government entered into four more production sharing con-tracts in 1980, 1981 and 1983, with three joint ventures by AGIP, AGIP!Total/Union of Texas, and Tenneco, all of which include Petroci as aminority shareholder. These contracts cover the remaining blocks off theeastern half of the Ivorian coast, as well as an onshore block in thesoutheastern corner of the Ivorian territory. AGIP has already drilledthree dry holes and is planning to drill three more exploratory wells in1985 one of which would be located in Block Al. Tenneco is carrying outa 730 line km of seismic survey in Block Il before drilling in 1985. Atthis time, prospects for continued exploration beyond 1985 are uncertain.
2.7 While considerable exploration investments, (US$ 700-1,000 mil-lion mainly during the last ten years) have been made by the operating
5/ The consortium originally included AGIP, Getty Oil and Hispanoil andwas joined later by Petroci. Getty Oil and Hispanoil withdrew fromthe consortium in 1978; their shares were partly absorbed byPhillips and partly by a new member, Sedco, a Texas drilling com-pany.
6/ These blocks had been part of the concession earlier relinquished byEsso.
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companies to carry out more than 40,000 line km of seismic studies, in-cluding 3-D seismic for reservoir definition, and to drill more than 70exploratory wells, the oil reserves that have been discovered are smallby industry standards and difficult to produce due to the geological com-plexity of the area, reservoir characteristics and water depth. Futureoil discoveries are likely to be small; thus the number of wells per km(1/70) drilled offshore is not sufficient for localizing all possibletraps. Consequently, additional high cost exploration wells would beneeded to maintain the same exploration effort in the future. Whilecontinued effort by oil companies seems rather uncertain in the mediumterm, government action is needed soon to maintain the momentum in theshort term.
Petroleum Production Prospects
2.8 Total oil production in the Ivory Coast has increased from1,650 BD in 1980 to 20,500 BD in 1983. It is important to note, however,that the production to reserves ratio is relatively high compared withthe world average. This means that production cannot be sustained atsuch a level over the medium term.
2.9 Future oil production in the Ivory Coast will be dependent onthe contribution from (a) the Belier and Espoir fields under their pre-sently known development program, (b) possible pressure maintenance(water injection) programs in Espoir field, (c) recently discovered oilfields and (d) possible new discoveries. Reserves to be expected fromthe recently discovered fields and possible new discoveries are difficultto estimate. However, on the basis of available data, these reserveswill be small, approximately of the order of those of Belier. In addi-tion to the indeterminate level of reserves, it is not known at this timewhether they would be economical, and if so, when such reserves could befully delineated and put into production.
2.10 For the purpose of production forecasting, two hypotheses aremade. One, the base case estimate, considers the presently known re-serves and assumes Espoir field would continue producing 71 beyond mid-1986. The other, a highly optimistic case, assumes the following: (a)the Espoir field would continue producing beyond 1986 with the additionof a water injection program by mid-1987, (b) recently discovered fields(Bl5X/Bl8X) would be put on production by late 1985, and (c) a new fieldof the size of Belier would be discovered and put on production by 1987.The base case shows a decline of production of about 20%/yr starting in1986. Table 2.1 summarizes the increase of production over the base case
7/ The Phillips consortium is still evaluating various productionsystems to replace the temporary facilities now in place in Espoirby mid-1986.
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due to the highly optimistic case (in BD). While implementation of thebase case program would require additional development investments ofabout US$200 million to be made soon, implementation of the optimisticcase would require larger outlays of the order of US$500 to 800 million,including several exploration wells during the next two years. As thevalue of the extra oil will be considerably less than US$ 700 million, itis not clear whether the additional outlays can be economicallyjustified.
Table 2.1: EXPECTED INCREASES IN PRODUCTIONLEVELS WITH THE OPTIMISTIC CASE
Year BD
1984 _1985 2,0001986 4,0001987 9,5001988 14,9001989 14,5001990 14,000
Source: Mission estimates.
Gas Production and Prospects
2.11 Both associated and non-associated gas reserves have been iden-tified offshore in the B1 and Espoir fields. Additional limited quan-tities are associated with Belier oil production. BI gas-in-place isestimated at between 500 and 1,000 BCF, with the lower figure currentlyconsidered more realistic by the Bank for planning purposes. Recoverablereserves are put at 310-350 BCF. Espoir associated gas is estimated ataround 36 BCF recoverable. If the fields are developed jointly, approxi-mately 350-400 BCF gas would be available, sufficient to sustain a pro-duction averaging up to 55 MMCFD for 20 years. Once they are betterknown, these reserves could prove to be much larger than the mission'sestimates.
2.12 Associated gas at Espoir is presently being flared at 20 MHCFD.This gas could probably be exploited at a conservative rate of about 10MMCFD over ten years, depending on whether or not measures to enhance oilproduction are taken. The Espoir consortium is now considering longerterm development of the Espoir oil field through installation of perma-nent facilities. Whether the consortium invests in ancillary facilitiesto recover the gas or not will depend on the establishment of a marketfor the gas and the conclusion of satisfactory negotiations concerning
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the price of gas. Having a market for the gas would also improve theoverall economics of long-term field development.
2.13 Associated gas frcm Belier is limited and expected to declinefrom 2.5 MMCFD in 1985 to depletion by 1990. This gas, however, canimmediately displace liquid fuels which are used to produce hydrogen forthe hydrocracker at the SIR refinery (the current low capacity utiliza-tion of the refinery unit does not generate enough process gas for thispurpose). Gas from Belier could be used with little investment costssince a pipeline to the refinery at Vridi aLready exists. The Bank hasalready urged the Government to move forward and negotiate a price forthe gas with the operator in order to exploit this depleting resource assoon as possible.
2.14 While Espoir and Belier associated gas can be counted on topartially and temporarily meet the potential gas demand of the country,gas from the Bl area is the most important supply for any future develop-ment and utilization of gas. Significant quantities of oil in placeappear to underlay the gas, but testing to date has shown low perme-ability of the oil sands. Additional drilling in other flanks of thefield could confirm whether this oil is commercially producible or not.If these additional wells do not find commercial oil, they could at leastdelimit the gas reserves and possibly be used as gas producers in thefuture.
2.15 Other non-associated gas reserves may exist in the Espoir northfield area. A well is programmed for 1984 to assess the possibility ofthe existence of commercial oil below the gas. If only gas is found, itmay complement possible gas production from the BI area (depending onlocation and the economics of developing it).
2.16 Prospects for increased gas reserves depend on continued explo-ration for oil and contractual arrangements to be negotiated by theGovernment with the oil companies. Additional amounts of gas may befound in offshore Ivory Coast either as associated or non-associated gasin view of gas/oil reserves ratio data and large unexplored areas thoughtto be gas prone.
Options for Oil and Gas Supply Expansion
2.17 Proved oil reserves are limited to those of Belier and Espoirand are modest relative to the medium term oil needs of the country. Theratio of production-to-reserves is high and prospects for substantiallyincreasing the reserves in the medium term are constrained by: (a) thegeological complexity and the size of the possible new finds; (b) thepossible reduced rate of oil exploration by the oil companies; (c) thehigh cost of exploration/development in offshore Ivory Coast; (d) theconsiderable production problems related to sand and water in the reser-voir and operations at greater water depths, and (e) the continuing
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uncertainty over the price level of the crude oil market. Prospects forincreasing gas reserves and production are constrained by a lack of awell-defined government strategy for gaa development and utilization andfor clear contractual arrangements with the private operating companies.
2.18 The government options for expanding oil and gas supply wouldbe to encourage:
(a) an increase in the oil and gas resource base;
(b) a more aggressive development effort to expand production,particularly of gas reserves; and
(c) more use of gas as a fuel substitute in the local market toreduce oil demand, taking into account the various constraintsmentioned above.
2.19 In particular, the government actions to increase the reservebase should include:
(a) encouraging continued and more aggressive exploration by theexisting consortia;
(b) attracting other companies whenever existing permits are due toexpire;
(c) promoting exploration through Petroci in blocks such as APE2and APE3 that have been abandoned by Esso;
(d) encouraging producing companies to resort to pressure main-tenance (water and/or gas injection) and enhanced oil recoverytechniques (such as polymer injection).
2.20 Specifica&ly, the following actions could be considered by theGovernment:
(a) Provide Petroci with the technical assistance it would need toplay its role as a full-fledged partner of the oil companies inexploration/production and fulfill its very important role asthe technical arm of the Ministry of Mines and Energy in chargeof applying government policy in the oil and gas sectors.
(i) An experienced explorationist should be named to head theexploration department and a basin study team should beformed within the exploration department. The latterwould be responsible for collecting and analyzing thetechnical and economic information generated by allexploration and development work, using it to update andreevaluate discovery prospects over the entire sedimentarybasin. Results of such studies will be useful inorienting continued exploration efforts.
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(ii) Concerning development projects, Petroci should improveits ability to evaluate the technical and economic aspectsof various production alternatives using the sophisticatedtools that exist in the industry. This is particularlyimportant when analyzing options for Petroci and theGovernment when participating in continuous fielddevelopment, water injection or enhanced oil recoveryapplications, or putting abandoned wells or fields intoproduction.
(b) Continue the technical training programs which have alreadybeen implemented to further strengthen the technical skills ofPetroci employees. In particular, there should be more on-the-job training taking advantage of the presence of expatriateexperts working with Petroci staff. Petroci's managementshould identify technical training needs and design a programto meet them. This program could be financed by the Bank loan.
Cc) Add more flexibility to the contractual provisions governingexploration and production by:
i) giving the companies the alternative of signing "seismicoption" contracts without requiring first stage drilling.This would allow the companies to reduce initial financialrisk and might improve the incentive for increasedexploration. This is particularly important in light ofthe relatively small size of the fields to be identifiedand the insufficient seismic survey coverage (in parti-cular 3-D seismic) over prospective areas;
(ii) establishing contractual arrangements for gas; and
(iii) establishing a progressive tax system to encourage the de-velopment of small oil and gas fields, pressure mainte-nance and enhanced oil recovery projects in producingfields.
Potential Markets for the Gas
2.21 The various end-uses in which natural gas could be consumed inthe Ivory Coast are:
(a) Power - in thermal power stations, such as the EECI unitat Vridi, displacing fuel oil and distillate.
(b) Refinery - gas could be used by SIR for refinery fuel, inplace of petroleum products (mainly heavy fueloil).
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(c) Industry - gas could displace fuel oil (and other petroleumproducts) in various industrial applications,mainly for generating steam and process heat-ing/furnace uses.
(d) Commercial/ - a potential use for gas is to displaceResidential distillates, LPG or electricity in
commercial/residential markets.
(e) Transport - in the form of compressed natural gas (CNG) gasmay displace gasoline or other transport fuels.
(f) Ammouia/ - natural gas could be used to produce ammonia,Fertilizers which could be exported directly, or used to
produce nitrogen fertilizers for domestic/exportmarkets.
(g) Others - g.s could also be used as feedstock and/or fuelto a variety of other processes, including meth-anol, direct reduction (sponge iron), LNC, syn-thetic gasoline, olefins production, etc.
2.22 Of these options, the most attractive for the Ivory Coast areuse in electric power generation and as a refinery fuel and industrialfuel. Potential demand for these uses was estimated to supportproduction of up to 55 MHCFD depending upon fluctuations in demand forthermal back-up power. If gas is to be used for additional thermal powergeneration (e.g., for new combined cycle units to displace high costhydro plants) then greater total volumes of gas would be required. Thiscould only be supplied at the expense of refinery or industrial marketsunless additional reserves are proven.
Table 2.2: PROJECTED GAS DEMAND FOR
FUEL SUBSTITUTION
(MMscfd)
Maximum b/ Average
1988 1990 1995 2000 20005 (1988-2006) (1988-2006)
Power 17.5 16.9 11.3 17.1 18.5 40.00 16.7Rpfinerv a/ 17.5 18.5 18.5 18.5 18.5 18.5 18.4
Industry 3.6 4.5 5.2 6.0 7.0 7.2 5.5
Total 38.6 39.9 35.0 41.6 44.0 40.6
a/ 330 days/yr
b/ Non-coincident peak demand in each market
Source: Mic5ion estimates.
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Electric Power Generation
2.23 The thermal generating stations of the EECI system representthe largest potential market for gas use. Gas could be used to replacefuel oil in units 3 and 4 at Vridi and in the gas turbines installed inearly 1984. On the basis of the plans contemplated in 1983 for develop-ing hydroelectric capacity, average thermal generation from 1988 to 2006will be about 700 GWh. Thermal generation will be highly variable,however. Even with a great flexibility of supply to EECI, that is,allowing for a peak demand of 40 MMscfd, 25% of the fuel requirements forthermal generation would have to be met by HFO. Gas intake at EECI wouldthus average 16.7 MMscfd over 20 years. EECI is studying the utilisationof natural gas and its competitiveness in relation to other fuels.
Table 2.3: PROJECTED CAS DEMAND: ELECTRIC POWER
1988 1990 1995 2000 2005
Thermal Generation 836 805 541 813 880(GWh)
Gas Intake a/ 17.5 16.9 11.3 17.1 18.5(MMscfd)
a/ Equivalent to 75% of projected thermal generation.
Source: Mission estimates.
2.24 Gas intake by EECI will increase if gas is used not only asenergy back-up, as in the projections in Table 2.3, but also to delay thecommissioning of hydroelectric projects in the early 1990s, since excesssupply from the estimated production plateau (55 MMscfd) exceeds15 MMscfd. The optimal gas supply pattern is difficult to predict giventhe uncertainties surrounding future medium-term hydroelectric supplies,power demand growth and exact available gas quantities. Since electricpower generation will be a major market in any gas development scheme forthe Ivory Coast, it is essential that studies be made in conjunction withplans for both gas development and new electricity generation develop-ments to design gas demand patterns that will make full use of gasfacilities.
Refinery Fuel
2.25 The SIR refinery represents an immediate and flexible marketfor gas substitution of fuel oil. Assuming a production level of 2million tons of products and improved operating efficiency, approximately150,000 tons/yr of fuel oil could be replaced by gas. This represents amarket for about 120 BCF of gas over twenty years at a rate of 18.5MNCFD. Factoring in gas from Belier, the demand profile would be as
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shown on Table 2.4. The actual demand for gas in the refinery could behigher if refinery production increases as a result of dem nd growth andsuccess in developing a greater export capability.
Table 2.4: NATURAL GAS DEMAND FOR SIR a/
1987 1988 1989 1990-2006
HFO ('000 tons) 150 150 150 150
Total gas (MMscfd equivalent) 18.5 18.5 18.5 18.5
From Belier (MMscfd) 1.5 1.0 0.5 0.0
From Bi/Espoir (MMscfd) 17.0 17.5 18.0 18.5
a/ 330 days/yr.
Source: Mission estimates.
2.26 Conversion and connection costs will be negligible, since agaseous fuel system exists throughout the refinery. Savings on fuel oilcosts at 1984 prices and assuming displacement of 150,000 tons/yr wouldamount to US$27.7 million annually. The refinery should also be able tooffer some flexibility to the overall natural gas distribution system; itcould switch from gas to HFO and back again for its fuel uses more easilythan other consumers, and it uses the cheapest fuel oil. The refinerymight therefore oct as the "swing" consumer in the system in a situationof limited gas availability, taking into consideration, of course, itsown supply commitr nts and planning requirements.
Industrial Market
2.27 The immediate potential for gas use in industry is not large,but a limited distribution network of about 10 km around the industrialzones of Vridi, Treichville and adjacent areas (Map IBRD 18077R1) couldsupply gas to a number of medium and small-size industries. Natural gascould be used to displace fuel oil and other petroleum products invarious industrial applications. The major industrial fuel is fuel oil180, used mainly for producing steam and process heating/furnace uses.Other petroleum products used in industrial applications include LPG andDDO (heavy diesel), used in relatively minor quantities by someindustries for heating or motive power applications.
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2.28 Total industrial fuel use in the country is estimated at 95,000tons/yr HFO equivalent. Based on data from various oil companies pluslimited statistical data, it would appear that:
(a) around 75 percent of industrial fuel use is in the Abidjanarea;
(b) of this, 70 percent is in the Vridi/Treichville area, mainly inthe designatv! industrial zones;
(c) of this, 80 percent could reasonably be connected to a simpleindustrial gas distribution system.
Thus, total potential gas demand likely to be initially connected to thesystem is 40,000 tons HFO equivalent. 8/ A number of medium-sizeindustrial energy users in the Vridi/Trelichville/Marcory/Koumassi areahave been identified. Estimates of the fuel oil consumption of some ofthese key companies are given in Table 2.5.
Table 2.5: INDUSTRIAL FUEL CONSUMERS NEAR VRIDI
Company Industry Location Fuel Consumption
(thousand tons/year)Blohorn Soaps, Oils, etc. Vridi, Abidjan 15Sotexi Textiles Vridi, Abidjan 6ICODI Textile Zone 4, Abidjan 4CAPRAL Food Products Zone 3, Abidjan 4SOLIBRA Drinks Zone 3, Abidjan 4CMA Flour Mill Port Zone, Abidjan 2Bracodi Drinks Zone 3, Abidjan 2SACO Food Products Zone 4, Abidjan 1
Source: Mission estimates.
2.29 These individual estimates are consistent with the "macro"estimate of around 40,000 tons HFO consumption within reach of the pro-posed industrial gas distribution network. However, in some cases theyare based on information several years old, and other companies in thesame area may also be worth connecting into the system. Therefore, asystematic program of interviews with all industries in the area needs tobe carried out to confirm and complete this data.
8/ 95,000 x 0.75 x 0.70 x 0.80 = 40,000 tons HFO equivalent.
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2.30 Table 2.6 shows the potential natural gas demand for industrialmarkets. It is assumed that the existing industrial market for gasaround Abidjan will be met over a three-year connection/build-up period.Growth over the next few years is unlikely to be significantp due tolimited economic growth plus some tendency for companies to moveproduction away to newer industrial zones. Beyond 1990, a conservative3%/yr growth rate is assumed. The economic incentive of gas availabi-lity, however, could result in growth significantly above this level,particularly over the long term as industrial development occurs alongthe coastal strip between Jacqueville and Vridi.
Table 2.6: PROJECTED GAS DEMAND:INDUSTRIAL MARKETS
1988 1995 2000 2006
HFO Equivalent('000 tons/yr) 32 46 54 64
Gas DemandMMscfd 3.5 5.2 6.0 7.2BCF/yr 1.3 1.9 2.2 2.7
Source: Mission estimates.
Urea Production
2.31 Urea production from gas is not economic for the small domesticmarket in the Ivory Coast, which is equivalent to 18,000 tons/yr ofammonia. The minimum efficient size for an average plant operating attypical "world-scale" capacity is 1,000 tons/day, well above presentneeds. If an Ivorian plant were to produce fertilizer or ammonia forexport as well, it would have to be price competitive with the main newexport projects in the Middle-East, Central America, Eastern Europe andelsewhere. Many of these areas have surplus gas valued at US$0.5-1.0/MCF--far lower than the cost of gas which could be produced in theIvory Coast. For comparison purposes, Table 2.7 shows relative costs ofurea production in the Middle East, U.S. and Ivory Coast. Two plantsizes are considered for Ivorian production:
(a) a 1000 metric ton ammonia/1700 tons/day urea plant, typical ofnew world-scale facilities, and
(b) a smaller 250 tons ammonia/425 tons/day urea plant, geared tomid-1990's domestic Ivorian demand.
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Table 2.7: UREA PRODUCTION COST COMPARISONS(1983 $)
Middle East US Gulf Ivory Coast a/
1000 tld 1000 t/d 1700 t/d 425 t/d
Gas Cost ($MM Btu) b/ 0.60 3.10 2.50 2.50
Production Costs ($/ton urea) c/Raw materials 15 75 51 51Utilities 19 22 20 20Operating Costs 31 18 21 40Overhead Expenses 36 20 23 44
Cash Cost 101 135 115 155
Debt Service d/ 46 0 70 120Cash Cost Incl Debt Service 147 135 185 275Target Return on Equity (25%) 50 20 48 83
Total "Target Price" 197 155 233 358
ai Ivory Coast capital costs taken to be 1.5 times United States GulfCoast (Middle East taken as 1.65 times USGC).
b/ United States gas cost is between "average" and "decontrolled"levels; Ivory Coast gas cost is vurely indicative, but is of thegeneral order of the likely economic cost to the country.
c/ United States plant assumes mid-1970s technology/efficiency; MiddleEast plant is early 1980s; Ivorian plant assumed to be best avail-able mid-1980s high efficiency unit.
d/ Middle East plant has favorable finance - assumed to be SaudiArabian terms, i.e. 3% interest for 60% of total cost, commercialterms for 10%, equity for 30%; U.S. plant already written off; IvoryCoast plant 70% financed at commerical rates; 30% equity.
2.32 It is clear from the table that Middle Eastern production bene-fits greatly from very cheap gas and favorable finance terms. UnitedStates (and European) producers are able to compete only on the basis ofincremental production from existing plants; new construction for exportcould not be justified at current or projected price levels. Export-oriented production from a large (1,700 ton/day) high efficiency plant inthe Ivory Coast would only be competitive if gas is made available atessentially zero cost.
2.33 Production from a "small" Ivory Coast plant, sized to provideonly domestic market requirements, would not be competitive with import.even if cheap gas is provided. The economies of scale in these productsare so great that for a coastal location such as the Ivory Coast, with
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alternative uses available for its natural gas, small-scale production isunlikely to be viable. Therefore, ammonia/fertilizer production shouldnot be considered as a candidate for natural gas utilization in the IvoryCoast at the present time.
Residential/Commercial Uses
2.34 In many parts of the world, including the United States andWestern Europe, the domestic/commercial market is a major consumer ofnatural gas - close to 50% of total gas consumption in both of theseindustrialized regions. In many smaller markets, including several de-veloping countries, gas also finds an important share of its market indomestic and commercial uses. In the Ivory Coast, however, this is un-likely to be the case. Since there is no space heating requirement inthe Ivory Coast, significant domestic energy uses are restricted to cook-ing, water heating and air conditioning. Electricity is readily avail-able at competitive prices for meeting most of these needs; LPG andcharcoal are the predominant cooking fuels. The average energy consump-tion per household is too small to justify conversion costs for eitherhot water heating or cooking. Without a space heating requirement, theeconomics of gas connection and conversion are unlikely to be attractive.
Transport
2.35 It is technically and economically possible to utilize com-pressed natural gas (CNG) as transport fuel for cars or heavier vehiclesin place of gasoline or diesel if low cost domestic gas is available.Costs of conversion and distribution are high, however, and considerableeffort and time is required to implement the change to CNG. For example,New Zealand, a country with large gas reserves and negligible domesticoil, has adopted an aggressive CNG conversion program. But despitestrong government support and also considerable economic incentives, theprogram has been running behind schedule because of the complexities andproblems of conversion.
2.36 In the Ivory Coast, the potential CNG market is significant.Total inland consumption of gasoline is around 220,000 tons/yr, almost502 of which is in Abidjan. Due to the costs of CNC distribution andmarketing, it is not likely that conversion would be economic outside theconcentrated Abidjan market. If 20% of this Abidjan market were con-verted to CNG, the gas consumption would be equivalent to 22,000 tons/yrof gasoline, or around 2.5 MHscfd. The automotive diesel market in thecountry as a whole is similar to the gasoline market, but this is muchless concentrated in Abidjan, and a smaller proportion of the totalnational fleet could be economically converted to CNG. Thus a total CNGmarket of 2-3 MMscfd could reasonably be targeted in the Ivory Coast.
2.37 Considerable conversion and promotion costs would be requiredto develop this market, however, and the full quantity would not bereached for several years. Adequate markets exist (in power generationand in refinery and industzial fuel markets) to absorb all gas currently
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proven to be available. When a gas distribution system is in place tosupply these other users, a more detailed evaluation of CNG potentialshould be made.
Other Potential Uses
2.38 Other potential uses for natural gas in the Ivory Coast includemethanol, synthetic gasoline, direct reduction, LNG or olefins produc-tion. These would all require gas volumes and costs comparable to MiddleEastern levels to permit competition in export markets. Since gas quan-tities are relatively modest, and costs/values well above Middle Easternlevels, none of these other uses would be viable.
Potential Gas Supply
2.39 Possible configurations for gas production and delivery (bothassociated and non-associated gas) were studied based on recoverabilityof 350-400 BCF. The proposed system would provide some excess capacityfor additional future supply and demand along the onshore pipeline.Investments in block Bl would include a production platform as well as awell head separator and treatment unit to extract the commerciallyvaluable condensate. The condensate could be transported by barge forsale to the refinery or sent via the gas pipeline (two-phase flow) toshore. The gas could be transported via a subsea 14 inch pipeline routeddirectly to shore (about 10 miles). Associated gas from Espoir could befed from the permanent facilities to be installed at that field through a10" pipeline to shore (about 10 miles), meeting the Bi gas at a gasprocessing plant/transfer point near Jacqueville.
2.40 Under the terms of current negotiations the consortium wouldseli the pipeline quality gas at the onshore transfer point to Petroci,which would be responsible for transmission to Vridi and distribution tousers. The gas could then be transported via a 14 inch pipeline onshorealong the coast to Vridi (about 44 miles) where a city gate station couldbe installed on available land within SIR's premises. Various optionswould have to be studied to take -he pipeline across or around the VridiCanal.
2.41 Alternatively, the consortium, in a joint venture with Petroci,could also develop the onshore pipeline and distribution system. Underthis option, the consortium would be rezponsible for all aspects of gasproduction, transmission and distribution, and it would negotiate pricesand quantities directly with the primary consumers.
2.42 Preliminary cost estimates were based on experience in similarfacilities existing in the Ivory Coast and elsewhere. Based on theseestimates, economic costs discounted at 1OZ to 1984 and assuming noescalation of the costs is in the range of US$1.9-2.2/MCF delivered atthe city gate station, depending on gas recoverability and well
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deliverability. For the analysis, gas recoverability ranged from 350 BCFTO 400 BCF, affecting the price inversely. This does not include adepletion value, which would be about US$1.0/MCF. A more thoroughanalysis of costs should be carried out by the Covernment and itsconsultants as it prepares for negotiations with the consortium.
Strategy for Gas Development
2.43 Preliminary analysis indicates there are probably sufficientgas reserves to meet the immediate domestic market at a reasonableeconomic cost. Exploitation of the gas could provide significant savingsin fuel costs for refinery and industrial uses and, in the case of elec-tric power generation, offer not only fuel savings but greater systemplanning flexibility and possibly capital savings.
2.44 It is crucial to further study gas utilization and prepare fornegotiations as soon as possible for the following reasons:
(a) The consortium must relinquish block Bl at the end of the ex-ploration phase in June 1985 or declare part or all of theblock commercially exploitable. The operator has indicated itis prepared to deliver gas to meet reasonable domestic marketrequirements if agreement can be reached on a contract commit-ting to the purchase of specific quantities of gas at an agreedprice as well as payment and currency guarantees.
(b) Under current estimates, up to 60% of total gas consumptioncould be for power generation. Gas availability and costs mustbe confirmed to permit correct long-term decisions to be maderegarding thermal power.
(c) In the short/medium term, substantial costs will be incurred insupplying petroleum products to the thermal power station atVridi. Early availability of gas will have major benefits infuel oil displacement.
2.45 A number of actions must be taken to ensure proper evaluationand implementation of the gas development program. They are:
(a) Institute a steering committee of top government officials,including the Ministers of Mines and of Industry and themanaging directors of EECI and Petroci, to coordinate allaspects of gas development and to provide the gas developmentproject unit (see following paragraph) with support and policydirectives.
(b) Institute a gas development project unit, and designate anexperienced manager as unit leader, to be in charge of allactivities in support of negotiations of gas sales and purchasecontracts. It is .mportant that EECI, potentially the singlelargest gas consumer, be officially consulted by this unit from
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the start. The unit should be staffed mainly by Ivorians, pri-marily from Petroci and later, possibly ECCI, and supported byexpatriate experts.
(c) Hire consultants to support the gas unit with relevantcontractual, commercial and technical skills, to be supportedby other staff in their home office as required.
(d) Begin detailed studies on electric power system optimization(with EECI); customer demand levels/plans, conversion forindustrial markets: requirements/costs, grid pattern optimiza-tion; refinery demand potential (with SIR); conduct an energyaudit to eliminate waste and assess potential gas use byapplication/unit, particularly with respect to use of gas as afeedstock for hydrocracking gas; condensate transportationoptions to SIR; composition and processing requirements, asbetter data becomes available; and gas transmissionoptimization, including "Right of Way" issues, options forlooping around the Vridi Canal, siting of "City Gate" station,etc.
(e) Refine reserve estimates.
(f) Improve cost estimates for offshore platforms/drilling,offshore and onshore pipelines, processing and "city gate"facilities, and industrial distribution network.
(g) Develop positions on pricing and other contractural issues,etc.
(h) Within twelve months, complete negotiations with the consortiumfor supply and with EECI/SIR/industrial consumers for sales.In the context of the supply agreement over the sales price ofgas and quantities taken, the consortium would be asked toagree to undertake additional delineation drilling to confirmthat gas is not overlying a possible commercial oil ring.There would also be an independent certification of gasreserves prior to commencement of the project.
(i) As the viability of the gas project and supply and sales agree-ments are confirmed, undertake detailed engineering studies,including developing bid specifications and obtaining quota-tions for supply and construction of all onshore facilities.
(j) Develop/improve standards for supply, installation and use ofgas.
(k) Continue to promote a long-term drilling/exploration program tosecure future supplies and permit market growth in existing andnew uses.
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Possible Role for the Bank in a Gas Project
2.46 The Ministry of Mines has already instituted a gas task forcewithin Petroci to begin preparing for negotiations with the consortium.With the participation of additional staff from both Petroci and EECI,the task force could be expanded to take up the responsibilities of a gasproject unit, as described above. It is essential that EECI participatein this effort. The role of the Bank initially would be to support thisunit by financing the technical assistance needed to accelerate prepa-ration of a possible future gas development and utilization project.This would include analyzing the market more closely, particularly inrespect of the electric power subsector, formulating a negotiatingstrategy both with the consortium and end users, and conducting thedesign and implementation of the future gas utilization project. Itwould also have the objective of mobilizing other ministries and agenciesof the Government, in addition to the Ministry of Mines and Petroci, toexpedite preparation for the gas development project and to establish asound infrastructure for the potential gas industry in Ivory Coast. Itis imperative for the Government to hire the outside expertise it needsand to begin the in-depth studies outlined above.
SIR (Societe Ivoirienne de Raffinage)
2.47 Societe I-oirienne de Raffinage (SIR) operates the onlyrefinery in the Ivory Coast. SIR is a limited liability company whoseequity shares are held by Petroci and Sonafi (47.2%), Shell Ivory Coast(10.29%), British Petroleum (BP) Ivory Coast (10.10%), Total (10.10%),Mobil (8.00%), Government of Burkina Faso (5.39%), Elf (5.00%), Texaco(3.70Z) and Esso (0.151). The Government indirectly controls SIR's sharecapital through ito sole ownership of Petroci and Sonafi; Petroci in turnowns 50% of the Ivorian subsidiaries of Shell and BP. The refinery faci-lities consist of three distillation units of total capacity 3.77 millionmetric tons per annum (mmtpa), a vacuum unit of capacity 1.7 mmtpa, ahydrocracker complex of 630,000 tons/yr, a hydrogen plant and sulfurplant, together with appropriate storage and offsite utilities faci-lities. The refinery was commissioned in 1965 and was progressively ex-panded, the last addition being a crude distillation unit of 1.9 mmtpacommissioned in July 1982 and the hydrocracker and associated facilitieswhich came onstream in December 1983. Current capacities of the variousrelevant units are given in Table 2.8.
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Table 2.8: SIR UNIT CAPACITIES
Unit Tons/Day Million tons/year Start-up Year
(330 days/year)
Crude Unit No. 1 2,880 0.95 1967" No. 2 2,784 0.92 1972
No. 3 5,767 1.90 19823.77
Bitumen Unit (SMB) 1,520 0.50Hydrocracker 1,920 0.63 1983
Source: SIR Refinery.
2.48 In recent years, production stagnated at a level of 1.5-1.6million tons of refined products per year, despite the expansion,resulting in low capacity utilization. Table 2.9 depicts the productionperformance of SIR by each unit over the past four years.
Table 2.9: CAPACITY UTILIZATION OF THE SIR REFINERY BY UNIT(in million tons per year)
l979/80 1980/81 1981/82 1982/83
Atmospheric distillates(hydroskimmer)
Capacity 1.87 1.87 1.87 3.77Production 1.65 1.46 1.58 1.68Capacity Utilization (Z) 88 78 84 44
Secondary Conversion(hydroskimmer)
Hydrocracker (capacity of 0.633 mty) started in May 1983.
Source: SIR Refinery
2.49 The traditional role of the refinery has been to supply domes-tic Ivory Cjast inland markets, relatively large domestic and interna-tional bunkers markets in Abidjan and to supply the product requirementsof its landlocked northern neighbors, Bukina and Mali. Under bilateralarrangements, SIR supplies these nations' petroleum productrequirements. Until the late 1970s, the consumption of petroleumproducts in this captive market had grown at an annual rate of 10 as thecountries' economies continued to grow rapidly, thus doubling consumption
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every seven years. Since the 1979 oil price increases, however, thedemand has stagnated with the continuing economic recession in the IvoryCoast and the neighboring countries.
2.50 The completion of expansion projects in 1982 has left therefinery with capacity far exceeding its local demand, resulting inforced exports at below-cost prices of various products ranging frompremium gasoline to heavy fuel oil. With the commissioning of the hydro-cracker in December 1983, the SIR refinery is not expected to export fueloil; exports will consist of only gasoline and middle distillates afterconverting fuel into more valuable distillates.
Main Issues
2.51 A series of temporary measures have recently been implementedby the Government to improve the refinery's situation in the fields ofcrude oil/feed optimization and crude oil/feed costs and procurement.However, major decisions are necessary to ensure the rehabilitation ofthe refinery in the long run and remove the difficulties with which ithas been coping. The refinery's problems are essentially due to acombination of financial, operational and managerial difficulties.
2.52 Financial Difficulties. SIR's financial structure hasdeteriorated substantially over the past four years. Since 1979/80, therefinery has operated with cash losses and has become increasinglydependent on the Compensation Fund, a subsidy designed to cover operatinglosses of the refinery and on new loans to service its debts. Internalcash generation has been negative over this period. Interest expense hasincreased tenfold since 1979/80 due to the burden of the long-term debtfor the refinery expansion and heavy reliance on expensive short-termdebt to finance operations.
2.53 A number of factors have contributed to the poor financialperformance of the refinery:
(a) Cost overruns of over 50X for the expansion project, largelydue to delays in its execution. The project took almost fouryears to complete compared to the planned two years. It shouldbe noted, however, that overruns of this magnitude have beencommon for similar projects elsewhere in recent years.
(b) Unexpected stagnation in domestic demand for petroleum productscompared to the increase anticipated when the project was con-ceived. In the absence of an aggressive export marketingstrategy, this has caused underutilization of installed capa-ci.y (1.5 million tons production versus 3.77 million tonsnominal capacity).
(c) Under-capitalization which has caused a serious debt burdensince virtually all the expansion investment has been financedfrom borrowings.
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(d) Excessive short term debts mainly caused by delays in paymentsfrom the Compensation Fund (which was designed to cover SIR'stotal costs) and aggravated by SIR's too favorable credit termson sales.
(e) SIR's balance sheet is saddled with unproductive assets such asthe training center at Bassam and the 42-inch sea line (con-ceived to meet the crude import needs before the Espoirdiscovery).
(f) In the past, SIR's shareholders marked up the price of thecrude they provide to the refinery by up to US$1.50/barrelabove normal world market prices, thereby squeezing the SIR'sfront margins. This is an important factor, since the crudeprice is by far the largest component of the SIR's operatingexpense (more than 90% of the refinery's fixed and variablecosts). In addition, Petroci, the main supplier, has charged aUS$0.50/barrel intermediation fee for imported crude.
2.54 Operational Difficulties. Significant savings in operatingcosts can be achieved if the refinery increases its operatingefficiency. A detailed analysis could identify options to increase theoperating efficiency in the following areas: (a) crude oil/feedoptimization; (b) reduction in energy consumption and losses; and (c)reduction in overhead expense.
2.55 With the completion of the hydrocracker, the refinery could in-crease its profitability by processing heavier crudes or imported residu-al fuel oil and operate the hydrocracker at a higher capacity utilizationrate. Under such an operating strategy, the captive market requirementscould be met by minimizing feed-input costs while increasing the capacityutilization of the hydrocracker. The appropriate mix of crude oil/feedwill depend on market demand. This is a continuing process which willrequire specialized knowledge of both processing and market conditionswith respect to product availability and price trends.
2.56 The refinery energy consumption and losses are high compared tointernational standards. Energy consumption and losses during the period1979/80 to 1981/82 increased progressively from 5.4Z to 7.3% of feed tothe crude distillation unit and associated facilities, excluding thehydrocracker. Energy consumption for similar facilities is normallyabout 4.5%. The relatively high energy consumption and losses could bedue to flaring of gas as a routine disposal operation, system leaks, poorheater design and inadequate process heat recovery. A detailed energystudy will need to be done to identify the causes for this relativelyhigh energy consumption. With regard to the hydrocracker, which wasdesigned in the late 1970s, energy consumption guarantees are consistentwith similar units elsewhere. If operated efficiently these guaranteesare likely to be met.
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2.57 The overhead expenses of the refinery are very high as comparedto refineries with a similar configuration and there are areas wherethese expenses can be reduced. The burden of national training require-ments carried out by SIR without compensation, the need for a largeexpatriate staff, future training and manpower needs will have to be re-viewed and corrective action taken to ensure that the refinery operationsare reliable and carried out efficiently at minimum cost to SIR.
2.58 Managerial Difficulties. Although SIR is, in principle, anindependent private company, there does not appear to be a clear under-standing of the role of SIR or its legal and commercial status. SIR isgoverned by a Board of Directors on which all the shareholders are repre-sented. However, over the years the roles of the shareholders and thecompany's senior management have become somewhat diffused. The executivemanagement of SIR, which is largely government appointed, in principlehas the responsibility for the production efficiency and the economicviability of SIR. Yet, SIR does not operate as an autonomous, com-mercially oriented enterprise at present and the pursuit of sometimesconflicting objectives by the different shareholders weakens the role ofthe executive management.
2.59 The Government exercises a dominant role in the activities ofSIR through Petroci. It provides loan guarantees and injects funds fromtime to time, controls the ex-refinery prices of petroleum products andauthorizes the refinery's annual budget. The private shareholders,having been deprived of the control of the refinery, act as sleepingpartners and do not share management responsibilities except on mattersaffecting their interests as suppliers of crude and buyers of products.The Government has recognized the need to clearly establish guidelinesand to restructure the management, and organization of the refinery andrestore its efficiency.
Rehabilitation Strategy
2.60 In December 1983, a Bank mission made a preliminary assessmentof SIR's problems and suggested that the refinery has the potential to beeconomically viable in the long term if significant measures are takenrapidly, in particular regarding management, organization and steps toincrease capacity utilization and reduce costs. The Bank's analysis wasbased on preliminary data that had to be further developed. Since therewere several alternative options to improve the viability of therefinery, the Government agreed with the Bank's recommendations to retainthe services of qualified and experienced consultants to carry out thereview of the refinery. This study is financed from the Bank's TechnicalAssistance Loan and is being carried out in two phases. The first phaseconsists of a diagnosis of the refinery's situation and identification ofthe main parameters that were constraining its viability. The secondphase assesses the alternative options or measures that are required torestructure the refinery.
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2.61 More specifically, the objectives of the first phase are to(i) prepare projections for petroleum products demand in Ivory Coast,captive and other potential markets in the region and outside the region,assuming that an appropriate marketing strategy is implemented; (ii)prepare projections of petroleum product prices so as to be able tocalculate the revenues that the refinery may generate at internationalprices; (iii) determine the refinery's production costs, including theeffect on them of potential improvements in efficiencies and energyconservation measures that may be taken in the short-term; (iv) on thebasis of the above information, prepare a comparative economic evaluationof the cost to the country of different petroleum product supply options,including the import of refined products and associated costs, processingin the refinery crude or residual fuel oil, and other options that may beappropriate.
2.62 The second phase assesses the alternative options or measuresthat are required to restructure the refinery, including: (i) managementand organizational restructuring to establish SIR as a completelyautonomous enterprise totally accountable for its operations;(ii) financial restructuring to re-establish its financial viabilitygiven tte high debt/equity ratio of the company; (iii) marketing restruc-turing to enable the company to penetrate foreign markets (includingcrude processing) and to increase capacity utilization; and (iv) opera-tional restructuring to reduce its current higher energy consumption andoperating costs.
2.63 The object of the study is to prepare a concrete plan of actionto restructure the company so as to enable it to become viable. It willform the basis of discussion between the Government of the Ivory Coastand the shareholders on the future role of each party. The study resultsare expected by Spring 1985.
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III. ELECTRICITY
Overview
3.1 Almost all facilities for commercial electricity generation aremanaged by EECI (Energie Electrique de la C6te d'Ivoire). The company,founded in 1952, generates 95% of the electricity consumed in thecountry. The remaining 5% is produced by a number of privately- orstate-owned captive plants. 9/ The EECI system is predominantlyhydroelectric (75% of installed capacity in 1983); about 25Z of the12,400 GWh of technically exploitable hydropotential is presentlyharnessed. Most generating capacity, both hydro and thermal, isconnected to the main grid, except for a number of diesel plants inoutlying areas with a total installed capacity of 32 MW. All powerplants, whether interconnected or not, operate at 50 Hz. Development ofthe system load and capacity is summarized in Tables 3.1 and 3.2.
Table 3.1: EECI BASIC DATA FOR 1960-1980-1983
FY ending September 30 1960 1980 1983
Energy Sales GWh 57 1522 1794
Interconnected system: GWh 67 1654 1935Hydro generation GWh 59 1769 1198Thermal generation GWh 8 385 737
Isolated generations GWh 6 63 53
Interconnected systemInstalled capacity: MW 25 848 832Hydro MW 20 614 614Thermal MW 5 234 218
Table 3.2: EECI GENERATION GROWTH RATES
Year 1965 1970 1975 1980 1981 1982 a/ 1983 a/
Percent 24.7 18.6 13.2 13.0 7.4 5.3 2.4
a/ Fiscal year starting in October of the previous year.
91 Many of these plants use agricultural residues and wood wastes aswell as conventional fuels, to fire their generators. This isdiscussed further in Chapter IV.
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3.2 EECI's policy for managing its generating stations is based onrational use of hydroelectric resources given that all reservoirs arerefilled annually except r'issGu, which has never attained its maximumstorage levels. A series of dry years (notably 1972-1978 and 1983)contributed to premature depletion of minimum reservoir storage andrecently has disrupted the electricity supply, despite sufficient totalinstalled capacity to meet demand. The resulting disruptions in themaintenance schedules for the thermal generators at Vridi led to a 15lreduction in their energy availability. Consumption growth rates havedeclined since 1981, the combined result of economic recession and supplyproblems. To meet future demand, prospects for load growth should be re-appraised. Hydro and thermal supply options must be evaluated andrevised to take into account the effects of recent drought cycles on thesystem rating, as well as the availability of new natural gas reservesfor thermal power generation. The need for firm energy to meet demand indry years may affect the hydro/thermal generation mix.
EECI System Characteristics
Generating System
3.3 Hydroelectric plants represented 752 of EECI's installedcapacity in 1983, and they can meet over 902 of current energy demandunder average rainfall conditions. There are five main stations: Ayame1 and Ayam4 2 along the Bia basin, Kossou and Taabo on the Bandama basinand Buyo along the Sassandra. The yearly generations for each plant aregiven in Table 3.3. These figures are only approximations, since actualenergy generation, especially at Kossou, depends greatly on reservoirlevels and operation over several years.
3.4 Most of the installed thermal capacity is concentrated at theVridi site near Abidjan. It consists of four steam units burning heavyfuel oil and four new gas turbines burning distillate. EECI alsopossesses a 12.5 MW gas turbine at the Abidjan harbor which is connectedto the grid and a number of isolated diesel plants (about 50) with atotal capacity of 32 MW.
Transmission and Distribution
3.5 The transmission and subtransmission network consists of 2,600km of 225 kV and 90 kV overhead lines. The 225 kV grid is tree-shapedand mainly serves as the connecting link between the hydro stations andthe major cities. This voltage is also used for the recently commis-sioned tie line with Ghana. The 90 kV network consists of spur or loopfeeders extending to lesser loads and generating stations and of meshedparts supplying distribution substations in the high density serviceareas requiring higher reliability.
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Table 3.3: HYDROELECTRIC POWER PLANTS
SassandraHYDROELECTRIC Bia basin Bandama basin basin
Ayame 1 Ayame 2 Kossou Taabo BuyoCommissioning date 1959 1965 1972 1979 1980
Number of turbines - 2 2 3 3 3Installed capacity (MW) 20 30 174 210 165
Live Storage: (106m3) 846 68 23,265 340 7,000
Average yearlyinflow: (106.3) 2,100 2,100 4,800 6,800 10,900
Average Generation (CWh) 80 120 350 a/ 850 900
EfficiencyHigh water level (kWh/m3) .051 .073 .118 .145 .086Derating atlowest level -352 0 -452 -40% -40%
THERMOELECTRIC Vridi 1-2 Vridi 3-4 Vridi 5-8
Commissioning Date 1968-70 1976 1984Nameplate rating (MW) 2 x 32 2 x 75 4 x 25Net rated Output (MW) 2 x 30 2 x 55 4 x 22.5
a/ Kossou's average generation is based on use of the dam's totalcapacity. In fact, the maximum storage level has never beenreached.
Source: "EECI Equipements 1980" and mission estimates.
3.6 The distribution system features some 6,000 km of mediumvoltage (MV) lines at 33 kV and about 7,000 km of low voltage (LV) linesat 220/380 V. All services, including residential, are equipped withcircuit-breakers. Contracted demand increases by steps of 1.1 kVA from1.1 kVA up to 13.2 kVA and by steps of 3.3 kVA from 13.2 kVA up to39.6 kVA.
3.7 EECI's dispatching center is located at the central head-quarters in Abidjan. Its functions include, in addition to supervisionand data acquisition, remote control of all the hydro turbines, all 225and 90 kV circuit-breakers and the 225 kV isolating switches. The compu-ters are shared with a distribution control center for greater Abidjan.In theory, these facilities give EECI the capability to minimize oper-ating margins and fuel outlays beyoi:d the levels which are presentlyachieved.
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Demand Characteristics
3.8 Demand Profiles. Total electricity sales in the EECI systemwere almost 1,800 GWh in fiscal year 1983. Over 62% of total consumptionis concentrated in the greater Abidjan area, where medium voltage (MV)customers are the largest consumers. MV demand throughout the system isequally distributed between industries and services, and accounts forslighly less than half (462) of total consumption. High voltage (HV)customers, including the SIR refinery and textile plants located outsidethe Abidjan urban area, account for 6Z of total demand. The share of lowvoltage (LV) consumption (47%) is relatively high for a developingcountry in Africa, in large part because residential consumption, whichaccounts for two-thirds of the LV total, is itself quite high. In 1983,residential per capita consumption was 3,007 kWh/yr in Abidjan, where 53%of the population had electricity; in other electrified areas, thesefigures amounted to 1,035 kWh/yr and 39% respectively. Half of thatdemand is contracted under powers of 4.4 kVA or more, reflecting theregular use of air conditioning by 10% of the customers. (Table 3.4).
3.9 Load Curve. For the interconnected system, the yearly loadfactor is 0.69 and the working day load factor is about 0.85. The loadcurve features three peaks: one in the morning, one in the afternoon(due to industry) and a larger one in the evening. The night loadreaches about 70% of the peak load. On Saturdays, there is no afternoonpeak and on Sundays, both morning and afternoon peaks disappear. Thereis only a small seasonal variation of about 10% after growth trendcorrection, with a high at the beginning of the year and a low in thesummer. Thus, system bottlenecks are mostly due to variations in theconditions of supply, that is plant outages or water availability.
3.10 Demand Forecasts. EECI demand is forecast on the basis of abreakdown of total consumption by regions and customer classes. Demandtrends are assumed to be a function of socio-economic variables for eachaggregate with the exception of new major public works or industrial pro-jects, which are considered individually. In early 1983, EECI preparedthe "Mauve Scenario", a demand forecast up to 1995. In this scenario,the energy for new projects in MV and HV was forecast to reach 530 GWh in1989 and 790 GWh in 1993. EECI also prepared a lower forecast, known asthe "Grey Scenario," taking into account the worsening economic situa-tion. In the Grey Scenario, there is less demand growth due to delays inor cancellation of a number of projects. Year by year generation andinterconnected system peak ioad for both scenarios are given in Annex 2.Table 3.5 compares some typical parameters of the two scenarios.
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Table 3.4: BREAKDOWN OF CONSUMPTION BY VOLTAGE ANDCLASS OF CUSTOMER
Abidjan Other Total forarea areas fiscal year Total
- -------- 1982 ---- 1983
Consumption in Z of totalHigh Voltage 0.6 6.6 7.2 5.YMedium Voltage 33.3 13.9 47.2 46.5Low Voltage 28.3 17.3 45.6 47.Of which:
- Residential 20.6 9.7 303 31.6- Professional 6.8 4.6 11.4 12.0- Street lighting 1.0 2.9 3.9 4.0
Total 62.2 37.8 100.0 100.0
Number of ConsumersHigh Voltage 1 3 4 4Medium Voltage 788 755 1,543 1,614Low Voltage 125,743 194,840 320,583 339,293
Of which :- Residential 114,129 165,491 279,620
337,251- Professional 11,113 28,056 39,169- Street lighting 501 1,293 1,794 2,042
Source: EECI.
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Table 3.5: COMPARISON OF GREY AND MAUVE SCENARIOS(GWh)
Grey Mauve DifferenceForecasts (a) (b) (b-a)
1985 2,100 2,244 144Consumption 1989 2,841 3,220 379
1993 3,830 4,310 480Of which:New MV and HV projects:
1989 174 530 3561993 374 790 416
1985 2,344 2,596 252Generation 1989 3,228 3,681 453
1993 4,352 4,926 574
Growth Rates (ZIYear)
Total Consumption 1983-1985 4.2 7.7 3.51985-1989 7.8 9.4 1.61989-1993 7.8 7.6 - 0.2
- LV Consumption :1983-1989 9.5 10.1 0.61989-1993 8.7 9.2 0.5
- Existing MV and HV:1983-1989 4.1 3.6 - 0.41989-1993 4.0 3.7 - 0.3
Total Generation 1983-1985 8.6 14.3 5.71985-1989 5.5 5.9 0.41989-1993 7.8 7.6 -0.2
Source: Mission estimates
3.11 Three comments can be made with respect to the two forecasts:
(a) For residential demand the detailed forecasts prepared for theMauve Scenario foresee yearly increases in numbers of customersof 8.4% for the Abidjan area and 5.7% for other already elec-trified areas. This corresponds to per capita yearly increasesof 1.9% and 3.8% respectively. In other words, the forecastresidential demand is mostly driven by the number of custo-mers. Indeed, per capita consumption decreased in 1982 andrenewed growth cannot be guaranteed due to the incentives forpower conservation triggered by recent tariff increases, powercuts and the prolonged economic stagnation. Water heatingappears to be of very little importance in the total consump-tion figures, and even if a solar alternative was developed, it
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would hardly affect residential consumption. For customerswith contracted power of 4.4 kVA and over, which representsabout half of the residential consumption, air conditioningappears to be a major demand component, which could explain thehigh load factor. Conservation measures could be directed inthis area with significant results. The action may cover theappliances and the houses themselves (improved equipmentdesign, heat insulation and air conditioner replacement) and/orthe way people use their appliances. EECI has carried outexperiments in this domain with very promising results (thermalinsulation of buildings).
(b) The "new rural" development hinges on new distribution networksand thus is largely under EECI's control. A severe shortage offunds could significantly hinder the schedule of the contem-plated program, but since it represents only 3Z of total con-sumption in 1993 (see Annex 2), its slowdown should have only aminor impact on overall demand trends.
(c) Both scenarios show a 4Z increase in consumption by "existing"MV and RV consumers, i.e. the present MV and HV customers andthe new small consumers at those voltages. The conservationpotential noted in residential uses also applies here for userswith a good share of tertiary activities (40% of the total).Energy for air conditioning could be saved by replacingincandescent lights with fluorescent lights, which dissipateless heat; commercial and industrial demand are also veryelastic to economic conditions and offer possibilities of powerconservation through adaptation of their equipment or more caregiven to equipment operation
3.12 For the long term, wide-spread adoption of techniques such asprocess heat and/or power generation from industrial biomass residues andcombined power and cold generation (through gas turbines and absorptionchillers, for instance) may somewhat alter the demand pattern.
3.13 There remain many uncertainties as to power demand in the IvoryCoast. Demand may fall well below the Grey Scenario figures or pick upagain. The outcome will depend upon general economic conditions, most ofwhich are not under the direct control of the Ivory Coast. It will alsodepend upon consumers' reactions to the new tariffs set in early 1984 andupon the psychological changes which may occur as a result of the powershortages experienced in 1984. After weighing the various risks of over-or underestimating the demands placed on EECI, the Grey Scenario has beentaken as the optimistic scenario, and the implications of demand laggingthis forecast by 600 GWh in 1990 have been examined as a variant. Thereaction of users over the near term should be carefully mor. tored todefine whether or not new elements must be introduced into the fore-casting process. It is also recommended that EECI study the impact ofdirect and indirect conservation measures on projected demand and thatthese results be incorporated into decisions concerning the futuredevelopment of generation capacity.
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Hydraulic Resources
3.14 The hydro power resources of Ivory Coast are located in thebasins of four major rivers flowing north-south and discharging into theAtlantic Ocean: the Cavally, (its lower two-thirds consitituting theborder with Liberia), the Sassandra, the Bandama and the Comoe. Averagerunoff decreases from west to east, as illustrated in Table 3.6. Theregional variation from west (Cavally) to east (ComoO) extends also tovariability of annual runoff and seasonal variation, which both increaseas the average runoff per km2 diminishes. This is an important elementin evaluating the risk of droughts.
Table 3.6: COMPARISON OF FLOW RECORDS FOR MAJOR RIVERBASINS IN THE IVORY COAST a/
River BasinsCavally Sassandra Bandama Comae
Drainage Area (kzq ) 30,000 75,000 97,000 78,000Average Flow Cm is) 600 575 340 250Average Runoff (Liters/s/km2) 20.0 7.7 3.5 3.2
a/ Based on 1954-1976 steam flow records.
3.15 In 1979, EdF completed a comprehensive inventory of the waterresources of Ivory Coast, including both power sites and multiple purposedevelopments that would primarily benefit agriculture. The technicalrealizable hydro power potential of the country (in terms of averageannual generation) was estimated at 12,400 GWh, including an estimated2,400 GWh already developed on the Sassandra, Bandama and Bia rivers (theBia drains the extreme southeast of Ivory Coast, near the Ghanaborder). The remaining potential of 10,000 GWh was distributed asfollows:
Cavally 1,300 13%Sassandra 5,700 57%Bandama 1,250 12%Comoe 1,750 18%
10,000 GWh 100%
The streamflow records on which these estimates are based do not includethe below average years recorded since 1977. Although the absolutefigures needs revision, the breakdown is still indicative of thegeographic distribution of the hydro resource base.
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3.16 Following completion of the EdF inventory, EECI considered anumber of priority projects for development after completion of Taabo(Bandama River, 1979) and Buyo (Sassandra River, 1980). The selectionexcludes some more costly storage and power developments at theheadwaters, and the Cavally River, where a major development will requireinternational agreement. The remaining projects, all competitive withoil-fired thermal plants, are developments in cascade downstream ofexisting plants on the Sassandra and Bandama Rivers, and two projects onthe Comoe River, as listed in Table 3.7. A development plan to the year2000, formulated by EECI in 1981, visualized the successive constructionof Soubre, Ndieliesso, Malamalasso, Daboitie and Louga. Among theseprospects, Soubre is outstanding: its low cost of power is attributableto a combination of favorable topography, large river flows and existingstorage upstream at Buyo. Accordingly, it was earmarked as the nextdevelopment, until its indefinite postponement in early 1984.
Table 3.7: RIVER DEVELOPMENT SCHEMES
Order ofRiver Basin Installed Annual Generation Average cost a/ Development
and Site Capacity Primary Average of energy in 1981 Plan
MW GWh GWh Scts/kWh
SassandraSoubre 328 1,330 1,580 2.3 1Gribo Popoli 112 415 515 5.5Bouloubre 156 635 785 4.5Louga (RN52) 280 1100 1330 3.4 5
Subtotal 876 3480 4210
Bandama
Kokumbo 78 310 350 4.5Singrobo b/ 67 260 315 4.5Daboitie b/ 124 290 375 6.8 4
Subtotal 269 860 1040
ComoeNdi&liesso 100 500 610 4.3 2
Malamalasso 90 490 600 3.6 3190 990 1210
Total 1334 5330 6460
Sites of 1981 Plan 921 4710 4495
a/ Based on 10% discount rate, 1984 costs.b/ Data superseded by KECI feasibility study (March 1983).
Source: EdF inventory data and World Bank estimates.
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3.17 Meanwhile, EECI recognized that the inventory required follow-up studies for each of the three major river basins, which would examine(i) the optimum development in cascade of each river stretch; and (ii) afeasibility study of the most promising site id^ntified in phase Mi).The first such study was commissioned for the Bandama River basin andcompleted in March 1983 by Kaiser Engineers and Constructors Incorporated(KECI). Reconnaissance of the river below Kossou resulted in adevelopment scheme visualizing four sites, two between Kossou and Taabo(Zambakro and Beriaboukro) and two downstream of Taabo (Singrobo andDaboitie). The site farthest downstream, Daboitie, was studied tofeasibility level. The layout combines the potential of two EdFInventory sites, Daboitie and Tiassale, in one development, withresulting economies of scale. KECI estimated that the cost of power fromDaboitie is of the same order as that of Singrobo, Louga and Comoe Riverdevelopments. Hence, since completion of the 1979 inventory,investigation of three projects of interest has advanced to pre-feasibility or feasibility stage: Daboitie, Singrobo and Soubre. Energyrequirements and costs are summarized in Table 3.8.
Table 3.8: COMPARISON OF SOUBRE AND LOWER BANDAMA SITES
Daboitie Singrobo Soubre
Installed Capacity (MW) 120 80 328Primary Energy (GWh) 360 200 1,330Average Energy (GWh) 540 310 1,580Construction Cost ex. IDC,July 1982 prices (US$x106) 206 106 348
Construction Cost per GWhAverage Output (US$xlO ) 381 342 220
Source: KECI, Bank staff estimates.
Thermal Power
Heat Recovery and Unit Repowering
3.18 There is a possibility of repowering the four Vridi 25 MW gasturbines into combined cycle unit(s). EECI is already investigating thisoption. Upgrading the four gas turbines with two 22.5 MW heat recoveryboiler steam unit would involve an estimated investment of $35 million.This corresponds to an annuity of (a) capital $4.24 million and (b)operation and maintenance $1.05 million, for a total of $5.3 million.The savings in distillate fuel oil amount to $7,860 per fuel-based CWhusing unescalated fuel prices (Annex 4). On this basis, installing the
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combined cycle would prove profitable as soon as average yearly thermalgeneration exceeds 675 GWh/yr. Using escalated fuel prices, thebreakeven point drops to 600 GWh/yr.
Additional Combined Cycle Units
3.19 EECI is investigating thermal installations which arecomplementary to existing units. Their studies, which are at an advancedstage, are based on standard steam power plants or combined cycle unitswith a capacity of about 300 MW. In the same sense, additional thermalcapacity in the form of two new combined cycle units (CCI and CC2) wasconsidered by the mission as an alternative to hydro projects in the casewhere gas is available. Combined cycle units are less costly than steamturbines in the range of 100-150 MW. Whatever the fuel employed, thebetter efficiency of the combined cycle units is enough to offseteventual fuel cost differentials. The two new units could each consistof a set of gas turbines (3x35 MW or 2x50 MW) and one 45 MW steam turbinewith 125 MW net output. Installation at a site close to the gas field,probably West Jacqueville, will be convenient if gas is used as theprimary fuel. Transmission would be by 225 kV circuits, contingent uponthe eventuality of new loads being developed between Jacqueville andAbidjan. The connection point to the 225 kV ring around Abidjan would bea new 225 kV substation between Abobo and Vridi. The total cost of eachnew combined cycle unit would be $71 million, including $10 million forthe 225 kV section associated to each unit.
Fuel Supply Considerations
3.20 Flexibility in the supply of gas is a key factor in determiningits role here. Thermal generation in a predominantly hydroelectricsystem is erratic: the daily fuel intake, if freely optimized, wouldvary from several times the yearly average to zero, especially in therainy season. To some extent though, reservoir operation can accomodatea more rigid supply pattern, at the expense of additional fuel require-ments and increased risks of water spillage. The precise relationshipbetween gas supply arrangements and the optimum gas share in thermalgeneration is worth a detailed study, far beyond the scope of thisassessment.
Captive Power
3.21 No accurate figures are available but, there is some indicationthat annual captive power generation is about 200 GWh, one half of whichis generated by the SIR refinery and the other half by various indus-tries. The SIR refinery is connected to the EECI grid and has two 25 MWturbines. Power generation is integrated in the refining process andnormally only one turbine is operated. Exchanges with the grid arecomon. Palm industry plants in the coastal area generate at least 14GWh/yr using both diesel units and back pressure turbosets associated
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with boilers fired by biomass residues. The residues produced in theseplants could be used to generate up to 94 GWh/yr of surplus electricityto be sold to the EECI grid. The palm industry plants are not currentlyconnected to the grid, however. Sawmills regularly use wood-fired steamunits and diesel units to generate power for their in-plant electricityrequirements, and sugar mills (connection to the grid under way), havetraditionally used bagasse as fuel for power generation. Other miscel-laneous industries have purchased diesel generating sets in recent yearsand other agro-industries are investigating the feasibility of usingbiomass residues for power generation. Further discussion of captivepower options can be found in Chapter IV.
Main Issues and Recommendations
Short-Term Issues
3.22 Energy Shortages. From December 1983 to March 1984, there havebeen severe power outages (load shedding) within the EECI system due todiminished water levels in the reservoirs. From 1980, the water inflowsto reservoirs have steadily decreased, down to 60% of the mean value atBuyo, 40% at Ayame and 23% at Kossou by 1983, as shown in Table 3.9.Moreover, since 1982 the capacity available at the Vridi thermal planthas been reduced due to damages on the two 75 NW steam units (units 3 and4); despite repair work, available capacity was still 40% below itsnameplate capacity at the beginning of 1984. Energy imports from Ghanaduring this period were impossible even after the tie line went intoservice. Shortages were only minimally offset by surplus power generatedat the SIR refinery (10 MW). The shortfall reached about 120 MW or 40%of peak demand (30% of the weekly energy).
Table 3.9: ENERGY DISPATCH ON THE INTERCONNECTED GRID
Fiscal year 1981 1982 1983
Total Generation (GWh) 1,797 1,893 1,935
Hydro Generation (GWh) 1,660 1,759 1,198Z of total 92 93 62
Thermal Generation (GWh) 137 134 737X of total 8 7 38
Watgr Inflow to Reservoirs(10 m3)Ayame 1,848 1,768 847Kossou 3,893 1,897 940Buyo 9,452 10,101 6,755
Hydro energy stored at theend of fiscal year (GWh) 778 506 106
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3.23 EECI's only immediate recourse was to systematically organizelarge scale load shedding by rotation and order of priority. Individualindustrial plants used emergency diesel generators or had them installed;by February 1984, the capacity of diesel units imported since the begin-ning of the power shortages amounted to about 25 MW. In the meantime,EECI was authorized to purchase four 25 MW gas turbines, which were in-stalled on the Vridi site in March 1984. The turbines will be fired withdistillate fuel oil which will be imported until it is produced by thelocal refinery or substituted by indigenous natural gas. Should the lessexpensive gas become available by 1988, the turbines could be convertedto gas use to save on the cost of liquid fuels. In the meantime, fuelrequirements for 1984 are expected to reach 180,000 tons (US$33.3 millionat 1984 prices) in addition to 300,000 tons of HFO (US$55.5 million) forthe steam units, which will place a heavy financial burden on EECI and onthe economy at large.
3.24 EECI's policy for managing its generating stations is based onoptimal use of hydroelectric resources (para. 3.2). The difficultiescaused by the drought undermined considerably the maintenance schedulefor the thermal units at Vridi, which were used to meet a large share ofthe electricity demand during the drought period. The risks of electricpower shortages will thus be eliminated as soon as the storage level inthe reservoirs has risen sufficiently. As for Kossou, an optimizationbased on the 30 most recent years of hydrological data indicates thattarget storage levels should increase yearly by about 1.2 billion m' forat least a decade. Yearly average generation at this plant wouldgradually approach 280 GWh and level off aroynd this amount. Livestorage should stabilize at around 11 billion m (50Z); at this level,any large swing in operating conditions - plant commissioning, dry year -could be absorbed comfortably.
3.25 The mission recommends that EECI take immediate action to:
(a) Revise operating policies so that water discharge strategiesare regularly based on the outcomes of dynamic optimizationmodels such as the EECI-owned MOGLI.
(b) Study the economic and technical conditions for the purchase ofelectricity from other producers, especially plants using agro-industrial residues and sawmill wastes to fulfill on-siteelectricity requirements. These sources may prove to beadditions to EECI's thermal back-up. (see Chapter IV).
3.26 Network Bottlenecks. With no generation at Kossou, lines wereso lightly loaded as a result of the drought that there was a largeexcess of reactive energy to be absorbed on the northern branches of the225 kV system and Kossou generators were used as synchronous compensa-tors. As a rule, despite its modest generation, Kossou plays a prominentrole in the system due to the fact that it is the only multi-year reser-voir; it is also the plant located farthest to the north along the 225 kVline serving Bouake and Yamassoukro, the most important load cencersafter Abidjan.
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3.27 The network size is generally adequate except for the Buyo-Abidjan link, presently ensured between Buyo and Taabo through a 225 kVsingle circuit. Failures along this link may cause instability when Buyois operated at high load and a second circuit may be needed betweenSoubr6 and Taabo. EECI is examining ways ti improve this link. In thearea of distribution, problems will likely arise due to the difficultiesof financing network extensions to new consumers.
Medium-and Long-Term Issues
Review of System Ratings
3.28 Generation capabilities of the exisiting system needreviewing. Natural river flows recorded during the past decade (1972-1978 and 1982-83) are well below long-term averages, but it is not clearwhether this is a long range trend. The phenomenon appears to be part ofa generalized drought affecting not only the Ivory Coast but alsoneighboring countries. However, there are possible country-specificreasons for decreasing flows that merit further study:
(a) Diversions for irrigation should be investigated in connectionwith the agricultural projects taking into consideration that aportion of the diverted water is recirculated into the riversupstream of the reservoirs.
(b) Rainfalls have decreased as a result of deforestation.
Cc) There is possibly a decrease of the restitution ratiorunoff/rainfall due to deforestation, lowering of the watertable, or both.
3.29 The existing hydro plants (Table 3.3) generate on average 2,000GWh/yr for an installed capacity of 600 MW (400 MW with all thereservoirs at their minimum level). The overall plant factor is 0.38 onthe basis of installed capacity (0.57 on the basis of minimum waterlevels), while the present load factor on the interconnected system is0.69. This indicates that there is no lack of peaking capacity and thatthe firm energy limitation is a controlling factor in system expansion.In that perspective, the generation capability of thermal units should bereviewed on the basis of expected performance rather than nameplateratings and a review of the hydro plants' capability is essential.Particular attention should be given to the central roLe of Kossoustorage and to the level of reliability EECI ought to achieve. At theoptimum steady state storage level of 50%, Kossou's firm energy can beconsidered as close to the average of 280 GWh if an isolated dry yearwere to occur. However, if this storage was to guarantee supply againstan occurence of the 1971-79 drought, Kossou must be rerated at some 160GWh. Taabo firm output would require similar reductions. With these newratings, additional capacity is needed by 1990, even with the lower
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demand forecast. This criterion is perhaps too conservative in view ofthe size of loads such as air conditioning, which have been and couldagain be curtailed at little economic cost.
Revising Expansion Plans
3.30 Existing plans for developing more hydroelectric generatingcapacity are based on EdF's 1979 study of the Ivorian hydro potential. AHydro Master Plan for developing hydraulic resources was considered byEECI in 1981. It includes the commissioning of Soubre, Ndielesso,Malamasso, Daboitie and Louga, in that sequence. Under this scheme, thehydro system would consist of four cascades by the year 2000: Ayame 1 -Ayame 2, Ndielesso - Malamasso, Kossou - Taabo - Daboitie and Buyo -Soubre - Louga, each including a large reservoir and one or two down-stream plants operated in a coordinated fashion. The mission estimatedtentative commissioning dates for these projects, a firm energy balanceand the fuel requirements of existing thermal plants for the base case(Grey Scenario, Annex 3).
3.31 It is highly unlikely, however, that future hydro developmentwill follow this sequence for several reasons:
(a) Revisions in the projected electricity demand following thepower shortages will undoubtedly influence the timing of newadditions to capacity and thus affect the optimal hydrodevelopment sequence.
(b) The uncertainties surrounding the timing of the Soubre project.
(c) KECI's study of the Bandama River Basin and the proposedstudies of the Sassandra and Comoe Rivers may modify thefigures given in Table 3.7, and thus change the optimaldevelopment sequence for proposed hydro projects.
The new studies of lower Bandama sites completed by KECI, forinstance, indicate that although unit costs of energy (Table3.8) are not nearly as attractive as Laose of Soubre, Daboitieis clearly a candidate for earlier development than foreseen inthe Master Plan. Singrobo's proximity upstream would make it alogicaL next step in the expansion program, while camps,manpower and construction equipment used for Daboitie are stillin the area. After making the point that none of the othermajor inventory sites have been investigated to the same level,KECI suggest that Daboitie and Singrobo rank slightly ahead ofLouga on the lower Sassandra River and N'Dielesso on the ComoeRiver.
(d) Ranking of known hydro projects may also change because ofreevaluation of their primary energy potential, taking intoaccount the drought experience since 1971. Hydrometric records
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show that streamflows in the western part of the country aremuch less variable than in the central and eastern regions.Consequently, construction of new hydro plants, for example onthe Sassandra River, entails less risk of unpredictable, largereductions of energy output in dry years.
(e) With the recent addition of gas turbines and the new generationalternative which they provide in conjunction with natural gas,EECI may find it advantageous to delay any new hydro projectsuntil economically attractive gas-fired generation is absorbedin the system.
The Case for Gas Turbine Repowering
3.32 Thermoelectric requirements in the Grey Scenario, which appearsto be optimistic, average 850 CWh/year in the late 1980's and until 2005the discounted average is 700 CWh which is above the break eve point tojustify repowering Vridi 5-8 units into a combined cycle on t..C basis offuel savings alone. This addition would aLso contribute at least 300 GWhof firm energy at no additional fuel cost. This energy is absolutelynecessary to bridge the supply-demand gap between 1988 and 1990 which isthe earliest date for the commissioning of a new hydroelectric plant.Even for the lower demand variant the addition of a 45 MW heatingrecovery boiler and turbine can be justified as a precaution againstdelays in plant commissioning or the repetition of a prolonged drought.Hence it has been considered in the sequel as the best logical step ofsystem expansion.
Gas Based Alternatives
3.33 Since natural gas has the highest value as a substitute forpetroleum fuels at existing generating plants, conversion of Vridi .teamplants to dual firing and burning gas in the combustion turbines would bethe most obvious measure to reduce operating costs. Thermoelectricgeneration averages 700 GWh/year over the next 20 years with peaks of 7GWh/day broken down as follows:
Vridi 1-2 (Steam): 1.4 GWh (18 MMscfd)Vridi 3-4 (Steam): 2.6 GWh (32 MMscfd)Vridi 5-8 (G.T.): 2.1 GWh (27 MMscfd)
Heat recovery: 0.9 GWh
Limiting the maximum gas intake by EECI to 40 MMscfd would enable gasmeet abo:.t 75Z of fuel requirements corresponding to an average gasdemand of 16.7 MMscfd. Only Vridi 3-4 need be converted at a cost ofabout $1.6 million.
3.34 With the lower demand variant the thermoelectric requirementswould be smaller and more irregular, gas demand could drop to 8 MMscfd(or 6 MMscfd if a combined cycle is used instead of steam turbines).
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Alternat..vely, this demand could be raised by acceLerating thereplenishment of storage levels at Kossou.
3.35 New gas fired capacity (para 3.19) would displace temporarilythe energy of hydroelectric projects. The economic benefit of thissubstitution must be assessed on the basis of development sequences whichrecognize the time value of capital. This benefit is at best small ifgas dispLaces Soubrh, the cost of which is only 2.3 c/kWh; it is hardlyhigher if it displaces projects after Soubre because those would beneeded only after 1995.
3.36 This Low value market must be served last and only if theincremental production cost is sufficiently small. This is often thecase where the production plateau exceeds the absorprive capacity of theoil substitution market and depletion is still a remote prospect. InIvory Coast, with the projected plateau of 55 MMscfd, this excess supplyis never Less than 15 MMscfd until the year 2005 and its economic cost ismainly an accelerated utilization of reserves. At depletion date thevalue of reserves net of extraction costs does not exceed $5/GJ, whichonce discounted back to the early 1990s translates into less than$1/CJ. The gas availability and cost conditions are met for a secondcombined cycle unit to substitute for the next hydroelectric projectwhich could be commissioned about two years later when demand growth hascaught up with this new thermoelectric capacity. In these conditions,fuel requirements would be higher and more regular and gas could meet alarger share of them than when Vridi is just a back-up plant. Later ifadditional gas reserves are found, more thermal units could come onstream and substitute the more expensive hydro projects. Such anexpansion plan in the base case with Soubre in 1992 has been examined inAnnex 7.
3.37 Other considerations. The insertion of combined cycle unitsinto EECI's plan would add flexibility to them since lead times betweendecision and plant commissioning are at least two years shorter than forhydro projects, or better if gas turbines are installed first. If it isavailable and reEained, the gas option deserves to be developed to themaximum extent as shown above, and as soon as possible because EECI'sfuel requirements will be particularly high between now and the early1990s.
3.38 The interconnection with Burkina now contemplated by EECI con-sists only of feeding zones across the border with smaLl amounts ofenergy. The tie line with Chana cannot provide a significant guaranteeagainst low hydro generation during dry years, as that system isbasically hydro and the climatic conditions are roughly the same in bothcountries. However, the exchanges comtemplated by the two nationalutilities may prove profitable to both. In the gas based alternative, theIvory Coast could export some excess energy if it can secure flexibilityin the gas supply contract. A study for the interconnection of WesternAfrican countries is under way whereby this contribution would lose itsimportance in the lace 1990's as a broader interconnection wotLd tap
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thermal generation from Nigeria and the hydrological diversity of a largearea. However, setting up and bringing this interconnection into fulloperation will be a long process. Gas availability in the Ivory Coast asof today would increase the incentives to develop energy exchanges on thetie lines which already exist with neighboring countries.
Recommendations
3.39 EECI should study the optimal share of future hydro and thermalgeneration based on the prospect of gas availability. The missionrecommends the following strategy for developing new generation options:
(a) Current load forecasts should be reassessed.
(b) EECI should investigate the feasibility of dual firing by oiland gas at the existing steam units at Vridi. If the economicsare favorable, then conversion should proceed.
(c) A comprehensive study should be undertaken -t evaluate thetechnical and economic feasibility of additional thermalgeneration, includirg heat recovery units at the existing gasturbine plant at Vridi and dual fired steam or combined-cycleunits at a site west of Abidjan or any other favorable site.
Cd) Hydro inventory studies should be followed up with furtherinvestigations of the lower Sassandra and Comoe Rivers. Theeconomics of the most promising sites sho'ild be compared withthat of additional thermaL generation with the view ofdetermining the least cost power development sequence.
Ce) Long-term power planning should consider full utilization ofgas supply facilities once they are built, if additional gassupplies can be obtained at costs competitive with hydropower.
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IV. FUELIOOD MND OTHER BIOMASS SOURCES
Fuetwood
Overview
4.1 Fuelwood accounts for 85% of total household energy consumptionin n.ie Ivory Coast. Non-commercial firewood is gathered in rural areasas a free good, while in urban areas, commercial firewood and charcoal isproduced, distributed and marketed by informal monopolies. Most of thefuelwood consumed in the country, both commercial and non-commercial, isthe by-product of land clearings associated with agricultural expansion.Despite the importance of woody biomass energy for meeting basic sub-sistence energy needs, management of the country's forestry resources isoriented towards timoer exploitation and does not take into account fuelneeds. With no changes in forestry management, the effects of competingdemand for industrial timber and inefficient use of traditional sourcesis expected to cause fuelwood shortages in urban areas in the nearfuture.
4.2 Forest resources are being rapidly depleted due to the combinedeffects of over-exploitation of sources for timber extraction and landrequirements for agricultural expansion. At a deforestation rate of290,000 ha/yr, the combined total annual fuelwood productivity potential(on a _-_sLained yield basis) of the southern de nse forest zone 10/ andthe northern savanna zone will drop from 13.3 million m3 in 1980 to 8million m3 in 1985. 11/ The present land use system is the main cause ofthe depletion of the forest capital in both the production forest anddegraded forest areas. Many potentially productive areas are occupied bycommercial and subsistence agriculture; even classified forests are sub-ject to the uncontrolled encroachments of shifting cultivation. In thedense forest zone, only 2.6 mil_ion ha of the total 16 million ha isaccessible for timber production, compared with 12.4 million ha occupied
10/ This zone contained an even and continous forest formation andboasted 16 million ha of hardwood forest at the beginning of thecentury. Although i: is still called the dense forest zone, theinternal composition has changed dramatically due to timber extrac-tion, expansion of agricultural lands, forest fires, and land ten-u-e. Today, only about 3.3 million ha of the original productiveforest cover remains.
Ill Based on anny3al fuelwood productivity potential of 3 to 5 n3/ha and0.2 to 1.2 m /ha respectively. This figure actually underestimatesthe magnitude of the problem, since recent estimates of thedeforestation rate suggest that the figure is closer to 500,000ha/yr.
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by agriculture. Only 1.8 million ha of the savanna zone (total area 12.2million ha) is reserved for productive savanna forests.
Current and Projected Consumption
4.3 Due to the informal and non-commercial nature of most of thesubsector, statistics on fuelwood consumption and analyses of futuredemand vary considerably, Estimates of global fuelwood consumption rangefrom 6.5 to 10 million m /yr. In rural areas, exclusive use of firewoodis assumed 12/, although villages located near urban centers are begin-ning to use some of the c-harcoal produced for sale in nearby cities.Consumption within urban centers is characterized by interfuel substi-tution within single households. 13/ It was estimated that 20% of thetotal population in Abidjan will use firewood, 40% charcoal, with therest consuming electricity, kerosene and/or a combination of the fuelsavailable in the market place. In other urban centers, the estimatedproportions are 47% and 50%; however, these figures are thought tomisrepresent actual consumption in cities with high population densitiesin the surrounding regions, such as Korhogo and Bouake. The proportionof wood to charcoal consumption varies significantly from city to city,and is estimated as 30/70 in Abidjan, 60/40 in Bouake, and 15/85 inKorhogo. Average Ser capita consumption among fuelwood users isestimated at 0.8 m /yr and 1.4 m /yr for firewooe and charcoal,respectively. Actual consumption patterns are very site specific andwill depend on many factors. 14/ Projected fuelwood demand by region,assuming no changes in fuel consumption patterns, is shown in Annex 8.
4.4 The urban informal sector and many small- and medium-sizedindustries also use fuelwood as a primary fuel. 15/ Data for theseconsumers is not currently available, but it should not be difficult tocollect from the industries. It will be far more complicated to estimate
12/ For both cooking and lighting, even in electrified areas. Familygatherings about the light of the three stone stove provide tradi-tional social forums.
13/ LPG is the alternative fuel most often chosen for cooking. In manycases, households will use both LPG and charcoal cookers. No infor-mation is available to quantify the extent of this practice, nor theextent of interfuel substitution in general.
14/ Especially the size and distribution of the population. In ruralareas, wood availability, settlement density, family size, dietpatterns, size of landholdings, and stove type for cooking are themajor factors for determining demand.
15/ The informa' sector consumers include fish-smoking and roadsidestalls. Sma'll- and medium-sized industries using fuelwood areceramics, bakeries, and blacksmiths.
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the fuelwood volume currently used by the informal sector. FAO estimateson fuelwood consumption by the informal sector in tropical Africa are 20Zto 40Z of domestic fuelwood consumption.
Potential Fuelwood Supply Sources
4.5 Rural Areas. Fuelwood supply in rural areas is generated as aby-product of shifting cultivation. The availability of pr sent andfuture supply sources will depend on the area of fallow land availablefor fuelwood production and the requirements of competing land uses ineach region. In order to satisfy rural demand, sources must be withinwalking distance and should have a sustained production rate capable ofsupporting the existing and future population density. Table 4.1 showsthe annual fuelwood productivity potential of fallow land which ispresently unoccupied.
4.6 The Korhogo province represents a special problem in fuelwoodLvailablity. Although the region is generally sparsely populated, about100p000 ha in the center known as the "Korhogo dense zone" has a highlyconcentrated rural population. The demographic pressures on the regionhave gradually degraded nearby forest stock. As a resul., the pro-ductivity level of remaining natural vegetation now falls far below thefuelwood requirements for local consumption and competing needs for char-coal production to meet demand in nearby Korhogo city. In addition, muchof the remaining natural vegetation is concentrated in "sacred forests"which cannot be exploited for cultural reasons. The villagers are nowchopping down trees formerly reserved for food production (mango, karite)to use as fuel. Although the case in the Korhogo province is extreme, itis exactly this Lype of situation which must be anticipated and addressedin the planning and management of rural fuelwood sources.
Table 4.1: POTENTIAL FUELWOOD SUPPLY SOURCES FOR RURAL POPULATIONS
Total Occupied Fallow Ecol. Annual Vol.Region Area Area a/ Land Zone Produced b/
--- (million ha) -- - (million m3)
South 4.7 2.3 2.4 forest 1.84Southwest and West 6.5 3.2 3.3 forest/ 2.29
savannaCentral, Central 14.7 6.8 7.9 forest/ 3.71West, and East savanna
North 6.0 1.8 4.2 savanna/ 1.71forest
a/ Occupied areas include classified forests, agro-industrial crops,parks and reserves, urban areas, and infrastructure. 3
b/ Productivity rate for dense forest fallow land: 0.75 m3ha/yr.Productivity rate for savanna fallow land: 0.4 m3/ha/yr. Due tosoil degradation from shifting cultivation, productivity rates willnot be constant over all years. Figures used here provideindicative estimates.
Source: Mission estimates.
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4.7 Urban Areas. Commercial firewood and charcoal for urban use isgenerally produced in degraded forests located close to urban centers.Most of the forest land surrounding urban ceaters have been stripped oftheir wood resources and alternative sources are needed to meet the grow-ing demand for charcoal and fuelwood on a sustained basis. Wood wastescurrently generated by industrial agricultural operations and ongoingforestry operations have been identified as major potential sourcesappropriate for c 3mmercial fuel consumption. 16/ Depending on theregion, 10 to 40 m /ha could be recovered from agro-industrial clearingsfor fuelwood production. The volume of fuelwood from this source willultimately depend on the productivity of the present plantation systemand the expansion of internal markets. The total potential fuelwoodproductivity of these sources is given in Table 4.2.
Table 4.2: VOLUMES OF POTENTIAL FUELWOOD SOURCES BY REGION(in thousand m3)
1985 1990 2000
So,ch and Abidjan 1079 1833 876South West 1300 1300 338Central West 728 728 429Central 610 610 373North 245 245 245East 71 71 54West 1141 1141 204
Source: Annex 9.
4.8 The major potential fuelwood sources from ongoing forestryoperations include logging wastes from natural forest exploitation, land-clearings ane thinnings from Sodefor operations. The actual availabilityof these sources is directly related to the long term outlook of the tim-ber industry. The Government's stated polIcy is to maintain the currenttimber extraction level of 4 million m /yr because of the need forforeign exchange earliings. With annual sustained forest productivity atonly 1.65 million m /yr, this extraction level depletes forest reservesmuch more rapidly than they can be replaced. Recognizing the problem,the Government initiated reafforestation progra;ms in the five year devel-opment plans for 1976-1980 and 1981-1985. Initial planned
16/ Exploitation of these sources will require investment, planning andGovernmelt supervision, as well as the participation of the privatesector for distribution and marketing. This limits their economicviabili y to commercial markets.
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reafforestation rates of 10,000 ha/yr have been reduced to 5,000 ha/yrdue to insufficient managerial and financial resources. Continuation ofthe current reafforestation rate will depend on external financing whichis currently being negotiated. If the Government maintains currenttimber extraction rates, the natural dense forest is not protected, andthe rate of reaff 9restation is not increased, forest production will dropto only 500,000 m /yr by the end of the decade.
Supply/Demand Balance
4.9 Table 4.3 merges the demand and supply projections to showpotential shortages/surplus on a regional basis if current practices forusing and replenishing the forest resources are continued. Since fuel-wood supply sources are site specific, there may be shortages within theregions even when surpluses exist countrywide. Urban areas and theirsurrounding rural populations are expected to experience the most diffi-culties in finding adequate supplies to meet demand. Available surplusesin rural areas cannot be counted on to offset shortages in other regionsdue to very high collection and transport costs, and the absence of awell-organized, efficient charcoal production system.
Table 4.3: PROJECTED SUPPLYIDEMAND BALANCE(in thousand my)
Urban Populations Rural PopulationsRegion 1985 1990 2000 1985 1990 2000
Abidjan and SouthSupply 1709 1833 876 1840 1840 1840Demand 2395 3509 6805 1114 1224 1450Balance -686 -1676 -5929 726 616 390
Central, Central-West, and EastSupply 1409 1409 856 3645 3645 3645Demand 1299 1751 2911 2072 2178 2376Balance 110 -342 -2055 1573 1467 1269
West and South WestSupply 2441 2441 542 2269 2269 2269Demand 349 484 865 691 720 774Balance 2092 1957 -323 1578 1549 1495
NorthSupply 245 245 245 1706 1706 1706Demand 203 266 417 415 414 410Balance 42 -21 -172 1291 1292 1296
TOTALSupply 5804 5928 2519 9460 9460 9460Demand 4246 6010 10998 4292 4536 5010Balance 1558 -82 -8479 5168 4924 4450
Source: Mission estimates.
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Policy Strategy for Closing Supply/Demand Gaps
4.10 Rational Management of Forest Reserves. Future shortages canbe avoided if appropriate planning and management policies are imple-mented in the interim. Due to the informal and non-commercial natare ofmost of the sector, the Government sill not be able to directly controlthe actual demand for fuelwood. 1-/ Instead, Government actions willhave to be directed to ensuring that adequate supply sources exist tomeet current and future fuel needs.
4.11 Recommendation. The basis for Government action must come froman integrated forest management policy which will ensure that objectivesfor commercial timber exploitation and the fuel needs of urban and ruralpopulations can be met without depleting remaining classified and produc-tive forests reserves. Strategies which can help achieve this balanceinclude:
(a) Improve natural forest productivity by replacing undesirablespecies with others of higher commercial value, while graduallydecreasing current levels of over-exploitation.
(b) Develop incentives to encourage private sector participation inestablishing and working fast-growing plantations for timberand fuel.
(c) Promote increased utilization of secondary species forcommercial timber to be processed in the country to supply partof the internal market.
(d) Improve forestry extension programs to teach forest protectionto rural populations and promote increased use of potentialwoody biomass wastes which ale currently being destroyed, 18/by (i) providing increased technical assistance for agro-forestry techniques, and (i-) integrating forest resourceconservation and protection methods into settlement programs
17/ This would normally be done through the pricing system, which doesnot apply to rural fuelwood use. Control of charcoal prices inurban areas may be possible, however. Indirectly, the Go-ernmentcan influence demand by increasing end-use efficiencies through thepromotion of improved stove designs and by encouraging interfuelsubstitution (kerosene, animal and vegetable wastes). See para.4.22-4.23 and para. 5.32-5.36.
18/ Of the 23 million m3 /yr destroyed by agricultural expansion, onlyabout 7 million m3 are used as fuelwood. The rest is burned on siteto free the land for planting. Thus, up to 16 million m /yr of po-tentiai woody biomass supply are lost because of inefficient fuel-wood conversion and distribution methods.
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and landuse patterns; and (iii) coordinating agriculturalexpansion drives with charcoal production.
4.12 Lack of Information. Strategies for rational resource manage-ment can be developed only if more is known about both demand patternsand the extent of remaining resources. The current estimates for supplyand demand are limited and outdated. Exiscing statistics must be updatedand resource availability further quantified by taking into accountpotential alternative sources. Given the site specific and seasonalnature of both demand patterns and supply sources, information should becollected on a regional and seasonal basis so that the develop-Ai policiesare appropriate for each region.
4.13 Recommendation. As a first step towards implementing azycomprehensive fuelwood policy, the Government shouLd conduct two surveys:
(a) National Forest Inventory to provide basic data on the precisearea and internal composition of the production forests, in-cluding: species; volume of each species based on diameterclass; volume of each species based on comercial timber volumepresently or potentially exploited; specific location andvolume of potentially exploitable fuelwood. Aerial photo-graphy, which would provide an overview of the entire forestcover, could be used to complement the detailed inventories.Data should be updated on a regularly scheduled basis.
(b) Localized Surveys of Woody Biomass Sources and ConsumptionTrends. Initial reconnaissance surveys must be carried outquickly to assess potential woody biomass supply sources andconsumption trends and clearly determine the supply/demandbalance in high-density population centers where there arecurrently signs of imbalance and those areas for which short-ages have been projected. 3oth rural and urban centers shouldbe included in this study. The regions surrounding Abidjan,Bouake and Korhogo deserve immediate attention because ofobserved shortages and the uncertainties concerning charcoalconsumption and use in the densely populated rural areas sur-rounding these cities.
4.14 Data collected in regional surveys of these and other areasshould include: (a) Distribution and area of all woody biomass sourceswithin a radius of 300 km from the major urban towns; (b) Land tenureand land use patterns, including areas of crop farms and range lands nowin use, and required area for future agriculture needs. Data should becollected throughout the year to identify possible seasonal trends.
4.15 Integrated Policy. Competing land uses must be considered inany strategy for rational forest resource use. Land which is currentlyavailable for fuelwood production may be needed in the future for foodcrop production. Neither agricultural policy nor forestry policy isdesigned to address the issue of fuelwood production and supply, northeir effect on the ecological balance of the forest reserve.
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4.16 Recommendation. A compromise land use system is needed whichwill conserve the essential protective features of the forest while atthe same time producing adequnte quantities of food and fuelwood tosustain the land users; food and fuel production should be complementaryrather than mutually exclusive. To this end, agro-forestry planning andimplementation should be integrated into regional rural developmentprograms as a matter of overall energy policy.
4.17 Regional Planning. The Ivorian forest reserves are owned bythe State and centrally managed by the Forest Service. Local authoritiesand communities have limitLd, if any, participation in the decision-making process regarding provincial forest exploitation and the reinvest-ment of revenue for improving the regional infrastructure. Thus deci-sions for exploiting and maintaining forests often do not take intoaccount the environmental and economic concerns particular to eachregion.
4.18 An outgrowth of centralized administration is stumpage valuesfor timber exploitation that do not reflect the production costs ofmanaging forest on a sustained basis. Contractors are charged cuttingfees which do not reflect production costs. As a result, there is noincentive to avoid waste; contractors selectively cut only a small partof the best standing timber and logging operations shift quickly from onesite to another. The lo, cutting fees have a long term effect on fuel-wood proauction costs because it induces resource mismanagement andfuelwood scarcity on a local/regional basis.
4.19 Recommendations. The utilization of forest resources should bebased on the management of timber exploitation on a regional basis. Thiswould permit integrated recovery of logging wastes for charcoal andfuelwood production. Specifically, the Government should:
(a) Create a strong and competent planning unit within the ForestryService to provide the basic operational guidelines for timberand fuelwood exploitation in each region. The unit will workin close liaison with the survey and inventory unit.
(b) Grant more financial and technical autonomy and ilexibility toregional forestry offices. Regional offices should be respons-ible for granting timber exploitation concessions, issuingfuelvood cutting licenses (logging wastes and species not usedfor timber) and collecting cutting fees. The fees charged bythe regional offices should be increased considerably to re-flect actual stumpage values. Control of licenses granted onthe regional level should remain centralized.
Short-Term Issues and Options
4.20 Supply Shortages in Korhogo Province. Immediate action must betaken before the problem in the Korhogo province worsens, to be supple-mented later with policy changes which integrate 'and tenure and rural
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agricultural practices with forest protection and conservation. Theshort-term strategies recommended for the Korhogo dense zone are:
(a) Establish a regional industrial energy plantation to meetdemand for commercial energy in the adjacent urban center,where resource requirements for charcoal production competeswith the limited resources for local use.
(b) Establish woodlots and provide trees for planting for the ruralpopulation.
4.21 Similar problems may appear in other densely populated ruralareas near large cities, in particular areas surrounding Abidjan andBouake. These areas should be given first priority in the surveys ofconsumption trends and biomass sources so that shortages are identifiedand appropriate strategies can be implemented. Alternatives to enhanceurban fuelwood supply, as discussed below, must be integrated with policyfor managing the rural sources in the surrounding regions.
4.22 Energy Efficiency of Cooking Stoves. Almost no effort has beenmade to promote the use of energy-efficient wood and charcoal stoves inthe Ivory Coast. Expenditures on commercial cooking fuel account for 8to 17% of average annual household income, thus making cash savings astrong incentive for stove purchase. With improvements in stove fuelconsumption, expenditures on cooking fuels can be decreased by about 30%and 20Z for wood and charcoal stoves respectively. Assuming an average30% savings for 25% of the charcoal-using households in Abidjan, 8,500tons of charcoal would be saved (630 million CFAF). This represents anannual turnover of 90 million CFAF for the stove market. 19/ ThusGovernment programs to promote improved stoves will not only decreasehousehold energy expenditures and indirectly decrease the drawdown ofwood supplies, but it can also generate urban employment.
4.23 Recommendations. A program to promote improved wood andcharcoal stoves iieeds to be formulated and vigorously supported.Elements for mounting a sucessful stove dissemination program appear tobe presenit. Potential improvements on the charcoal stove model currentlybeing soid have already been applied sucessfully to similar models inother African countries. What is needed is:
(a) Establishment of an entity to coordinate and monitor thediffusion program; training and extension leading to thecreation of a production and marketing net:rork; publicitycampaign;
19/ Assuming annual production of 45,000 stoves to cover 25Z of thehouseholds using charcoa'. Savings and production turnover increaseproportionally with the percentage of households reached.
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(b) Large-scale dissemination; monitoring of user responses andactual charcoal savings; assessment of long-term economicviability as a small industry activity; evaluation of programbenefits, constraints, possibilities for expansion or replica-tion elsewhere in the country, and further investment require-ments.
Terms of reference for this program are given in Annex 10.
4.24 Charcoal in Abidjan. The supply and demand balance for char-coal in Abidjan presents several short-term difficulties. 20/ Charcoalproduction and distrib-ti'or. is presently controlled by a tightly knitgroup of Malians, VoLL 4cs and, to a minor extent, Ivorians from theextreme north. The prr'ucers often act as both wholesaler and retailer,hiring the team to cut the wood and produce the charcoal, then trans-porting it to Abidjan, where they control over 90% of the market. Theyhave almost full control over charcoal prices and are highly flexible inadapting to changing market conditions. Thus, attempts in industrialcharcoal preductiun for residential consumption were unable to competewith this monopoly.
4.25 The charcoal market is highly irrational, as is evident fromthe variability and long-term trend in charcoal prices. Supplies arerestricted and prices increase 30 to 50% during the rainy season. Thereis almost no control on the quality of charcoal and, because sale is on avolume rather than on a weight basis, cheatng is rampant. Based onavailable data, charcoal prices have grown at an average annual rate of10%, and are almost double the production costs. As traditional woodsupplies for charcoal manufacture are exhausted 21/, higher transportcosts and anomalous pricing practices will contribute to sharp andunpredictable escalations in charcoal prices in the medium term,particularly in Abidjan.
4.26 Alternative sources of wood for charcoal production includewastes from agro-industrial clearings, loggin.3 wastes from natural forestexploitation, wastes from Sodefor clearing/thinning operdtions, and saw-mill wastes. Wastes from agro-industrial clearings and from naturalforest exploitation are highly variable; the availability of projected
20/ Except for the northern savanna regions where localized shortages inurban areas such, as Korhogo, are already being felt, there is as ofyet no generalized shortage in cha:coal supplies.
21/ Charcoal supplies come from two major sozr-es: 25Z from sawmillwastes and 75Z from rural forest domain, mostly in conjunction withsmallholder agricultural clearing. Potential supply sources in theAbidjan region are highly degraded or have been clained by agricul-ture; supplies now come from a distance range of 150 to 200 km fromthe capital, as compared to around 50 km in the mid-1970s.
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fuelwood volumes from these sources depends on future plans for agricul-tural expansion and the continuation of Government policies for timberproduction. Surplus sawmill wastes and wastes from Sodefor operationsare the most promising alternatives.
4.27 Theoretically, approximately 25,000 tons of charcoal can beproduced from the total amount of surplus sawmill wastes. 22/ Inpractice, about half this amount can be economically produced and dis-tributed. Only sawmills which are both contiguous to the Dimbroko rail-way stop and have a good long-term roundwood supply can be realisticallyconsidered as potential sources. Transportation costs to Abidjan are toohigh to justify transport other than rail, and the sawmill must be ableto guarantee a reliable supply of wood waste. Diverting bulk wastes fromcurrent uses in woodworking cottage industries could provide additionalsupplies, but the opportunity costs in terms of lost rural employment maybe significant.
4.28 Sodefor clearings and thinnings are a larger potential source,but recovering the wood for charcoaling presents more problems. Sodeformust have 85 to 90Z of the replanting area cleared and de-stumped withinthe year prior to planting; thus charcoal production must take placewithin the time limits of Sodefor's operations. Sodefor could install astationary industrial charcoal unit. However, the unit would generallyoperate at low capacity 23/, and transport costs for wood from dispersedsites could be prohibitive. 24/ Transportation costs may prove to be anobstacle to using Sodefor wastes in any case, as some of the reaffores-tation sites are over 200 km from Abidjan and even sites within a 120 to150 km radius may not be easily accessible.
4.29 The most practical option will be to integrate the system forproducing charcoal from its wastes with the existing network of artisanalcharcoal producers, while providing them with more efficient kilns.Improving charcoal conversion technology is crucial if the artisanal
22/ The amount of sawnill wates generated and alternative uses for thesewastes are discussed further in the second half of this chapterunder the heading "Sawmill Wastes".
23/ The unit w3uld have to be oversized to process the large volumes ofwood available during clearing operations (only about 5 sites/year).Smaller volumes of wood from numerous a±spersed sites would have tobe processed during thinning phases.
24/ The delivered price of charcoal may be affected by the cost oftransport by truck from clearing/thinning site to the nearestrailway stop for delivery to the conversion unit, depending on theconditions of access Lo the site.
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producers are to work within the time frame for Sodefor' s operations.25/ Criteria for selecting a particular conversion method should includeimproved conversion efficiency, cost, local availability of materials,training requirements for improving charcoal production techniques, andincentives for adopting the new method. The Casamance kiln, originallydeveloped in Senegal, should be investigated; it offers significantimprovements over traditional methods at much lower costs per productionunit than transportable metal kilns. 26/ The Argentine and Brazilianbrick kilns should also be investigated.
4.30 Charcoal from new and alternative sources will not be able tocompete with the existing informal network unless the market is rational-ized. It will be difficult to motivate private sector participationunless there are guarantees that gross price undercutting by itinerantproducers and retailers will not occur. New producers also do not wantto become involved in the retail market. Since it is impossible todismantle or displace the eacisting network, new and existing producersshould be integrated into an organized production system featuringofficially monitored charcoal retail prices. For new producers such assawmills and Sodefor, a profitable operation that permits waste disposalat the same time should be a sufficient incentive. For the informalsector, however, a mix of incentives are required: (a) higher producti-vity through the use of more efficient kilns; (b) guaranteed wood supplysources at acceptable exploitation fees; (c) the possibility of purchas-ing charcoal wholesale from sawmills and Sodefor; and (d) an organizeddelivery system, including assured transport means and links with offi-cially recognized wholesalers and retailers. The latter implies soneform of co-operative that would register and issue permits among charcoalproducers, wholesalers and retailers. As wood supply sources at economicdistances become exhausted, it should become easier to interest currentproducers to integrate themselves within an organized market drawing frommore reliable wood sources.
4.31 The possibility of producing charcoal in the Ivory Coast forexport to Upper Volta has been the subject of previous studies 27/ whichindicate that it is a profitable option; however, it should be consideredwith great caution. Production and distribution of exported charcoalmust be a highly organized commercial activity. The only possible wood
25/ It is uncertain if the network, operating in limited numbers withlimications on the size of individual kilns, will be able to absorball the wood, as welL as de-stump, condition the wood and producecharcoal at the pace required by Sodefor operations.
26/ 1980 data on charcoal production costs for applications in Cameroonwere only two-thirds the costs using earthen kilns.
27/ Based on 1980 and 1983 data for delivered cost and retail prices inOuagadougou.
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sources in this case are sawmills and Sodefor sites. Exports will effec-tively remove the two major sources of incremental supply for domesticconsumption and tight control of the Abidjan market by current producersand retailers will be reinforced. Export promotion may precipitatefurther incursions into forest reserves by itinerant producers, whichcould be catastrophic if producers concentrate on the northern savannaregions in order to minimize transport costs to Ouagadougou. In sum,priority should be given to meeting projected gaps in domestic charcoaldemand before export markets are tapped. 28/
Recommendation
4.32 The charcoal issue in the Ivory Coast is not simply that ofincreasing supplies. It is a complex question of selecting the mosteconomic supply sources given the opportunity costs of wood wastes,promoting the most appropriate conversion technology, rationalizing themarket and setting up an effective delivery system.
4.33 A survey of charcoal consumption in Abidjan should be conductedin addition to the regional survey recommended for establishing fuelwoodutilization policy. The survey should investigate: (a) current charcoalsources, and priority future ones; (b) status and outlook of the woodresource for charcoal production; (c) entities involved in production,transport, wholesale and retail; (d) components and past trends in theproduction costs and retail prices; (e) profile of charcoal users; and(f) demand elasticities for alternative energy products for cooking andrate of interfuel substitution.
4.34 This data is a prerequisite for assessing the scope for,requirements of and constraints to rationalization of the charcoal mar-ket. This will be a difficult task; considerable attention must be givento the practicability of concrete measures recommended, particularlythose concerning enforcement.
4.35 Appropriate charcoal conversion technologies should be definedfor each category of producers: industrial scale (sawmills, Sodefor);corganized rural cooperatives; and improved artisanal production, eitherpermanent or itinerant. Technical and economic performance data shouldbe obtained through pilot installations. It is recommended :hat a woodenergy expert be appointed at tl'e CTFT to manage this work.
28/ Charcoal exports might be considered based on logging wastes, but asit stands, local capacity is unable to absorb and manage the moreeasily accessible sawmill and Sodefor sources.
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Other !iomass Sources
Overview
4.36 The agro-industries and the wood transformation industry 291generated an estimated 500,000 TOE of biomass residues in 1980 (Table4.5). Agro-industries alone annually produce around 340,000 TOE (roughlyover 1 million tons) of biomass wastes. Over 40% of this amount isutilized in the originating planLs, thus making them nearly or completelyautonomous in meeting their process steam and power requirements. Of thebalance, about 150,000 TOE of palm oil and coffee residues (44% of thetotal agro-industrial waste resource) appear to be of economic inter-est; up to 94 GWh/yr of surplus power could be generated in palm oilextraction plants and diesel-based power and process steam generation inthe coffee industry could be displaced. Structural problems in the sugarindustry preclude the exploitation of bagasse beyond the captive require-ments of the sugar mills up to the medium term. Sawmills annually pro-duce an estimated 160,000 TOE of wood wastes, of which around 70% isalready utilized for process steam and power generation, charcoal pro-duction and manufacture of small wood products. Economic and technicalconstraints limit further exploitation of wood wastes as an energy sourcefor in-plant use in many sawmills; however, some mills may be able toexploit wood wastes for charcoal production.
Agro-Industrial Residues
Palm Oil Wastes
4.37 Supply. Nearly all of the wastes from the Ivory Coast's annualproduction of about 150,000 tons of unrefined palm oil is generated byPALMINDUSTRIE. This government-owned corporation manages 85% of theindustrial oil palm plantations, accounting for 65% of total plantedarea. It also owns 12 of the 15 palm oil extraction plants and accountsfor over 90% of total processing capacity. PALMINDUSTRIE processes anaverage of 700,000 tons of fruit bunch (TFB) per year, over 50% duringthe peak months from January to March, although plants are in operation
291 Refers only to sawmill wastes. Other wood wastes from logging andshifting cultivation were treated in the previous section.
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throughout the year. Based on the mass balance, 30/ solid wastes accountfor around 56% of total TFB processed, in the following proportions:stem, 182,000 tons; fiber, 154,000 tons; palm nut shell, 38,500 tons; anddebris, 17,500 tons.
Table 4.5: BIOMASS RESIDUES a/
PresentlySource Residue Total Utilized b/ Balance
--- in 103 TOE(Z in brackets) c/ -
Agro-industries
Coffee husk, parchment 107 9 (8) 98 (92)Oil Palm stem, fiber, shell 84 30 (36) 54 (64)Sugar Cane bagasse, molasses 110 58 (53) 52 (97)d/Cotton cotton gin waste 13 13 (100) nilCoconut husk, shell, trunk 5 3 (60)e/ 2 (40)e/Cocoa bean shell f/ 4 3 (73) 1 (25)Others 15 nil 15 (100)
Sawmills bark, shavings,offcuts, sawdust 162 118 (73) 44 (27)
Total 500 234 266
a/ 1980 data.h/ Both for energy and non-energy purposes.c/ Percentages are summed horizontally.d/ Mostly molasses.eI Around 50 Z used as boiler fuel. Unknown quantities used for char-
coal-making and fish-drying.f/ As distinguished from cocoa pods, which are hard to valorize for
energy uses due to the high moisture content (wet basis) of 70 to80%.
Source: Conseil de l'Entente.
30/ PALMINDUSTRIE provides the following mass balance (Z): (a) Products- oil palm, 20; oil palm nut, 5; (b) Solid Wastes - stem, 26; fiber,22; palm nut shell, 6; debris, 2.5; (c) Moisture Content (wet basis)of stem, fiber and shell are 63%, 40% and 6% respectively. On a drybasis, the mass balance of components other than products are asfollows: (a) Solid Wastes - stem, 10; fiber, 13; shell, 5; debris,2.5; (b) others, 44.5. The conseil de 1'Entente report (8) confirmsthese figures.
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4.38 Current Use. All Ivorian palm oil extraction plants have theirown power and process steam cogeneration systems. PALMINDUSTRIE's plantsare entirely independent of the EECI grid, with total installed biomass-based electricity generating capacity of 9,900 kVA. Specific consumptionper TFB is 15 to 20 kWh of electricity and 450 to 490 kg steam.PALMINDUSTRIE's total electricity consumption for the processing plantsalone varies from 11 to 14 GWh/yr. Assuming a 10 overall conversionefficiency, about 12,000 TOE of fiber and debris are used to meet themaximum level of electricity demand. On average, plants are in operation8 hours/day, up to 20 hours/day during the peak season. Total annualoperating time is about 1600 hours (20% utilization factor) based ontotal processing capacity of 420 TFB/hour. 31/ Diesel generatingcapacity of 4,800 kVA is used for electricity needs in workers' quartersat night when plants are not operating.
4.39 Unused Energy Potential. Significant amounts of energy in bio-mass wastes from PALMINDUSTRIE's operations are not utilized. The totalenergy content from all wastes available at plant sites is presented inTable 4.6. Assuming use of only 12,000 TOE, as cited above, over 87% ofthe total energy potential of the wastes is unutilized. 32/ If potas-sium-rich stem waste is excluded due to its alternative use as a ferti-lizer source 33/ and difficulties in pre-drying, 81% of the total fiber,debris and shell wastes (50,500 TOE) remain unutilized.
4.40 The unexploited fiber, debris and shell residues represent asignificant electricity generation potential, up to 59 GWh in surpluspower (beyond plant needs) (Table 4.7). With prior drying and condi-tioning, stem wastes could add an additional 35 GWh/yr, for a totalsurplus of 94 GWh/yr. This surplus electricity could displace the pre-sent diesel units by meeting the power requirements in workers' quarters;any excess power could then be sold to the EECI grid.
31/ The 12 plants comprise 8 plants of 40 TFB/hr, 2 plants of 30 TFB/hrand 2 plants of 20 TFB/hr.
32/ Refers essentially to fiber, since debris accounts for only 2.5X ofthe mass balance. On a mass basis and given NHV = 2,620 kcal/kg Q40% MC, around 30,600 tons of fiber wastes are used, or 202 of the154,000 tons available.
33/ Incineration of stem wastes and recuperation of ashes can providearound 15 to 20% of annual potassium requirements in industrial palmoil plantations.
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Table 4.6: ENERGY FROM PALM OIL RESIDUES a/
Net Heating Moisture ContentResidues Value b/ (wet basis) TOE/yr
(kcal/kg) (Z) (1,000)
Fiber 2,620 40 40.3Debris 3,900 15 6.8Palm Nut Shell 3,990 15 15.4Stem 3,450 20 cl 30.2 c/
Total 92.7
a/ 1983 data.b/ From the empirical formula provided by David Tillman, in Wood as an
EnergMy Resource:NsV = uHV - (0.0114 x HHV x mcwb)
where NHV, net heating value; HHV, higher heating value; and mcwb,moisture content (wet basis). HHVs are as follows (kcal/kg):fiber, 4,830; debris, 3,990; palm nut shell, 3,990; stem, 4,550.
c/ Assumes the use of exit steam for pre-drying. Otherwise, NHV =1,084 kcal/kg at 63 Z MC without pre-drying. At 20 Z MC, 87,500tons of stem wastes are available.
Source: PALMINDUSTRIE.
Table 4.7: SURPLUS POWER FROM PALM OIL RESIDUES
In-Plant Surplus,Options Requirements Power al Total
-GWh/year------------
Current Practice 14 0 14
In Global Thermal Resource Termsfiber, debris, shell 14 59 73fiber, debris, shell, stem 14 94 108
In Plant Capacity Terms b/use idle capacity 14 41 55install additional generating capaci5 y:(i) fiber, debris and shell u37d c 14 59 73(ii) all 4 waste sources used - 14 94 108
a/ Of which 7 GWh/year would displace the current practice of dieselgeneration for electricity needs of workers' residences at nightwhen plants are shut down.
b/ Utilization factor increased to 6,500 hours/year.c/ 3,300 kVA additional capacity required.d/ 9,600 kVA additional capacity required.
Source: Mission estimates.
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4.41 Development Options. There are two major options for tappingthe generation potential: use idle capacity to consume half of theavailable wastes or install additional capacity to consume all availablewastes. Using idle capacity would provide an additional 41 GWh/yr ofsurplus power and results in almost full use of fiber and debris; butPALMINDUSTRIE will have to invest in new facilities to pre-dry, condition(including briquetting), and store residues for use during the off-peakseason. To use all fiber, debris and shell residues, 3,300 kVA of addi-tional generating capacity is needed. If the stem wastes are used also,a total of 94 GWh/yr of surplus power can be produced, but additionalcapacity of around 9,600 kVA would be needed. Investments for thisoption include installation of between 275 and 800 kVA in each of the 12plants, as well as briquetting and storage systems due to increasedutilization factors.
4.42 Apart from the revenues from selling surplus power, the othermain benefit of these power generation options to PALMINDUSTRIE is dis-placement of the 2200 tons/yr of DDO used in diesel generators 34/ At1984 prices, this is a savings of CFAF 350 million annually. Sale of thediesel generators themselves could provide additional revenues, althoughthese should probably be retained as back-up capacity. Other importantbenefits include: (a) minimizing thermal stress damage to boilers causedby frequent shutdowns at current utilization factors 35/; an-!(b) decreasing environmental pollution from undisposed wastes.
4.43 Options other than power generation include briquetting thesolid wastes and selling them as fuel to (a) a central power station,(b) sawmills and other industries, and (c) households for cookingfuels. Liquid effluents, which are now a major pollution source, canalso be used for methane generation. Transportation costs and entrenchedconsumer preference 36/ will likely be major obstacles for the powerstation and cooking fuel options respectively. On the other hand, saleof briquetted wastes to sawmills and other industries, if it can beproven technic.Lly and economically viable, is an interesting possibilityand is discussed in the following section.
34/ Based on usage rates of 200 tons DDO/yr for each of the eight 40TFB/hr plants, and 150 tons DDO/yr for each of the four othersmaller plants.
35/ All orifices are closed when the furnaces are turned off in order tominimize large temperature drops, which can be highly damaging toboilers, prior to re-firing the following day.
36/ To date, there has been no successful experience in traditional fuelsubstitution with briquettes; consumer preference for fuelwood andcharcoal, even in urban areas, remains very strong.
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4.44 Any action taken to exploit the energy potential of PALM-INDUSTRIE's wastes must take into account the medium-term outlook for theproduction of palm oil, which will affect the amount of wastes avail-able. Peak production should be reached with the existing industrialcrop within the next five years 37/, and afterwards should declinerapidly, even at current replantation rates. Village plantations, whichaccount for the balance of palm oil production, cannot be expected tofill the gap, as their crop is generally allowed to grow taller than isdesired, increasing harvest losses.
4.45 Recommendations. A pre-investment study is recommended toestablish the economic and technical viability of the power generationoptions. The study should:
(a) Analyze the impact of predicted decreases in palm oilplantation productivity over time on the waste resource supply,surplus generation prospects, and cost recovery.
(b) Determine for the 11 unconnected plants the costs of: (i) con-necting to the EECI grid, (ii) conditioning and storing resi-dues, (iii) additional labor and maintenance, (iv) boilerefficiency improvements 38/ necessary for surplus powergeneration, and (v) additional generating capacity. When con-nection and briquetting/storage costs are added to the cost ofadditional generating capacity, the option of adding new capa-city may no longer be economically feasible.
(c) Determine the technical feasibility of gasification of palm oilwastes under Ivorian conditions. Given the required additionalcapacity in each plant (275 to 800 kVA), experience suggeststhat biomass gasification is more economical than directcombustion. Cost is estimated at US $5 to 15 million (fortotal 3,300 kVA and 9,600 kVa respectively) for the biomassgasifier components alone. 39/ Local experience with biomassgasifiers includes a project mounted by I2T, now in operation
- for four years, in which two 300 m3/hr gasifiers using coconuthusks, with a moisture content of up to 60%, generate producer
37/ The existing crop was planted 15 to 20 years ago. Peak productionoccurs when the crop is between 12 and 18 years of age.
38/ Boiler efficiencies are presently around 60 to 65% due toinsufficient heat transfer and inadequate regulation of airintake. Around 10 to 15% improvement in efficient can be achievedby reducing exhaust temperatures and excess air.
39/ Based on European gasifier systems or small-scale package steamelectric plants at around US$1,500/kVa. Local fabrication ofcertain components can decrease these costs significantly.
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gas as fuel for a fluidized dryer and a 150 kW electricgenerator in the Coprah factory at Assinie. This technologyshould be further developed and adapted to use Palmindustrie'spalm oil residues.
(d) Determine if the selling price for PALMINDUSTRIE that willrecover the costs of producing surplus electricity can competewith EECI's marginal cost of alternative power generation forthe grid.
(e) Examine and establish legal provisions for sale and purchase ofelectricity. No such provisions currently exist.
Coffee Residues
4.46 Supply. Approximately 277,000 tons of coffee wastes (95,200TOE) are generated from the 300,000 tons of coffee beans (TCB) producedannually in the Ivory Coast. Coffee cherries are planted, harvested andsun-dried almost entirely by smallholders, then delivered at 8 to 14%mcwb to one of 16 decortication plants (total capacity: 332,000 TCB/yr).40/ There, using the dry-pulping method 41/, the combined epicarp, husk,parchment and other residual matter are hulled and the coffee bean ex-tracted. The plants operate at peak capacity from December to May,following the harvests from October to January, but are usually closed oroperate at low levels for the rest of the year.
4.47 Current Uses and Surplus Wastes. At present, only COGEXYM'sdecortication plant 42/, built in 1974, uses coffee husk and parchmentfor power generation. The plant initially experienced high maintenancecosts due to boiler tubes clogging, furnace vitrification and rapid de-gradation of the refractory chamber; this discouraged other plants builtafter 1977 from installing direct combustion systems using coffeewastes. These plants are connected to the EECI grid or have their owndiesel generators. The COGEXYM plant used 3.7 GWh in 1980/81 to produce32,000 TCB 43/, requiring 3,200 TOE of thermal input from coffee
40/ At 14% mcwb, each ton of coffee cherries yields approximately 48%wastes, 52% coffee bean and small amounts of bean losses. NHV ofgenerated wastes = 3,440 kcal/kg @ 14Z mcwb.
41/ The alternative method is wet pulping in "washing stations".Epicarp and some mucilage are removed, leaving the husk, parchmentand bean. Remaining mucilage is allowed to ferment and is washedoff with water. After drying, the husk and parchment are removed,and the bean polished for export.
42/ Formerly AGRIVOIRE, which accounts for 11% of processing capacity,or 35,000 TCB/yr.
43/ Specific consumption = 144 kWh/TCB.
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wastes. About 92,000 TOE, 97% of the total available supply, was leftunutilized.
4.48 Options. Theoretically, there are three options for usingcoffee waste resources: (a) replace DDO for power generation; (b) bri-quette the wastes to be sold as cooking fuel or to cocoa processingplants for drying needs; or (c) non-energy uses, such as (i) mixing withanimal feed, (ii) composting for soil conditioning and potassium recov-ery; or (iii) use as a substrate for mushroom production, for which thereis a high domestic demand, at the cottage industry level.
4.49 If used to generate power in other plants besides COGEXYM,coffee wastes could displace up to 3.8 million liters of DDO. 44/Assuming that 80% of the DDO can be displaced using gasifiers operatingon a dual-fuel mode, a total of CFAF 408 million would be saved annuallyin 1984 prices.
4.50 With installed capacity in plants ranging from 500 to 1,600kVA, gasification would normally be more economic than direct combus-tion. However, due to the experimental nature of gasifying agriculturalresidues, direct combustion systems should also be considered. althoughsince they require twice the thermal input of gasifiers of similar size,more costs will be incurred for extra handling and conditioning of coffeewastes. Direct combustion systems as low as 500 kVA are now reportedlyavailable at US $1,250/kVA, which is competitive with gasification sys-tems, usually quoted at US $1,000 to $1,500/kVA.
4.51 The use of briquetted wastes outside the decortication plants,as fuel for cocoa drying or residential cooking needs, for instance, hasseveral constraints. In the case of cocoa drying, very expensive highpressure briquetting methods would have to be used to improve handlingand storage processes before sale to nearby cocoa drying plants.Seasonal storage of large quantities of briquetted fuel would also benecessary, since the cocoa drying season does not correspond to thecoffee decortication season. The cost of industrially briquetted fueland storage costs are likely to be prohibitive for the mostly small-scalecocoa planters, although the option may become feasible as industrialcocoa drying and processing develops. For residential use, sale ofbriquetted wastes will face the same consumer preference constraints aspalm oil wastes.
4.52 The only short-term option would be non-energy use of thewastes, as cited above. This would prove a direct benefit to the coffeeindustry by displacing a portion of purchased fertilizer inputs, as wellas decreasing the amount of wastes to be disposed.
44/ Amount required for annual production of 270,000 TCB at a specificconsumption of 14 liters DDO/TCB.
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4.53 Recommendation. DDO substitution in the decortication plantsis the most attractive option for the medium term. Actions should betaken now to ensure that the coffee industry will be economically andtechnically prepared to implement any feasible conversion program. Aprogram to field-test and monitor gasifier systems based on coffee wastesshould be implemented in connection with palm-oil wastes and other agro-industrial residues. In addition, the technical and economic performanceunder field conditions of the available small direct combustion systems,including those currently being tested by I2T, 45/ should be evaluated.If these tests are positive, a work program for conversion should bedeveloped. The economics of transporting and storing coffee wastes forboth smallholder and industrial cocoa drying should be explored, withsensitivity analyses based on alternative scenarios for development ofthe cocoa industry.
Bagasse from the Sugar Industry
4.54 Surplus power from the sugar industry cannot be considered asan option until the medium term, pending the rehabilitation of the sugarsector. Present. levels of power production from bagasse barely meet theinternal requirements of the irrigated plantations and sugar cane pro-cessing complexes.
4.55 Bagasse has traditionally been burned to generate process steamand power in sugar mills. However, cane processing efficiency varieswidely from mill to mill depending on the type and age of equipment.Excess bagasse may be produced in some while supplementary fuel may berequired for others. The Ivorian sugar industry is caught in a viciouscircle: inadequate sugar cane and bagasse production are the result ofpoor soils and low rainfall; low production levels prevent sufficientenergy production for mill operations and the crop irrigation needed tooffset the effects of low rainfall. This situation is exacerbated by thefact that most of the 6 mills have not been designed to maximize energyproduction; only one mill is self-sufficient in its energy requirements.
4.56 The key technical constraint now is underutilization of capa-city and the resulting high production costs. Given the fixed coststructure of sugar production, improved financial performance can only beachieved by increasing production volume and improving operational effi-ciency. In addition, the management, organizational and marketing func-tions of SODESUCRE, the parastatal sugar development company, need to be
45/ In addition to gasifi_ation of coconut husks (para. 4.45), I2T isalso involved in prototype testing of gasifiers using maniocresidues, and has been asked to investigate gasification technologyfor hevea bark and coffee parchement.
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improved. A detailed program for rehabilitating the sugar sector hasalready been prepared and is now under consideration. 46/
Sawmill Wastes
4.57 In 1982, there were reportedly 86 wood processing plants in theIvory Coast, of which 76 were sawmills and the rest semi-integratedoperations that also produce veneer. Over half of the total processingcapacity (2.1 million m3) is concentrated in 6 of the 22 departments. Aprofile of the wood transformation industry is presented in Table 4.8.This profile has changed slightly over the past year, as there is aconstant turnover of wood processing plants; as of June 1983, theMinistry of Agriculture reported 66 mills active and 22 inactive.
4.58 The availability of wood industry wastes for energy use is afunction of the amount of roundwood processed and will depend upon thedevelopment of the timber subsector. The long-term outlook for theindustry is not encouraging primarily because of the rapid depletion offorest reserves, described in the previous section on fuelwood. In thenear term, the wood transformation industry may find itself in a verytight situation characterized by both the inability to solve financialdifficulties unless production volumes are increased, and at the sametime, the unwillingness to invest in necessary equipment conversion thatwould maintain or increase productivity levels despite expected forestreserve depletion. 47/ Valorization of sawmill wastes for energypurposes has to analyzed in this context.
4.59 Supply and Current Uses. The wood transformation industryannually generates over 1 million m3 (160,000 TOE) of residues, composedof sawdust (12%) and bulk wastes (88%). The sawdust, which is not cur-rently used as an energy source, is burned near the plant site. Half ofthe total volume of bulk wastes (approximately 850,000 m is sold tocharcoal manufacturers. Of the remaining half, 270,000 m is sold tolocal joineries, cabinet-makers and other wood-working cottage indus-tries. The balance (150,000 m3) is not used and is available at thesawmill site. In energy equivalent terms, this represents around 26,900TOE, which if added to the 17,600 TOE from sawdust, totals to 44,500 TOEof unutilized sawmill wastes. At 10% overall efficiency of directcombustion systems, the bulk surplus wastes would be equivalent to 52
46/ Etude - Diagnostic de la SODESUCRE. Ministre de l'economie et desfinances and Minist&re d'agriculture.
47/ Existing equipment cannot process the smaller diameter logs whichremain; yet sawmills hesitate to invest in new heavy equipmentbecause of the decreasing supply of commercial timber species intraditional exploitation areas.
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CWh|yr. The possibility of tapping these wood wastes as substitutes forcommercial fuels is highly attractive in view of the industry's financialsituation. In 1984 prices and at 25% overall efficiency for power gasi-fiers, the industry-wide financial savings from displacing the DDO neededto generate 56 GWh/yr would be an annual CFAF 2,770 million.
Table 4.8: PROFILE OF THE WOOD TRANSFORMATION INDUSTRY
I. SAWMILLS a/ Percentof Total
Number of ProcessingSawmills Capacity d/
Categories9 departments with the largestconcentrations of sawmillscentral belt and Abidjan area b/ 43 52extreme west and southwest c/ 16 24
13 other departments 27 24Total number of sawmills 86 100
II. WOOD WASTES e/Recovery Rate (Z) 44.0Total volume processed (million cu.m.) 1.8Wastes (million cu.m.) 1.0
Of which: 1000 tons 1000 TOE f/ ZSawdust 89.7 17.6 12.0Bulk wastes 675.5 144.4 88.0
765.2 162.0 100.0
a/ 1982 data.bi/ Departments: Abidjan, Abengourou, Bouafl, Bouake, Daloa, Dimbokro.c/ Departments: Guiglo, Sassandra, Soubre.di Total of 2.1 million cu.m. roundwood.e/ 1980 data.fl Humid wastes @ 2,000 kcal/kg for sawdust and 2,200 kcal/kg for green
wood.
Sources: Ministere de l'agriculture and Conseil de lEntente.
4.60 From the point of view of energy needs, the country's woodindustries can be divided into two categories: (a) regular mills withonly electricity requirements, and (b) semi-integrated mills whichrequire process steam in addition to electricity. The latter, which in-clude various peeling, veneering, slicing and plywood manufacturingoperations, either produce their own low-pressure steam from wood waste-or fuel oil-fired boilers and puchase power from the grid, or operate ona cogeneration mode based on DDO. One of these mills presently cogen-erates power and process steam from its wood wastes, but it must purchaseadditional wastes from neighboring sawmills to meet its thermal require-ments. The other mills are connected to the grid or have captive diesel
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units to meet power needs. Four other sawmills are considering wood-fired power generation in light of the recent power shortages.
4.61 Substitution Options. Due to the absence of records on howenergy requirements are being met, and on future availability of woodsupplies for each plant, the precise extent of substitution possibilitiescannot be presently quantified. However, based on knowledge of the gen-eral energy use of the two types of mills, the following options havebeen suggested depending upon the outlook for resource availability. Ifthe medium- to long-term outlook for commercial timber and wood wastesappear to be good for the mill, possible options include:
(a) For 2 or 3 of the largest sawmills, conversion to wood-fireddirect combustion/steam cycle systems, coupled with appropri-ately sized wood plantations, where necessary. Three of thefour companies considering such systems are among the largestin the industry and are located in the central belt, where thewood resource outlook is much better than in the coastalregions.
(b) For small- and medium-sized sawmills, gasifier retrofit ofexisting diesel generating units, or conversion to power gasi-fiers where diesel units are not used.
(c) For semi-integrated plants, gasifier retrofit of fuel oil-firedboilers used for generating process steam, and/or conversion toa cogeneration system based on wood wastes. The wood planta-tion requirements here are likely to be more stringent due tothe large process steam needs. 48/
4.62 In the case of mills for which the short-term timber and woodwaste resource outlook is not good, the investments in new, wood-firedequipment are not likely to be amortized before the commercial timberresource is depleted. In rare cases, however, where plants are co-located in palm oil or coffee processing regions, the option of usingmulti-fuel boilers running partly on wood and briquetted agriculturalresidues should be explored. If investments in new equipment to processlesser diameter logs are also made, financial viability of these fewmills may improve. The possibility of having a market for briquettedresidues should be of interest to the palm oil and coffee industries.
4.63 Sawdust, which accounts for 12Z of total wastes from sawmills,could be used as an additional fuel for existing biomass-fired boilers ifit is briquetted to improve handling. Briquetting may be very costly forthe quantities available in each plant. It is preferred, however, todirect-heat gasifier systems using sawdust. One sawmill is planning to
48/ Humidification prior to slicing and subsequent drying are energy-intensive operations that require 60 to 70% of the total energy con-sumption of these types of mills.
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briquette sawdust for process heat production, and its experiences shouldbe monitored.
4.64 Constraints. The most attractive option above is that ofdirect-heat gasifiers in boiler retrofit applications in semi-integratedplants. By removing the existing oil burner and replacing it with a heatgasifier, the cost advantages of switching to wood wastes are achievedwithout replacing the entire heating system.
4.65 The other option of engine gasifiers for power generation ismore problematic. There may be considerable problems in the conversionof some makes of engine since most gasifier equipment is best used onlywith specific engine t;pes. Casifiers aLso have a slow response time inthe electricity generation mode. Furthermore, capital costs are adominant factor. In cases where gasifiers cost more then US$400/kU andwhere liquid fuels cost less then 60 USC/liter, engine gasifier systemsare not likely to be economic. However, current DDO and fuel oil costsare 50% and 20% of this level, respectively. On the other hand, annualoperating hours will be long and power demand is steady. Besides, al-though it is not clear how much the local fabrication of peripheral com-ponents can lower gasifier costs, therse decreases can be significantgiven the high level of local technical capabilities. This option,therefore, constitutes a "gray area" teat merits further investigation.
4.66 The main constraint in the gasifier and especially in thedirect combustion options will be the long-term wood resource. Theexperience of the only wood-fired sawmill should provide lessons. Withforest exploitation proceeding in a concentric fashion and with hightransport costs due to peculiar topography precluding economic fuelwoodouttake from remaining degraded forests, wood plantations for energypurposes may be necessary. Plantations and associated fuel handling andconditioning, however, become a major component of energy cost. There islikely to be little incentive for the mills to undertake major invest-ments in new energy equipment, much less in managed energy plantations,given the uncertainties in: (a) commercial timber supplies; (b) the via-bility of required conversion of processing equipment; and (c) governmentpolicies for the forestry sector and for export of timber vis-a-vis pro-cessed wood. This perception has led many companies to conclude thatwood-fired power generation should have been considered 10 to 1S yearsago during the peak productivity of the timber industry, but that it istoo late at this stage.
4.67 The most important overall constraint in using sawmill wastes,however, is the possible diversion of wood away from charcoal makers andsmall woodworking industries. With 86 sawmills dispersed throughout thecountry, these activities are a significant source of rural employment.Almost 25% of the total amount of wood converted into charcoal in thecountry comes from sawmills. Removal of this source could triggerfurther forest degradation and/or incursions into classified reserves.In addition, over 30% of the bulk sawmill wastes are used in woodwork-ing. Loss of livelihood from woodworking may also contribute to further
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migration into urban areas, although no statistics are available to provethis.
4.68 Recommendation. The operati-ns, energy needs, resource outlookand financial health of the wood transformation industries differwidely. Hence, the analysis of wood waste utilization for energypurposes is complex and needs to be selective. The energy systemrecomendations will be specific to each plant and will therefore have tobe identified on a case-by-case basis. Given the importance of thetimber subsector to the Ivorian economy, it is of urgent necessity toundertake the following:
(a) an industry-wide survey to identify for each major plant 49/the i outlook for timber and wood waste resources; (ii) spe-cific energy requirements for powc- and process steam genera-tion; (iii) current methods used for meeting these needs andenergy costs; (iv) technical parameters determining the possi-bilities for substitution, including gasification, directcombustion, multi-fuel boilers, and potential improvements inefficiencies of existing boilers; (v) requirements for dedi-cated energy plantations; and (vi) co-location with oil palmand coffee processing centers;
(b) an economic analysis covering: (i) capital and operating costsof industrial fuelwood plantations; (ii) costs of drying, pre-paration, transport, handling and storage of wood wastes; (iii)cost-effectiveness analysis among alternative means of meetingthe required energy mix, including the purchase of briquettedpalm oil and coffee wastes; (iv) sensitivity analyses of timberor sawn wood mix, export outlook, local fabrication of gasifiercomponents, and use of multi-fuel boilers; (v) comparativeadvantage of industrial charcoal production for sale to Abidjanand other urban areas, and for export to Upper Volta, underalternative bulk waste recovery assumptions; and (vi) impact ofwood waste diversion for energy use on local sources oflivelihood;
(c) prototype testing of direct-heat and engine gasifiers operatingon wood to derive data on technical performance, compatibilityin combination with existing engines, and potential costreductions; and
(d) analysis of official forestry sector policy, in particularexport promotion policies and incentives, and forest protectionand regeneration measures.
49/ Priority should be given to SIT, SITB, SOFIBOI, and ATP, all of whomhave expressed strong interest in using their wood wastes to meetpower and steam needs.
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V. SECTOR MANAGEHEIT ISSUES
Planning and Oraanization
5.1 The Ivorian energy sector is characterized by operational frag-mentation which impedes coordination and prevents the clear definition ofa global energy policy. Areas of responsibility for policy and planningare divided among different ministries: the Ministry of Mines for hydro-carbons; the Ministry of Industry for electricity; the Ministry of Agri-culture, Water and Forests for wood and biomass; and the Ministry ofScientific Research and National Education for renewable energy. Thereis no authority or organization to coordinate the individual decisions ofthe Ministries. Decisions are often made within the narrow framework ofa single sector without taking into account the possible impacts upon theglobal energy system. The Ministry of Economy and Finance offers minimalbut insufficient coordination of the financial aspects of the sector(prices, investments, fiscal policy). 50/
5.2 The Ministry of Mines and its Directorate of Hydrocarbons areresponsible for petroleum policy formulation and the direct supervison ofall petroleum activities. The Ministry's jurisdiction includes explora-tion contracts; petroleum legislation and taxation; production conditionsand control; crude oil and petroleum product imports; pricing of ex-refinery products and exported crude, and security stocks; and organiza-tion of distribution. An informal petroleum committee was established inearly 1981, chaired by the Minister of Mines and including the Ministerof Economy and Finance and the Secretary General of the Government. Thecommittee was formed to ensure a consistent government approach to policymaking in the petroleum field. However, most of the key decisionsconcerning petroleum are taken at the cabinet level.
5.3 Due to lack of qualified staff, many of the Directorate's re-sponsibilities are exercised defacto by Petroci (the Societe Nationaled'Operations Petrolieres de la C6te d'Ivoire). Petroci was cieated in1975 as a vehicle for government participation in joint ventures withforeign oil companies for oil and gas exploration. The Minister of Minesacts as president of the company; the board holds exploration rights onall prospective areas not yet assigned to oil company consortia. It nowhas joint ventures with five of these consortia covering nine offshore
501 Until 1983 the Ministry of Industry and Planning was responsible forthe preparation of the national plan. This function has been givento the Ministry of Economy and Finance. The preparation of the lasteconomic plan was not really supported by extensive contacts anddiscussions between the Energy Sector and the Planning Administra-tion.
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blocks. 51/ In addition to exploration and oil production, Petrociparticipates in a range of intermediation activities, includingsupervision of the supply of domestic crudes and importation ofadditional crude for refinery operations. It is the sole importer ofrefined products and participates in joint ventures for processing anddistribution. 52/
5.4 Petroci's operations have been hampered by several organiza-tional problems, including insufficient coordination among its variousdirectorates (exploration/production, economy/finance, logistics andadministration). Coordination between the technical departments and theplanning staff is needed in order to evaluate the financial aspects offuture investment options in the hydrocarbon sector. Significant staffincreases, from less than 100 in 1978 to 260 in 1983, and growth ofactivities not related to exploration and development have complicatedthe situation. The latter is especially worrisome in view of the uncer-tainty of Petroci's future intermediation activities. The mission'srecommendations to Petroci concerning its organizational problems are:
(a) give top priority to hydrocarbon exploration and developmentactivities and try to limit or reduce extraneous activities andgeneral overhead;
(b) strengthen management by providing for better coordinationbetween the technical departments on the one hand and financeand planning on the other;
_c) strengthen financial planning, including computerization todevelop the capacity to evaluate future projects and establishinvestment priorities.
5.5 The Ministry of Industry supervises EECI, the sole entityresponsible for electricity production and distribution in the country.The Ministry has recently been reshuffled and resulted from a split ofthe previous Ministry of Planning and Industry, which played a nominalcoordinating role with the preparation of national five year developmentplans. EECI is a mixed economy company with 6 billion CFAF in capitalassets. The shares are held by the Ivorian State (90%) and the Caisse
51/ Petroci's capital expenditures to date on petroleum exploration anddevelopment have been about US$76 million. In early contracts,Petroci paid its share of exploration expenses. It has been a car-ried partner for its 10% share during exploration in later con-tracts.
52/ Petroci is the largest shareholder (47%) in the refinery and a 50%shareholder in the Ivorian affilitates of Shell and BP. It is alsothe principal shareholder (93%) of SMB and a 12.5% shareholder inGestoci, the newly created company to manage security stocks.
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Centrale de Cooperation Economique (France), Electricite de France andprivate shareholders. Because of the need for a long term perspective inthe development of hydroelectric resources and the possibility ofutilizing natural gas as a primary energy source, EECI has taken theinitiative of proposing that a national energy plan be established.
5.6 The Ministry of Agriculture, Water and Forests is responsiblefor the development of biomass resources. As discussed in Chapter IV,current forestry activities lack appropriate management and planning tomeet competing demands for biomass sources. The government agencyresponsible for the implementation of the forestry development strategyis Sodefor (created in 1966 under the aegis of the Ministry ofAgriculture, Water and Forests). The agency manages and operatesindustrial forest plantations, mostly in the central and northern regionsand carries out forest inventories. Sodefor's capabilities (personnel,equipment and financial shortages) are not sufficient, however, for--plementing and managing the established action program forreafforestation.
5.7 Sodefor was recently reorganized and a new unit responsible forcharcoal production was created to maximize waste utilization from landc-learing operations and improve the Abidjan charcoal market situation..e mission recommends that:
(a) the charcoal production unit be expanded gradually and staffedwith: a forester as head of the unit; one engineer responsibLefor transport of wood and mobile equipment maintenance; oneengineer responsible for supervision of building operations(kiln), and one expert responsible for charcoal marketing anddistribution.
(b) the Scdefor unit for inventory and delimitation of naturalforests overlap with the Inventory and Conservation units whichalready exist in the Ministry of Agriculture, Water and Forestsand this task should be left with this ministry.
Sector Planning
5.8 The responsibility for other important aspects of evaluationand planning within the energy sector is only partially delegated in somecases; at times, these aspects are not covered at all. At the institu-tional level, coordination is needed for centralization and interpreta-tion of energy data. This will facilitate (a) establishing nationalenergy balances; (b) obtaining consistent physical and financial energystatistics and flows; (c) studying economic and social relationshipsbetween the energy sector and the rest of the economy (particularly forfuelwood, agriculture and agro-industry). A global demand managementpolicy is needed to promote conservation, interfuel substitution andrational energy use through appropriate pricing policies and fiscalincentives. At the level of supply policy, economic, financial andsocial impacts of each energy source have to be thoroughly examined,especially for possible interfuel substitution.
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5.9 Major decisions affecting the long term future of the energysector require that the country rapidly define and implement plan forcoordination. Immediate decisions concerning hydrocarbon development,possible exploitation of natural gas reserves, construction of futurehydro plants, and biomass use will affect not only the individual sub-sectors but also the total balance between energy supply and demand.Thus, a comprehensive energy policy must be defined which takes itoaccount the objectives and contraints of each subsector. This policymust ultimately reconcile contradictory objectives so as to assureoptimal use of human, capital and natural resources.
5.10 Many countries have recognized similar weaknesses in theirinstitutional structure and have estabilished a specific organizationresponsible for coordination and management of the energy sector. Theseorganizations have often bi-level structures:
(a) A directorate authorized to formulate policy and to makecritical decisions concerning investment, prices, etc.
(b) A technical agency to monitor plan implementation in thevarious suDsectors.
Ministries of Energy (or Energy and Mines) have been created in manycountries. In other cases interministerial commissions, a centralministry (planning, economics), or an executive level council coordinatesthe actions of the technical ministries.
5.11 Given the human resources constraints in the sector, themission considers it impractical and premature to establish a separateMinistry of Energy at this time. Instead, a more modest and phasedprogram of institutional development would seem appropriate. The missionhas prepared a proposal for strengthening the organization of the energysector as a whole. The proposal provides for a two-tiered organizationalstructure: sector planning and policy formulation would be coordinated byan Energy Agency, and high-level policy making would be theresponsibility of a national Energy Committee. Day-to-day managementwould be largely left to the subsector institutions as at present.
5.12 The following phased approach is recommended:
(a) The first priority would be to form a National EnergyCommittee. The Ministry of Industry has previously prepared aproject for the creation of such a Committee. This Committeewould be formally responsible for submitting energy policiesand programs to Cabinet for approval, and recommendinggovernment actions for developing strategies within thenational energy sector. The Committee would have as fullmembers representatives from the Ministries of Industry, Mines,Economy and Finance, Agriculture and Forestry, Civil Work,Transport, Scientific Research, and Trade.
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(b) The second step would be to establish an Energy Agency tosupport the National Energy Committee and formulate proposalsfor Cabinet consideration. This agency would have three majorfunctions:
(i) Identify and integrate the objectives and constraints ofeach subsector, formulate a global energy policy;
(ii) collect energy data, construct and follow up energybalances, analyze the energy system; and
(iii) define in coordination with all parties involved coursesof action (incentives, legislation, pricing and taxpolicies) to improve system efficiency and to promoteefficient energy use.
Its initial functions would include first monitoring energy trends anddeveloping an integrated approach to energy issues, second assisting therelevant ministries and organizations to establish their own energyefficiency program.
5.13 An ad-hoc committee should be formed to set up the Agency. Itis proposed that the Government identify suitable staff and begintraining them within the existing institutional infrastructure to formthe nucleus of the future Energy Agency. The nucleus should be headed byan experienced energy expert assisted by five professional staff (twoeconomists, two statisticians, and an engineer). An expatriate energyadvisor could also be hired to help with set-up of the Agency and provideinitial technical support.
5.14 The mission recommends that the Government seek technicalassistance to review proposals for an Energy Agency, prepare a programfor implementing institutional changes and define job descriptions formanpower requirements.
Energy Pricing
5.15 The Government controls the price of commercial energy throughthe EECI and the Ministry of Industry for electricity and by directPresidential Decree for crude oil and all petroleum products. Prices inboth sectors were revised at the beginning of 1984 to meet revenue re-quirements and to better reflect economic costs. The EECI raised elec-tricity tariffs in February 1984 in response to the increased use ofhigher cost thermal generation; the basic tariff structure remains thesame. The Ministry of Mines implemented several measures in earLy 1984designed to improve the SIR's financial situation, including changes inthe pricing structure of petroleum products. Further modifications havebeen suggested by World Bank officials, and they are being discussed withthe Ivorian Government.
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5.16 Prices for non-commercial fuels, mostly urban firewood andcharcoal, do not reflect the social costs incurred by deforestation.These prices differ from region to region and are not subject togovernment control. The Government may have to impose special pricingpolicies for commercial fuels, especially butane or kerosene, toencourage substitution for firewood consumption if forest resources areto be conserved. Proposed changes to the pricing system should be basedon all major substitution choices, including those presented by naturalgas availability.
Electricity Tariffs
5.17 Electricity pricing based on long run marginal costs of supply(LRMC) was adopted by EECI after a detailed study in 1973 (based on pre-dominantly thermoelectric generation). In 1981, EdF conducted anotherstudy consistent with the conversion of the expansion program to hydrofollowing the fuel prices increases of the 1970's. The marginal costs inthis study vary from USc4.15 to 8.84/kWh (Table 5.1). EECI modernizedand simplified its rate structure on the basis of the study. However,strict LRMC pricing along these lines would have fallen short of meetingfinancial requirements, in part because past investments were costlierthan the ones projected in the near future; the size of the adjustmentwas such that it was spread over all tariff charges except BV rates,which were considered ̂ s most sensitive.
5.18 The present tariff structure is the same as in 1981 with theexception of the residential rate, which is now merged with the LVcommercial rate. For HV and MV, a two-part tariff is proposed in threeoptions, with a larger share of capacity costs rolled into the kWh chargeas the load factor diminishes. The kWh charges decrease according tothree tariff periods: "peak hours" from 19:30 to 23:00, "intermediatehours" from 7:30 to 19:30 and "off peak" the rest of the time. For LVcustomers, the tariff includes a demand charge per subscribed kVA and twoenergy rate blocks with the first at 180 kWh per subscribed kVA. Specialtariffs also exist:
(a) MV supply directly connected to 90 kV substations, little dif-ferent from the HV High Load Factor tariff but with lowerenergy rates;
(b) The "tarif modere domestique" for 1 kVA only, with a reduceddemand charge and a single block (rate between those of the twoblocks in the general LV tariff):
(c) Street lighting and the "Tariff conventionnel," each consistingof only one energy charge.
5.19 Contributions to rural electrification are added to the MV andLV demand and energy charges; and in the 28 main cities, municipal taxesare also levied on the LV energy charges.
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5.20 The present rate structure adequately represents the marginalcosts of this predominantly hydroelectric system. Peak to off peakdifferences are due to network capacity limitations and generating costsare the same around the clock. The capacity cost roll-in scheme alsoreflects the varation of cost of service for a wide range of demandpatterns.
5.21 A new analysis of long run and short run marginal costs wouldbe useful to cross check crucial decisions concerning the timing of in-vestments versus storage levels in reservoirs. However, a completeoverhaul of rates based on these findings raises two questions. Whatcosts are likely to be affected by these decisions, especially if gas isavailable, and how are these changes to be reflected in the rates?
5.22 - Marginal energy costs will remain ccnstant around the clockeven with low storage levels; but for at least five years, these costswill be pegged more on fuel prices than on hydro investment costs. In1984, when gas turbines are operated round the clock, generation incre-ments will cost 8.5C/kWh, capacity costs included; that figure shoulddrop to around 7¢/kWh in 1986 when steam units would be used at themargin most of the time. In the 1990's, the Hydro Master Plan couldlower the need for thermoelectric backup to two-thirds of the time andthe marginal cost to 5C/kWh, close to the average incremental cost ofhydro development found in Table 5.1. Availability of gas could reducethis figure by 10 to 20% depending upon price and reserves.
5.23 In light of the above, rate adjustments to be made by EECI willlie between two extreme solutions: reflect the steep hike and gradualdecline of marginal generating costs or accept a smooth transitiontowards a long term target. The new rate increases in January 1984 tendto reflect the latter choice., as seen from Table 5.1. This level, 25%higher than the 1983 average, is adequate for meeting financial targetsafter 1984 under optimistic assumptions on hydroelectric capability.
Table 5.1: AVERAGE ELECTRICITY PRICES VERSUS MARGINAL COSTS(in 1984 US$ Equivalents)
Load Energy Total Long RunFactor Demand Charge Charge Price Marginal Cost a!
(US$/kW) (USC/kWh) (USC/kWh) (US¢/kWh)
lV 0.80 109.13 4.00 5.55 4.15Mv 0.32 44.01 7.41 8.98 6.05LV - - - 12.84 8.84
a/ Based on EdF's 1981 study.
Source: EECI
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5.24 However, it is likely that EECI will have to spend up to $70million annually in fuel alone for several years to restore this capa-bility. A case can be made for passing part of this additional expen-diture on to consumers without going to strict marginal cost pricing,which would temporarily add 5C/kWh to 1983 tariffs and elicit someunwarranted responses from consumers. This would stimulate more energyconservation and improve EECI financial performance without undulydepleting hydro storage, as was done in the past. The temporary rate in-crease, which would narrow the gap with actual marginal costs, could bedirected to the most price-elastic HV and MV consumers. Rates should bekept under the threshold of lOC/kWh, which would trigger anothermushrooming of private diesel generating sets. However, this one-timeadjustment, which would last only a few years, should not have thecharacter of permanerce that befits fuels adjustment clauses found inutilities with a large share of thermoelectric generation.
5.25 The rate structure would need no major modifications, butshould include innovations aimed at a more rational use of power. Wherenetwork bottlenecks are costly to remove, off-peak usage could be stimu-lated through rate discounts and control techniques easy to apply onloads such as water pumping, air conditioning and ventilation. In addi-tion, the mission recommends that cost-based rates for captive powerpurchases by EECI be studied and introduced. This option, which is nowconsidered only for the refinery, may prove interesting from two pointsof view:
(a) For normal operating conditions, captive plants either usingindustrial refuse as fuel and/or generating power through com-bined heat-power cycles may have excess generation at a lowercost than the marginal generating cost on the interconnectedgrid.
(b) For emergency situations, EECI could take advantage of a supplyby the many diesel units now installed in plants and commercialestablishments in so far as they choose to generate above theirelectricity requirements of the moment.
Petroleum Prices
5.26 The Government sets the price of refined products at each levelof sales activity. In the past, ex-refinery prices of petroleum productswere set at the beginning of the year on a projected cost-plus basis.Fixed margins for distributors and government taxes, including a specialpetroleum activities tax for financing petroleum exploration anddevelopment and a security stock tax used to finance construction ofpetroleum security storage, are added to these figures to obtain thefinal retail prices. Before the recent price increase in January 1984,prices had not changed since August 1982. Devaluation of the CFAFagainst the dollar during this period meant that prices could not coverfluctuating input prices, further exacerbating the SIR's financialdifficulties.
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5.27 The pricing system was revised on January 1984 on therecommendation of an IMF/World Bank Mission which had previously visitedthe country. Under the new system, crude and ex-refinery prices aretheoretically based on the CIF Abidjan prices, adjusted twice monthly.The final retail price will be adjusted less frequently. TheGovernment's new pricing policy will end subsidization of heavy fuelsupplied to the EECI by increasing its price to import parity. Theprices of products sold directly to national and international bunkersand to the fishing industry have also been increased to import parity.Part of the tax levied for the Compensation Fund 53/ is being temporarilyincorporated into the SIR ex-refinery prices until management changes aredecided upon.
5.28 Table 5.2 shows the changes in ex-refinery and retail pricesfor petroleum products and the corresponding CIF Abidjan prices forDecember 1983. Although they are supposed to be based on CIF Abidjanprices, the ex-refinery prices have increased substantially, reflectingthe temporary incorporation of part of the tax levied for the Compen-sation Fund. This temporary action has raised ex-refinery prices abovelevels which reflect the economic costs of the products. Once decisionsconcerning managerial changes at the refinery have been taken, the ex-refinery prices should be revised to exclude the Compensation Fund taxand thus reset the prices at levels near import parity.
Table 5.2: IVORY COAST - CHANGES IN EX-REFINERYAND RETAIL PETROLEUM PRODUCTS
(in USS/ton)
CIF AbidjanEx-refinery Retail Ex-refinery Retail Price
(December 1983) (January 1984) a/ (December 1983)
Butane 210.0 - b/ 486 - b/ 550.0Premium Gasoline 365.4 994.8 530.44 1111.41 321.6Regular Gasoline 367.7 972.1 533.48 1073.90 317.6Kerosene 191.1 358.4 304.94 503.15 290.0Gas Oil 308.0 661.1 429.35 705.78 257.0Diesel Oil 251.3 339.2 326.94 460.81 239.2Light Fuel Oil 150.0 203.2 - d/ - d/ 189.2Heavy Fuel Oil 122.5 - c/ 209.38 240.77 180.0
a/ 1984 prices converted at 405 CFAF/USS.b/ Retail prices vary with location and are based on distance from the refinery.c/ No retail prices. Heavy fuel oil was supplied only to EECI at ex-refinery prices.d/ Information not available.
Source: Minist6re du Commerce, Ministere des Mines.
5S/ The Compensation Fund is a special fund administered by the Ministryof Commerce and fed by a tax on the retail sale of products-. Thefund is used to compensate the SIR refinery for losses due tofluctuations in crude oil prices.
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5.29 Retail prices show a less dramatic increase, since the levy forthe Compensation Fund has been temporarily lowered. The Governmentarbitrarily increased the taxes on some products (10% for gasoline, 16%for gas oil) but made no changes for others (such as kerosene). Theresulting increases to the consumer range from 7X for gas oil to 40Z fordiesel oil.
5.30 Table 5.3 shows the price structure of selected products as ofJanuary 1984. The Government is continuing its policy of heavily taxinglight products, particularly gasoline and gas oil. In general, thesetaxes provide the Government with an easy means of collecting revenues;taxes on gasoline and gas oil accounted for 3.6% of the General Budgetresources in 1983. The taxes are also supposed to raise retail prices tolevels which will induce energy conservation in the transportationsector. However, past experience has shown growth of light productconsumption despite price increases. It appears that the majordetermining factor for tax levels is revenue requirements.
Table 5.3: PETROLEUM PRODUCT PRICE STRUCTURE,
JANUARY 1984 (USS/ton) a/
Premium Regular Gas Diesel Fuel
Gasoline Gasoline Kerosene Oil Oil Oil
Ex-Refinery Price 530.44 533.48 304.94 429.35 326,94 209.38Taxes 393.67 363.07 83.19 144.01 109.06 17.90Distribution (Margin aCosts) 93.29 83.94 56.41 54.80 27.71 16.10
Equalization Fund
(Transportation) 35.36 36.37 32.02 30.88Joint Inventories (8.42) (8.66) (7.62) (7.35) (29.06) (26,17)Compensation Fund 33.68 34.64 29.41
Equalization Fund 34.05 31.05 34.21 24.69
Retail 1,111.41 1073.90 503.15 705.78 460,81 240.77
a/ 1984 prices converted at 405 CFAF/USS.
Source: Ministere du Commerce, Ministere des Mines
5.31 Pricing issues for petroleum products will have to be reviewedas decisions are taken concerning the rehabilitation of the refinery'sfinancial situation. In the interim, the mission recommends thefollowing:
(a) After further steps have been taken to improve the refinery'sfinancial position, ex-refinery prices should be kept separatefrom the partial Compensation Fund levy so as to encourage more
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efficient refinery operation. The readjusted ex-refineryprices should be based on the economic costs of the refinedproducts; this can be achieved if the ex-refinery prices, areindeed based on the CIF Abidjan prices, as outlined by the newpricing system.
(b) The Government should evaluate the impact of its tax policieson demand for light products to determine the extent to whichtax policy can be used as an effective demand managementtool. This should include studying more carefully the impactof price changes on petroleum product consumption in thetransportation sector.
Residential Interfuel Substitution
5.32 Table 5.4 compares current cooking fuel costs in Abidjan, basedon the assumption that households use only one particular cooking fuel.The reality in a large number of cases, however, is that one householduses a mix of fuels and 2 or 3 different stoves depending on the foodbeing cooked. Hence, the most cost-effective mix of fuels may differ fromhousehold to household and cannot be identified with confidence in theabsence of a detailed urban household energy use survey.
Table 5.4: COMPARISON OF ACTUAL COOKING FUEL COSTS IN ABIDJANON A USEFUL ENERGY BASIS a/
Useful Energy CFAF Uss
Yield (S) (per capita per year)
Firewood b/traditional open fire 10 10,300 25improved wood stoves 15 6,900 17
Charcoal c/existing stoves 15 14,000 37improved charcoal stoves 20 10,700 28
LPG d/ 45 8,000 20Kerosene e/ 35 11,700 29Electricity f/ 65 18,600 46
a/ Fuel requirements estimated on the basis of 200,000 kcal per capita peryear of useful energy. Mission estimates on firewood and charcoal priceswere based on visits to Abidjan and Korhogo markets.
b/ Energy content in wood of 3,500 kcalAkg e 25 % mcwb; firewood retailprices at CFAF 18/kg.
c/ Energy content in charcoal of 7,000 kcalAkg; charcoal retail prices atCFAF 70/kg.
d/ Energy content of 10,880 kcal/kg; price of one 12.5-kg cylinder at CFAF2,460.
e/ Energy content of 10.3 million kcal/ton; retail price of CFAF 165/iiter.f/ At CFAF 52/kWh.
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5.33 Electricity, charcoal and kerosene are the most expensivefuels. Charcoal has the highest costs, even if cooking efficiencies wereimproved, compared to LPG and fuelwood. Firewood used in improved stovesis slightly cheaper than LPG, but firewood is used only by less than 20 Zof urban households and will probably be taken over gradually by the nextmost accessible and convenient fuel, which is charcoal.
5.34 Although LPG is currently the least-cost cooking fuel source,there are many constraints to its wider use, of which the most importantare supplies. Butane must be imported to meet residential demand sincerefinery production is currently needed for captive fuel requirements.However, if natural gas becomes available, internal refinery fuel needscould be met and up to 20,000 tons of LPG could be produced by therefinery for residential users. This can more than cover the currentmarket of about 60,000 households. 54/ Continued imports will berequired to expand the residential market. The second constraint con-cerns the high first costs of converting to LPG and the household cashflow problem. Stoves that operate on LPG are much more expensive thanthe charcoal stoves they will replace. Running fuel costs also peak onceevery 2 or 3 weeks when the cylinders need recharging, whereas relativelysmall cash outlays are required for charcoal to meet daily needs. Recentstudies by the Direction des Hydrocarbures indicate that localmanufacture of cylinders does not reduce retail prices significantly.The third constraint concerns the distribution system. LPG has beenintroduced in filling stations rather than by the usual direct supplier-customer delivery. LPG use has therefore been effectively limited tothose who own cars. However, while direct supplier/consumer contact issafer and more convenient to the user, it can add to retail cost. Abetter sales system needs to be defined, addressing in particularconsumer resistance due to safety concerns and consumer preference forcharcoal as the most appropriate traditional fuel for the local diet.
5.35 Non-wood biomass resources, such as dung and agriculturalresidues, could be processed to produce household fuels, but their use isnot without limitations. Gasification of agricultural wastes,recommended by the mission for industrial use (para. 4.41-4.54), wouldnot be economic for smaller scale uses. Briquetted residues could beused as household fuel, but the associated drying, handling and storagecosts during production tend to be prohibitive (para. 4.51). In fieldtests in other developing countries, biodigesters using animal wastesgenerally have proven uneconomic at the household level since, as is thecase in the Ivory Coast, individual households frequently do not haveenough livestock to provide a steady supply of feedstock for theequipment. When initial investment costs, technical trainingrequirements for each household and opportunity costs of collecting the
54/ Based on a consumption of 15 to 20 kg per household per month, andassuming that 14,500 tons (85%) of the total 18,000 tons of LPG con-sumption in 1983 occurred in the residential sector.
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dung are taken into consideration, it would be more convenient andeconomic for the household to simply purchase fuel.
5.36 There may be scope for operating biodigesters at the villagelevel. Community-based production presents other difficulties, relatedmostly to organization of the supply system. These difficultiesinclude: (a) who will manage and operate the facilities; (b) who willcollect and prepare the dung; (c) how will the gas be distributed toindividual households; (d) what will be the price of the gas to theconsumers and on what basis should it be set. More field work is neededbefore these questions can be properly addressed. The relative economicsof community-produced biogas versus the available alternatives should beevaluated based on field tests using the technologies now being tested atthe University.
5.37 Unless the constraints affecting supply and use of alternativefuels are addressed, charcoal will probably continue to be the maincooking fuel source for urban households, although it is the mostexpensive fuel on a per useful energy unit basis. It is in the economicinterest of Covernment to consider the additional benefits derived frombringing gas on stream, developing alternative biomass fuels, andpromoting more efficient end-use technologies; namely, stemming forestdepletion and alleviating the burden on household budgets of expendituresfor cooking fuel.
Conservation
5.38 Despite the relatively low efficiency of energy consumption inthe Ivory Coast, little has been done to officially promote energy con-servation and efficient end-uses of energy sources. Many of the consump-tion figures used in this report are estimated (there are no reliablesources for end use efficiencies); however, there are other indicationsthat overall end-use efficiencies are low:
(a) Only 5 to 15% of the energy content of non-commercial householdfuels, which account for 48% of net domestic consumption, istransformed into useful energy due to low efficiency cookingstoves. Most traditional cooking habits are not conducive torational energy use.
(b) The transportation sector accounts for almost 65% of the netdomestic consumption of petroleum products. Historically,there has been little concern within the sector for the energyefficiency of vehicles, many of which were purchased during theperiod of strong economic growth when fuel sources wererelatively inexpensive. Replacement of the older stock ofinefficient vehicles has been hindered by insufficientmaintenance and the economic recession.
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(c) The average weight of energy in industrial costs tends to below in the Ivory Coast since there are few highly energyintensive industries. As a result, managers tend not to paymuch attention to energy expenditures and possible energysavings.
(d) Fifty-five percent of low voltage electricity is consumed byair conditioning systems. These systems are designed to beused with the assumption of readily available low costelectricity. Thus, they usually have poor physicalefficiencies and are not subject to any sort of regulationregarding use.
5.39 Among the steps which can be taken to promote conservation andrational energy use are:
(a) Promote high-efficiency air conditioners to be used byresidential customers and use price incentives to induce moreconservative use of the equipment.
(b) Mount a program to promote and disseminate improved woodcharcoal stoves.
(c) Develop a program to improve the distribution of LPC suppliesand study the costs of household LPC conversion under varyingsupply constraints.
(d) Replace incandescent lights in commercial and industrialestablishments with fluorescent lights for immediate savings.
(e) Initiate a program to evaluate and to improve the energefficiency of industrial processes and public lighting. TheGovernment has already asked their traditional lenders toassist them in the development of such a program.
(f) Study the scope and requirements for fuel conservation andsubstitution in the transport sector including:
(i) Trends and prospects of petroleum product consumptionin road and rail transport;
(ii) Present sector position with regard to transport modes,fleet composition, capacity utilization, andinfrastructure;
(iii) Fuel efficiency performance of the principal transportentities and to the extent possible, the impact ofprice changes on fuel consumption in the transportsector;
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(iv) Scope for conservation, through improved vehicle androad maintenance, and improved driving and cargodispatch practice; and substitution, through use offuel oil and possible, LPG as transport fuels.Possible fuel savings should be estimated;
(v) Policies, administrative and institutional measures(including training) and investment required in supportof increasing energy efficiency in the transportsector.
Investment Requirement
5.40 Substantial energy investments will be required over the restof the decade to provide for expansion or development of domesticresources. The mission's estimates on energy investments are only indi-cative and based on a preliminary assessment of investment components andcosts (Table 5.5). These can only be firmed up once the various planningexercises and studies proposed in this report have been completed. Theinvestment program for the Ivorian energy sector will be necessarilylimited by the financial difficulties of EECI and Petroci, whose cashflow and resources are not sufficient to cover their plannedinvestments. The availability of additional public resources or externalborrowing should be made possible if there is a rapid improvement ofthese companies' financial situation following the measures taken thisyear and in 1985.
5.41 Many of these investments will have to be made by the publicsector. However, the Government should encourage investments which canbe undertaken by the private sector (e.g., in petroleum exploration, woodfuel plantation and the development of more efficient wood fuel storesand charcoal production). The availability of private capital for oiland gas projects will depend largely upon the real rate of return whichcan be expected by operators.
Hydrocarbons
5.42 Petroleum development investments for both Belier and Espoirfields, probably in the range US$400-700 million during the last sixyears, have been high due to (a) the geological complexity thatnecessitated more wells than normally required to delineate the fields,(b) the need of more reservoir data than normally needed to understandthe production mechanism, (c) the high cost of field development at greatwater depths and (d) production problems necessitating expensive andrisky workover investments. The high cost of exploration/development ofnew fields in offshore Ivory Coast most probably will continue to prevailin the future as petroleum activities move to deeper and deeper waterdepths area.
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Table 5.5: MAJOR PROJECT INVESTMENT REQUIREMENTS: PETROCI AND EECI(1984 USS million)
1984 1985 1986 1987 1988 1989
Petroci Investments
Oil Exploration and
Development a/ 7.5 11.5 15.0 18.5 7.5 - d/Gas Development - 2.0 11.5 _3.5 6.0 - d/
TOTAL 7.5 13.5 26.5 52.0 13.5 -
EECI InvestmentsConversion of Vridi
Steam Units - - 6.7 - - -
Repowering Gas Turbines
at Vridi - 10.5 17.5 7.0 - -
Combined Cycle Unit - - - 12.9 32.7 30.9
Trans., Dist., and
Others b/ 115.0 119.0 76.0 77.0 - d/ - d/
TOTAL 115.0 129.5 100.2 96.9 32.7 30.9 c/
a/ Includes investments for water injection at Espoir and development of new reserves.
b/ Projected investments for the Man Spider Network, equipment for the maintenanceworkshop at Yogougon, and training, as outlined in the First Power Project, IBRD loan
1896-IVC.c/ Construction of the next hydroelectric project should start by 1989. If this project
is Soubre, additional investments of up to S75 million will be required.
d/ Information not available.
Source: Mission estimates, Ivory Coast Loan 1896-IVC Operating Results and Forecasts, Gas
Engineer Project-initial Project Brief.
5.43 The mission prepared estimates of past investments 55/ inexploration and development in Ivory Coast based on the programs thathave been carried out (seismic survey, drilling and existing surfacefacilities) and cost estimates for similar activities and facilitiespublished in the technical literature. An estimated US$200 million hasbeen invested annually during the period 1979-1983 by the operatingcompanies and Petroci, probably more than half of which has been expendedin exploration activities. Petroci's investments have been estimated inthe range of US$10-15 million annually during the same period.
55/ Statistical data on total investments in the oil and gas sectors inthe Ivory Coast were not available to the mission.
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5.44 Based on the various scenarios of exploration and developmentprogram presented previously in Chapter 3, the total investments for thenext five years could be estimated at about US$100-200 millionannually. The lower end estimate would represent the investments re-quired for the base case for oil including continued exploration at thesame scale as in 1984 while the higher end estimate would additionallyinclude the required investments for water injection in Espoir, develop-ment of B15X/Bl8K and another new discovery, development of gas of B1-LX/Bl-2X and construction of an onshore gas network. 56/ Petroci'srespective contributions could be estimated at about US$7-20 millionannually during the same period, around 6% of the total investment.
Electricity
5.45 EECI's investments for the rest of the decade will cover theexpansion of its transmission and distribution network as well as newgenerating capacity requirements. Table 5.7 shows the investmentrequirements for both, based on use of natural gas in the short term andcontinuation of electrification projects. Total investments in newgenerating capacity, which includes repowering the gas turbines at Vridi,converting steam units 3 and 4 to gas, and adding an additional combinedcycle unit to use slack gas demand, are estimated at $113.1 million (1984US$). Investments for transmission and distribution include the costs ofexpanding the Man Spider Network, equipment for the maintenance workshopat Yopougon and further technical training. These investments havealready been funded by the Bank, and form part of a larger electrifica-tion program co-financed by CIDA and EDC. Costs will range from $77 to$119 million annually.
Biomass and Fuelwood
5.46 Investment requirements for biomass energy (firewood, charcoaland agricultural wastes) cannot be established on preliminary estimates.As discussed in Chapter 4, pre-investment work, feasibility studies andvarious surveys must be undertaken in order to firmly establish theeconomic and technical viability of projects. This is the case for thepalm industry, the utilization of coffee residues, sawmill wastes, andalso for improving the knowledge of the charcoal subsector, which shouldbe given first priority. A national forest inventory is necessary toprovide basic data for medium and long range planning localized surveyson woody biomass sources and consumption trends as needed to show moreclearly the supply/demand balance and to detect possibile shortages.
5.47 Preliminary studies for the palm industry, use of coffeeresidues and sawmill wastes, and charcoal consumption were estimated ataround US$800,000. Estimates of the cost of feasibility studies and
56/ For the sake of investment estimates, this system is assumed to beimplemented by Petroci.
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surveys to be undertaken by Sodefor on forestry inventory are neededalso.
Table 5.6: IVORY COAST EXPLORATION AND DEVELOPMENT INVESTMENTS(1984 USS millions)
1984 1985 1986 1987 1988
A: Base case: Oil
Exploration 50 66 45 45 45Development 45 90 90 30 30
Subtotal 95 156 135 75 75Petroci 7.5 9.0 9.0 3.0 3.0
B- Highly Optimistic CaAA
Exploration 50 66 45 45 45Development (Oil) 45 115 150 185 75
Subtotal (Oil) 95 181 195 230 120
Petroci (Oil) 7.5 11.5 15.0 18.5 7.5Development (Gas) - 20 65 85 60Petroci (Gas) - 2.0 11.5 33.5 6.0
Subtotal (Oil & Gas) 95 201 260 215 180Petroci (Oil & Gas) 7.5 13.5 26.5 52.0 13.5
Source: Mission estimates
Table 5.7: EECI INVESTMENTS FOR GAS USE,TRANSMISSION AND DISTRIBUTION PROJECTS
(1984 USS million)
1984 1985 1986 1987 1988 1989
GenerationConversion to gasat Vridi - - 6.7 - - -
Repowering Gas Turbinesat Vridi - 10.5 17.5 7.0 - -
Combined Cycle Unit - - - 12.9 32.7 30.9
Transmission, Distributionand OtherTransmission 40.0 54.0 33.0 20.0 - b/ - b/Distribution 54.0 54.0 25.0 34.0 - -Buildings 13.0 3.0 5.0 10.0 - -Studies - - 3.0 3.0 - -Current a/ 8.0 8.0 10.0 10.0 - -
a/ Covers items such as vehicles, office equipment, tools and operatlon/m-,intenanceequipment.
b/ Information not available.
Source: Mission estimates, First Power Project Loan 1896-lVC
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Annex 1Page 1 of 2
CGW4ERCIAL ENERGY CONSUWTION IN IVORY C0AST('000 Metric Tons)
1974 1975 1976 1977 1978 1979 1980 1981 1982 1983
Gasoline 170 189 205 220 245 265 276 265 244 222Kerosene 38 43 46 45 49 52 63 67 69 69Gas oil V 158 175 219 256 294 302 295 265 247 240Diesel oil l 38 42 46 49 56 53 61 61 65 60Fuel 180 65 69 74 78 100 110 105 98 86 76Butane 6 6 8 9 11 13 15 16 18 19(Fuel 380) b/ (124) (144) (194) (277) (318) (219) (105) (37) (51) (262)TOTAL PETRDLEUL4 PRODUCTS
(EXCLUD. H.F.) 475 524 598 657 755 795 815 772 729 686Electricity (Low Voltage) 84 99 111 123 137 180 200 207 229Electricity (Medium &
High) 108 125 147 169 191 219 236 252 258TOTAL ELECTRICITY 192 224 258 292 328 399 436 459 487
TOTAL COMMERCIAL ENERGY 667 748 856 949 1083 1194 1251 1231 1216
a/ Excluding EECI consumption,b/ EECt consumption.cf Electricity conerted at thermal efficiency rate of 34%. 1 toe = 4,000 Kwh.
Source: EECI, GPP.
AVERAGE ANNUAL GROWTH RATES FOR ENERGY DEMAND
(% per year)
Total Electri- Petroleum Tot. Commercial Electricity/ PetroleumCamercial city Products Energy/GDP !/ EDP Growth GDP Growth
GDP Energy Demand Demand Demand Growth Ratio Ratio a/ Ratios a/
1974-1978 8,4 12,9 14.3 12.3 1.53 1.461975-1979 7.1 12.4 15.6 11.0 1.74 2.20 1.551976-1980 5,7 10.0 14.1 8.1 1.75 2.47 1.421977-1981 4.6 6.9 12,1 4.3 1.50 2.63 0.931978-1982 1.1 3.0 10,5 -0.8 2.73 9.54
a/ Ratio of demand growth to GOP growth.
Source: EECI, GPP
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Annex 1Page 2 of 2
DEMAND FORECASTS FOR PETROLEUM PRODUCTS('000 Metric ton)
Gasoline Gasoil Butane Kerosene Diesel Oil Fuel 180
SIR Forecasts1983-84 224 248 19.9 67.1 86.2 76.5
1984-85 224 248 20.9 67.1 86.2 76.5
1985-86 249 (+11%) 262 (+5.6%) 22.0 67.1 86.4 a/ 84.3
Consumption1983 222 240 19 69 60 b/ 76
Mission-Forecast
1984 222 240 20 69 60 76
1985 229 (+3.25%) 248 (+3.5%) 22 76 62 (+3.25%) 79 (+3.25%)
1986 238 (+3.9%) 258 (+4.2%) 24 83 64 (+3.9%) 82 (+3.9%)
1987 247(-) 269(-) 27 92 67(-) 85(-)
1988 257(-) 280(-) 29 101 69(-) 89(-)1989 267(-) 292(-) 32 111 72(-) 92(-)1990 277(-) 305(-) 35 122 75(-) 96(-)
e = 1.3 e =1.4 g = O%/y g = lO%/y e 1.3 e =1.3 c/
a/ Including E.E.C.I. consumption for electricity generation.b/ Excluding E.E.C.I. consumption.
c/ e: elasticity of demand with respect to GDP
g: annual growth rate.
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Annex 2Page 1 of 2
POWER DEMAND IN THE "MAUVE SCENARIO"(GWh)
Historical -- - - Forecast - - - -
FY82 FY85 FY89 FY93
Low voltage 777.1 1,054.1 1,550.0 2,202.4Abidjan urban area 482.3 656.3 975.2 1,375.6
Residential 350.9 482.5 728.5 1,044.1Professional 115.4 150.6 214.8 289.4Street lighting 16.1 23.2 32.0 42.0
Others areas alreadyelectrified 294.8 363.8 496.0 687.8
Residential 166.2 218.0 315.1 462.0Professional 78.7 97.2 124.3 160.5Street lighting 49.9 48.4 56.7 65.2
New rural 0.0 34.2 78.8 138.9Residential 0.0 21.8 51.9 93.6Professional 0.0 4.8 11.1 20.0Street lighting 0.0 7.6 15.8 25.3
Medium voltage existingcore of consumers 802.0 854.8 981.3 1,132.3
Abidjan urban area 566.4 605.0 680.6 766.8Other areas 235.6 249.8 300.7 365.5
Medium voltage new projects 0.0 200.5 460.5 720.5
High voltage existingcore of consumers 123.1 135.0 157.9 184.7
High voltage new projects 0.0 0.0 70.0 70.0
Total 1,702.2 2,244.4 3,219.8 4,309.9
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Annex 2Page 2 of 2
POWER DEMAND FOR GREY AND MAUVE SCENARIOS
Generation(GWh) Peak load on
Interconnected Isolated the intercon-Total system centers nected system
(NW)
FY83 (Historical) 1988 1935 53 320
Grey Scenario (1)1985 2344 2318 26 3781986 2558 2548 10 4201987 2782 2776 6 4621988 3000 2995 5 5061989 3228 3225 3 5561990 3493 3490 3 6111991 3766 3763 3 6711992 4051 4047 4 7351993 4352 4348 4 7941994 a/ 4613 4609 4 8601995 4892 4888 4 9321996 5186 10121997 5502 10991998 5837 11991999 6192 13042000 6572 1419
Mauve Scenario1985 2596 2570 26 4191986 2826 2816 10 4671987 3106 3100 6 5221988 3414 3409 5 5771989 3681 3678 3 6331990 3975 3972 3 6961991 4283 4280 3 7611992 4595 4591 4 8331993 4926 4922 4 9051994 5278 5274 4 9901995 5650 5646 4 10841996 b/ 6046 11871997 6476 13021998 6935 14331999 7428 15732000 7956 1727
al Assumed to be the same as in the Mauve Scenario.bi Extrapolated from this year.
Annex 3Page 1 of 2
HYDRO ELECTRIC MASTER PLANFIRM ENERGY BALANCE
(In GWh)
1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
DEMAND 2995 3225 3490 3763 4047 4348 4609 4888 5186 5502 5837 6192 6572(Interconnected System)PLANTS
Ayame 190 190 190 190 190 190 190 190 190 190 190 190 190Kossou 100 125 150 175 200 225 250 250 250 250 250 250 250Toabo 300 335 370 405 440 485 520 520 520 520 520 520 520
Existing Buyo 600 600 600 600 600 600 600 600 600 600 600 600 600In VrIdI ST a/ 1100 1100 1100 1100 1100 700 700 700 700 700 700 700 700
1984 VrIdi GT 450 450 450 450 450 450 450 450 450 450 480 480 480Miscellaneous 150 150 150 150 150 150 150 150 150 150 150 150 150
Subtotal 2890 2950 3010 3070 3130 3000 3060 3060 3060 3060 3060 3060 3060 I
Planned Soubre 650 1300 1300 1300 1300 1300 1300 1300 1300 1300 1300Ndlelesso 250 500 500 500 500 500 500 500Malamalasso 245 490 490 490 490 490Daboltie 145 290 290 290 290Louga 550 1100 1100
Subtotal 650 1300 1300 1550 1800 2045 2435 2580 3130 3680 3680
Total 2890 2950 3660 4370 4430 4750 4860 5105 5495 5640 6190 6740 6740Balance -105 -275 170 607 383 402 251 217 309 138 353 548 6024
a/ Unit 1-2 (400 GWh) retired In 1993,
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Annex 3Page 2 of 2
HYDRO ELECTRIC MASTER PLANFUEL REQUIREMENTS
Thermal Fuel Requirements a/ Fuel OutlaysGeneration b/ HFO Distillate escalated unescalated
(GWh) (TJ) (TJ) (US$ million)
1985 720 7488 2088 40.7 42.21986 549 5710 1592 31.6 32.21987 365 3796 1058 21.6 21.41988 836 8694 2424 51.3 48.91989 949 9870 2752 60.2 55.61990 805 8372 2334 53.0 47.21991 554 5762 1607 38.4 32.51992 641 6666 1859 47.0 37.51993 396 4118 1148 30.8 23.21994 118 1227 342 9.5 6.81995 541 5626 1569 46.4 31.61996 615 6396 1783 54.0 35.91997 600 6240 1740 53.5 35.01998 980 10192 2842 88.8 57.31999 853 110890 0 74.0 46.62000 813 8455 0 57.3 35.5
2001to 880 11440 0 77.6 48.12005
Actual1985-2000 10335 109701 25138 758.1 589.42000-2005 4400 57200 0 388.0 240.5
Total 14735 166901 25138 1146.1 829.9
Present Worth1985-2000 4992 52453 13372 342.6 288.92000-2005 726 9437 0 64.0 39.7
Total 5718 61880 13372 406.6 328.6
a/ Until 1998, 20% with gas turbines, 80% with steam units(1 GWh = 10.4 TJ of HFO + 2.9 TJ of Distillate)From 1999, 100% with steam units (1 GWh = 13.0 TJ)
bl The hydroelectric generation underlying this table was obtained asfollows:- for existing plants and §oubr6 assumed to come on-stream in 1990 by
the MOGLI model run from 1984-2000.- for projects after 1992, by taking the average generation found in the
Master Plan.
- 105 -Annex 4Page 1 of 3
REPOWERING THE GAS TURBINES AT VRIDI
Fuel Savings
With the present equipment, the gas turbines are only used forpeaking or during periods of extreme energy back up requirements. Theanalysis of generation dispatch shows that, as an average, 202 isgenerated by gas turbines and the remainder at lower cost by the steamturbines.
With a combined cycle unit (CCO), the generation cost would bereduced and generation could be split 55Z for CCO and 45% for the steamturbines (taking into consideration the actual ratings of the units).The fuel expenditure to generate 700 GWh per year, a value close to theaverage for the 1985-2000 period, are found below at 1984 fuel costs i.e.HFO: $170/t = $4.21/GJ; Distillate: $210/ton = $5.10/GJ.
Without combined cycle
80 Z generated by Vridi S.T. - 20% generated by Vridi C.T.
Vridi S.T. 560 GWh x $ 54.7/M1W = $ 30.6 millionVridi G.T. 140 GWh x $ 72.3/MWh = $ 10.1 million
Total A = $ 40.7 million
With combined cycle
45 Z generated by Vridi S.T. - 55% generated by Vridi C.C.
Vridi S.T. 315 Gih x $ 54.7/MWh = $ 17.2 millionVridi C.C. 385 GWh x $ 46.8/MWh = $ 18.0 million
Total B = $ 35.2 million
Difference A - B = $ 5.5 million
Average saving per GWh is $5.5 million/700 = $7,860/GWh
Design Options
Two designs are possible: (a) install one steam turbine, andheat recovery boilers at the exhaust of the four turbines, generatingsome 45 MW when all four gas turbines are operated at full load or (b)install two sets, each on two gas turbines. In both cases, some modifi-cations in the existing plant are likely to be necessary to accomodatethe new equipment (displacement of a workshop, for instance). From thisviewpoint, to install only the recovery equipment and the relevant turbo-set for two gas turbines would be easier and the idea has been contem-plated to move the other two gas turbines to some other place. TheBouake area has been contemplated. This would create a new generationcenter near this area. The suitability of such a project should be in-vestigated very carefully for several reasons:
- 106 -Annex 4Page 2 of 3
(a) Shifting two gas turbines with the relevant by-costs (sitepreparation, civil works, new substation and ancillaryservices) may prove as costly as the works involved at Vridifor accomodating a complete recovery system for the four gasturbines.
(b) Operating two gas turbines at Bouake or some place in the sameregion would involve fuel transportation costs and wouldeliminate the possibility of firing them with gas; and
(c) Under normal system operation conditions the Bouake areaalready benefits of tbe Kossou plant as load generationsupport.
An alternative would be to transfer all the four gas turbines on theshore facing the gas field (Jecqueville Area) and develop the combinedcycle scheme there. The profitability of such a transfer would have tobe shown in the larger framework of the gas development project.
Note on Combined Cycle Plant Availability
The following figures are taken from the "Proceedings of theAmerican Power Conference", Volume 44, 1982. They cover the combinedcycle plants operated in USA at that time.
- Number of units 44
- Total installed capacity 6890 MW
- MW operating over 4000 h/year 3,400 MW
- Best operating heat rate 8,400 Btu/kWh
- Average Capital Cost:
-- Natural Gas 410 US$/kW
- Distillate Oil 430 US$/kW
- Residual Oil 495 US$/kW
- Forced Outage Rate 7.5 Z
- Availability 88.9 X
- Mean Time Between Failure 150 to 300 hours
- Origin of Forced Outages Z hours Z events
Combustion Turbine System 65.3 58.4
Heat Recovery Steam Generator 16.5 20.3
Steam Turbine System 12.7 10.3
Plant Level Equipment 5.4 11.0
- 107 -Annex 4Page 3 of 3
Such values show that the unavailability of combined cycle is directlylinked to that of its components, and very little to the plant levelequipment. This latter source of unavailability is largely offset by thepossibility of operating separately the gas turbines. Of more directrelevance are the excellent availability records found at utilities inthe United Kingdom and Ireland where old steam units were repowered. InDublin, a 105 MW Frame 9 gas turbine was added to an existing 41 NW unitand fitted for fueling by distillate, LPG or treated heavy fuel oil;total cost in 1984 was estimated at $270/kW.
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Annex 5
SWITCHING VRIDI TO CASGAS SUPPLY UP TO 40 MMCFD
Thermal Fuel Requirements al Cost ofGeneration HFO Distillate Gas Liquid Fuels
(CWh) (TJ) (TJ) (TJ) (US$ Million)
1985 720 7488 2088 0 40.71986 549 5710 1592 0 31.61987 365 3796 1058 0 21.61988 836 2717 0 6404 12.01999 949 3084 0 7269 14.01990 805 2616 0 6166 12.41991 554 1801 0 4244 9.01992 641 2083 0 4910 11.01993 396 1287 0 3033 7.21984 118 384 0 904 2.21985 541 1758 0 4144 10.81986 615 1999 0 4711 12.61987 600 1950 0 4596 12.51988 980 3185 0 7507 20.71999 853 2772 0 6534 18.52000 813 2642 0 6228 17.9
2000-2005 880 2860 0 6741 19.4
Actual1985-2000 10335 45272 4738 66650 254.72000-2005 4400 14300 0 33705 97.0
Total 14735 59572 4738 100355 351.7
Present Worth1985-2000 4992 26111 4009 27652 142.12000-2005 726 2360 0 5561 16.0
Total 5718 28471 4009 33214 158.1
Without fuel price escalation 135.4
a/ Generation DispatchUntil 1987, 20% vith gas turbines (1 CWh 10.4 TJ of HFO + 2.9 TJ
of Distillate).From 1988: steam turbines 25% on HFO, 20% on gas combined cycle 55X
on gas (1 CWh = 3.25 TJ of HFO + 7.66 TJ of gas).
- 109 -
Annex 6
THERNAL ALTERNATIVES: FIXED COSTS
Technology Steam Turbines Combined Cycle Gas TurbineFuel Coal Fuel Oil/Gas Distillate or Gas
Reference Plant 2 x 125MW 2 x 125W 2 x 125MW 2 x 35 MW
Investment Cost S/kW 1050 750 525 310
Interest during Construction % 10 10 7 5
Investment Cost + S/kW 1155 825 562 326Interest during construction
t?fe Time years 25 25 15/25 15
Capital Annuity - %/kW/year 11.02 11.02 11.87 - 13.15
SAW/year 127.3 90.9 66.7 42.908N % year 3 3 3 3
SAW/year 31.5 22.5 15.8 9.3Total Yearly Charges SAW/year 158.8 113.4 82.5 52.2
Mean Heat Rate kJ/kWh 11000 10700 9200 14000
a/ With a 10% year discount rate.b/ On the basis of 40% and 60% for the gas and steam turbines respectively.
FUEL COSTS
1987 1995
Heavy fuel oil S/ton 187 269(40 400 kJ/kg) SJJ 4.6 6.7
Distillate $/ton 212 308(41 200 kJ/kg) S/GJ) 5.2 7.5
Coal S/ton 85 85(30 000 kJ/kg) S/GJ 2.8 2.8
Annex 7Page 1 of 2
POSTPONEMENT OF ALL HYDRO PROJECTSFIRM ENERGY BALANCE
1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
DEMANO 2995 3225 3490 3763 4047 4348 4609 4888 5186 5502 5837 6192 6572PLANTS
Ayame 190 190 190 190 190 190 190 190 190 190 190 190 190Kossou 600 125 150 175 200 225 250 250 250 250 250 250 250
Existing Taabo 300 335 370 405 440 485 520 520 520 520 520 520 520In Buyo 600 600 600 600 600 600 600 600 600 600 600 600 6001984 Vrldl ST 1100 1100 1100 1100 1100 700 700 700 700 700 700 700 700
Vrldl GT or CCO 450 750 750 750 750 750 750 750 750 750 750 750 750MIscellaneous 150 150 150 150 150 150 150 150 150 150 150 150 150
Subtotal 3190 3250 3310 3370 3430 3300 3360 3360 3360 3360 3360 3360 3360 F'
New CU1 500 750 750 750 750 750 750 750 750 750 750Soubre 650 1300 1300 1300 1300 1300 1300 1300 1300CU2 a/ 500 750 750Ndleleseo 250 500
Sub Total 500 750 1400 2050 2050 2050 2050 2050 2550 2800 3050
Total 3190 3250 3810 4120 4830 535C0 5410 5410 5410 5410 5910 6410 6660
Balance 195 25 320 357 783 1002 801 522 224 -92 73 218 88
!/ AssumIng the discovery of larger gas reserves; otherwise, gas wIll have to be diverted from other uses,
Annex 7Page 2 of 2
POSTPONEMENT OF ALL HYDRO PROJECTSFUEL REQUIREMENTS
Fiscal Thermal Fuel Requirements Cost ofYear Generation Dispatch HFO Distillate Gas Liquid Fuels
(Cwh) (TJ) (TJ) (TJ) (US $ million)
1985 720 A 7488 2088 0 40.71986 549 A 5710 1592 0 31.61987 365 A 3796 1058 0 21.61988 718 B 2334 5500 10.31989 884 B 2873 6771 13.11990 1588 C 2064 13450 9.81991 1664 C 2163 14094 10.81992 1427 C 1855 10562 9.81993 1060 C 1378 8978 7.71994 1107 C 1439 9376 8.11995 1463 C 1902 12392 11.71996 1733 C 2253 14679 14.21997 1856 D 2413 15368 15.41998 2385 D 3101 19748 20.21999 2615 D 3400 21652 22.62000 2640 D 3432 21859 23.3
2001to2005 2551 D 3316 21122 22.5
Actual1985-2000 22774 47601 4738 174429 271.22000-2005 12755 16580 0 105610 112.5
Total 35529 64184 4738 280039 383.7
Present Worth1985-2000 9145 26497 4009 63748 145.62000-2G05 2105 2736 0 17425 18.5
Total 11250 29233 4009 81173 164.1
Without fuel price escalation 138
A Steam T. 80Z, Gas T 30%B (HPO) 25%, (Gas) 25%, and CC (Gas) 55ZC (HFO) 10%, (Gas) 5%, and CC (Gas) 85ZD (HPO) 10%, and CC (Gas) 90Z
A 1GWh = 10.4 TJ of HFO + 2.97 TJ of distillateB 1GWh = 3.25 TJ of HFO + 7.66 TJ of gasC 1GWh = 1.30 TJ of HFO + 8.47 TJ of gasD lGWh = 1.30 TJ of HFO + 8.28 TJ of gas
Annex 8Page I of 2
DEMOGRAPHIC PROJECTIONS BY REGION (In 1000 Inhabitants)
Rural Population Urban Population Total
1975 1980 1985 1990 2000 1975 1980 1985 1990 2000 1975 1980 1985 1990 2000
Abldjan 87 93 99 103 110 1,017 1,673 2,624 3,966 8,048 1,104 1,766 2,723 4,069 8,158
South 957 1,131 1,294 1,428 1,703 259 355 470 607 938 1,216 1,486 1,764 2,035 2,641
Central-West 623 700 767 821 925 160 219 292 379 589 783 919 1,059 1,200 1,514
South-West 142 170 196 219 265 54 91 146 227 482 196 261 342 446 747
West 626 650 667 681 703 108 141 179 223 323 734 791 846 904 1,026
Central 1,264 1,327 1,375 1,411 1,472 415 605 850 1,158 1,963 1,679 1,932 2,225 2,569 3,435
North 522 522 519 517 512 102 142 189 247 387 624 664 708 764 899
East 342 397 448 490 573 31 46 65 90 154 373 443 513 580 727
Total 4,563 4,990 5,365 5,670 6,263 2,146 3,272 4,815 6,897 12,884 6,709 8,262 10,180 12,567 19,147
- 113 -
Annex 8Page 2 of 2
PROJECTED DEMAND FOR F ELWOOD a/(in thousand m )
Rural Urban Rural Urban Rural Urban1985 1990 2000
Abidjan and SouthFuelwood 1114 597 1224 863 1450 1641Charcoal - 1798 -- 2646 -- 5164Total 1114 2395 1224 3509 1450 6805
Central, Central West and EastFuelwood 2072 454 2178 612 2376 1017Charcoal -- 845 -- 1139 -- 1894
Total 2072 1299 2178 1751 2376 2911
West and South WestFuelwood 691 122 720 169 774 302Charcoal - 227 -- 315 -- 563Total 691 349 720 484 774 865
NorthFuelwood 415 71 414 93 410 146Charcoal -- 132 -- 173 -- 271
Total 415 203 414 266 410 417
Total 4292 4246 4536 6010 5010 10998
Fuelwood 4292 1244 4536 1737 5010 3106Charcoal -- 3002 -- 4273 -- 7892
a/ Based on demographic projections provided in the NationalDevelopment Plan 1981-85. These projections show the resultingdemand if there is no further interfuel substitution or changes incooking habits.
- 114 -
Annex 9
AVAILABILITY OF POTENTIAL FUELWOOD SOURCES
(in thousand m3i)
1985 1990 2000SOUTH AND ABIDJAN-
Logging wastes from natural dense forest a/ 1196 1196 149Land clearing for Sodefor plantations 126 126 126Sodefor thinnings and clearcuts b/ 187 311 401Land clearings for agro-industry 160 160 160Controlled agricultural expansion 40 40 40
TOTAL 1079 1833 876
SOUTH-WESTLogging wastes from natural dense forest 1100 1100 138Land clearings for agro-industry 160 160 160Controlled agricultural expansion 40 40 40
TOTAL 1300 1300 338
CENTRAL WESTLogging wastes from natural dense forest 342 342 43Fuelwo 1 extraction from savanna 144 144 144Land ciearing for Sodefor plantations 82 82 82land clearings for agro-industry 120 120 120Controlled agricultural expansion 40 40 40
TOTAL 728 728 429
CENTRALLogging wastes from natural dense forest 271 271 34Fuelwood extraction from savanna 260 260 260Logging wastes from pre 1966 plantations 3 3 3Land clearings for agro-industry 56 56 56Controlled agricultural expansion 20 20 20
TOTAL 610 610 373
NORTHFuelwood extraction from savanna 184 184 184Logging waste from pre-1966 plantations 1 1 1Land clearing for agro-industry 50 50 50Controlled agricultural expansion 10 10 10
TOTAL 245 245 245
EASTLogging waste from natural dense forest 20 20 3Fuelwood extraction from savanna 11 11 11Land clearing for agro-industry 30 30 30Controlled agricultural expansion 10 10 10
TOTAL 71 71 54
WESTLogging -waste from natural dense forest 1071 1071 134Fuelwood extraction from savarna 10 10 10Land clearing for agro-industries 40 40 40Controlled agricultural expansion 20 20 20
TOTAL 1141 1141 204
a/ Harvestable biomass for fuelwood production (top, branches, rejected logs)assumed to be at least equal to the extracted merchantable logs.
b/ Volumes based on planned thinnings over the next 25 years.
- 115 -
Annex 10
TERMS OF REFERENCE FOR AN IMPROVEDSTOVE PROMOTION PROJECT
1. Study the potential for marketing improved cooking stoves inAbidjan, by: (a) assessing the current cooking practices, the cost and fuelperformance of stove models in use, the impact on the household budget of highwood/charcoal prices stratified by income level and location, consumer prefer-ences in terms of design and manner of use, and the present system of stoveproduction and distribution; (b) evaluating the availability of artisanalskills, materials, alternative sales methods, and retR..1 outlets for the im-proved models; and (c) determining acceptable production cost and user pur-chase price, and appropriate incentive systems for manufacture and adoption ofthe improved stoves;
2. Identify stove models to promote, by; (a) technical work to improvecurrent models and/or design alternative ones, along with cooking utensils;(b) selection of core sample units for initial distribution; (c) field-test-ing, demonstration, follow-up and monitoring of economic and technical perfor-mance and stove acceptability; and (d) further adaptation;
3. Prepare a work program based on the results of the above, delineat-ing: (a) standardized models, production units, procurement of constructionmaterials, and procedures for quality control; (b) training requirements andprograms for stove producers and promoters; (c) schedule of target householdsand number of stoves to diffuse; (d) mechanisms for technical and sociolo-gical backstopping; and (f) promotion techniques.
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