Document of

The World Bank

Report No. 12774-IVC

STAFF APPRAISAL REPORT

REPUBLIC OF COTE D'IVOIRE

PRIVATE SECTOR ENERGY PROJECT

JUNE 6, 1995

Industry and Energy Operations DivisionWest Central Africa DepartmentAfrica Region

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CURRENCY EQUIVALENTS

Currency Unit CFA francCFA franc 1 US$0.001852US$ 1 CFA franc 540

WEIGHTS AND MEASURES

I hectare (ha) 2.47 acresI cubic meter (m3) 37.3 cubic feet1 kilovolt (kV) 1000 voltsI kilowatt hour (kWh) 1000 watt hoursI Megawatt (MW) 1000 kilowattsI Gigawatt hour (GWh) I million kilowatt hoursI mcf 1 thousand cubic feetI bcf I billion cubic feetI bpd I barrel per dayI barrel (bbl) 0.16 cubic metersI Ton of Oil Equivalent (TOE) about 7 bbl of Crude oil

PRINCIPAL ABBREVIATIONS AND ACRONYMS

BOAD Banque Ouest Africaine de DeveloppementBOOT Build-Own-Operate-TransferCAA Caisse Autonome d'AmortissementCFD Caisse Francaise de DeveloppementCIE Compagnie Ivoirienne d'ElectriciteCIPREL Compagnie Ivoirienne de Production d'ElectriciteDCGTx Direction et Controle des Grands TravauxEDF Electricite de FranceEECI Energie Electrique de C6te d'IvoireESAL Energy Sector Adjustment LoanFNEE Fonds National de l'Energie ElectriqueGOCI Government of C6te d'IvoireIPP Independent Power ProducerPETROCI Societe Nationale d'Operations Petrolieres de Cote d'lvoireSAUR Societe d'Amenagement Urbain et RuralSIR Societe Ivoirienne de Raffinage

FISCAL YEAR

Government: January 1 - December 31Energy Sector Enterprises: October 1 - September 30

REPUBLIC OF COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

TABLE OF CONTENTS

Page No.CREDIT AND PROJECT SUMMARY ............................................................ i

I. INTRODUCTION ...........................................................1I

11. MACROECONOMIC SETTING...................

III. ENERGY SECTOR ............................................................ 3A. Background ............................................................ 3B. Energy Sector Reform and the Energy Sector Adjustment Loan (ESAL) ............ ...............4C. Power Sector Reform ............................................................ 5D. Current Issues of Power Sector Reform ........................... ................................. 5

IV. THE PROJECT ............................................................ 10A. Background to Project Development .10B. Project Objectives .13C. Project Description .14D. Project Cost .16E. Financing Plan .16F. Procurement .17G. Disbursements. 1H. Project Implementation, Monitoring and Reporting .19T. Environmental Impact .21

V. FINANCIAL ANALYSIS ................................... 21A. Financial Assessment of CIPREL ................................... 22B. Electricity Sector Financial Evaluation ................................... 23

VI. ECONOMIC ANALYSIS ................................... 23A. Introduction .23B. Electricity Demand .23C. Electricity Supply .24D. Demand Supply Balance. 25E. Least-Cost System Expansion Program .25F. Economic Worth of CIPREL Phase I .25G. Sensitivity Tests .......... , 26

VII. AGREEMENTS REACHED AND RECOMMENDATIONS ............................................... 26

J i ,uTh,IsZs;:sfui ':.t-I l' u A , i.i'm, stsr4.u.w...u0'1 r .:4 *M*) i*t ,~ ,Salid Mihail, Task Manager (Senior Power Engineer, AF4IE), Mark Segal (Senior Economist, AF4IE), andMoiffak Hassan (Petroleum Specialist, Consultant). Legal support was provided by Claudine Morin. Support forProject procurement aangemtnent and disbursement plan was provided by Thu Ha Nguyen. Mess. WilLmPorter (IENOG) and Winston Hay (IENPD) were peer reviewers. Secretarial assistance was provided by PaneaBlytba and Sylvianne Mossu. Mrs. Mary Oakes Smith (AF4IE) and Mr. Olivier Lafourcade (AF4DR), are themanaging Division Chief and Department Director, respectively.

Annexes

Annex 2-1 Selected Economic Indicators

Annex 3-1 Energy BalanceAnnex 3-2 Existing Power Generating FacilitiesAnnex 3-3 The Power Sector Structure

Annex 4-1 Summary of the CIPRELIGOCI ConventionAnnex 4-2 Detailed Project DescriptionAnnex 4-3 Detailed Cost EstimatesAnnex 4-4 Summary of Procurement MethodsAnnex 4-5 Estimated Disbursement ScheduleAnnex 4-6 Project Implementation ScheduleAnnex 4-7 Supervision PlanAnnex 4-8 Environmental Mitigation Measures

Annex 5-1 Project Financial AnalysisAnnex 5-2 Electricity Tariff Formula

Annex 6-1 Economic Analysis

Annex 7-1 Selected Documents in the Project File

MAPS AND DIAGRAMS

Ref. IBRD 26926 C6te d'lvoire - Transmission SystemRef. IBRD 26927 C6te d'Ivoire - Hydrocarbons Concessions and Fields

REPUBLIC OF COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

CREDIT AND PROJECT SUMMARY

Borrower: Republic of C8te d'Ivoire (RCI).

Beneficiaries: Compagnie Ivoirienne de Production d'Electricite (CIPREL); andRepublic of CMte d'lvoire (RCI)

Poverty Category: Not Applicable

Amount: SDR 50.6 million (US$79.66 million equivalent).

Terms: Standard IDA, with 40 years maturity including a ten year grace period.

OnlendingTerms: RCI would onlend to CIPREL US$50 million equivalent of the credit at an interest

rate of 8 percent for 17 years including a five year grace period. The creditbalance of US$29.66 million remains with Government to finance theComplementary Sector Investments and the Institutional Building Components ofthe project. This amount would also refinance the PPF advances of US$2.0million.

Financing Plan: See para. 4.16

Rate of Return: 34 percent

Staff AppraisalReport: 12774-IVC

Map: IBRD 26926 C6te d'Ivoire - Transmission SystemIBRD 26927 C6te d'Ivoire - Hydrocarbons Concessions and Fields

L. INTRODUCTION

1.1 Cote d'lvoire is one of the principal countries in the CFA zone, with a population of about13.5 million and a GDP of US$6.7 billion in 1994. High population growth and the deep recessionof the 1986-1993 period have resulted in a steady fall of living standards. GNP per capita in 1994was estimated at about US$525 compared to well over US$1,000 in the early 1980s. Followingthe devaluation of the CFA franc in January 1994, the economic decline has been reversed and theGovernment is now attempting to accelerate economic growth through the implementation of astabilization program and of structural reforns as well as through the promotion of investmentprojects, including the proposed Private Sector Energy project.

1.2 The Country Assistance Strategy (CAS) was prepared in the wake of the devaluationand discussed by the Board in June 1994. The CAS supports the Government's objectives ofincreasing real GDP growth and strengthening extemal and internal competitiveness, as formulatedin last year's PFP and its recent update covering the 1995-97 period which has been circulated tothe Board in April 1995. Major priorities in the FY95-97 CAS are to help the Govermment: (i)maintain macroeconomic stability and strengthen public sector finances through reforms in bothrevenue and expenditure, (ii) promote private sector development through continued liberalizationof trade, financial and labor markets, and through investments in productive activities, includingenergy, (iii) increase the effectiveness of the human resources development progran throughincreased focus on primary health care, AIDS, basic education, and population policy, (iv)strengthen institutional capacity through existing IDA-supported technical assistance programs,and (v) intensify environmental work through projects and the National Environment Action Plan(NEAP) process.

1.3 The assistance strategy is being implemented through (i) active portfolio management,involving enhanced project supervision and elimination of undisbursed IBRD balances, (ii) anintensified policy dialogue on macroeconomic, sector-specific, social, and environmental issues,(iii) adjustment lending in support of policy reforms in agriculture, transport, private sectordevelopment, and finance, and (iv) a reactivation of the project pipeline. The proposed PrivateSector Energy project is an integral part of this effort.

1.4 The proposed project aims to continue C6te d'Ivoire's process of reform in the energysector which was initiated under the Energy Sector Adjustment Loan (ESAL) (Loan 3150-IVC) in1989/90 . The ESAL made a significant contribution in improving efficiency in the energy sectoras well as in promoting private sector participation through the privatization of the management ofthe electricity production, transport, and distribution. The proposed project continues this effort tostiengthen private sector development in this sector through the financing of Phase II of theprivately owned and operated power plant developed under a Build-Own-Operate-Transfer(BOOT) arrangement. The proposed project has been closely coordinated and prepared with theIFC which is cofinancing Phase I of the power plant.

H. MACROECONOMIC SE1TING

2.1 Medium Term Strategy. Following the CFA franc devaluation, the Governmentreformulated its economic and social program and spelled out its new stabilization and structuraladjustment program in a Policy Framework Paper (PFP) which has been updated to cover the

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1995-97 period. The PFP aims at: (i) increasing real GDP growth to annual rates in excess of 6.5percent, beginning in 1995 (Annex 2-1), (ii) generating sustained and increasing primary budgetsurpluses, (iii) increasing public sector efficiency through institutional reforms and an accelerationof the privatization program, (iv) strengthening external competitiveness through trade, price, andregulatory reforms, and (v) intensifying human resource development and increasing efforts toalleviate poverty. These objectives have been translated into a comprehensive reform programranging from policy actions in the fiscal, trade, and price areas to reforms that stimulate privatesector development and improve the delivery of basic social services.

2.2 Deepening public sector reform is a central element of the strategy, involving reductionand streamlining of the civil service, institutional capacity building and public enterprisedivestiture. Inter alia, this will involve strengthening certain ministerial capacities, improving themanagement of domestic budgeting and the external public debt, accelerating the privatizationprocess, creating a legal framework compatible with dynamic private sector development (asbusiness confidence is presently undermined by outdated laws and shortcomings in the judiciarysystem). The Government has selected 42 enterprises for privatization during the 1994-1996period. For monopolistic enterprises, the privatization process will include the adoption of a clearand transparent regulatory framework defining the conditions under which they will operate'.

2.3 In addition to the rehabilitation effort, important steps were taken in 1994 towardliberalizing the economy and reducing the role of the public sector. The Government dismantledsome non-tariff barriers, adopted a new labor code which liberalized hiring and firing procedures,privatized several enterprises, and started restructuring several public enterprises in the agriculturaland transportation sectors.

2.4 Economic Trends in 1994. Preliminary results for 1994 suggest that with the paritychange and the implementation of the accompanying fiscal, monetary, and structural adjustmentpolicies, the Ivorian economy has been able to strengthen its international competitiveness andrestore economic growth. Real GDP growth was 1.7 percent in 1994 versus -0.8 percent in 1993.The Government succeeded in reducing inflation to pre-devaluation levels within 8 monthsfollowing the parity change. During the last quarter of 1994 the monthly inflation rate was 0.3percent. This was largely achieved by a restrictive monetary and fiscal policy. In this context,fiscal policy has been the cornerstone of the stabilization program. The Government met itsrevenue and expenditure targets throughout 1994 and generated its first primary balance surplus inthe 1990s. Expenditures were tightly controlled by increasing base wages on average only by 10percent, thereby reducing the Government's wage bill from almost 13 percent of GDP in 1993 to9.5 percent of GDP in 1994. The same policy stance was adopted by the private sector. TheGovernment also unblocked on schedule the three-month price freeze on 34 products it had enactedimmediately following the devaluation and adjusted utility tariffs, including water (15 percent),electricity (20 percent), and public transport (40 percent).

These provisions reflect forthcoming developments in the power sector. While EECI is not yet onthe privatization agenda, this is an option to be examined in the power sector institutional study to befunded under the proposed project. This study will also include proposals for improving powersector regulation, insofar as some aspects of the supply system will require a regulatory framework.

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m. ENERGY SECTOR

A. Background

3.1 Total energy consumption in 1990 amounts to 3.2 million tons oil equivalent (TOE)(Annex 3-1). The main sources of energy are biomass, hydrocarbons, and hydroelectric power.Abundant forestry reserves have traditionally been the major source of energy (over two-thirds oftotal energy consumption), but intensive exploitation and land clearing are threatening both thesustainability of fuelwood supply and the environment.

3.2 Fuelwood and charcoal supply originates mainly from land clearance for agriculture, atthe expense of rapidly diminishing forestry reserves, now reduced to about 8 million hectares.Clearing is expected to continue at a rate of at least 250,000 bectares per year, compared toreplanting of only 5,000 hectares. The widespread and growing use of charcoal as a fuel and thelow conversion efficiency of wood into charcoal (only 12 percent of the primary energy isconserved in the final product) accounts for a large indirect demand for fuelwood. There is a riskof fuelwood shortages in the not-too-distant future, and, more importantly, the concomitant risk ofirreversible damage to the environment, unless more efficient ways of producing, replenishing andusing fuelwood are widely introduced and household consumers switch to alternative fuels such asbutane and kerosene.

3.3 Exploration for hydrocarbons commenced onshore in the 1950s but failed to identifysignificant hydrocarbon deposits there. Since 1971, exploration focused on the offshore basin,initially conducted by major companies such as Exxon, Shell and Phillips, then by the nationalcompany PETROCI and small independcnts like United Meridian of the USA. The early effortsresulted in the discovery of several significant oil and gas accumulations: Exxon found the Belieroil field in 1974; and Phillips discovered in 1979 the Espoir oil field and several oil and gasstructures including Foxtrot, Lion and Panthere. Belier and Espoir were developed and exploited,but abandoned recently due to either depletion or high operational cost. In 1989, Phillipsrelinquished all their acreage and termiinated their activities in C6te d'lvoire due to the lack of aremunerative market for gas. Since 1990, the Government, with the help of the Bank, the JapaneseGovernment and the African Development Bank has successfully revived the interest of foreigninvestors in the hydrocarbon sector, amended the fiscal and contractual terms to provide moreincentive for exploration and development of oil and gas resources, and carried out two explorationpromotion campaigns. These efforts resulted in the conclusion of several Production SharingContracts (PSC), with the private sector, for the exploration and development of hydrocarbonresources. Two PSCs were signed with a group of investors represented by United Meridian Co.(UMC)) of USA, for the offshore blocks Cl-l I (Lion and Panthere fields), Cl- I and CI-2. AnotherPSC was concluded with another group of investors represented by Apache of USA for theoffshore block CI-27. The latter agreement replaced the Convention Generale concludedpreviously with the same group for the development of the Foxtrot field. (Map IBRD 26927 showsthe location of the different concessions and hydrocarbon fields).

3.4 Petroleum products are supplied from an efficient modern refinery - "Socite ivoiriennede Raffinage "-SIR (3 million tons per year capacity) owned by the Ivorian subsidiaries of seveninternational petroleum companies and the Governments of C6te d'lvoire and Burkina Faso. Therefinery is located at Vridi near Abidjan and in addition to supplying the Ivorian market, exports

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significant quantities of petroleum products within the West African region. The refinery producesabout 22,000 tons of Liquified Petroleum Gas (LPG) per annum. Its utilization is concentrated inurban areas. The stagnation of utilization is mainly due to supply and marketing constraints. Theproposed project includes preparation of a program for developing the LPG market.

3.5 About 25 percent of the population has access to electricity. Supply of electricity isprovided by a combination of hydro and thermal facilities. Total system capacity is about 918MW (Annex 3-2). The hydroelectric system, with 604 MW, represents two-thirds of the installedcapacity. The Kossou hydroelectric plant, designed as a multi-annual storage reservoir, has neverfunctioned anywhere near its design capacity, because the reservoir has never filled up since itsconstruction in 1972. The hydro-electric production potential is highly variable from year to year,depending mainly upon rainfall. CMte d'lvoire also possesses a thermal power plant located in Vridion the outskirts of Abidjan . This plant has an installed capacity of 314 MW, but due toinadequate maintenance over the years, operates at much below capacity. CMte d'Ivoire has beenpurchasing electricity from Ghana; however, growing Ghanaian demand and the need torehabilitate its hydro system have curtailed exports to CMte d'Ivoire. Ghana now imports some ofits electricity needs from CMte d'Ivoire. With the improving macro-economic climate in C6ted'lvoire, domestic demand for electricity is expected to resume the growth recently interrupted byseveral years of recession. These developments mean that new generation capacity is urgentlyneeded. (Further analysis of electricity supply and demand is in Chapter VI).

B. Energy Sector Reform and the Energy Sector Adjustment Loan (ESAL)

3.6 Before the ESAL was implemented in 1989, electricity and petroleum supply were in thepublic sector, with little private sector investment. Until the late 1970's, energy sector performancewas satisfactory; however, the heavy public sector investment progran triggered by the coffee andcocoa boom did not leave the energy sector untouched. The public sector electric utility "EnergieElectrique de C6te d'Ivoire" (EECI) launched an investment program of questionable economicjustification, which ultimately jeopardized the very existence of the company. In 1975, theGovernment created a national petroleum company (PETROCI) and at about the same timeinduced the petroleum distribution companies to build, and subsequently expand, the SIR refinery(in which the Government holds 45 percent). The Government took fifty percent share holding intwo private petroleum product distribution companies, and a public sector petroleum productstorage company (GESTOCI) was created, as was a bitumen company (SMB).

3.7 The debt service associated with this public investment program and the inefficiency ofpublic sector management substantially increased the fixed costs of supplying energy. Thus, by thetime the ESAL was under preparation in 1989, the prices of electricity had risen to an average ofUS$0.18/kWh and gasoline to over US$4.50 per US gallon (at the exchange rate of the day).Nonetheless, EECI was unable to maintain a positive cashflow and built up very substantialarrears. By the time the sector was reorganized (Section C below), arrears had reached over one-fifth of the country's total internal arrears, placing the country's fiscal position at risk. At thesame time, international oil prices were declining. Therefore international petroleum companies lostinterest in marginal exploration territories such as CMte d'Ivoire, and private investment in thecountry's energy sector declined to zero.

3.8 In 1988, the Government undertook a reform of the energy sector, supported by the Bankin the form of the ESAL, presented to the Board in December 1989. In the hydrocarbons subsector,the program sought to redefine and refocus the role of PETROCI, promote the hydrocarbon

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potential of Cote d'Ivoire to the international petroleum industry to encourage investment inpetroleum exploration, and rationalize petroleum product pricing and taxation. The ProjectCompletion Report of this operation (Report No. P-5165-RCI) indicates that the program waslargely successful in these areas. Subsidies have been removed from petroleum product prices andtaxation was rationalized; however, product price changes are not systematically linked tointernational price movements.

C. Power Sector Reform

3.9 It was in the electricity subsector that the Government undertook the most far-reachingreforms. At the time the program was implemented in 1990, EECI was effectively insolvent (lossesfor this year alone amounted to more than US$240 million). Rather than undertaking a financialrestructuring, the Government decided to privatize management of the power sector. In November1990, with the assistance of the Bank, the Government negotiated and signed a ConcessionAgreement with a group of two foreign companies, transferring operation and regular maintenanceof the power system to the "Compagnie Ivoirienne d'Electrcit " (CIE), which pays a leasing feeto the Government for its use, while leaving in the hands of EECI the sector's assets, stewardshipover system expansion and renovation and supervision of the concession agreement between GOCIand CIE. The tariff to the consumer was brought down by about 10 percent, but recently increasedas a result of the January 1994 devaluation. It now averages 57.3 CFA franc per kWh (orUS$0. 106/kWh at the current exchange rate).

3.10 Building upon this first success with private sector participation, the Government invitedthe private sector to build, own and operate a new power plant, which is being done by CIPREL, aconsortium owned largely by Bouygues and "Electricite de France" (EDF). The CIPREL facilityis being built in two phases: as provided for in the agreement between GOCI and CIPREL, Phase I(the first 99 MW) was financed by the private sector, while Phase 11 is to be financed by publicfunds. The proposed project supports the Phase II development under the GOCI/CIPRELagreement. CIPREL assumes responsibility for the commissioning date of Phase I and plantavailability for the whole facility (about 165 MW total capacity operating at a minimumavailability factor of 77 percent), while CIE (through FNEE) undertakes to buy energy at aminirnum load factor of 77 percent, the amount depending upon the installed capacity. Phase Iwas conmmissioned on schedule in March 1995.

3.11 Given the need to re-establish the power sector's financial equilibrium and the presence ofnew corporate entities in the industry, the Government has created a new financial mechanism, the"Fonds National de l'Energie Electnique" (FNEE), lodged within the "Caisse Autonomed'Amortissement" (CAA), for better tracking and managing the flow of funds through the powersector. The present structure of the power sector and the relationships between the various entitiesis shown in Annex 3-3.

D. Current Issues of Power Sector Reform

3.12 Largely on account of the structural transition occurring in the sector, it has becomeimnportant to review and refine the allocation of certain power sector responsibilities, in order toassure an orderly and efficient future development of the power system. The experience of the pastseveral years has indicated that the following five subject areas deserve further attention:

(a) Responsibility for and implementation of system planning

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(b) Responsibility for and implementation of renewal/rehabilitation

(c) basis of tariff setting and mechanism for tariff adjustment

(d) Financial regulation of debt service and consumption arrears

(e) Functional responsibilities and competition policy

System Planning

3.13 There does not appear to be an institutional focal point adequately equipped to carry onsystem planning, and assure on-going coherence between the investment programs in generation,transmission and distribution. Furthermore, the very role of public sector system planning needs tobe re-conceptualized in the context of a system with private sector participation. System planningwill most likely remain a necessary public sector function, both to help identify requirements forwhich the Governnent will seek and negotiate private sector support, and to indicate those areas ofcomplementary investment in which the public sector may have to participate. Hence the issueswhich need to be resolved in this area are as follows:

- What is the role of system planning in a market-oriented private sector "IPP"environment?

- Should the three planning functions (generation, transmission, distribution) beallocated to one institution, and if so, to which one? If not, how will coherence ofsystem planning be assured?

e All three areas of system planning need technical strengthening.

These matters will be addressed in the institutional arrangements study (para 4.13 (a)(i)).

Renewal and Rehabilitation:

3.14 As operator of the power system, CIE is not responsible for major maintenance andrehabilitation. This remains the responsibility of EECI. As system operator, CUE notifies EECI ofactual or impending problems involving maintenance and rehabilitation beyond the terms of CIE'sconcession, whereupon EECI is supposed to remedy these difficulties. In practice, CIE has beenundertaking rehabilitation, according to two supplements to the agreement between CIE and theGovernment (supplements "A and B')2 Supplement "A" is financed through a fee which CElevies at source through the tariff. Supplement 'B"is supposed to be financed through FNEE, butthe sector is not generating enough net cash flow through FNEE to support this work.3 It wouldappear that the split of responsibility between EECI and CIE, while clear in principle, in practicehas been recast for reasons of expediency. Hence the key issues which need resolution in this areaare:

2 The supplements are available from the project fle.

3 Part of the problem is due to arrears on Govermnent's electricity bills, discussed below.

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* Which entity should be responsible for major maintenance and rehabilitation, theprivate sector operator, or the public utility? If not the private sector operator,how will this responsibility be addressed effectively?

* How should this work be financed?

These questions will be addressed in the Institutional Arrangements study (para 4.13(a)(i)).

Tariffs: Basis and Adjustment Procedures

3.15 The present level of tariffs in Cote d'Ivoire appears reasonable, however, three tariffmatters deserves review for the future: (i) the level of the tariff, (ii) the tariff structure, and (iii) thetariff adjustment mechanism. Regarding the level, at US$0.106/kWh, the Cote d'Ivoire electricitytariff is in the higher range of international retail electricity prices. GOCI would like to reduce thetariff if the introduction of natural gas-based energy supply made this feasible. A key factoraffecting future tariff requirements are the incremental expenditures on transmission anddistribution (T&D). In countries at C6te d'Ivoire's level of electricity market penetration, the costof T&D can exceed the cost of generation. Available data indicates that this is indeed likely to bethe case in Cote d'Ivoire. Hence the grid extension program, the technical standards adopted andimplementation arrangements will add to Long Run Marginal Cost (LRMC) and contribute totariff requirements, making it necessary to review and integrate the investment program for theseitems in the tariff setting process. Also germaine to the tariff setting process is the structure of thetariff - that is the prices charged to each customer class, and the shaping of the tariff within theseclasses. These matters have not been reviewed for quite some time in C6te d'Ivoire, hence theeconomic appropriateness of the price signals going to the consumers is not self-evident, anddeserves review.

3.16 There is not a regular, systematic process in place for reviewing and adjusting theelectricity tariff. The latest tariff change after the devaluation was prepared by "the Direction etControle des Grands Travaux" (DCGTx)4 and agreed between the Ministries of Mines andEnergy, Industry and Commerce and the Finance and Planning Ministry (on behalf of the PrimeMinister's office). It consisted of a devaluation adjustment based on the pre-existing structure.5 Tosome extent, tariff adjustment "looks after itself' through the contracts entered into between theState and the private sector operator. The private sector insures that its services are adequatelyremunerated, and the State enables it to collect these revenues from customers. However, becausethese contracts do not cover all of the aspects of electricity supply which incur costs, thecontractual mechanism is not a sufficient approach for tariff setting. The FNEE has beenestablished recently as a mechanism for assuring the financial equilibrium of the sector, but it isnot authorized to set tariffs. Furthermore, its structure is embryonic. It consists of a designatedgroup of officials which meets periodically, but has no supporting secretariat to co-ordinate andfollow-up on the work of the delegates. This arrangement will be examined in the proposedinstitutional study under the project.

4 DCGTx is the Government arm exercising control on the investment projects.

Given the already high level of tariffs, the increase was less than proportionate to the devaluation.

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3.17 These considerations suggest that the following tariff issues deserve attention:

* The level and the structure of the tariff should be reviewed for (i) their adequacyto satisfy financial performance criteria and (ii) their economic efficiency.

* Appropriate institutional arrangements for adjusting tariffs remain to bedeveloped. The tariff adjustment process should be timely, transparent, systematicand technically based.

A tariff study is proposed under the Power System Investment study (para 4.13(a)(ii)) toaddress these matters. Pending completion of this study, the Government is committed tointroduce a formula which adjusts the current tariff so as to meet satisfactory financialperformance criteria. The proposed tariff formula and implementation are discussed inChapter V (para 5.8).

Financial Regulation of Debt Service and Consumption Arrears

3.18 Before the devaluation, relevant power sector institutions knew what was the initial debtcontracted with each creditor. Since these loans were contracted, there have been cancellations, re-schedulings and early pay-outs. With devaluation, the sector's total obligations have been packagedand rescheduled. This is handled by the Caisse Autonome d'Amortissement (CAA), and the powersector does not have a clear picture of the debt being serviced on its behalf. For purposes ofassessing the financial adequacy of the tariff, it would be essential to re-construct a comprehensivedebt service schedule by creditor under existing debt-service and "on-lending" arrangements.

3.19 The financial equilibrium of the sector is impaired by the accumulation of Governmentalarrears for its own electricity consumption. Annual Governmental consumption amounts to aboutCFA franc 12 billion (US$22 million), and the estimate of the unpaid balance in December 1994was CFA franc 32 billion (US$59 million) or 2.7 years' worth of Governmental consumption. With1994 sales revenue at about US$215 million, annual Government consumption is about 10 percentof the total and Government accumulated arrears amount to about 27 percent of one years' sales.The Government has been '"vorking down" these gross outstandings by paying contributions todebt service directly to the CAA. However, this is a situation which, for both financial andeconomic reasons, cannot be allowed to persist. At present, the Treasury is responsible for payingall of the Government's electricity bills, after the bills have been verified. This approach is notconducive to adequate discipline over electricity use at the point of consumption.

3.20 The following issues need to be addressed in order to rectify the Governmental role in thefinancial status of the power sector:

* An up-to-date, detailed debt service schedule by creditor needs to be compiled, anda commercially-based "charge-back" to the power sector determined. This will beaddressed in the tariff study.

* A plan is needed for capping the amount of Governmental arrears on electricityconsumption, and settling it and a system is needed to insure that no furtherarrears will accumulate on Governmental consumption.

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These matters will also be addressed in the tariff and institutional arrangement studies.During negotiations, agreement was reached that CAA will prepare a detailed schedule forthe sector debts no later than February 1, 1996 and that Government arrears to the sectorwill be settled by June 30, 1996.

Functional Responsibilities and Competition Policy

3.21 While EECI is titularly the "maitre d'oeuvre" and "maltre d'ouvrage6" of the powersector, in practice its role is more limited. For example, (i) the Government has assumed ownershipof the sector's productive assets; (ii) DCGTx has a major role in system planning, contracting andimplementation, (iii) the FNEE is in charge of the sector's financial equilibrium, and (iv) theMinistry of Mining and Energy has a role in supervision of the sector. Nonetheless, EECI has astaff of about 180 people and a current budget projection in the range of US$5.5 million. Thecompany has a core of well-qualified technical staff who know the sector and have considerableexpertise to contribute. However, as a corporate group, its functional pre-eminence in the powersystem has been eclipsed due to problems of corporate performance which the new structures havebeen created to resolve. Today, EECI's work is complementary rather than competitive with CIE:it undertakes transmission and distribution project planning and implementation (some of which isdone in-house, some contracted out). While it is responsible for renovation of the power system, agood part of this work has been contracted to CIE .

3.22 EECI, an entity of considerable prominence within the political hierarchy of the country,will have to re-define its role in the context of a restructured power system. While some"unbundling" of power generation from transmission and distribution is necessary to theintroduction of competition and private sector participation, it carries special transitional problemsfor the incumbent and the system as a whole, such as moving from control to collaboration, andadapting from a supplier-oriented to a customer-oriented market mentality. The company faces adifficult challenge to make this transition, and it is a concern of GOCI and lenders to the powersector.

3.23 The present system structure is not competitive. It is a set of complementary institutions,which need to be well co-ordinated so as to minimize overlapping control and responsibility, whileinsuring that important matters which need co-operation do not "slip between the cracks". To somenotable extent, this is being achieved on certain project initiatives by teamwork between therelevant parties - for example the CIPREL project was conceived and negotiated on the Coted'Ivoire side by a working-level team of staff from the Ministry of Energy, EECI and DCGTx,reporting to the Minister of Mines and Energy. The same team structure is now handling Phase IIof the project. Important to the longer-term sustainability of sector efficiency is the introductionof: (i) competition where competition can efficiently regulate prices and supply, and (ii)appropriate regulation or co-ordinating mechanisms, as needed to manage or co-ordinate otheraspects of system operation.

3.24 Hence the issues arising from this overview of sector structure and competition policy are:

6 "Maitre d'oeuvre" is the party responsible for supervising the tendering, contracting and projectsupervision process. "Maitre d'ouvrage" is the owner of the assets.

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* the future role and structure of EECI should be re-defined in the context of apower system likely to become increasingly unbundled over time;

* arrangements remain to be developed for systematically opening the sector tocompetition at such a time and for those functions where competition wouldenhance sectoral efficiency;

* appropriate regulatory and co-ordinating mechanisms are needed to administernon-competitive functions and those requiring co-ordination to assure the system'sefficacy.

3.25 The project includes four provisions for addressing the above-mentioned issues, to resultin specific implementation measures over 1996-1997 to be coordinated with IDA.

* a review of system planning

* a tariff study and tariff adjustment mechanism.

* a review of sector structure, allocation of responsibilities and financialmanagement of the sector.

* preparation of standard bidding documents for IPPs.

3.26 During negotiations agreement was reached that GOCI will consult annually with IDA andother donors in the sector on the power sector investment program, and that before undertakingmajor changes to the organizational structure of the electricity sub-sector which may have anadverse impact on the objectives of the Project, GOCI shall exchange views with IDA.

3.27 GOCI supports the encouragement of more private investor participation in the powersector as weli as the above mentioned institutional development initiatives (para 3.25). Thesecommitments are reflected in the GOCI Letter of Sector Development Policy (LSDP) (available inthe Project File). Agreement on the LSDP was reached during negotiations, and IDA has receivedthe LSDP, signed June 1, 1995.

IV. THE PROJECT

A. Background to Project Development and Rationale for IDA Participation

4.1 GOCI has made a solid commitment to private investor participation in the power sector(Chapter III), firstly in 1990 by leasing the system to a private consortium, subsequentlyproceeding with the development of the "Foxtrot" project, then modified, as explained in para 4.3and 4.4, to become the United Meridian Corporation (UMC) natural gas development and CIPRELpower projects. The CIPREL project is the first commissioned IPP in Africa.

4.2 The Bank has been assisting GOCI since the late 1980s with refonn of the energy sectorunder the ESAL and since 1990 with the development of the Foxtrot project. Foxtrot, and thesubsequent UMC and CIPREL projects, were designed to involve private sector resources andskills in the development of C8te d'Ivoire's indigenous natural gas resources in line with a least-cost

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electricity supply strategy. Foxtrot was the first field to have demonstrated sufficient reserves to beof interest for project development. Thus, Foxtrot was to have been an integrated scheme in whicha new private energy company would sell electricity and natural gas to CIE, natural gas to SIR andindustrial customers, and Natural Gas Liquids (NGLs) to SIR.

4.3 However, during project preparation in late 1993/early 1994, work was proceeding (byUMC with financial support from IFC) on proving-up the potential of the Lion and Panthere fields.Through this period there was an open issue of the gas development strategy - i.e. the sequencingof field development. During this period, the Bank was assisting GOCI's energy strategydevelopment through in-situ technical assistance and on-going dialogue between Bank staff andtheir Ivorian counterparts. At the time of the Foxtrot project appraisal (January 1994), the Foxtrotfield was the most obviously "ready" candidate for early development, and it appeared to be aneconomic fuel source. The timing and nature of the final results from work on the other two fieldswas not known at the time, and there was some urgency to moving forward, given the importanceof securing the power supply with additional thermal capacity. Hence the appraisal proceeded onthe basis of priority to the Foxtrot field.

4.4 Within a few months after appraisal, UMC confirmed sufficient hydrocarbon potential inthe Lion and Panthere fields to justify reconsidering the gas development strategy. Moreover, theLion field contains oil and associated gas, whereas Foxtrot is only non-associated gas. ThereforeGOCI approached the Bank with the idea of delaying Foxtrot, but moving forward with Lion andPanthere in order to produce the oil from the Lion field, while at the same time generatingelectricity with the associated natural gas. This necessitated splitting the natural gas and electricitycomponents into separate projects, and negotiating new agreements with the different entities foreach component. The Bank indicated its willingness to appraise an amended project developmentstrategy involving private investors in the electricity subsector, indicating that any eventualfinancing from the Bank would only be complementary to that of the private sector and supportiveof a stronger private sector role in the power system. GOCI issued requests for proposals to privatesponsors and selected a consortium of Bouygues/EDF which formed the nucleus of CIPREL(Compagnie Ivoirienne de Production d'Electricite).

4.5 CIPREL's proposal was to develop a power plant in two phases with total capacity of165 MW, costing approximately US$106 million of 1994 (Phase I US$68 million, Phase II,US$38 million). During contract negotiations 7 all reasonable attempts were made to achieve asubstantial equity share in CIPREL, and to find private money to finance Phase II. The financialstructure which emerged reflected the exposure limits of the private sector and other lenders on thisoperation: GOCI and CIPREL signed a contract wherein the CIPREL group assumedresponsibility for financing the first 100MW (Phase I), and which required that the Government beresponsible for financing the remainder (Phase II). CIPREL's financing of Phase I is 25 percentequity and 75 percent debt, the lenders being IFC, Cafssefranpalse de Developpement (CFD) andthe Banque Ouest-Africaine de Developpement (BOAD). Under the proposed project, GOCIwould borrow from IDA the financing it is committed to provide for Phase II. The Governmentloan of IDA funds to CIPREL on commercial terms would be complementary to the resources thatit was possible to raise from the private sector. The financial structure (firm for Phase I andenvisaged for Phase II) is given in the table below:

7 The Bank's on-going technical assistance to GOCI's energy sector development strategy providedsupport to this process.

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Table 4.1: Project Financial StructureCFA franc million

ouw Phane Percent Phase II Percent Total Parecmk

ToWa Colt 36,700 20,700 57,400

Equity 9,200 25.0 n/a 9,200 16.0

WFC A Loon 9,200 25.0 Ufa 9,200 16.0CFDlLon 13,800 37.7 n/a 13,800 24.1BOAD Loan 4,500 12.3 n/a 4,500 7.9IDA on-lent ILA 2Q7 10 20.Q70

Total Debt 27,500 75.0 20,700 100 48,200 84.0

4.6 The GOCI/CIPREL General Agreement of July 1994 is a significant event in thedevelopment of private power in sub-Saharan Africa, insofar as it is the first of its kind in thatarea: an IPP BOOT (without an obligatory transfer of the property back to the Government). Thekey cmmarcial features of this agreenent are summaized in Annex 4-1. In essence, CIPRELassumes responsibilities to the State for completion, completion delay, cost over-rn, annual

act quantity, maintenance, repair and renovation, while the State has a minimum paymentoligation, a fuel supply obligation, and a right to buy-back the plant after ten years of operation.Every year GOCI and CIPREL will agree on actual production from the CIPREL units, so as todispatch the entire electricity supply at least cost.

4.7 The proposed credit, would support significant and far-reaching developmental objectiveswith respect to the overall technical integrity of the power system, and most importantly, theefficacy and sustainability of reformed sector structures (see chapter III). The LSDP statedobjectives include reducing costs, improving efficiency, and avoiding monopoly in powergeneration. To this effect, it wiU invite independent power producers (IPP) to build the powerplants needed in the future. No one group would be allowed to hold more than a predefinedpercentage of the country's electrical capacity, the intention being to foster competition.

4.8 System expansion analysis undertaken for the proposed project indicates that futurecompetition among private power producers should be possible. Three kinds of competition maybe envisaged: competition for the market, competition within the market, and competition inprocurement. As a result of the economic recovery accompanying the structural adjustmentprogram agreed with the Bank and the IMF, over the past year electricity demand grew by about 7percet. Future demand is expected to grow by at least 5 percent per year, given that only 25percent of the population have now access to electricity. Under these demand conditions, Coted'Ivoire would need about 260 MW beyond the CIPREL project, over the next 10 years to bedeveloped in four or five increments individually timed to match requirements. This would allowopen competition (based on least-cost criteria) for different groups to enter the market with newcapacity, fueled by naturl gas (Chapter VI). Hence the beginnigs of compettive marketconditons are foreseeable. The process of selecting CIPREL was competitive and the contract costof Phase I was at CIPREL's risk. The Phase II gas turbine costs (resulting from ICB andnegotiaed financing terms) will be passed through the power price which CIPREL charges thepower sector. In these conditions, another element of competition - competitive procurement - isneeded to assure least-cost inplementation of Phase II. IDA financing of these turbines entails thesupport and advice required to achieve this objective.

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4.9 CMte d'Ivoire requires financial and technical support to pursue its agenda of institutionaland structural reform along the lines indicated above. This is consistent with the main objective ofIDA's on-going participation in the development of CMte dlvoire's power sector, which is tosupport the necessary deepening and progression of institutional and structural reform. Inparticular, IDA would be providing important support to the development of competitive marketstructures in the power sector, thereby increasing the role of future private investors in the sector.This includes the development of transparent arms' length regulatory processes, clear principles oftariff setting, clarification of the roles and responsibilities of the various public sector entitiesactive in the power sector, and establishment of pro-competitive "rules of the game" throughstandard bidding documents for forthcoming IPPs, which are all necessary components forimplementing a sectoral framework conducive to attracting a wide range of competitors for amarket share in the generation segment of CMte d'lvoire's power sector.

4.10 "Complementary investments" are necessary to assure the technical integrity of the powersystem, and the proposed project makes provision for them (para 4.13(c)). These investments relatemainly to the power transmission and transformation segments of the system. These segments areunder private sector management, but the public sector owns these assets and is responsible formajor maintenance and renovation, which is now essential to system reliability and theeffectiveness of private sector operations - be it for CIE's management functions or the utility ofthe CIPREL investment. Hence, here as well, IDA financing is complementary to the private sectorinput and necessary to sustain it.

4.11 The Bank's policy on lending to the electric power sector states that Bank lending forelectric power will focus on countries with a clear commitment to improving sector performance inrespect of (i) transparent regulation, (ii) corporatization, commercialization and private sectorparticipation, and (iii) contracting-out of services. C6te d'Ivoire has demonsaed this clearcommitment with the actions it has taken on sector reform to date, including those embodied in thisproject (chapter mI and para 4.13(a)). The use of IDA resources for this project also recognizesthat C6te d'lvoire is a heavily indebted country, recently emerging frorn a long period of recessionwith the help of a Bank/Fund adjustment program, an important element of which Was the halvingof the exchange rate between the CFA franc and the French franc. In sum, the proposed IDAcredit is consistent with the country assistance strategy (Chapter I) and would support anintegrated package of goods, services and advice all designed to assist the progress of C8ted'Ivoire's power sector into increasingly pro-competitive, private sector modes of operation.

B. Project Objectives

4.12 The objectives of the proposed project are to:

(a) continue the restructuring of power sector institutions begun under the ESAL,particularly an appropriate regulatory fiamework and strengthened institutionalcapabilities, thus enabling the development of competitive and expanded privatesector participation;

(b) improve power supply reliability, reduce enviromnental impacts and reduce thecost of electricity by supporting efficient gas-fired capacity using indigenousnatural gas developed under a private sector BOOT arrangement; and

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(c) enhance operational reliability and efficiency through reinforcement andimprovements of the transmission system.

C. Project Description

4.13 The project includes the following three major components, contents of which are detailedin Annex 4-2

(a) Institutional Development Component

(i) Power Sector Management Study, including:

* distribution of sector responsibilities* development of a power sector regulatory framework* assessment of manpower planning and training requirements* implementation proposals

This work arises out of needs identified in paras 3.12 to 3.25. It will identify theroles and responsibilities of each entity in the sector. The regulatory frameworkwill be designed to operate within the Government's policy framework at arms'length of the utilities and the Government. It will help promote an environment ofefficient private sector participation, while protecting the public interest. It willmainly cover entry, performance monitoring and terms and conditions of service.Training needs for public administration of the recommended sector structures willbe identified, and arrangements for implementing these proposals put in place.(terms of reference are in the Implementation Manual). Detailed terms ofreference were agreed during negotiations.

(ii) Power System Investment, Operations and Pricing Study, including:

* preparation of load forecast (including scope for demand management)* development of a least-cost system expansion (generation, transmission,

distribution, loss reduction)* tariff study (including revaluation of major fixed assets and pricing

formulas)

Load forecasting and system planning work will be necessary for administering anorderly and efficient process of expanding private sector involvemnent. It will giveguidance to the Government for the kinds and amounts of investments to elicitfrom the private sector, evaluating the merits of proposals put before it, and - asthe private sector will not finance everything - judiciously selecting acomplementary public investment program. The tariff study is essential for puttingthe process of electricity pricing and price adjustment on a transparent, arms'length, technical basis which meets satisfactory economic efficiency and financialperformance criteria (terns of reference are in the Implementation Manual).Detailed terms of reference were agreed during negotiations.

(iii) Measures to Encourage Further Sector Privatization:

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* standard IPP bid document* study to determine the cost of energy from Vridi steam thermal units and

their future role in the power generation in RCI.

The standard IPP document will give the Government an instrument for efficientlyattracting and evaluating a broader range of potential private sector entrants intofuture, new generation projects. With regard to existing capacity, the steam unitscannot produce at design capabilities without substantial rehabilitation.Alternative studies have varied on the merits of undertaking this work. A studywill be carried out to determine the feasibility of withdrawing these units from theCIE concession for a private sector rehabilitation and operation under a powerpurchase agreement with CIE (terms of reference for the preparation of thesedocuments are in the Implementation Manual). Detailed terms of reference wereagreed during negotiations.

(iv) Hydrocarbon Sector Studies:

* hydrocarbon production and distribution system planning* butane utilization and implementation arrangements

This group of studies will focus particularly on the organization and allocation ofresponsibilities for up-stream activities, relationships between private sectorparticipants and electricity producers, enabling conditions for competition, safetystandards, technical standards, and environmental legislation. Also, an analysis isneeded of prospective hydrocarbons supply, demand and production/marketingstrategy, to assure an optimal exploitation of the resource base. The developmentof the natural gas resource will also enable the development of an LPG industryfor domestic consumption and export, for which a development and productionstrategy analysis is needed (terms of reference are in the Implementation Manual).

(b) Generation Expansion

Generation expansion comprises supply and erection of one or two identical simplecycle gas turbines of capacity between approximately 75 MW and 105 MW'; Thegas turbines will constitute Phase II of the CIPREL power plant, located at Vridi;the plant layout for the gas turbines will be designed such that a heat recoveryboiler could be added at a later stage in order to operate the units as a combined-cycle plant; and engineering and construction supervision.

(c) Complementary Sector Investments

This includes extension of the 90 kV substation at Vridi to accommodate theCIPREL power plant capacity expansion; reinforcement of the transmissionsystem around Abidjan in order to improve system reliability in case of loss of the225 kV transmission line, including for this purpose: extending the 90kV

This capacity range is designed to allow the maximum number of manufacturers of gas turbines toparticipate in the bidding process, within the limits of the capacity required at this time.

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transmission system between Treichville and Plateau substations (comprising twocircuits of 90kV cables of about four kilometers each and associated substationequipment), and tapping the 90kV transmission line between BiaSud and Ayameat Riviera substation; rebuilding the Treichville 90/15kV substation; andreplacement of some 60 kilometers of l5kV paper-insulated cables.

D. Project Cost

4.14 The total cost of the project, including contingencies and interest during construction, isestimated at US$86.29 million. The foreign exchange component is about US$81.94 million,equivalent to approximately 95 percent of the total project cost. The cost of the private sectorgeneration component is about US$50 million.

4.15 The project base cost is in January 1995 prices. Physical contingencies of about 10percent for goods, works and services have been applied except for the power plant (CIPRELPhase II), no contingencies have been included. Price escalation based on the Unit Value Index ofManufactured Exports (MUV Index) of 2.5 percent per year, are also included. In accordancewith agreements entered between the Government and CIPREL there are no taxes and dutiesapplicable to the project. A summary of project cost is provided in the table below; Annex 4-3provides a detailed cost estimate.

Table 4.2: Components Pro ect Cost Summary

*~~~~~~~~~~~O I ,6'i ,40 : . ,, i: ::. , tCMA frame m.) (UB$ U..) P.MW4U XdLocal Fore4n Total L-oa }konlg Taiy Luhampl. Coart

1. Power Genration Expansion - 27,000.00 27,000.00 - 50.00 50.00 100 632. Power Systn Reinforcement 1,714.50 9,652.50 11,367.00 3.13 17.88 21.05 85 273. Institutional Building 299.70 4,139.05 4,48S.75 0.56 7.76 8.31 93 12

Total Baseline Coas 2,014.20 40,841.55 42,855.75 3.73 75.63 79.36 95 100Physical Contingencies 200.34 1,363.64 1,563.98 0.37 2.53 92.90 87 4Price Contingencies 130.66 877.31 1,007.97 0.24 1.62 1.87 87 2

Total Project Cosb 2,345.20 43,082.49 45,427.69 4.34 79.78 24.13 95 106IntaereDuingConst.uction - 1,166.30 1,166.30 - 2.16 2.16 100 3

Tota Costs to be Fbnunced 2,345.20 44,248.79 46,594.00 4.34 81.94 86.29 95 109

Figures may not add-up due to rounding.

E. Financing Plan

4.16 An IDA Credit of US$79.66 million equivalent is proposed to the Republic of Cotedlvoire. Of this amount US$50 million would be on-lent to CIPREL under a Subsidiary LoanAgreement between the Government and CIPREL for the Phase II of CIPREL power plant. Theon-lending terms would be 17 years (the duration of the concession of CIPREL) including 5 yearsgrace at 8 percent per year. The S years grace are to allow for the debt service payment forCIPREL Phase I, which has an average amortization period of about 10 years, withoutjeopardizing the sector. The balance of the project cost US$6.62 million will be financed by thesector. Tle remaining US$29.66 million of the lDA Credit would finance the foreign exchangecomponent of the Power System Reinforcement and the Institutional Building Components. Ihefinancing plan is given in the table below. The signature of a Subsidiary Loan Agreement between

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GOCI and CIPREL satisfactory to IDA, would be a condiion of Credit Effediveness (para7.2(a)).

Table 4.3: Components by Financiers(USS million)

Amout %- A&6rn No ...........

Power Plant 50.00 100.0 - - 50.00 59.4 50.00 -

Goods, and Works 20.25 87.2 2.96 12.8 23.21 27.6 20.54 2.67Cosulking Services 8.26 84.6 1.50 15.4 9.76 11.6 8.26 1.50Training 1.16 100.0 - - 1.16 1.4 0.98 0.17

Total 79.66 94.7 4.46 53 84.13 100.0 79.78 4.34

F. Procurement

4.17 The following procurement arrangements have been agreed with the GOCI and thedeveloper of the BOOT power plant (CIPREL).

Table 4.4: Procurement Arrangements(US$ million)Procurement Method

16tirnational LimitedC:::I :Xompetitive Interoational0:4Biddlnz Bidding Other N.BLF. Total

Power Plant 48.30 48.30(48.30) (48.30)

Transmission and Substations 21.98 21.98(19.60) (19.60)

Goods 0.35 0.30 0.59 1.24(0.35) (0.30) (0.65)

Consultant Services 9.45 9.45(7.95) (7.95)

Training 1.16 1.16(1.16) (1.16)

Miscellaneous PPF Advance 2.00 2.00(2.00) (2.00)

Interest During Construction 2.16 2.16Total 70.28 0.35 12.91 2.75 86.29

(67.90) (0.35) (11.41) (79.66)Note: Figures in parenthesis are the respective amounts financed by IDA.

NBF denotes non-bank financing.

4.18 The Power Plant (CIPREL Phase II) will be procured through ICB in a single lot (supplyand erection) including civil works and all auxiliaries. No prequalification was carried out,however, the bid documents include post-qualification requirements. The capacity of the powerplant has been defined in the bidding documents as a range between 75 and 105 MW in order to

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allow the maximum number of manufacturers and suppliers to bid while fulfilling the powersystem capacity requirement.

4.19 The substation and transmission system expansion and reinforcement will be procuredthrough ICB in four separate lots for supply and erection. No prequalification will be carried out,however, post-qualification requirements will be included in the bidding documents. The 15kVcables will be procured through ICB. The installation of the cables will be carried out by localcontractors and supervised by EECI.

4.20 Goods contracts for the supply of equipment and vehicles will be procured through ICBwith the exception of (i) goods estimated to cost less than US$200,000, which in aggregate will notexceed US$350,000, and will be procured through LIB, and (ii) goods estimated to cost less thanUS$50,000, which in aggregate will not exceed US$300,000, will be procured through Shoppingby comparing price quotations obtained from at least three reliable suppliers, to ensure competitiveprices.

4.21 IDA-financed consultancy contracts totaling about US$8 million will be awarded inaccordance with IDA's Guidelines for the Use of Consultants (August 1981). During negotiations,it was agreed that all construction will be supervised by consultants acceptable to the Associationunder agreed terms of reference and following Bank guidelines. Training programs would beapproved annually. A detailed procurement table giving the estimated man-months for consultingservices and the procurement methods is given in Annex 4-4.

4.22 Procurement review. All contracts for goods and works exceeding USS200,000 will besubject to prior review. Bank standard bidding documents and standard contracts appropriatelymodified to meet project needs, would be used for procurement of goods, works and services.Contracts for goods under international or local shopping will be subject to random post review.All procurement for services exceeding US$100,000 for consulting firms and US$50,000 forindividuals will be subject to prior review, and other procurement for services will be subject topost review. IDA continues to require prior review for (i) terms of reference of consultant contractsregardless of value; and (ii) any standard documents that the Borrower(s) intends to use repeatedly.Prior review will consist of reviewing bidding documents, advertisements, advertising procedures,prior to solicitation of bids, as well as reviewing bid evaluation reports and proposed contractawards. Agreement on the above procurement arrangements was reached during negotiations.

G. Disbursements

4.23 The project is expected to be completed by June 30, 1999 as shown in Annex 4-5.Disbursement per category is indicated in the following table. Given the availability of the SpecialAccount (SA), the minimum application for direct payment by IDA would normally be for theequivalent of 20 percent of the initial deposit to the SA. All withdrawals from the credit accountwould be fully documented except for expenditures relating to trining, contrcts for goods andworks costing less than US$200,000, which will be eligible for reimbursement on the basis ofStatements of Expenditures (SOE). SOE would also be used for consultants services contractscosting less than US$100,000 for firms and US$50,000 equivalent for each individual.Documentation of SOEs will be retained by DCGTx on behalf of the Project Unit and will be madeavailable for review by IDA supervision missions and auditors.

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Table 4.5: Disbursements

Category Amount (USS MW) 04Fibinced by MA- 04

1. CIPRELA. Power Plant 48.30 100 FE and 80 LEB. Engineering Services 1.70 100 T

2. GOCIA. Transmission and Substations 17.00 100 FE and 80 LEB. Equipment and Vehicles 0.65 100 FE, 100 LEXF, 80 LEC. Consultant Services and Training 6.74 100 T

3. Refinancing of PPF 2.00 Amount Due4. Unallocated 3.27

Total 79.66

4.24 Special Account. To facilitate disbursements, a SA for GOCI would be opened in theCAA. The initial deposit would be in CFA franc equivalent to US$1.0 million estimated to coverproject expenditures for about four months. The SA will be replenished by submitting withdrawalapplications to IDA on a monthly basis, or more often when the account is diminished by one-third.Replenishment applications submitted against the SA will include a bank statement showingaccount activity since the last application, with the balance certified by the CAA holding the SA, areconciliation statement and supporting documents as required by IDA. As a condition ofeffectiveness, GOCI will open a Project Account (PA) and deposit CFA franc equivalent toUS$200,000 (para 7.2(b)). It was agreed during negotiations that the amount in the ProjectAccount would be replenished on a quarterly basis up to US$200,000 equivalent or when the PAbalance is less than US$50,000 equivalent.

4.25 Accounting and Auditing. Project account will be maintained by the Project Unit(para 4.26) in accordance with generally accepted accounting standards (IASC). Audited accountsand reports, prepared by independent auditors, would be submitted to IDA no later than six monthsafter the end of each fiscal year. These will include the audit of CIPREL accounts. The auditor'sreport on project expenditures will verify that (i) project accounts pennit identification of allreceipts and payments, (ii) goods had been received or work performed, (iii) payments had beenmade, (iv) all expenditures had been legitimate, and (v) the SA have been used appropriately. Theauditors will provide an opinion on the reliability of the SOE procedures and on whether the goodsand services acquired under the project were being utilized in accordance with its objectives. Theauditors would also prepare the audit report including the management letter revealing possibleshortcomings in the staffing, accounting system and efficiency of the internal control procedures.The appointment of auditors, acceptable to IDA will occur no later than six months after crediteffectiveness. Assurances on the foregoing were obtained during negotiations.

H. Project Implementation, Monitoring, Reporting

4.26 The power generation component will be implemented by CIPREL. CIPREL, the owner,will also be the engineer supervising the construction of the plant. CIPREL has alreadyimplemented Phase I of the power plant (99 MW), which is now in service less than eight monthsfrom contract signature. With the capacity of Phase II being defined as a range between 75 to 105MW, the convention between GOCI and CIPREL and the legal agreement between CIPREL andits lenders, for Phase I will have to be amended to reflect the capacity of the lowest evaluatedbidder. During negotiations, agreement was reached with GOCI on all the articles that will have to

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be amended in the General Agreement between GOCI and CIPREL and the Loan Agreementsbetween CIPREL and its Phase I lenders prior to contract award for Phase HI. As a condition ofcredit effectiveness, all amendments to existing contractual agreements wil have to be approvedand signed by the respective parties (para 7.2(c)). The Complementary Sector Investments,including the reinforcement and extension of the transmission system, will be implemented by theexisting Project Unit assited by EECI. The Project Unit, which comprises staff from DCGTx,EECI and the Ministry of Mines and Energy was established by Ministerial Order No. 028 ofJanuary 15, 1995 in support of activities financed under the PPF. The Institutional DevelopmentComponent will be implemented by Project Unit assisted by the Ministry of Mines and Energy,DCGTx and PETROCI. During negotiations, agreement was reached with GOCI to maintain theProject Unit for the duration of the Project with membership and responsibilities satisfactoryto IDA.

4.27 Consulting firms will be retained to assist the Project Unit in the preparation of engineeringstudies, preparation of tender and contract documents, and evaluation of bids for the proposedComplementary Sector Investments. These consulting firms will also assist in the constructionsupervision for the substations and line works. All lines and substations works will be wellcoordinated with CIE, the power system operator, who will also participate in the review of theengineering design and construction supervision. Terms of Reference for the studies and technicalservices have been agreed during negotiations.

4.28 The project is expected to be completed by June 30, 1999. The combustion turbines willbe operational by early 1997. The Project Unit is preparing an implementation manual for theproject. This implementation manual will include all terms of reference for the studies, theimplementation timetable, performance targets and performance indicators. Contents of theimplementation manual were agreed during negotiations. Presentation of the final ImplementationManual by GOCI to IDA is a condition of effectiveness (para 7.2(d)) A project implementationschedule is set out in Annex 4-6.

4.29 Supervision Plan. The proposed project would require careful coordination and frequentIDA supervision. The key areas for supervision are (i) periodic monitoring of the progress oninstitutional studies and development plans, (ii) periodic review of the implementation ofinstitutional studies recommendations, (iii) periodic review of regulatory initiatives, (iv) monitoringthe compliance with covenants and the Letter of Sector Development Policy, (v) technicalsupervision of CIPREL Phase R power plant and the complementary power system reinforcements,and (vi) review and follow-up of procurement and disbursement. During supervision, the Bankwould undertake a review of the Bank-financed procurement.

4.30 Procurement information would be collected and recorded as follows: (i) prompt reportingof contract award information by the borrower, (ii) comprehensive quarterly reports to the Bank bythe borrower (assisted by consultants), indicating: (a) revised cost estimates for individualcontracts and the total project, including best estimates of allowance for physical and pricecontingencies, (b) revised timing of procurement actions, including advertising, bidding contractaward and completion time for individual contracts; and (iii) a completion report by the borrowerwithin six months of the credit's closing date. Supervision of the project would require expertise inpower systems engineering, economic and financial analysis and environmental engineenng. Therewill be a review of implementation progress for CIPREL Phase II, no later than June 30, 1996,covering CIPREL's performance on execution of Phase II, procurement, record keeping, audit andenvironment. There would be a mid-term review in early 1997, with the participation of the

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Government and IDA. The review will conduct a comprehensive assessment of progress ofphysical components and agree on actions required, if necessary to ensure the meeting of projecttargets. Among other things, the review will cover performance of CIPREL, EECI, DCGTx andthe Project Unit, achievement of institutional objective, Borrower, FNEE and CIPREL compliancewith financial and audit obligations, execution of Phase II of the CIPREL Power Plant andcomplementary sector investments, evolution of key performance indicators and environmentalfactors.

I. Environmental Impact

4.31 Key project objectives are to improve the efficiency and reliability of the power supply andto reduce the environmental impacts through the transition from the use of liquid fuels and biomassto natural gas. Positive global environmental impacts are therefore expected from the project aswell as localized benefits through a decrease in air pollution in the Abidjan area (reduction of No.SO and C02). A full Environmental Assessment (EA) has been carried out in a form acceptableto IDA for the Foxtrot project. The EA was later amended to reflect the changes in the projectscope. The project design includes a series of measures that the project sponsor (CIPREL) willtake to minimize all potential negative environmental impacts. These measures are summarized inpara 4.32 and listed in detail in Annex 4-8.

4.32 The main environmental issues identified in the EA relate to noise level, risk of oil spills,waste disposal and risks of fires and explosions. The noise level of the gas turbines will not exceed85dB at one meter, as a result of adding acoustic enclosures. The new gas turbines will not affectthe present noise level at nearest residential areas. With regard to oil spills, the existing oil tanks inVRIDI site have been refurbished and checked before use. For the tanks on CIPREL site, aretention basin is installed with a complete fire protection and detection system. Liquid wastes aredrained to an existing settling pit and after separation, water is sent to the VRIDI collection andrejection system. There are no other liquid effluents from the gas turbines. Gas and fire detectionsystems, as well as fire fighting systems consisting of CO2 for the gas turbines, water for theoverall site and foam injection for the oil storage tanks will greatly minimize the risks of fires andexplosions. In addition, there will be regular monitoring of alarm and fire fighting systems. Theproject envisages significant amount of training and skills development for staffing in the area ofsafety and environmental monitoring.

V. FINANCIAL ANALYSIS

5.1 The financial analysis provides an assessment of the financial status of CIPREL, and ofthe electricity sector's financial equilibrium over 1994/95 - 2004/05. The analysis assumes a 189MW installation in accordance with IDA proposed financing. Annex 5-1 provides a detailedfinancial analysis of CIPREL and Annex 5-2 an analysis of the electricity sector financialequilibrium.

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A. Financial Assessment of CIPREL

CIPREL Ownership and Financing Structure

5.2 CIPREL is a private holding company created for the purpose of the project. The majoritystake in CIPREL (75 percent) is held by VALENER a company incorporated in C6te d'lvoire ofwhich 65 percent is held by SAUR, a wholly-owned subsidiary of Bouygues and 35 percent byEDF International, a wholly-owned subsidiary of EDF. Other project lenders (IFC, CFD andBOAD) and PETROCI hold the remaining 25 percent of CIPREL's equity.

5.3 For the financing of the first phase (99 MW), equity financed 25 percent of project costsand private long term debt the remaining 75 percent. The second phase (75 to 105 MW ISOConditions or 65-90 MW site rating) will be financed by a long term loan from the Republic ofCMte d'ivoire to CIPREL, onlending IDA resources. As a result, the initial debt:equity ratio of75:25 will be increased to 86:14 (Annex 5-1, Table 1).

CIPREL Key Financial Information

5.4 The Convention between the Republic of CMte d'Ivoire and CIPREL provides thefrarnework for defining CIPREL production levels and revenues. With gas turbines totaling 189MW of site capacity and annual production levels and pricing based on provisions of theConvention, CIPREL's base case annual revenues in constant 1994 units are estimated to be about$28.8 million (Annex 5-1). CIPREL key financial indicators are shown in table below.

Table 5.1: CIPREL - Key Financial Indicators

-1995196 1997198 2007/08 2012/13

Revenues 15.10 28.80 28.80 28.80

Operating Income 5.83 14.30 14.20 14.20

Net Income 0.02 5.49 7.69 9.21

RATIOSOperating Income/Net revenues 0.39 0.50 0.49 0.49

Operating Income/Average 0.09 0.14 0.28 4.88fixed assets in operationDebt Service Coverage .90 2.63 3.29 n/aDebt:Equity Ratio 86/14 86/14 42/58 0/100

Project Financial Returns

5.5 With an installation of about 189 MW, the CIPREL financial rate of return is estimated tobe 15.8 percent and the rate of return on equity is estimated to be 21.4 percent. Tax on dividendsdepends on nationality, and is 12 percent for French investors; there is no withholding tax ondividends paid to international institutions such as IFC, CFD and BOAD.

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B. Electricity Sector Financial Equilibrium

5.6 This analysis compares the electricity sector financial requirements once the project iscommissioned with the revenues provided by the current tariffs and develops proposals forelectricity tariff policy. The sector includes operating entities such as CIE (managing public sectorassets), EECI (holding public sector assets), CIPREL, FNEE and certain functions of DCGTxcharged to the sector.

5.7 The 1995 average revenue of CF'A franc 571kWh (US$0.106/kWh) will be adequate tocover all costs, service the sector debt and provide for a self-financing ratio usually exceeding 20percent (Annex 5-2). Given the reduction of fuel costs due to use of natural gas, there wouldappear to be some room for a slight decrease in tariffs. However an immediate tariff reduction isnot recommended. Tariff reduction may leave the sector with little flexibility in face of unexpectedevents such as poor rainfall or unavailability of gas. Finally, a review of external debt serviceobligations and the sector investment program is necessary for underpinning future tariff policy.

Electricity Tariff Adjustment Formula

5.8 Adjustment to electricity tariffs does not follow well-established and transparent rules. Inorder to provide for a rational and transparent tariff setting framework, the Government willestablish a periodic adjustment mechanism ensuring that: (i) tariffs are adequate to cover operatingcosts, debt service and a minimum 20 percent self-financing of the investment program; (ii)increases or decreases in costs are born by or benefit the end-users. During negotiations, the GOCIDelegation put forward a proposal for annual adjustment of the tariff based on the tariff beingsufficient to meet certain financial performance criteria, details of which are outlined in Annex 5-2.Under this proposal, the tariff would be sufficient for the power sector to earn at least 8 percentrate of return on its net assets in operation, provided that this rate of return is consistent with a debtservice ratio of 1.5, an operating ratio below 0.85 and self-financing ratio of at least 0.2.Assurances to that effect were obtained during negotiations.

VI. ECONOMIC ANALYSIS

A. Introduction

6.1 The economic analysis of the project begins with the load forecast, the supply capability ofthe existing system, and identifies the need for additional capacity as the deficit between expecteddemand and available supply. The analysis then assesses whether the proposed project is the least-cost system expansion option. Once confirmed as the least-cost option, the internal economic rateof return is calculated on the basis of incremental economic benefits relative to incrementaleconomic costs, and sensitivity tests are done to assess the impact of changes in key uncertainvariables on the project's internal rate of return.

B. Electricity Demand Forecast

6.2 The base case load growth projection broadly reflects a positive medium term economicoutlook for the country. Most significantly:

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* GDP growth is expected to be about 6 percent in 1995/96, with expected goodperformance of the industrial sector and an up-take of private consumption induced partlyby the devaluation of the CFA franc;

* the Government has indicated its intention to pursue a high growth strategy combined withsound monetary and fiscal policies, and has established targets as well as an enablingstrategy in close consultation with the IMF and the Bank;

* over the long term in the past (Annex 6-1, page 1), growth of electricity consumption hasoutpaced that of the key economic variables underlying that consumption, largelyreflecting a relatively high growth rate of new customer connections and resilience ofconsumption per customer, which are expected to continue into the future.

6.3 Under the circumstances, load growth should be no less than 5 percent per year over thenext three years, and based on an econometric projection, 5.2 percent per year thereafter9. In thecase of Cote d'Ivoire, provided that the load will not actually decline, the accuracy of the longerterm load forecast is not critical to project risk: once the natural gas supply is established, currentinformation indicates that the least-cost generation expansion program should consist of gasturbines, which can be sized and timed appropriately with load growth, as perceived quite soonbefore investment. The load forecast assumes no real increase of tariffs.'0

6.4 With the development of economic natural gas-based gas turbine capacity, C&te d'Ivoirewill become well positioned to export electricity to neighboring countries. An export contract for60 GWh/year to Burkina Faso is in place, and the transmission interconnection project underway.This export is included as a firm load in the forecast. Two other export contracts were undernegofiation at time of post-appraisal: 50 MW continuous to VRA (Ghana) and 30 MW continuousto CEB (Togo and Benin), subject to annual review of quantity and price. These recentdevelopments are not included in the load forecast.

C. Electricity Supply

Hydro Plants

6.5 Performance of the hydro system has been highly variable; however, it is reasonable touse a figure of 1216 GWh/year to represent "expected" hydro production for simulating "normal"operation of the systen and 565 GWh for firm supply capability. (Annex 6-1, page 2)

Thermal Plants

6.6 The mission reviewed recent operational experience with the existing thermal plants, andthe contractual performance commitments for the CIPREL Phase I facility, which has beencommissioned in March 1995. Annex 6-1, page 2 shows the up-dated estimates adopted forsysten planning and simulation.

9 This would reflect a long-tenn GDP growth projection of about 5 percent per year.

l0 Since the early 1980s, the real average tariff has fluctuated within a very narrow range, with no trend eitherup or down. A case could be made for reducing tariffs once natural-gas and hydro based generation providea substantial portion of total supply, however, before doing so, it is important to establish the futureprogram and costing of transmission and distribution system expansion.

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D. Demand: Supply Balance

6.7 Annex 6-1 (page 2) indicates that the system as presently installed (including CIPRELPhase I) is energy constrained: there is not enough energy generation capability to meet thesystem's annual energy requirements on a firm basis. Before considering any export to VRA orCEB, and including CIPREL Phase I, without additional capacity there would be an energy-relatedcapacity deficit of about 44 MW in 1995, growing to 63 MW in 1996 and 323 MW by 2005. Therequired timing and amount of new capacity was broadly confirmed in modeled system simulationruns, which provide a more detailed assessment of usable capacity and optimal dispatching on amonth to month basis over the entire simulation period.

E. Least-Cost System Expansion Program

6.8 Generation system expansion costs are determined primarily by the cost, size and timing ofnew power plants, and the cost of fuel. Gas turbines provide the lowest capital cost per kW andquickest construction and commissioning cycle of any thermal plant. CMte d'Ivoire's gas turbineexpansion program is based on indigenous natural gas, which is now being developed in parallelwith the CIPREL Phase I power plant. The existing gas turbine plant, currently using oil, will beconverted to natural gas in late 1995/early 1996. The natural gas volumes likely to be needed forpower generation and SIR over the next twenty years were estimated and compared with the knowndeliverable reserves from Lion, Panthere and Foxtrot. These reserves will be adequate to meet therequirements till near the end of the study period (2009/10), when small make-up volumes fromother sources (identified but not delineated) may be needed.

6.9 The economic cost per mcf of natural gas to the power sector was estimated on the basis ofthe gas sales contract, taking into account current projections of requirements and world oil pricesyielding US$0.87/mcf (equivalent to about $5.20/bbl oil). As there is no cheaper combination ofcapital and fuel costs for thermal generation, and no hydro development of this size in CMte d'lvoirewhich could compete with these costs or be developed as quickly, gas turbines using natural gas isthe least cost strategy of system generation capacity expansion. Nonetheless, the economic cost ofsubstituting low-speed Diesel plant for the proposed investment was estimated in order to measurethe extent of the gas turbines' advantage over the next best option. The present worth costs (10percent discount rate) of the gas turbines versus low speed Diesel as the first plant after CIPRELPhase I are as follows:

Table 6.1: Present Worth Cost Comparison.USS millionX

Technolo gytttff- 0000t0:000000000-t;0900-00$-0030itft Ca ig0ta Operat ng Fuel T otal

Low Speed Diesel 165 62 73 300CIPREL Phase n 132 53 60 245Net Advantage of CIPREL Phase II 55

F. Economic Worth of CIPREL Phase II

6.10 The economic worth of the investment is indicated by the economic internal rate of return(EIRR) of incremental benefits relative to incremental costs over a twenty year period of systemdevelopment and operation based on the least cost system expansion strategy. The incremental

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benefit per kWh is the average tariff (US$0.106/kWh) ", less the incremental economic costs oftransmission and distribution (T&D) estimated at USS0.058/kWh (at 10 percent social discountrate), yielding USS0.048/kWh at point of generation. Incremental energy sales in GWh are thedifference between sales which the system can supply with system expansion and those assumingno expansion. Total incremental benefits are incremental sales times US$0.048/kWh.

6.11 Incremental costs are derived from sinulating system operation with and without thegeneration expansion program over the twenty year economic life of the proposed project. WithCIPREL Phase n1 of 66 MW, the EIRR to the net cash flow is 34 percent (Annex 6-1, page 3 & 4).If CIPREL Phase II were a 90 MW plant, and assuming about 5 percent decrease of plant cost perkW, 7 percent fuel efficiency increase, displacement of fuel oil use in 1996 and reduction in size ofthe first increment aflter CIPREL, the EIRR would be 35 percent with no change in the loadforecast. The apparently high EIRRs occur because the average tariff is high, while theincremental system cost of generation (at 10 percent social discount rate) is relatively low(US$0.042/kWh).

G. Sensitivity Tests:

6.12 The Base Case EIRR is tested for uncertainty of key factors as follows:

Table 6.2: Sensitivty Testsa'ab les New E ---

Incremental T&D cost increased from US$0.058/kWh to USS0.064/kWh 10Load growth reduced from 5.2 percent to 3.5 percent per year 15Project commissioning delayed by one year 19Plant cost increased by 20 percent 26Fuel Cost increased by 20 percent 21Plant and fuel cost increased by 20 percent each 16Plant and fuel cost increased by 20 percent each with low load growth 7

CHAPTER VII

AGREEMENTS REACHED AND RECOMMENDATION

7.1 During negotiations, agreement was reached on the following matters:

(a) CAA will prepare a detailed schedule for the Power Sector debts no later thanFebruary 1, 1996 (para 3.20);

(b) GOCI commitment on settlement of Government electricity bills within threemonths of billing date and settlement of arrears by June 30, 1996 (para 3.20);

This implicitly assumes that neither the real tariff netback nor the struture of sales between tariffcategories will change significantly over the evaluation period.

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(c) annual consultation between GOCI and IDA on the power sector investmentprogram (para 3.26);

(d) before understanding major changes to the organizational structure of theelectricity sub-sector which may have an adverse impact on the objectives of theProject, GOCI will exchange views with IDA (para 3.26);

(e) letter of sector development policy (para 3.27);

(f) detailed terms of reference for the studies to be financed with the IDA credit (para4.13).

(g) procurement to be done according to World Bank policies and procedures (para4.17 to 4.22);

(h) project account to be replenished when the balance reaches US$50,000 equivalent(para 4.24).

(i) audits of the project accounts and the special accounts and the status of IDAcredit disbursements to be done by independent auditors to be appointed no laterhan six months after credit effectiveness (para 4.25);

(j) annual financial audit of CIPREL (para 4.25);

(k) agreement on the list of clauses in GOCI/CIPREL Convention that need to bemodified prior to the award of the contract for Phase II Gas Turbines (para 4.26);

(I) GOCI to maintain the Project Unit for the duration of the project (para 4.26);

(m) Implementation Manual (para 4.28);

(n) presentation of semi-annual progress reports by the Ministry of Mines and Energythrough the Project Unit (para 4.30);

(o) implementation review of CIPREL Phase II by June 30, 1996 and mid-termreview of project implementation before June 30, 1996 (para 4.30);

(p) principles and timing for periodic adjustment of electricity tariffs (para 5.8);

(q) contents of the Subsidiary Loan Agreement (para 4.16).

7.2 Conditions of Credit Effectiveness:

(a) Signing of Subsidiary Loan Agreement between the Government and CIPREL(para 4.16);

(b) Opening by GOCI a project Account and depositing US$200,000 equivalent(para 4.24);

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(c) Signing of all amendments to the convention between GOCI and CIPREL and theLoan Agreement between CIPREL and its lenders for Phase I (para 4.26);

(d) Adoption and presentation by GOCI to IDA an Implementation Manual for theProject satisfactory to IDA (para 4.28).

7.5 Recommendation: On the basis of the above agreements, the proposed project is suitablefor an IDA credit of SDR 50.6 million (US$79.66 million) to the Republic of Cote d'Ivoire atstandard terms with maturity of 40 years including 10 years grace.

ANNEX 2-1

COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

SELECTED ECONOMIC INDICATORS

1994 1995 1990 1597*st rev. pam.

A. Baance of Paymonts (1)

Exports 1538.4 1749.7 1886.3 2050.4Imports -784.6 -916.8 -1048.1 -1187.5Service reciepts 240.7 281.1 308.7 340.2Service payments -995.8 -1102.5 -1127.5 -1150.4Net transfers -141.6 -157.2 -174.0 -191.0Current Account -142.9 -145.7 -154.6 -138.3Official project loans 64.3 87.7 105.2 115.8Other bi/multilateral 495 329.8 284.8 0Central Gov. amortization -360.6 -422.5 -369.8 -324.2Public entr. amortization -19.4 -16.7 -15.7 -15.6Other capital (priv. etc.) 206.1 9 21.2 6.2Capita Account 385.4 -12.7 25.7 -217.8Overall Balance 242.5 -158.4 -128.9 -356.1Financing -242.5 158.4 128.9 49.7Balance 0 0 0 -306.4

B. Selected Macro-Economic Indicators (1)

Real GDP; % per year 1.3 6.5 6.4 6.6Nominal GDP (FCFA billion) 3729 4382 4850 5374GDP deflator (%/year) 39.2 10.3 4.0 3.9Consumer Price Index (%/year) 25.9 6.4 5.6 5.6e As a percent of Nominal GDP:'Public Sector Consumption 14.4 12.8 11.8 11.0'Private sector consumption 60.2 61.3 63.1 64.0'Public sector gross fixed capital formation 4.6 4.5 4.2 4.4*Private sector gross fixed capital format'n 7.7 9.4 10.2 10.8

Net Savings 12.3 14.0 14.8 16.2

Nomina Exchange Rate (rounded) 555 534 538 544

Source: Draft Policy Framework Paper, February 16, 1995,

COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

Energy Balnce 1989/90

(toe)

PRIMARY ENERGY DERIVED ENERGYAgdl & DomeuTo Totl Total non TOTALFoet Hyr1.- Other Supe nd Db..d l In-Procm Pct,oemm Enery rated

Flrewood Residue. Elect. Crude 01 Feedtock Charcoal Ebeotdahy LPG petrol Kogene Ge ON Fuel Feedutock Producat Product.

Raw SupplyProduction 3,283 595 326 106 10 4.320Impors 2,354 539 25 2,918Prknary Exports OUnused Supply -172 -172Stock Movemwnts -128 24 -104

Total Aval. Supply 3,283 423 326 2,332 573 25 6*,f2

ConversionPetoeum Refinig 2,332 -573 28 429 504 822 801 177 2.561 67 -277Charcoal Production -1,623 -106 415 -1,314Elatukity Production

Thermal 48 -37 -118 -155 -107Eleobiity Prdo

Hydno -326 126 -200Trans. & Dist. Leases -32 -32Stock Movernents 1 -19 -12 28 37 35 35

Not upIy 1m660 317 416 167 29 410 492 813 520 177 2,441 67 5,067

Secondwry Exports -3 -234 -346 -352 -394 -177 -1,506 -49 -1,555Bunker -76 -122 -79 -277 -277

Not ntemnl Con. 1,660 317 415 167 26 176 70 339 47 G6M 18 3,236

ndustry 311 52 1 39 48 86 18 467Service 167 96 66 6 7 1 14 343Rsidential 1,493 6 319 49 19 49 68 1,935Transport 154 14 279 1 448 448Agriculture, 22 20 42 42

ANNEX 3-2

REPUBLIC OF COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

EXISTING POWER GENERATING FACILITIES

A- Hydroelectric Plants

Power Plant Year put Installed Cap. Turbines Reservoir Cap. Annual Output (GWh)1in service (MW) (million m3) Average Firm

Ayame I 1959 20 2 Kaplan 846 65 52

Ayame II 1965 30 2 Kaplan 68 100 94

Kossou 1972 174 3 Francis 23,260 80 80

Taabo 1979 210 3 Francis 340 416 339

Buyo 1980 165 3 Kaplan 6,812 561 388

Rapid Grah 1983 5 2 Bulbe 0 2 0

TOTAL 604 1224 953

01) source: Plan National de l'Energie. SNC-Shawinigan Inc. May-1993.

B- Vridl Thermal Plant

Unit Year put Fuel Consum. Fuel Availability Capacity (MW)in service g/kWh Type Factor % Nameplate Operating

Steam #1 1968 351 FO 380 60 32 29

Steam #2 1970 319 FO 380 50 32 32

Steam #3 1976 306 FO 380 35 75 50

Steam #4 1976 308 FO 380 35 75 50

GT #1 1984 360 HVO 67 25 21.5

GT #2 1984 360 HVO 67 25 21.5

GT #3 1984 360 HVO 67 25 21.5

GT #4 1984 360 HVO 67 25 21.5

Total 314 247

Cote dlivoire Power Sector Structure

Government | t CFD | | EDF | | Other DCGTx:10 D% 92.3% 4.7% 1.3% 1.7% oversight of policy,

strategy, works

and procurement

Power sector EECIassets excluding Project ImplementatiornOversightCIPREL: Monitors CIE technical/financialapprox. 918 MW

| SAUR || EDF

gas supply1000~~~~~~~~~~~~~~ ~~UMIC, IFC,

SISP SAUR I Staff Public Petroci, Gov.

sales

operator - ~~~CIE provides fuel and CIPREL FrE/AISAURI I EDF I operator Concessionaire for generation, services sector debt65% 35% transmission, distribution, remits revenues title holder of gas,

connections, billings, collectionssector finiance mgmt

VALENER power sales pay bills175% share >|CIPREL c.100-200|

others 25 MW gas turbines. Customer

+ ~~~~~~~~~~~~provides gas; buys CIPREL elecricity

ANNEX 4-1Page I of 2

COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

Summary of Key Features of the Convention between C8te d'Ivoire and CIPREL

The following summary is provided only to give the reader a general understanding of the nature ofthe agreement. It is not a substitute for the Convention for any purpose. All provisions of theConvention are considerably more detailed.

1. CIPREL assumes certain responsibilities vis-a-vis C6te d'Ivoire with respect tocompletion, completion delay for Phase I and capital cost over-run. The capital cost and capitalportion of the price relating to Phase I capacity became fixed and firm as of the conclusion of therelevant financing agreements. For Phase II, cost adjustment is provided for differences betweenthe actual costs and on-lending terms relative to those suggested in the Convention, once thecontract is awarded and the on-lending terms between the Government and CIPREL are finalized.

IThereafter, CIPREL is at risk for cost over-run, completion and completion delay

2. CIPREL has an annual supply obligation (as of dates certain covering the first 99MW)for the duration of the Convention, in default of which penalties apply. For example, with 165 MWof capacity, the maximum obligation is for 1150 GWh (availability factor of almost 80%). Thepenalty applies to differences between programmed and actual deliveries, and can be either 8% or acombination of 8% and 38% of the price, depending upon the volume of the shortfall. If in twosuccessive years CIPREL is unable to deliver the cumulative ACQ2, the Convention can beannulled.

3. CIPREL earns a bonus for energy requested and delivered over and above the ACQ. Thebonus for the marginal kWh beyond ACQ can range from about 5% to 38% of the base price,depending upon the volumes taken in excess of ACQ.

4. CIPREL is obligated to undertake all inspections, maintenance, repairs and renewals tokeep the units in proper operating condition for the life of the Convention, and to undertake aperfornance test of each unit every year.

5. CIPREL is responsible for an environmental impact study and implementation of measuresit considers necessary in light of the study conclusions.

6. On the authority of the State, CIE has an obligation to pay CIPREL for the ACQ2, theprice per kWh decreasing as capacity increases through three, four or five turbines commissioned.This is equivalent to a capacity charge, because given the capacity to which it applies, it isinvariant with respect to actual kWh taken, and the State provides the fuel separately. The plant isfully dispatchable, which allows the system operator to minimize the variable cost of meeting the

' Completion delay penalties are defined for Phase I, which was commissioned on schedule. For Phase II,the cost to CIPREL of completion delay would be the absence of revenue to cover costs incurred.2 Annual Contract Quantity

ANNEX 4-1Page 2 of 2

load. Failure of the State to remedy a notified payment gap within 30 days of notification isgrounds for annulment of the Convention. The same applies for the State's failure to supply fuel.

7. Take over and indemnity provisions are specified in case of annulment.

8. Every year the State, CIE and CIPREL will agree on CIPREL's production, taking intoaccount optimal system dispatching requirements anticipated for the coming year.

9. CIPREL is to invest its own equity for 25% of the Phase I costs, and the remaining 75% isborrowed from IFC, CFD and BOAD. The State is to finance Phase II through public debt on-lentto CIPREL.

10. CIPREL is solely responsible for studies, technical specifications and documents, exceptthat the State has rights of approval for Phase II documents. CIPREL is solely responsible fortendering on Phase I, while for Phase I, there wil be obligatory ICB, managed by CIPREL butsubject to State approval.

11. CIPREL is solely responsible for implementation of tendering and construction. The Statehas open access to the construction and manufacturing sites. CIPREL will report progress monthlyto the State. The State has the right to inspect and approve the acceptance of all CIPREL works.

12. The State has the right to buy-back the CIPREL plant after the first ten years of operation,in which case a specific agreement would be negotiated including compensation for the presentvalue (at time of buy-back) of foregone dividends to CIPREL and CIPREL's capital, and the take-over of remaing debt service obligations.

ANNEX 4-2Page 1 of 3

COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

DETAILED PROJECT DESCRIPTION

The project includes the following investments components:

Extension of CIPREL II Power Plant:

CIPREL Power Plant consists of CIPREL phase I (99MW) went in service in lateFebruary and early March, 1995. The IDA project finances the CIPREL phase II whichconsists of supply and erection of one or two Gas Turbines with total ISO rating between75MW and 105MW. This gives a site rating of between 65MW and 90MWapproximately. This capacity range was defined with two purposes in mind: (a) meet thecapacity need for the sector; and (b) allow as mnany as possible manufacturers of GasTurbines to bid. The scope of work to be supplied include: the civil works, supply anderection of the Gas Turbines, all electro mechanical accessories including powertransformers, extension to the 225kV substations and auxiliaries, supply of spare parts,tools and a warehouse to store the parts and tools, and training for local staff.

2. Rebuilding of the 90kV/15kV Treichville Substation

With more than 50 MVA transit (more than 10% of the system load) and seventeen 15kVfeeders, the Treicheville substation, is a crucial injection point for the power supply ofAbidjan. The present poor reliability of the substation directly impacts the quality ofsupply and causes numerous power shortage in the Abidjan area. The new substation willhave:

- two 90kV breakers- four 90kV line bays- three 90/15kV transformer bays- twenty 15kV feeders

The scope of work will include the demolition of the existing installation, the civil work forthe new equipment including the construction of a control and switchgear building and thesupply and erection of the following equipment:

- two 90kV outdoor busbars- eight 90kV circuit breakers- sixteen 90kV disconnecting switches- four 90kV earthing switches- four 90kV current and voltage transformners- four 90kV line traps- four 90kV surge arrestors- auxiliaries- twenty 15kV circuit breakers including the 15kV switchgear- three block of 15kV capacitors- protection relays and control system

ANNEX 4-2Page 2 of 3

teleconnmunication system- auxiliaries

3. of te _ktatioatRD

This incudes cexension of the 90kV bus including circuit breakers switches andi ons ntation to accommodat the additional 165MW of CIPREL generating plant. Thengieeng and design will be carried out by Consulting Eogineers and the work will be

conrcd on a supply erection basis. The scope of work will include the necessary civilwork and the supply and eection of the following equipment:

a set of new 90kV bars (O 100 mm instead of 80 nun)- a set of new connectors fbr each equipment- eight 90kV circuit breakers- twenty-five 90kV disconnecting switches

4. S g the transnission system around Abidjan

In case of loss of the 22OkV semi ring around Abidjan, the existing 90kV system will notbe able to transit all the generating capacity at VRIDI during the peak. In order to provideths additonal reliability to the system, the following will be carried out.

(a) In eng the existing Plateau with the rebuilt Treicheville substation. Thework scope includes: about 4 km of two 90kV circuits, and two new 90kVpositions at the 90kV bus in Plateau substations.

Each 4 kn, 90kV circuit will be made of three insulated cables, including aUnecsary joints and accessories. The section of each cable will be 630 mm 2

aluminum.

The instllauon of two additional line bays at the 90kV Plateau substation wilinclude the necessary civil work and the supply and erection of the foUowingequipment:

the existing 90kV busbar extensiontwo 90kV discting switchestwo 90kV earthing switchestwo 90kV current transfomerstwo 90kV voltage transfonnmersprotection relays and control system extensiontelecommunication system extension

(b) Taping the 90kV line between Bia-Sud and Amaye 2 at the Riviera substation,including the modification of the overhead line and the installation of two 90kVpositions and the associated modifications in the substation.

The insbllation of two new line bays at the 90kV Riviera substation will includethe ncessay civil work and the supply and erection of the following equipment:

ANNEX 4-2Pags 3 of 3

- the existing 90kV busbar extension- three 90kV circuit breakers- six 90kV disconnecting switches- two 90kV earthing switches- three 90kV current transforners- two 90kV voltage transformers- four 90kV line taps- two 90kV surge arrestors- protection relays and control system extension- telecommunication system extension

5. The replacement of about 60 km of 15kV underground cables

The urban distribution network of Abidjan includes 700 km of l5kV cables, of whichabout 60 km have been identified as unreliable and source of numerous power faults andthe loss of supply. These cables are very old (around 40 years) with an average of 20splices per mn, a low insulation level (dried up oil impregnated paper), a poor trsitcapacity and high losses (22mm2 diameter conductor). These cables wifl be replaceod byXLP 15kV cables, with 150 mm2 conductors.

REPUBLIC OF COTE D0IVOIREPRIVATE SECTOR ENERGY PROJECT

Table 1. POWER GENERATION EXPANSIONDetailed Costs(USS Million)

Breakdown of TotalsIncl. ContLocal

Base Cost Totals Including Contingencies For. (Excl.1995 1996 1997 1998 Total 1995 1996 1997 1998 Total Exch. Taxes) Total

1. investment CostsA. CIPREL STEP 2

Supply and Erection of rew GT Plant 24.15 24.15 - 48.30 24.15 24.15 - 48.30 48.30 - 48.30Eng.& Constion Spn. 1.70 - - - 1.70 1.70 - - - 1.70 1.70 - 1.70

Total 25.85 24.15 - 50.00 25.85 24.15 - - 50.00 50.00 - 50.00

Table 2. POWER SYSTEM REINFORCEMENTDetailed Costs(USS Millon)

Breakdown of TotalsInc. CantLocal

Base Cost Totals Including Contingencies For. (Excl.1995 1996 1997 1998 Total 1995 1996 1997 1998 Total Exch. Taxes) Total

1. Investnent CostsA. Reinf. of Vridi 90 kV Syst. & Connection 0.60 1.20 0.90 0.30 3.00 0.67 1.37 1.05 0.36 3.45 3.11 0.35 3.45B. Reinforcement of Abidjan Transm. System

9OkV Treichville-Plateau Intercon. 0.00 0.90 1.80 1.80 4.50 0.00 1.03 2.11 2.16 5.29 4.76 0.53 5.29Taping Bia Sud-Abrobakro line @ Rivier 0.00 0.35 0.70 0.70 1.75 0.00 0.40 0.82 0.84 2.06 1.85 0.21 2.06

Subtotal Reinforcement of Abidjan Tra 0.00 1.25 2.50 2.50 6.25 0.00 1.43 2.93 3.00 7.35 6.62 0.74 7.35C. Rebulding Trechvlle Substaon 0.00 1.10 2.20 2.20 5.50 0.00 1.26 2.57 2.64 6.47 5.17 1.29 6.47D. Replacement of 15 kV Cables

Supply of Cabls and Materials 0.00 0.80 1.60 1.60 4.00 0.00 0.91 1.87 1.92 4.70 4.70 0.00 4.70Insaliation of Cables 0.00 0.10 0.20 0.20 0.50 0.00 0.11 0.23 0.24 0.59 0.29 0.29 0.59

Subtotal Replacementof16kVCables 0.00 0.90 1.80 180 450 000 1.03 2.11 2.16 5.29 500 029 5.29E. Engneering and Constr. Spn. 0.36 0.72 0.36 0.36 1.80 0.40 0.82 0.42 0.43 2.08 1.04 1.04 2.08

TOTAL 0.96 5.17 7.76 7.16 21.05 1.07 5.90 9.08 8.59 24.64 20.93 3.71 24.64

SI

REPUBLIC OF COTE O'IVOIREPRIVATE SECTOR ENERGY PROJECT

Table 3. Insabutional BuildingDetailed Costs

(USS Million)

Brekdown of Totals Inc. ContLocal

Sesa Cost Totals Including Contingencies For. (Excl.1996 1996 1897 198 Total 1996 189 1997 1996 Total Exch. TAX4s) Total

1. Investment CodstA. Sector Oranisatlon A MAnpowr Planning

Study by aManageert Cons. Firm 0.18 0.18 - - 0.35 0.19 0.20 - - 0.39 0.39 - 0.39

Impkementon of te Study Recom. - - 0.30 0.30 0.60 - 0.35 036 0.71 0.64 0.07 0.71

SubtotISectoOrganisationaManpower Planning 0.18 0.18 0.30 0.30 0.95 0.19 0.20 0.35 0.36 1.11 1.03 0.07 1.11

B. Regubtion and TA to Min. of Energy 0.20 0.30 0.25 0.25 1.00 0.22 0.34 0.29 0.30 1.16 1.04 0.12 1.16

C. Studs for Systm PlanningPower Sysern E4Nlon Studies 0.90 0.36 0.36 0.18 1.80 1.00 0.41 0.42 0.22 2.05 2.05 - 2.05

Hydrocarbon System Planning Studies 0.64 0.16 - - 0.80 0.68 0.17 - - 0.85 0.81 0.04 0.85

PFpwationof Standar dlPPBidDoc 0.15 0.15 - - 0.30 0.17 0.17 - 0.34 0.34 - 0.34

Prparton ofidDoctfrPflvat oSteamUnits - - 0.10 0.10 0.20 - 0.12 0.12 0.24 0.24 - 0.24

Taff Study 0.24 0.36 - - 0.60 0.27 0.41 - 0.68 0.64 0.03 0.68

SubtotalStudes forSystmrnPbtnning 1.93 1.03 0.46 0.28 3.70 2.12 1.17 0.54 0.34 4.16 4.08 0.08 4.16

D. Energy EffcicencyButaneU lzatonStudyandImpewtabon 0.06 0.09 0.15 - 0.30 0.07 0.10 0.18 - 0.35 0.33 0.02 0.35

Loe Reducton Study and lmpemeitl 0.09 0.09 0.12 - 0.30 0.10 0.10 0.14 0.34 0.27 0.07 0.34

DSM Study and Implementation 0.15 0.20 0.15 - 0.50 0.17 0.23 0.18 - 0.57 0.46 011 0.57

Subtotl E ErgykeWncy 0.30 0.38 0.42 - 1 10 0.33 0.43 0.49 1.26 1.06 020 1.26

E.TrwllngfortheSectorStWf 0.25 0.25 0.25 0.25 1.00 0.28 0.29 0.29 0.30 1.16 0.98 0.17 1.16F. Mlis_oeoux Equpment & Supples 0.15 0.15 0.15 0.11 0.56 0.17 0.17 0.18 0.13 0.65 0.65 - 0.65

Total 3.01 2.29 1.83 1.19 8.31 3.31 2.60 2.14 1.43 9.49 8.85 0.64 9.49

512195 12.39 PM IDT.3.XLS

ANNEX 44

REPUBLIC OF COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

SUMMARY OF PROCUREMENT METHODS

Volume ofDescription Procurement Timing consulting

method for award work(men-month)

1.Power Generation Expansion( CIPREL phase ll l

1.1 Engineering & construction supervision single source awarded 55

1.2 Supply & erection of Ciprel phase 11 ICB Sep-95

2.Pow-r System Reinforcement

2.1 Engineering & construction supervision shortlist Oct-95 50

2.2 Extension of Vridi 90KV substation ICB Oct-96Supply & erection

2.3 Rebuilding of Treichville substation ICB Oct-96Supply & erection

2.4 Extension of Plateau and Riviera substations ICB Oct-96Supply & erection (including taping

of the line Bia-Sud Amaya2 at Riviera)

2.5 90kV cable from Treichvilile to Plateau ICB Sep-96Supply & erection

2.6 Replacement of 57km of 15kV underground cable ICB Feb-96Supply

2.7 Replacement of 57km of 15kV underground cable local procedures Oct-96Erection

3.1natitutional Development

3.1 Institutional restructuration and man power analysis shortlist Oct-95 40

3.2 Demand forcast and system planning study shortlist Jan-96 52

3.3 Financial analysis and tarif adjustment study shortlist Jan-97 32

3.4 Preparation of bidding documents for the next IPP shortlist Jan-96 20

3.5 Hydrocarbone subsector development plan shortlist Jun-96 28

ANNEX 4-5

COTE D'IVOIRE

PRIVATE SECTOR ENERGY PROJECT

ESTIMATED DISBURSEMENT SCHEDULE(US$ million)

BANK :SE3MSTEO -:4f : DISBURSEMENT DISBURSEMENTPROFILEPROJECT

____ ___ __ ___ ___ ___ _ C UM ULA f V % )

________ -. ANNUAL CUMULATIVE

1996 I 7.0 7.0 9.0II 3.0 10.0 12.6

1997 I 30.0 40.0 50.2II 10.0 50.0 62.8

1998 I 10.0 60.0 75.3II 7.0 67.0 84.1

1999 I 7.0 74.0 92.9II 5.66 79.66 100.0

The above disbursement profile reflects the private sector involvement in the project anddoes not match available disbursement profiles in the country.

Annex 4-SREWUSU OF COTE OWVOIEPRIVATE SECTOR iMeOY PROJECTSUMMARtY SiPUMENTATION SCHEDULE

Description 1995 1998 1997 1999 1999

1.PowwOenwsthn Expewice~ 2 3 4 5 8 7 8 9 lOll1 12 1 2 3 4 5 8 7 II 10 ll t2 I 2 3 4 8 8 7 8 80 1Ol 12 2 3 4 5 0 7 8 8 10 It 12 I 2 3 4 a

I IOMW single cy'cl combustin tuorbine)

-muence of bidin doctN,nt-tender period-tender evaluation*contrect eward

*commiessoning

2.Power Ssvtem Reinforoemaent 1Extension of Vrid 90CV substation*design end boding process

*supply end orection

Reinforcement of Abidfan transmnission system*design end biding process.... ......*supply and orection

Rebuilding Treinchiviles substationr-design and biding proes*supply and erection

Rteplaement of I15KV cables-design end biding process-supply

-instelletion.. ....

3.1notitutionel Development

Electnicity eubsector manegmlent study 11- tElectricity subsecetor menegment implementation

Power System Investment, Operstions & Pricing Study I II IInvestment, operation and pricing implementationI

Sub-sector privetiuation strengthening situdySub-sectoiprivetizetion strengthening imiplementation

Hydrocarbon seubsctor reform study

Hydroerbone subeector refrm imptemsntation I

ANNEX 4-7

COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

SUPERVISION PLAN

P.- - 7 m m , .... :.7.. Ef7-f:- .-i7 .(f. :.. ... i. ; .- E -;;ii' '' '' '' ''" '''

7/95 Project launch Power Engineer, Economist 6workshop and Disbursement officer

11/95 Supervision Mission Power Engineer, Economist, 4Environmentalist

3/96 Supervision Mission Power Engineer, Regulation 6Specialist, and FinancialAnalyst

7/96 Supervision Mission Power Engineer, Economist 4

11/96 Supervision Mission Power Engineer, Economnist, 6Financial Analyst, andInstitutional Specialist

3/97 Mid-Term Review Power Engineer, Economist, 6Financial Analyst,Institutional Specialist andEnvironmentalist

7/97 Supervision Mission Power Engineer, Economist 4

11/97 Supervision Mission Power Engineer, Economist 4

3/98 Supervision Mission Power Engineer, Economist 5and Financial Analyst

7/98 Supervision Mission Power Engineer, Economist 4

11/98 Supervision Mission Power Engineer, Economist 4

4/99 Final Supervision Power Engineer, Economist, 6Mission Financial Analyst and

Environmentalist

ANNEX 448Page 1 of 2

REPUBLIC OF COTE D'IVOIREPRIVATE SECTOR ENERGIE PROJECT

ENVIRONMENTAL REVIEW SUhMMARY

1. This project consists of the construction and operation of a 75 - 105 MW ISO gas turbinepower plant as an expansion to the existing CIPREL power plant which is already equippedwith three turbines of 33 MW each (100 MWe in site conditions). The new turbines will beinstalled in the same industrial area as the 3 others, adjacent to an existing power plant whichis oil-fired and in poor operational condition.

2. The plant will use natural gas as the prinary energy source, but it will also be able to useheavy vacuum oil (HVO) as a back-up fuel.

3. The key environmental issues that were evaluated during the environmental review of thisproject included:

- air emissions- noise levels

4. Natural gas will be free of sulfur, fuel oil, if used in the new power plant, will have less than0.5 percent sulfur by weight. S02 emissions, therefore, are expected to be negligible and incompliance with Bank guidelines. NOx emission design specifications for the turbines areexpected not to exceed 115 ppm for 38 MW gas turbines. The high tempeature (5400C) andhigh velocity (40m/s) of exhaust gses at the exit of the stack will lead to a very low NOxconcentration at ground level (few ug/m3). The use of natural gas fired turbines instead of oil-fired units would result in a significant reduction of NOx enissions over current levels. It willalso reduce particulate emissions to virtuaDy zero.

5. Noise levels are generally of low significance in power plants using gas-fired turbines, and areparticularly of little concern in this industrial area. The new power plant will generate lessnoise than the existing power plant.

6. The project will comply with local environmental regulations and World Bank guidelines.

7. The following table gives the nmtigation measures adopted by CIPREL m accordance with allthe potial negative impacts listed in the Environmental Assment Study made in April1992 on FOXTROT BOOT Project by 'Vater & SOILS Ltd".

ANX 44Page 2 of 2

INVIRONMENTAL MITIGATION MEASURES

MPACT MEASURIS TAKEN IMTO ACCOUNT1. Retriction in land-ue becuse of the 1. The CIPREL power plant location fotlows the salfety zone requirment ofsafety of local people SOOm from the naest village2. Noise level of 85 dB(A) at a dice of 2. The nois level of ga; turbines will not exceed 85 d13(A) at one meter by3 m firm the tubines adding acoutic enclosues. The new gs turbina will not affect the prest

noise level at the narest residential as.3. Dranae of the paved plant res. 3. Drainage of the paved plant area is collcted direly in an exstng sttngDicarge of waters from the pit There is no demineralization unit in the CIPREL site. Ihe deminerlizeddemineraliraton unit and other possible water needed by CIPREL for boilers and compresor washing unit is derivedrocess water. directly from the existing demineralization unit at VRHI site.

4. Emissions of C02 4. The efficiency of the new gas tubines wiIl be higher than exiding ones andas efficient as the existing steam power plants in VRIDI site.

5. Risb of PCB emisions frm 5. The transformers are oiled ones and when burning oils do not developtmnsfonmer and capacitor oils during fires. PCB.6. Risk of oil spills frm the oil storwage 6. The existing oil tnks in VRIDI site have been refibisbed and dulytanks and pipelines. cebcked before use. For the daily tnks on CHPRE site, a retention baxin is

installed with a complete fire protection and detection system.7. Risk of chemical spiLs (NaO'H, NaCL, 7. Thre is no demin aized plant in CIPREL site.HIS04) wbhen sxing and handling.

8. Emitsions of nitigen oxides (NOx). 8. The nitrogen oxide emissions are low due to natual gas use as main fuel.If the new gas turbines are more often used than existing thermal power plantswhich operate on fuel, the global NOx emissions frm VRIDI site will bereduced

9. Emissios of paticles and S02, when 9. The CIPREL plant will use natual ps s its main fuel. The S02 emissionsusing heavy vacuum oil as fuel. wiIl be negligible. The particle emissions will be less than 10 mg/nm3,

thanks to the air filtration at the inlet of the gas turbines, the high enrgy andexcess air combustion and the negligible ash content in the naual gas used.

10. Recruitment of personnel. 10. The new ps turbines will not create many new jobs as most employeeswil be from the existing plant The person in charge of plat safety will alsobe responsible for the envirowment and wiU receive the prope training.

11. Waste disposal 11. Ordinay wastes should be disposed to a municipal landfill. Liquids aredrained to an existing settling pit and after sepamtion, water is sent to theVRIDI collection and rejection system.

12. Discha of the sewa to the 12. For the oily waters, after separation, the water is sent to the existingmunicipal waste water system. coectio and rejection system. There are no other liquid effluents from he

gas turbines13. Risk of sbotge. 13. The power plant area is fenced by concrete walls of 3m height There is a

genl lighting system instaUed in the tation. Thre is a guard houe wherethere wiU be in pernanence sewity peronnel.

14. Risk of fires and explosions. 14. There are gas and fire detection systems. The fire fighting systen are:- C02 for the gas turbirnes compartmentr,- water for the overall site;- foam injection for the oil storage tanks.

There wiUl be regular checking of the alarm systems and fire fighting stems.There will be braining of the whole penonnel and firemen.

AMNX 5-1Page I of 5

COTE D'IVOIREPRIVATE SECTOR ENERGY PROjECT

FINANCIAL ANALYSIS OF CIPREL

1. This financial analysis provides an assessment of the financial status of CIPREL,assumiing a 189 MW (site conditions) installation. Financial statements for CIPREL are simulatedon the basis of relevant provisions in the agroments between the State and CIPREL and CIPRELand its financiers.

CIPREL Ownership and Financing Structure

2. CIPREL is a private electricity generating company, in which 75% of the equity is held byVALENER, a holding company incorporated in. Cte d'Ivoire of which 65% is held by SAUR ( awholly-owned subsidiary of Bouygues) and 35% by EDF International (a wholly-owned subsidiaryof EDF). The other 25% of the equity islheld in varying shares by IFC, PETROCI and otherinvestors.

3. For Phase 1 (99MW), 25 percent of project costs are equity financed and 75% debt-financed. Phase 2 (75MW to 105MW ISO conditions or 65MW to 90MW site conditions) will befinanced by a long-term loan from GOCI to CIPREL, consisting of funds onlent from IDA. For thetwo phases together, the'resulting debt equity ratio will be 86:14. Table I shows a summary of thefinancing plan.

Table 1: CIPREL Summary Financing Plan(USS million)

Phase 1 Phase 2 Total

Costs 68.0 50.0 118.0FinuacingEquity 17.1 (25) - 17.1 (14)Private Long Term Debt 50.9 (75) - 50.9i(43)Public Long Term Debt - 50.0 (100) 50.0 (43)

Total Financing 68.0 (100) 50.0 (100) 118.0 (100)

Revenues:

4. The July 1994 Convention between the Republic of CMte d'lvoire and CIPREL providesthe framework for defining annual contract quantities and prices according to the number ofmegawatts of productive capacity. Annual revenue is estimated based on 189 MW (site conditions)of capacity, using estimates of price and annual contract quantity to be derived by the contractingparty on the basis of the framework in the Convention. In the Convention, the price esfimateassumes that Phase 2 financing will be made available at an interest rate of 7% and amorized over18 years. The price will be similar for an on-lending agreement carrying 8% interest and 17 years'amortization. This analysis does not include bonus revenues applicable in the Convention forproduction exceeding the annual contract quantity. CIPREL's base case annual revenues areestimated to be about $28.8 million.

! / I.

ANNEX-5-APage 2 of 5

Operating Expenses

5. Tbe selling price of electrical energy from CIPREL to CIE covers debt service and alloperating costs other than fuel, which will be provided by the FNEE and the cost of which will berecovered in the end-user tariff. CIE will operate and maintain the turbines under an operatingagreement between CIPREL and CIE. Annual maintenance costs are estimated at about 2.4 billionCFA francs.

Net Income and Cash Flow

6. CIPREL's simplified income statements for representative years and for a 189MWscenario are shown in Table 2. Over each year of the period, CIPREL's net income will bepositive. Net operating income over revenues will be maintained at about 40 percent to 50 percent.Operating income over net fixed assets in operation will increase steadily from 10 percent to about62 percent in the last year of the Convention.

Table 2. Projected Income Statement(constant US$ million equivalent)

1995/96 1997/98 2007/08 2012/13RevenuesOperating costs (non-fuel) 15.1 28.8 28.8 28.8Depreciation 3.4 6.1 6.1 6.1

Operating Income 5.8 14.3 14.2 14.2Interest 5.8 8.9 2.3 0Net income before tax .02 5.4 11.8 14.2Income tax - - 4.1 5.0

Net Income .02 5.5 7.7 9.2

RATIOS

Operating Income/Net Revenue 0.4 0.5 0.5 0.5Operating Income/Average fixed 0.1 0.1 0.3 4.9assets in operation

Sources and Uses of Funds

7. Despite a high initial debt:equity ratio, CIPREL will generally meet its covenants to thePhase 1 lenders, in particular the debt-service coverage ratio (minimum agreed value of 1.2) and asix-month equivalent of debt service to private lenders (to be held in an offshore escrow account).The five year grace period preceding debt service for the Phase 2 loan will moderate overall debtservice during the first five years of operations; however, when all debt service will be concurrent(in FY 2002/03 and FY 2003/04) the debt service ratio will fall to between 1.0 and 1.1 in thosetwo years.

Balance Sheet Projection

8. The projected balance sheet is sumnmaized in Table 3 for representative years.Shareholders' equity increases over the first several years as debt repayment and dividenddistribution restrictions force CIPREL to retain most of its earnings.

ANNEX S-1Page 3 of 5

Table 3: Projected Balance Sheet (189 MW~(constant US S million equivalent)

1995/96 1997!98 2007/08 2012/13

Current Assets 2.2 4.9 12.3 34.4Fixed Assets 114.9 103.2 50.1 3.0Total Assets 117.1 108.1 62.4 37.4

Current Liabilities (1) 7.2 8.2 7.3 3.2Long-term Debt 92.9 83.3 20.8 0.0Shareholders' Equity 17.1 16.5 34.2 34.2Total Liabilities 117.1 108.1 62.4 37.4(1) Includes current portion of long-term debt.

Financial Returns

9. The financial rate of return is estimated to be about 15.8%. The rate of return on equityis estirnated to be 21.4%. Taxes on dividends depends upon nationality, and is 12% for Frenchinvestors. There is no withholding tax on dividends paid to international institutions such as IFC,CFD and BOAD.

ASSUMPTIONS FOR THE FINANCIAL PROJECTIONS

I. FINANCIAL COVENANTS

1. As part of the undertaking of Phase I of the project, financial covenants relevant to thisfinancial analysis are as follows:

(i) Dividends Payment: Dividends will be paid out of cumulative netearnings and if the current ratio of CIPREL (including debt due within 12months) exceeds 1.0 after payrnent of such dividends.

(ii) Debt Service Coverage. Debt service coverage should not be less than1.2.

(iii) Escrow Account Reserve. An offshore escrow account reserve wiln beestablished and be kept at the level needed to support six-month debtpayment, effective March 1996.

ANNEX 5-1Page 4 of 5

II. ASSUMPTIONS

Forecasting period 17 years (FY 1995/96 - FY 2012/13)Fiscal Year October I - September 30Exchange Rate: US $= 540 FCFA**Valid at time of appraisalAll figures are in constant 1994 units.

2. For the purpose of the financial analysis of CIPREL, the installed generating capacity isassumed to be 189MW (Phase I: 99 MW; Phase II: 90MW). Results for an installed capacity of165MW (i.e. Phase II 66MW) are not significantly different. Bid analysis will lead to a decisionfor a phase II capacity within this range.

Project Costs and Financing PlanPHASE I PHASE IITOTAL(99MW) (90MW) ~~~~(189 MW)~

MFCFA USS MFCFA USS MFCFA USS

Total Costs 36,700 68.0 27,000 50.0 63,700 118.0Equity 9,200 17.1 - - 9,200 17.1Long Ter-m DebtIFC ALoan 9,200 17.1 - - 9,200 17.1CFD Loans 13,800 25.6 - - 13,800 25.6BOAD Loan 4,500 8.3 - - 4,500 8.3IDA on lent - - 27,000 50.0 27,000 50.0Total Debt 27,500 51.0 27,000 50.0 54,500 100.9Debt + Equity 36,700 68.0 27,000 50.0 63,700 118.0

Financing Terms

Phase I Long Term Debt

Currency Duration E~qu eivaet ~~~~~~~Aznortization InJterest Rt

IFC ALoan FF 1 + 9 9 200 9 12.00CFD Loan FF I + 9 13 800 9 11.00BOAD Loan FF I + 9 4 500 9 12.75

Phase 11 Long Term Debt (Government of C6te d'lvoire to CIPREL)

:Currency-- :Duration Amount Azn lotizaiionj 0Iterest Ratd-

IDA Credit FCFA 5 + 12On lent to CIPREL FCFA 5 + 12 50.0 12 8

CIPREL Unit Revenues

3. As envisaged in the Convention, CIPREL unit revenues will vary depending upon thecontracted facilities cost and financing conditions for Phase 11 investment.

ANNEX S-1Page 5 of 5

Annual Oneratin! ExDenses

4. These expenses are defined in the Convention between CIPREL and the State of C8ted'Ivoire for an installation of 165MW. For a 189MW installation such costs have been adjustedaccordingly.

Depreciation

5. Equipment costs are depreciated over 17 years on a straight-line basis, coincident with theraining years in the Convention. Other non-project capital expenditures are depreciated also on astraight-line basis at a rate of 20%/o/year.

Income Tax

6. Income taxes are 35% of income before taxes. A tax holiday regime has been granted toCIPREL according to which the tax exemption phases out gradually over a five year period.

Dividends

7. Gross Dividends are paid out from cumulative cash subject to the condition that thecurrent ratio at the end of the fiscal year is no less than one and a minimum cash balance ismaintained. Gross dividends are subject to the following dividend tax:

FY95-02 18%FY03-FY13 12%

Current Assets

Minimum cash balance MFCFA 300 (US$ 0.56 million)

8. Lone Term Debt Service Account: An offshore debt service account for the debtprovided by the private lenders is to be maintained at the level of six-months of the next year's debtservice, subject to the condition that no short-term debt is incurred. This requirement does notapply to IDA fiuds on-lent to CIPREL.

Accounts Receivable: 30 days of net revenues

Current Liabilities

Accounts Payable: 30 days of operating expenses.VAT Payable: 15 days

Interest on Short-Term Debts: 10% p.a.

Interest on Short-Tenn Deposits:4% p.a.

AneL 5Page 1 of 3

Electricity Tariff Formula

General Provisions

1. The average price per kilowatt hour of electricity sales to domestic customers willbe sufficient for the power sector to earn 8% rate of return on its net assets in operation(hereafter "RRA") every year, subject to the RRA being adequate to achieve a debtservice ratio of at least 1.5, a self-financing ratio of at least 0.2 and an operating ratio ofless than 0.85, all terms as defined below and according to the following procedure.

2. Every November, GOCI will prepare a power system investment, operation andfinancial performance forecast in a manner satisfactory to IDA using the current "basetariff" in order to determine the tariff sufficient to achieve the adequate RRA (hereafter"the sufficient tariff'). The effective base tariff for November 1995 is FCFA 57.3/kWh.

3. The tariff will be adjusted to achieve the adequate RRA if the sufficient tariff is atleast 5% above or 10% below the base tariff. The adjusted tariff will be the base tariff forpurposes of each November's tariff assessment.

Definitions:

"RRA" (Rate of Return on ANFA) = operating income/ANFA.

ANFA = Average net fixed assets, defined as one half of the sum of the sector's (non-CIPREL) fixed assets in operation at the beginning and at the end of the fiscal year.

Operating Income = revenue minus operating expenditures.

Revenue = proceeds of domestic and export electricity sales from CIE to FNEE, and therural electrification fee paid into FNEE.

Operating expenditures = Fees and expenses paid to CIE, CIPREL, EECI and DCGTx,electricity imports, the commercial cost of fuel supply to CIE and CIPREL, depreciationand net payment of value-added tax.

Annual debt-service coverage ratio = operating income plus depreciation both dividedby net debt service.

Net Debt Service = the year's projected payment of principal and interest on all of thesector's net debt.

Self-financing ratio = internal funds available for investment divided by total investment.

Internal Funds available for investment = operating income plus depreciation minus thesum of changes in working capital, interest and debt service.

Annex 5-2Page 2 of 3

Irvesment - construction plus interest during construction.

Operating ratio = operating expenditures divided by revenue.

A sample accounting format is provided on page 3 of this Annex. Data is subject tochange.

Specific Provisions for 1995/1996

Book value of assets will be used instead of revalued assets until asset revaluation iscompleted as pan of the forthcoming tariff study. Asset revaluation will be done under theproject so that RRA can be computed on the basis of net revalued assets, defined as non-CIPREL, non-CIE operable assets in current value net of accumulated revalueddepreciation.

External debt service is a working estimate agreed between GOCI and the IMF, and it willbe used pending a review and specification of external power sector debt service to beconducted as part of the tariff study.

The first application of the formula for 1995/1996 will be in November 1995.

Accounting Format for Financial Tariff Formula Annex 5-2Page 3 of 3

Item 1993194 11994/95 1995/96 1996/97FCFA million except as noted

Income StatementRevenueDomestic Sales in GWh 1904.0 2032.0 21340 2241.0Export Sales in GWh 0.0 0.0 60.0 80.0Dom. Sales Revenue 98969.9 116433.6 122278.2 128409.3Export + Other Revenue 7323.8 8818.1 11274.6 11728.3Total Revenue 106293.7 125049.7 133552.8 140137.6

Operating Expenses('l 87963.6 98456.5 95435.4 102225.0

Operating Income 18330.1 26593.2 38117.4 37912.6

Balance Sheet Items

Net Assets 300000.0 303788.0 308438.4 313101.2Accumulated New Debt 13811.0 28676.2 43705.4 58851.4

Fund Flow ItemsNew InvestmentConstruction 12788 13764 13916 14024Interest during construction 1023.04 1101. 12 1113.28 1121.92Total New Investment 13811.04 14865.12 15029.28 15145.92

Internal FundsOperating Income 18330.1 26593.2 38117.4 37912.6Depreciation 900.0 9113.6 9253.2 9393.0Internal Funds 27330.1 35706.9 47370.5 47305.6domestic debt service 7409.0 10478.0 8495.0 8495.0external debt service 12500.0 12500.0 12500.0 12500.0debt service new loans 2201.0 3493.8 4712.0 9185.0Intemal Funds for Inv 5220.1 9235.1 21663.5 17125.6

Ratio Anal sis _loperating ratio 0.83 0.79 071 0.73debt servic coverag rato 1.24 1.35 1.84 1.57self-financing ratio 0.38 062 1.44 1.13Rats of Fetum on Net AsWt 0.061 0.088 a 124 0.121

critical ratio: debt servicerequired internal funds 33165.0 39707.7 3856a5 4527aoavailable internal funds 27330. 1 35706.9 473705 47305.6incremental income req. 5834.9 400.8 -881ao -2035.6incremental FCFA/kWh 3.06 1.97 -4 13 -0.91Adequate Rate of Return 0.081 0.101 0.095 0. 115

* Operating expenses includes: communal and value added tax, CIE remuneration,fuel costs, CIPREL remuneration, DCGTx and FNEE services, EECI budget,connection subsidiy and depreciation.

Non-italic data from CMte d 'Ivoire; italicized data from Bank stff

_ , . w___~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

Annex 8-1 Page 1 of 4

Electricity Consumption 1970-1994

2500 -- LV cons

i 2000 * MV + HVcons

1500 - Total Cons

15000 _ t _ _=.7500

00 c_ N It to *o C r O 0 0 - N I V D 0o rt 00 0 0 o N _t 41N N - r N r- - -1 co -co 0 0 co a co o r -c a0 al CD Ot 0 0 0 1 al at 0 CD CD co 0 m 0 im Q CDc

Predicted Versus Actual Load Growth: 1970-1993

2500 | * Actual |

20000~~~~~ Predicted

0.

1 2 3 4 5 8 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Predicted versus Actual Customer Growth 1970-1993

500000 * Actual

* 400000 - PredictedE 300000

* 200000

100000 .

1 2 3 4 5 8 7 8 9 10 11 12 13 14 15 18 17 18 19 20 21 22 23

Growth of Selected Economic Indicators and Electricity Consumption1970-1993/94

8.00

6.00

'S4.0022.00*0.00

-2.00 Cl a 0 c > >,

GDPr - Real GDP. INDVAr - real Indusral value added; PDYr - reel personal disposable come; POP =population; PDYIC - PDYr por capita; column. 6.7,8 armeeity consumption

Annex 6-1page 2 of 4

Hydro Energy Production (GWh per year): 1980 - 1993

1980 1981 198 18 1984 198 198 198 198 198 122Q 199 12 1991660 1759 1198 351 1176 1387 878 1216 1518 1465 1288 1116 1046 971Average: 1216 GWh per year

Estimates of Future Power Plant Performance

Plant Type MW op. Ayailability/Year RetireFirm Average

Hydro 485 565 GWh 1216 GWhStean #1, #2 61 0.548 0.548 1997/98Steam #3, #4 100 0.350 0.700Gas Turbines 1-4 86 0.670 0.700 2004/05CIPREL I 99 0.770 0.770

Source: Mission estimates.Notes: The hydro capacity is the firm power available at time of system peak. For thethermal plants, the fraction under "Availability/Year" indicates the proportion of the yearfor which the capacity is available; e.g. 0.548 means 54.8% of the hours of the year. Theavailability of the steam plant assumes no further rehabilitation work.

Balances:Energy (GWh per year) Cagaav

|Demand Requirements: Supply Cumulative Balance Peak Load PlantYear Growth Dom. Sales Export Losses Total Total GWh MW + reserve Available

1992/93 1863 382 2245 2245 0 0 MW S1993194 1.039 1936 398 2333 2333 0 0 434 7321994(95 1.050 2032 416 2449 2449 0 0 449 7321995/96 1.050 2134 60 437 2631 2337 -294 -44 489 8311996/97 1.060 2241 60 459 2760 2337 -423 -63 529 8311997/98 1.052 2357 60 416 2833 2337 -496 -74 555 8311998/99 1.052 2480 60 438 2977 2337 -641 -95 570 83199/2000 1.052 2609 60 460 3129 2044 -1085 -161 587 7702000/01 1.052 2744 60 484 3289 2044 -1245 -185 626 7702001102 1.052 2887 60 510 3457 2044 -1413 -209 658 7702002/03 1.052 3037 60 536 3633 2044 -1589 -236 692 7702003/04 1.052 3195 60 564 3819 2044 -1775 -263 727 7702004/05 1.052 3361 60 593 4015 2044 -1970 -292 765 7702005/06 1.052 3536 60 624 4220 2044 -2176 -323 804 770Note: Growth rates for domestic market only w/o mining loads (as yet not confirmedl.Growth rates 1993/4 to 1996/7 inclusive reflect experience of 1993194 over 1992193 and macro-economic prospectsExport only includes 60 GWh to Burkina.Hydro production is historical and producable till 1994/95 inclusive; thereafter firm value assessed for system planning.Thermal production is historical till 1993/94, and at sustainable availability thereafter; includes CIPREL Phase 1.

8eae Case Economic Rate of Return Analysis

1. De_md M. hIvestment 11l. Opaating Cost IV. Net hnemnwntal Benefit8Bas No hv hkr. Load kwr. Val. Fuel O+ M

Yee (3Wh OWh _ Wh USDmm Inv. Ant Ann. Cha. Ann. Cost Bse No.hv Net Fuel Bae No. hIv. Net 0 +M Net OpC hIc. ben Inc Cost Not Bn1994 2032 2032 0 0.00 0 31.91 31.91 0.00 10.08 10.06 0.00 0.00 0.00 0.00 0.001906 2194 2104 90 4.32 37.0 4.36 4.36 16.17 17.44 -1.27 11.21 9.41 1.80 0.53 4.32 4.87 .0.551996 2301 2157 144 6.91 36.2 4.13 8.48 17.90 18.21 -0.30 12.69 9.41 3.28 2.97 6.91 11.45 -4.641097 2417 2229 188 9.02 8.48 18.80 18.56 0.25 12.69 9.41 3.28 3.62 9.02 12.00 -2.981998 2640 2127 413 19.82 29.7 3.49 11.97 20.17 16.21 3.96 12.11 7.36 4.75 8.72 19.82 20.80 -0.861999 2669 2153 518 24.77 29.7 3.49 16.46 19.96 16.61 3.35 12.19 7.36 4.83 8.18 24.77 23.64 1.132000 2804 2179 626 30.00 15.46 23.15 17.00 6.15 13.59 7.36 6.23 12.39 30.00 27.84 2.162001 2947 2193 754 36.19 29.7 3.49 18.96 25.50 17.22 8.27 15.07 7.36 7.71 16.99 36.19 34.93 1.262002 3097 2207 890 42.72 18.96 27.59 17.45 10.14 15.07 7.36 7.71 17.86 42.72 36.80 5.922003 3255 2220 1036 49.68 29.7 3.49 22.43 29.58 17.66 11.93 16.55 7.36 9.19 21.12 49.68 43.56 6.122004 3421 2233 1188 67.02 22.43 31.89 17.88 14.04 16.55 7.36 9.19 23.23 57.02 45.86 11.382006 3696 2241 1365 65.04 29.7 3.49 26.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 66.04 52.41 12.632006 3596 2241 1366 65.04 25.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 65.04 52.41 12.632007 3696 2241 1356 65.04 25.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 65.04 52.41 12.632006 3696 2241 1365 65.04 25.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 66.04 52.41 12.632009 3696 2241 1365 65.04 25.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 66.04 52.41 12.632010 3696 2241 1365 65.04 25.92 33.85 18.03 16.81 18.03 7.36 10.67 26.49 66.04 62.41 12.632011 3696 2241 1365 66.04 25.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 65.04 52.41 12.632012 3596 2241 1355 65.04 25.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 66.04 52.41 12.632013 3696 2241 1355 66.04 26.92 33.65 18.03 15.81 18.03 7.36 10.67 26.49 66.04 52.41 12.632014 369s 2241 1366 65.04 25.92 33.65 18.03 15.81 18.03 7.36 10.67 26.49 65.04 52.41 12.632016 3696 2241 1365 65.04 26.92 33.85 18.03 15.81 18.03 7.36 10.67 26.49 66.04 52.41 12.63

RRk:NPV 10% 5S09 279 132 60 53 113 279 245 34%hicil/kWh: 0.048 0.0228 0.0103 0.0091 0.0195 0.0480 0.0422

Value: Taitf T&D Notbackl IRRA | DR Yr CRF|0.106 0.058 0.048 34% o.1 20 0.1174

6/3195 3:46 PM CiBUF64.XLS

Investment and Operating Cost Data for System Simulations

Plant Type & Fuel heat rate fuel price cap. cost fixed O+M var O+M available plant lifeScenario kJ/kWh USD/mmkj USDmm USDmm USD/kWh (years)Phase II 2x 33MW GT nat gas 13,000 0.87 36.7 1.8* inc. fixed 0.77 20Phase II 90 MW GT nat gas 12,090 0.87 48 2.5* inc. fixed 0.77 20Low speed Diesel hfo 380 8560 1.50 72.6 1.8 0.0095 0.77 20

No new investment: (operates existing system; show unserved energy)delay 1 33MW 1 yrdelay 2 33MW 1 yrlow load forecast

value unserved kWh: $0.37/kWh I 200FCFA at 1994 exchange rate - viz 1991 value of 100FCFA)TAG 1-4 existing nat gas 13,800 0.87 sunk 1.3 .67F;.7 OP to 2004/5TAV existing: hfo 12,200 1.50 sunk $33.65/kW see note see noteGTs beyond Phase II:

first 55MW nat gas 13,000 0.87 $640/kW 1.48 inc. fixed 0.77 20other 55MW nat gas 13,000 0.87 $560/kW 1.48 inc. fixed 0.77 20TAG not converted hvo 13,800 3.50hydro system: sunk 565 firm

1216 expected

Derivation of Phase 11 GT cost: USDmm

3 turbines 63.94 turbines 82.25 turbines 100.6net cost Phase II @ 66MW 36.7Phase II @ 90 MW 48.0(^) based on French francs converted at appraisal exchange rate of 5.4/ USD 1

Notes: based on fixed cost of $0.004/kWh.hfo value based on export value of $60/tonne, 40GJ/tonneTAV availability: units 1&2: 0.548 (till 1998); units 3&4: .35 firm, .7 'expected" (till 2004/5).Firm value for investment planning; expected value for operation

>

x0

ANNEX 7-1

REPUBLIC OF COTE D'IVOIREPRIVATE SECTOR ENERGY PROJECT

SELECTED DOCUMENTS IN THE PROJECT FILE

1. Plan National de l'Energie - Etude Complementaire - SNC Shaminigam Inc. -Mai 1993

2. Convention de concession du Service Public National de Production, deTransport, de Distribution, d'Exploitation et d'Importation de l'EnergieElectrique - Etat de CMte d'Ivoire /CIE - Octobre 1990

3. Avenant No 1 a la Convention Etat/CIE - Dcembre 19934. Avenant No 2 a la Convention Etat/CIE - Aout 19945. Avenant No 3 a la Convention Etat/CIE - Mars 19956. Convention pour la Construction, l'Exploitation et le Transfert de propriete

d'une centrale thermique de Production d'Electritie - Etat de CMted'Ivoire/CIPREL - Juillet 1994

7. Avenant No 1 a la Convention - Etat/Ciprel - Aouit 19948. Environmental Impact Assessment Study of Exploration of Gas Foxtrot -

Cote d'Ivoire-Soil and Water Ltd. - October 19929. Environmental Impact Assessment Study of Oil and Gas Transport - Cote

d'Ivoire - UMIC Cote d'Ivoire Corp. - April 199410. CENCI - Etude d'Impact sur l'Enrvironnement pour la Construction et

l'Exploitation du Projet de Gaz Naturel et d'Electricite - CENCI -F6vrier1993

11. CIPREL - Etude d'Impact sur l'Environnement pour la Construction etl'Exploitation de la Centrale de production d'Electricite a Base Turbines aCombustion au Gaz Naturel - Etape II du Projet VRIDI II - CIPREL -Fvrier 1995

12. Letter of Sector Development Policy, "Strategie Sectorielle dans le Domainede l'Energie" - MIME - Juin 1995

13. Etude de Faisabilit6 - Mise en faleur de Foxtrot - CENCI/DCGTx - Janvier1994

14. Comparison Study Between Foxtrot and Panthere Projects - CENCI -November 1993

15. Foxtrot - Pr6sentation MB - CENCI - Avril 199316. Foxtrot - Avant Projet Sommaire - Vol I-II-IV-V - CENCI - Avril 199317. Foxtrot - Analyse Economique et Financiere - Institut Fran9ais du Petrole -

Janvier 1993

MAP SECTION

¢ ~~~~~M A LI 5eg C O T E D'I V O I R E IP

*-<> rf- \) -- J' ot r>~-u BURKINA FASO PRIVATE SECTOR ENERGY PROJECT- j ., t -- o l (_ jo 4g- ~~~~~~~~~~TRANSMISSION SYSTEM

> oM -< oC { z M Ws2 \; ff , i U S2 CON : 90 IV TRANSMISSIOS IIN L S tS- -~~~~~904V TRNSMISIONLINE

X C vv- \ / twX Sr1 jf / 00_ \ l- _ ~~~~~~~~~~~~~~~~~~~~~22S kV TRANSM115510N LINES

\ Oufi*nRe~~~~~~l O ^~~~~ / 8 = 8 j= W = X ln \ \ ; 0~~~~~~~~~s 90 kV SUBSTATIONS

_ <>C 0s0 1 8 \ /% A I-rl S¢^ HY~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~"DROfLECTRIC STATIONS

(,> _ i \ < j ^, o g , , T~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~HERMAL STATIONS

G U I N EA 1 t nt _5 | __<)NATIONAL CAPITAL

\N r \ D.¢o'- t | t 6 DEPARTMENT CAPITALS

_ _g \ ,) e ss 7- : i ; ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~RIVERS<S_ [ < >¢ ° - \ u- e~~~~~~~~~~D.6.ko.*6 _ INTERNATIONAL BOUNDARIES

(~~~~~~~~~~~~~~~~~1~, Kh.ubo B...k T.S 6.b T. .9 ''46

8* <_ l Es.4wO\^powic lneMonLono ,/$e\ tKohob _ Bonciulode ( < ti t ABIDJANABIDJADETAAI

p ~~~ ~~~~s ) r e t so ^N P vc 1 b T~~~~~~~~~~~~~.d. P1 -

=_ Vsv do *'ar MBbor _CO n

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_ _ | _#w=_ ; r _wt _ -r | | bv/ a / < _ l [1 G.

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C O T E D' I VOI RE0Sikensi Azaguie

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Aboisso 0 0

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: _ r ^ t -G d . ~~~~~~~~~~~~~~~~~~~~a Adideq;,08tGHAkN GHANAI , ' ' 4 Jacqu~~~~~~'Ie 7 sSOnv'00

|~~~~~~~~~~~~~~~~~~~~~~~~~~~~--- -< Cl 02S ' _ .xj Ft/

t: : 0 , .0 ,. . . :. JrOMEO SURtfG ZEILL , , E , 0 C1-28 C--25 .-"

GRAND C$OR-26

The boundaries, colors, denominationsand any other information shown onthis mop do not imply, on the port ofThe World Bank Group, ony judgmenton the legal stotus of any territory, or

COTE D'IVOIRE such boundaries. r

PRIVATE SECTOR ENERGY PROJECTHYDROCARBONS CONCESSSIONS AND FIELDS MrLI

} 5 ' ~~~~~~~M A L t CONCESSION AGREEMENT SIGNED SENEGAL? Nr (N GER

CONCESSION BOUNDARIES > 2 *Ba mao )

t@ OIL FIELD IN EVALUATION CONCESSIONS v'-"' BURKINA *Ouagodougo,,K~X JtK s OIL/GAS FIELD IN EVALUATION CONCESSIONS G U I N E A FASO

Z::0: ;? PROSPECTS oor - >|7, j ,f

40 BATHYMETRIC CONTOURS IN METERS XSE NSIERN <-' '~

DEPARTMENT CAPITALS LEONE , CGT E oo0 OTHER SELECTED CITIES F ek 0 D'IVOE 2 GHANA

INTERNATIONAL BOUNDARIES / - . Yamoussoukro

Moo,nrosa LIBERIA s __-__¢ Acr >

0 20 40 60 80 KILOMETERS i5Area of mop

o so 5o l r 59 ff 0'0 40 '0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1

IMAGING

Report No: 12774 IVCType: SAR