Document of

The World Bank

Report No. 16001-KE

STAFF APPRAISAL REPORT

KENYA

ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

May 21, 1997

Water, Urban and Energy 1 DivisionEastern and Southern Africa DepartmentAfrica Region

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CURRENCY EQUIVALENTS

Currency unit = Kenya Shilling (K Sh)USS 1.00 = K Sh 56 (As of January 1996)K Sh i 00 = US$0.01,

WEIGHTS AND MEASURES

Metric System

I Kilovolt (RV) 1,000 VoltsI Megawatts (MW) = 1,000 Kilowatts (kW)I Gigawatt hour (Gwh) I million kilowatt hours (kwh)I ton of oil equivalent (toe) = about 7 bbl of crude oil1 barrel (bbl) = 0.16 cubic meters

GLOSSARY OF ABBREVIATIONS

CAS Country Assistance StrategyCPDM Chief Project Development ManagerEA Environmental AssessmentEAPLC Eastern Africa Power and Lighting CompanyEIB European Investment BankERB Electricity Regulatory BoardERR Economic Rate of RetumESAF Enhanced Structural Adjustment FacilityESMAP Energy Sector Management Assistance ProgrammeGoK Govemment of KenyaICB Intemational Competitive BiddingIDA International Development AssociationIDC Interest During ConstructionIMF Intemational Monetary FundIPP Independent Power ProducerISG Implementation Support GroupKICM Kenya Association of ManufacturersKffW Kreditanstalt fur WiederaufdauKPC Kenya Power Company LimitedKPL Kenya Pipeline Company LimitedKPLC Kenya Power and Lighting Company LimitedKPRL Kenya Petroleum Refinery Company LimitedKVDA Kerio Valley Development AuthorityKWS Kenya Wildlife ServicesLPG Liquefied Petroleum GasLRMC Long Run Marginal CostMOE Ministry of EnergyMOF Ministry of FinanceNCB National Competitive BiddingNGO Non-Govemmental OrganizationNOCK National Oil Corporation of Kenya

NPV Net Present ValueOECF Overseas Economic Cooperation FundPPF Project Preparation FacilitySDR Special Drawing RightsSOE Statement of ExpenditureTARDA Tana River Development AuthorityTRDC Tana and Athi Rivers Development AuthorityUEB Uganda Electricity Board

GOVERNMENT FISCAL YEAR

July I - June 30

Vice President Callisto E. MadavoDirector Harold E. WackmanTechnical Manager Jeffrey RackiTeam Leader Joel J. Maweni

KENYA

ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

CONTENTSPage No.

CREDIT AND PROJECT SUMMARY

1. ENERGY SECTOR AND THE MACROECONOMIC CONTEXT .......................................................IA. MACROECONOMIC CONTEXT .............................................................. 1B. THE ENERGY SECTOR AND THE ECONOMY .............................................................. 2C. ENERGY RESOURCES .............................................................. 3

2. ENERGY SECTOR ORGANIZATION .............................................................. 6A. POLICY INSTITUTIONS .............................................................. 6B. ELECTRICITY SUB-SECTOR .............................................................. 6C. PETROLEUM SUB-SECTOR .............................................................. 9

3. ENERGY MARKETS, PRICING AND KEY ISSUES ............................................................. 10A. THE ENERGY MARKETS - ENERGY CONSUMPTION AND SUPPLY ....................................................... 10B. ENERGY PRICING ............................................................. 15C. KEY ISSUES IN THE ENERGY SECTOR ............................................................. 16D. WORLD BANK GROUP INVOLVEMENT ............................................................. 21

4. THE PROJECT ............................................................. 23A. PROJECT ORIGIN, RATIONALE AND OBJECTIVES ............................................................. 23B. PROJECT DESCRIPTION ............................................................. 24C. PROJECT COSTS AND FINANCING ............................................................. 27D. PROJECT SUSTAINABILITY ............................................................. 28E. PARTICIPATION ............................................................. 29F. ENVIRONMENTAL ASPECTS ............................................................. 29

5. FINANCIAL ANALYSIS ............................................................. 31A. THE FINANCIAL MANAGEMENT FRAMEWORK ............................................................. 31B. PAST AND PRESENT FINANCIAL PERFORMANCE ............................................................. 32C. PROJECTED FINANCIAL PERFORMANCE ............................................................. 36D. AN ACTION PLAN FOR FINANCIAL REFORM IN THE ELECTRICITY SUBSECTOR .............................. 37

6. IMPLEMENTATION ARRANGEMENTS ............................................................. 39A. OVERALL ............................................................. 39B. IMPLEMENTATION ARRANGEMENTS ............................................................. 39C. PROJECT IMPLEMENTATION PLAN ............................................................. 40D. PROCUREMENT ............................................................. 41E. DISBURSEMENTS ............................................................. 43F. ACCOUNTING AND AUDITING ............................................................. 44G. MONITORING AND EVALUATION ............................................................. 44

7. PROJECT JUSTIFICATION, ECONOMIC ANALYSIS AND RISKS . ............................................... 45A. OVERALL ........................................................ 45

B. NEED FOR THE PROJECT, ITS SIZE AND TIMING ..................................................... 46C. ECONOMIC RATE OF RETURN AND SENSITIVITY ANALYSIS .................................................. 47D. RISK MITIGATION ...................................................... 49E. FISCAL IMPACT AND SUSTAINABILITY ..................................................... 50

8. AGREEMENTS TO BE REACHED AND RECOMMENDATION ..................................................... 52

ANNEXES

Annex 2.1 Action Plan for Restructuring the Power SubsectorAnnex 3.1 Energy BalanceAnnex 3.2 Electricity Generation, Sales and LossesAnnex 3.3 Available Generating Capacity and Generation in FY1994/95Annex 3.4 Letter of Sector Development PolicyAnnex 4.1 Documents Available in the Project FilesAnnex 4.2 Description of the Sector Restructuring and Reform ComponentAnnex 4.3 Description of the Efficiency Improvement ComponentAnnex 4.4 Description of the Power System Expansion and Rehabilitation ComponentAnnex 4.5 Description of the Geothermal Resource Development ComponentAnnex 4.6 Rural and Household Energy Development StrategyAnnex 4.7 Project Component by FinancierAnnex 4.8 Project Component and Expenditures by YearAnnex 5.1 Financial AnalysisAnnex 6.1 Table of Contents for the Borrower's Project Implementation PlanAnnex 6.2 Summary Project Implementation ScheduleAnnex 6.3 List of IDA-financed ActivitiesAnnex 6.4 Estimated Schedule of DisbursementsAnnex 6.5 Supervision Plan and Staff InputAnnex 7.1 Lease-Cost Generation Expansion PlanAnnex 7.2 Details of Economic Analysis and AssumptionsAnnex 7.3 Estimated Willingness to Pay for ElectricityAnnex 7.4 Quantitative Risk AnalysisAnnex 7.5 Fiscal AnalysisAnnex 7.6 Performance Indicators

IBRD MAP No. 28165

This report is based on the findings of Bank appraisal and post appraisal missions in November 1994 andJanuary 1996, respectively. The mission members included: Mr. Joel Maweni (Task Manager), MangeshHoskote (Power Restructuring Specialist/Consultant), R. I. GopalKrishnan (Senior ProcurementSpecialist), Paivi Koljonen (Economist), Rowena Martinez (Operations Analyst), T. S. Nayar (PrincipalChemical Engineer), Said Al Habsy (Senior Legal Counsel), J. Koenig (Consultant, Geothermal Specialist),A. Posada (Consultant, Power Engineer), K. Zaki (Consultant, Petroleum Exploration Specialist), S. Dhar(Consultant, Power Engineer), G. Calderon (Consultant, Geothermal Specialist), J. Sasia (OperationsOfficer). Peer reviewers for the project were Messrs. B. Thiam, D. Jordan and C. Algandona. Secretarialsupport and report production were done by Mmes: N. Jones and V. Fofanah.

REPUBLIC OF KENYA

ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

CREDIT AND PROJECT SUMMARY

Borrower: The Republic of Kenya

Implementing Agency: Ministry of Energy (MOE)

Beneficiaries: Kenya Power Company (KPC); Kenya Power andLighting Company (KPLC)

Poverty: Not applicable.

Amount SDR 86.6 million (US$125.0 million equivalent)

Terms: Standard IDA Terms with a 40-year maturity

Commitment Fee: Standard (variable rate between 0 and 0.5% of theundisbursed credit balance set annually by the ExecutiveDirectors of IDA)

Onlending Terms: SDR 72.4 million (US$104.6 million equivalent) andSDR 8.1 million (US$11.7 million equivalent) wouldbe onlent to KPC and KPLC respectively at 7.7% with arepayment period of 20 years, including five years' grace.KPC and KPLC would bear the foreign exchange risk.

Financing Plan: See Schedule A

Net Present Value: US$ 343.0 million

Staff Appraisal Report: Report No. 16001-KE

Map: IBRD No. 28165

Project ID 1344

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1. ENERGY SECTOR AND THE MACROECONOMICCONTEXT

A. MACROECONOMIC CONTEXT

1.1 Kenya's 25 million people had a per capita income of US$260 in 1994 (at current pricesand exchange rate). Kenya's economy depends on agriculture, which employs 70 percent of thelabor force and contributes more than one quarter of GDP. Coffee and tea are the mainagricultural products and account for almost one half of merchandise exports. The service sector,including tourism (a leading foreign exchange earner), accounts for half of GDP and is animportant source of employment. The manufacturing sector is relatively developed anddiversified, and contributes about 13 percent of GDP.

1.2 Recent Economic Developments. The period 1990-1993 was marked by a sharp declinein all the major macroeconomic performance indicators. Agricultural production was adverselyaffected by unfavorable weather conditions. External imbalances worsened as a consequence ofthe Gulf crisis during 1990-1991, a general deterioration in terms of trade, and the decision ofmultilateral and bilateral donors, in November 1991, to withhold aid to Kenya because ofconcerns about poor macroeconomic performance, governance and multiparty democracy.

1.3 Since the middle of 1993, the Government's sustained effort to tighten fiscal andmonetary policy has been effective in stabilizing the economy and contributing to the revival ofeconomic growth. GDP grew by 3 percent in 1994 and by 5 percent in 1995. The fiscal deficit(exclusive of grants) has sharply reduced to 1.4 percent of GDP in 1995 and annual inflationdeclined from a peak of 62 percent in January 1994 to 6.9 percent in December 1995. Withrespect to structural reforms, the Government has eliminated foreign exchange controls and mostcontrols on exports and imports. The liberalization of the maize market in December 1993 andthe petroleum sub-sector in October 1994 abolished all price controls. Since 1992, theGovernment has also been implementing a major civil service reform program that has trimmedthe sector by over 40,000 since July 1993. However, progress on parastatal reform has been slowuntil recently.

1.4 The Government has outlined its reform program over the period 1996-1998 in a PolicyFramework Paper, which was distributed to the Board on February 23, 1996. This documenthighlights poverty reduction as the principal objective. The reform program is beingsupplemented by a new one-year Enhanced Structural Adjustment Facility (ESAF) arrangementwith the IMF and an IDA Structural Adjustment Credit.

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1.5 As noted in the Bank's Country Assistance Strategy (discussed by the Board on January30, 1996), an acceleration of economic growth is needed for poverty reduction in Kenya. Thus,the key development challenge facing the Government over the next few years would be to createthe conditions for rapid and sustained growth which would reduce unemployment and povertysignificantly. Given its relatively strong human resource endowment, Kenya has good prospectsfor export-led economic growth in excess of 5 percent per year, over the medium term, and evenhigher growth rates could be achieved in the longer term. However, in order to achieve thesegrowth rates, which require rapid growth in manufactured exports, investment in basicinfrastructure, including energy, must increase.

B. THE ENERGY SECTOR AND THE ECONOMY

1.6 The energy sector plays a critical role in the development of the economy. Adequate andreliable supplies of power and energy are indispensable for economic growth, which is central forpoverty reduction - current shortage of power supplies is seriously affecting economic activity.The energy sector also contributes significantly to the financing of public expenditures throughpetroleum and income taxes. On the other hand, crude oil and petroleum products imports have asignificant impact on the balance of payment account and the sector draws on foreign exportearnings to service its external debt.

1.7 Because of the long time it has taken to reach agreemnet between the Government and thedonors on sector policies, investment in new power generation capacity has been delayed. As aresult, the power system is not adequate to meet demand. Peak load shedding has becomeunavoidable and has increased from about 40 MW (6 percent of peak) in FY93/94 to about 75MW (10 percent of peak) in FY94/95. During FY94/95 the Kenya Power and LightingCompany Limited (KPLC) implemented a daily load shedding program, which curtailed suppliesduring the morning and evening peak hours. Although many industries shifted loads to off-peakperiods in consultation with KPLC, and were thus able to reduce the economic impact of therationing, continuous processing industries had limited possibilities to shift their consumptionand therefore suffered losses in output. Although exact data on the quantity of unserved energydemand is not available, the comparison of the forecast and actual sales for FY94/95 indicate afigure of about 190 GWh. Assuming conservatively that the cost of unserved energy demand isUS$0.25 per kWh, which is comparable to the cost of running a private diesel generator, the costof energy shortages could be estimated at about US$50 million in FY1995. The rehabilitation ofexisting plant is providing some relief in 1996, but, as the earliest possible date forcommissioning new generating capacity is FY1997/98, the gap between demand and supplywould grow wider, resulting in increased private sector costs and disincentives for newinvestment.

1.8 In terms of contribution to the exchequer, the sector contributes revenues in the form oftaxes from the importation and sale of petroleum products, and corporate taxes and dividends. InFY94/95, the sector generated about KSh 16,831 million (US$ 300 million) in fiscal revenue,which was about 13 percent of total central Government revenue. About 80 percent of this wasfrom petroleum taxes.

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1.9 On the expenditure side, the net petroleum import bill in 1995 was about US$270 million.This means that Kenya used about 20 percent of its merchandise export earnings to pay forpetroleum - mostly crude oil imports. In addition, because of its high degree of monopolypower, the refinery is able to pass on the costs of inefficient operations to the consumers. Thiscost is estimated at about US$22 million per annum in the form of high prices for petroleumproducts. Deregulation of the petroleum sub-sector, which is partially supported by the proposedproject would benefit consumers through efficient market-determined prices.

1.10 Because of Government policy of low tariffs until recently, the power sub-sector hasdepended on Government support for financing some of its investment programns. With the tariffreforms and other efficiency improvements initiated in the course of the preparation of theproject, the power sub-sector's financial performance would improve significantly, therebyeliminating the requirement for future Government expenditure support.

C. ENERGY RESOURCES

1.11 Kenya's known energy resources include hydro and geothermal power, biomass, windand solar energy. Exploration is in progress for hydrocarbons, but to date no significant reserveshave been discovered.

1.12 Hydropower. The hydroelectric potential that would be economic to develop for the gridincluding installed capacity, exceeds 1,400 MW, with an annual average generation potential ofabout 6,000 GWh. Tana and Turkwell Rivers have the largest potential. Hydro potential alsoexist on other rivers, including the Ewaso Ngiro, Sondu, Nzoia, Nyando, Arror, and Athi. TheSondu basin has been the subject of two studies towards the multipurpose development of thebasin's hydropower and irrigation potential. Consultants' reports have indicated that thedevelopment of the Miriu Falls site on the Sondu River for power generation would beeconomic. A feasibility study and economic evaluation was prepared under the GeothermalDevelopment and Pre-Investment Project (Cr. 1973-KE).

1.13 Geothermal Power. Potential geothermal sites are located in the Rift Valley which runsfrom the border with Tanzania in the south to Ethiopia in the north. There are three major areasof geothermal activity: Olkaria, Eburru, and Lake Bogoria, with possible reserves measured inthousands of megawatts of electric generation capacity. The Olkaria field near Lake Naivasha,about 100 km west of Nairobi, contains proven reserves of 350 MW, which are the basis forpower generation at the existing Olkaria Power Plant, and probable reserves of 600 MW atexploration sites. The Eburru prospect, 30 km north of Olkaria, contains probable reserves in theorder of 100 MW. Several thermal manifestations in the Rift Valley between Eburru and thenorthern border of Kenya indicate the existence of extensive, but as yet unquantified additionalenergy resources. The Geothermal Development and Pre-Investment Project (Cr. 1973-KE)assisted in drilling of about 30 production wells to deliver steam to the Olkaria I and II PowerPlants.

1.14 Biomass Resources. Kenya has large and diverse forest resources, though there ispressure on forests around major population centers. The main biomass energy is woodfuel --

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firewood and charcoal -- which is the major source of energy in Kenya, accounting for about 70-75 percent of total energy use. Firewood is consumed by rural households and industries,particularly for tea drying, while charcoal provides cooking energy for many urban householdsand small commercial establishments. The only non-woody biomass resource which is beingutilized on a proven commercial scale is sugar cane bagasse. The Kenya sugar industry producesabout 35,000 tons of bagasse annually which, supplemented by fuelwood or fuel oil, is used toraise steam for producing sugar cane and generating about 25 GWh of electricity from turbinesinstalled at individual sugar mills. The efficiency of power production from bagasse is low andcould be increased with the introduction of pre-drying, palletizing and other measures, whichcould create surpluses to produce power for additional uses such as pumping water for irrigationor for sale to a power company. The project would provide financing for a Renewable/HouseholdEnergy Survey to provide the analytical basis for formulating a sustainable renewable/householdenergy strategy. Further, a rural electrification master plan is currently being carried out toexplore alternative strategies for meeting rural power needs.

1.15 Solar and Wind. Kenya has a large potential of solar and wind energy, which haveeconomic potential for meeting energy requirements particularly for rural communities becauseof the high cost of traditional network electrification. Indeed, Kenya has utilized its solar energypotential more successfully than most African countries. According to an ESMAP study, atleast 20,000 photovoltaic units (PV) have been sold by the private sector since 1987. Thesystems have been sold mainly to rural middle class households, which are well integrated intothe cash economy, but live far away from KPLC's power lines.' A unique feature is also thepredominant role played by the country's private sector. There are currently eight Nairobi-basedcompanies who supply the PV market, each with scores of agents in rural areas, to market,install, and maintain the systems. To promote the use of PV technology, the Government hasover the past couple of years reduced the level of import tariffs and value-added tax on most PVequipment. The proposed project would further assist the Government to maintain a competitivetariff and tax policy for renewable energy equipment, and to establish guidelines for equipmentquality. These policy actions are supplemented by an ESMAP-financed micro-solar project,initiated in 1995. The objective of the project is to overcome hurdles to wider adoptation of solarenergy technology: it would investigate innovative financing options for lower incomehouseholds, disseminate small solar powered lanterns on a commercial basis in rural villages andevaluate technical product performance and customer satisfaction. In addition, the Arid LandsDevelopment Project, approved in November 1995 (Cr. No. 27970) would support renewableenergy. For example, if a community microproject on water would use a solar or a wind-drivenpump the project would finance it. To promote renewable energy technologies, the districtmobile extension teams would sensitize communities and other development actors on thepotential of renewable sources of energy and train community personnel in maintenance of thefacilities.

1.16 Wind energy is used on a limited scale, mainly for irrigation: currently some 200 waterpumps are in operation, many of them manufactured locally. In addition, KPLC operates a 200

Further information about photovoltaics in Kenya can be found in the ESMAP report "Photovoltaic Power tothe People - The Kenya Case", January 1994 (no report number).

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kW wind turbine which, in 1995, provided 1.1 GWh to the grid, and a 350 kW hybridwind/diesel system to serve the electricity needs of the surrounding community.

1.17 Hydrocarbons. No commercial petroleum resource has yet been discovered. Based onevidence available from drilling by privately owned oil companies in Kenya and in neighboringcountries, Kenya's petroleum prospects are rated modest, but in view of the sparse data coverageits petroleum prospects remain to be fully evaluated. The most attractive areas at present are theRift-related structural basins in the interior. Also of interest is the coastal margin basin where themajority of Kenya's exploration to date has taken place. The Bank has supported Kenya inpromoting petroleum exploration by private companies, most recently through the PetroleumExploration Technical Assistance Credit 1 675-KE.

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2. ENERGY SECTOR ORGANIZATION

A. POLICY INSTITUTIONS

2.1 The Ministry of Energy (MOE) is responsible for energy policy formulation andoversight of the operations of the organizations in the power and petroleum sub-sectors.MOE is also concerned with the development of power, petroleum exploration andsupply, and the development of biomass and other new and renewable energy resources.Until recently the Ministry of Finance (MOF), in consultation with MOE, establishedprices and tax rates for both power and petroleum products. Since October 1994,petroleum products retail prices have been market-determined.

B. ELECTRICITY SUB-SECTOR

2.2 Sub-sector Institutions. Three limited liability companies, and two regionaldevelopment authorities are currently operating in the power sub-sector: the Kenya PowerCompany (KPC), the Kenya Power and Lighting Company (KPLC), the Tana RiverDevelopment Company (TRDC), the Tana and Athi Rivers Development Authority(TARDA) and the Kerio Valley Development Authority (KVDA). The salient features ofthese institutions are:

(a) KPLC: KPLC was established in 1983, to become the successor of the EastAfrica Power and Lighting Company (EAPLC), a private company founded in1922. KPLC is owned by the GoK (51.49%), Kenya residents (41.13%) andnonresidents (7.38%). It is the only institution licensed to distribute electricity,and therefore, owns all the distribution facilities. It also owns some smallhydroelectric plants, some thermal plants and transmission lines. It operates thegeneration and transmission system and manages both KPC and TRDC, as well asthe generation facilities of TARDA and KVDA. It is responsible for thepreparation of the sub-sector's expansion programs and is the GoK's executingagency for designing, constructing and operating rural electrification schemes.

(b) KPC: KPC was created in 1954, to import electricity from Uganda for sale by theEAPLC. KPC is wholly owned by the GoK, has no staff of its own and ismanaged by KPLC under a management contract. It owns the Olkaria geothermalpower station, two small hydro plants (Tana and Wanji, 14 and 7 MW,respectively), the interconnection line with Uganda and other transmission lines.The power generated from KPC's plants and imported power from Uganda is sold

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to KPLC at cost (includes debt service, operation, maintenance and developmentsurcharge to meet the local contribution for new investment).

(c) TRDC: TRDC was created in 1964 as a separate company to develop thehydroelectric potential of the Tana River. TRDC is wholly Government ownedand is also managed by KPLC. The company owns three power stations, Gitaru(145 MW), Kamburu (92 MW) and Kindaruma (44 MW).

(d) TARDA: This is a development authority fully owned by GoK. It was created in1974 for the integral development of several basins in the Tana river includingtheir hydroelectric, irrigation, fisheries and associated tourism potential. It ownsthe Masinga (40 MW) and Kiambere (144 MW) power stations and theirassociated transmission lines. KPLC operates and maintains the power facilitiesand buys power in bulk from TARDA. Under the financing of Kiambere, KPLCis obligated to cover the cost of debt service on higher terms than those providedto the Government by lenders. The difference was originally intended to provideTARDA with financing for its non-power activities. In 1988 the GoK instructedKPLC to direct its payments to the Treasury and to base them on the terms atwhich the loans had been provided to the GoK. To compensate TARDA for theloss of revenue, since 1994 the Treasury and KPLC have provided support toTARDA.

(e) KVDA: This is also a development authority fully owned by GoK. It was createdin 1979 with similar objectives to TARDA. It implemented the Turkwell HydroPlant (106 MW), completed in 1991 (para 3.18(c)).

2.3 The complexity of the power sub-sector organization, especially the overlappingfinancial functions among the entities, has given rise to disputes on issues of assetsownership and responsibility for debt service. The GoK has therefore decided torestructure the sub-sector with a view to creating commercial-type relationships amongthe companies. The restructuring has separated management of generation assets fromthat of transmission and distribution assets. The Turkwell Hydropower Plant will betransferred to the generation company at a cost reflecting replacement cost. The actionplan for reorganization of the power sub-sector which has been agreed with theGovernment is shown in Annex 2.1.

2.4 As of May 1993, KPLC, the only institution with staff, was over-staffed. It had10,616 employees, serving 300,000 customers giving a customer/employee ratio of 28:1.In early 1994, agreement was reached between KPLC and the Bank for KPLC to improveits customer/employee ratio to at least 45:1 by the end of 1995. By December 1994 thecustomer/employee ratio had increased to 35.4:1 and currently stands at 50:1. SinceKPLC was understaffed at the professional level and over-staffed at other levels, theseimprovements have been achieved through contracting out non-core services and staffreductions,

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2.5 Applicable Legislation and its Impact on the Sub-Sector: The limited liabilitycompanies are governed by the Companies Act, and as such should be able to operate ascommercial concerns. As part of the sector reforms, KPLC and KPC were recentlyexempted from the provisions of the State Corporations Act. The Act severely limits theentities' management and operational autonomy including that of the developmentauthorities. Apart from the State Corporation Act, the other legislation affecting thegeneration, transmission and distribution of power consists of the Electric Power Act, theGeothermal Resources Act, and other Acts that deal with foreign investment and withland use. There is currently no environmental legislation for the sub-sector. The effectsof the various laws on the sub-sector are as follows:

(a) The State Corporations Act poses restrictions on the companies anddevelopment authorities, as it gives the President and the responsible Ministerwide discretionary powers over them. For example, the President may appointand remove board members, and he may issue directives which must beimplemented by the Board.

(b) The Electric Power Act. The Act provides the Minister with broad powers. Inaddition to formulating sub-sector policy, he has control over electricity tariffs.The Minister also is the dispenser of the licenses needed to participate in any ofthe sub-sector's activities. He may also revoke or modify the terms of a licenseduring its life. Such wide ranging powers are not conducive to the efficientoperation of the sub-sector and are incompatible with today's accepted industryand business practices which are based on a clear separation of the ownership,regulation and operation of the sub-sector.

(c) The Geothermal Resources Act is meant to regulate the use of Kenya'sgeothermal resources. It establishes that the resources belong to the State andagain confers power to the Minister of Energy. He issues licenses for explorationand exploitation and can impose levies, rentals and royalties for use of theresources.

2.6 The sub-sector has been regulated by the Minister of Energy. The creation of anindependent and credible regulatory mechanism is clearly important for the long-termsustainability of private sector participation in the sub-sector. The Government hasprepared an action plan for reform of the legal and regulatory framework for the powersub-sector including specific proposals for establishment of an autonomous ElectricityRegulatory Board (ERB). The draft enabling legislation has been prepared with PPFfinancing and would be presented to the Borrower's legislature prior to Crediteffectiveness (para .8.2 (i)). Further, the Government has stated in its Letter of SectorPolicy that the power sub-sector will now be required to operate on a commercial basiswithout burdening the Government budget.

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C. PETROLEUM SUB-SECTOR

2.7 Sub-sector Institutions. Eight private companies, two parastatals and one semiprivate company operate in the petroleum sub-sector. The supply and distribution ofpetroleum products is in the hands of subsidiaries of six multinational oil companies(AGIP, BP, CALTEX, ESSO, SHELL, TOTAL), and two other private companies(KOBIL and KENOL). The state-owned National Oil Corporation of Kenya (NOCK)oversees exploration activities and procures crude oil and petroleum products incompetition with the other oil companies. The Kenya Petroleum Refenery Ltd. (KPRL)at Mombasa, is jointly owned by four oil companies (Shell, BP, Esso and Caltex - 50%)and the Government (50%). The Kenya Pipeline Company (KPL) operates the petroleumproducts pipeline which runs from Mombasa to Nairobi and farther to Nakuru, Eldoretand Kisumu in western Kenya.

2.8 The Government deregulated the procurement and importation of crude oil andfinished products, and retail prices in October 1994. NOCK's right to supply at least30% of the distributors' crude oil requirements was rescinded and the distributors are nolonger obliged to meet their requirements through KPRL (para. 3.22). However, thepetroleum sub-sector could not be fully deregulated because of the market's dependenceon KPRL for LPG (a by-product in the refining process) and the absence of infrastructurefor its importation. Therefore, the Government: (i) required oil companies to import andprocess through the refinery at least 1.6 million tons of crude annually, which is thevolume required to meet the market's current demand for LPG; and (ii) protected therefinery's operations, initially for two years through a tax on selected imported products.

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3. ENERGY MARKETS, PRICING AND KEY ISSUES

A. THE ENERGY MARKETS - ENERGY CONSUMPTION AND SUPPLY

3.1 Kenya's total energy consumption amounted to about 12.5 million tons of oilequivalent (toe) in 1994. This translates to 0.48 toe per capita, which is low by worldstandards but the highest in the Eastern Africa Region'. Fuelwood and charcoal met 70-75 percent of total energy consumption. Modem energy products - electricity andpetroleum products - met the remainder. Kenya's modem energy consumption (0.10 toeper capita) is below other developing countries, though it is higher than the average 0.07toe for sub-Saharan Africa2 . Annex 3.1 shows the national energy balance.

Electricity

3.2 Consumption. The growth rate in KPLC's electricity sales has declined duringthe past couple of years, owing to a combination of a slowdown in economic growth, anda supply shortage. While KPLC's sales increased by more than 5 percent annually during1987 and 1991, the average annual increase has been around 4 percent since 1991. Totalsales in the interconnected system were 3,402 GWh in FY96 of which 45% was to largeindustrial and service establishments. Larger industrial and service sector have also beenthe consumer category with the most rapidly increasing demand. The total number ofconsumers, including rural electrification, is about 406,000 of which 307,000 (76%) areresidential. It is estimated that only 7 to 8 percent of the total population has access toelectricity. Table 3.1 and Annex 3.2 show electricity sales by consumer category inFY96.

3.3 The growth in system peak demand has also slowed down significantly over thepast few years, and was 648 MW in the 1995/1996 fiscal year. Overall, the averageannual increase has been below 4 percent since 1990, compared to 6.5 percent during thesecond half of the 1980s.

Total per capita energy consumption in Uganda and Ethiopia is about 0.3 toe and in Tanzania about0.45 toe.

2 Modem per capita energy consumption in 1991 was about 0.4 toe in Thailand; about 0.3 toe in thePhilippines, India and Indonesia, while it was about 2.1 toe in Korea.

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Table 3.1 - Electricity Sales by Consumer Category in FY96

1995/96 Average annual growth rateConsumer Category (GWh) FY90-FY96 (%)

Domestic/small commercial & 993 4.1%irrigation

Medium commercial & industrial 660 3.0%Large commercial & industrial 1,492 4.7%Off-peak 92 -3.9%Street Lighting 15 1.2%

Total KPLC 3,252 3.8%Rural electification 150 14.7%

Total Sales 3,402 4.2%System Peak (MW) 648 3.7%

Source: KPLC

3.4 Chart 3.1 below illustrates that the Nairobi and the Coastal (including Mombasa)areas account for the bulk (70 percent) of KPLC sales.

Chart 3.1 KPLC Electricity Sales per Geographic Area FY1995

M t. K e ny a North RiftW cst Kcn y

C entrol R ift

N airobi

C oIut

3.5 Generation Facilities. Hydro power stations dominate (79%) the interconnectedsystem of 776 MW of available generating capacity, while geothermal and oil thermalstations provide the balance. In addition, Kenya has an import agreement with theUganda Electricity Board (UEB) for 30 MW of firm power up to the year 2005.However, because UEB has had little capacity to spare, it has usually been able to exportonly during off-peak hours. During 1990-1995, UEB provided only 17 MW of off-peakpower. Table 3.2 shows the available generating capacity and annual generation in FY96.Annex 3.3 provides plant details.

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Table 3.2 Available Generating Capacity and Generation

Capacity (MW) as at February 1996, andgeneration (GWh) in FY96

AVAILABLE CAPACITY (excl. imports) MW 776Of which Hydro 619

Oil thernal/thennal/diesel/gas turbine 105Geothermal 45Wind 0.4Diesels in isolated areas 7

GENERATION (gross) GWh 4,119Of which Hydro 3,163

Oil thermal/diesel/gas turbine 397Geothermal 390Wind IImports from Uganda 149Diesels in isolated areas 19Network losses and station use GWh 717

SALES GWh 3,402

Source: KPLC

3.6 The two most important power stations are the Gitaru and Kiambere hydroelectricstations, which together produced almost 80 percent of total energy in the interconnectedsystem in 1995/1996. The Olkaria I geothermal station and the liquid fuel generators(diesels, steam units and gas turbines) provided less than 10 percent each.

3.7 Transmission and Distribution Facilities. The transmission facilities are thefollowing: 980 km of 220 kV lines; 450 km of 66 kV; 120 km of 40 kV; 3,450 km of 33kV; and 8,300 km of 11 kV circuits. The 220 kV network is about 10 years old andconsists of four line segments. All 220 and 132 kV lines have single pole reclosing. As aresult of only one 220 kV line connecting Mombasa to the major hydrostations andbecause the thermal capacity in the Mombasa area is insufficient to meet the demand, thequality of service suffers when the line fails. There is also insufficient voltage support inMombasa (supply voltage is too low part of the time, and too high at other times). Toimprove supply in Mombasa, the project includes installation of transformers,construction of lines and substation. Distribution voltage is typically 33 and 11 kV.Secondary distribution voltage is 415 volts for three phase supply and 240 volts for singlephase service.

3.8 System Operations. System operations have been constrained over the last fewyears due to insufficient reserve margin, and were further affected by the damage sufferedby one of Gitaru's generating units which took about a year to repair and was returned toservice in March 1996. As no new capacity has been added to the system since FY1990/1991, reserve margins have continuously decreased, and KPLC has been forced toresort to periodic load shedding (para 1.7). The output from the thermal plants haveincreased in the past couple of years as a result of: (i) a rehabilitation program that hasmanaged to bring up the steam, gas turbine and diesel units close to their rated capacities;and (ii) the connection, in 1995, of drilled make-up wells to recover the original output ofthe Olkaria I Geothermal Power Plant.

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3.9 KPLC has been relatively successful in managing system losses -- about 16percent of net generation -- when compared to neighboring countries (internationalstandard is 10 %). However, they are quite high in some parts of the transmission anddistribution system, especially in the Coastal area, where KPLC rely on long 33 kVfeeders to supply load concentrations on the Mombasa Island. As loss levels increasewith load growth, targeted loss reduction measures are required to prevent unacceptablegrowth. The proposed project includes a four-year line loss reduction programcomprising upgrading and installation of new feeders, replacement of capacitors, lowvoltage system reinforcements and construction of new substations (para. 4.5 (c (ii)).

3.10 Demand and Supply Balances. The sales forecast predicts electricityconsumption to increase on average by 5.6 percent per year over the next ten years to5,785 GWh in 2006. Charts 3.2 and 3.3 below depict the operation of the interconnectedsystem with and without the proposed project. Chart 3.2 shows the annual balancebetween peak demand and available generating capacity and indicates that the system'sreserve margin presently is negligible resulting in peak load shedding. The situationworsened during 1996 as several of the old Kipevu thermal units were derated due tobreakdown. With the investments under the proposed project, the capacity balance wouldremain comfortably positive from the year 2000 through 2004. Thereafter, new capacityneeds to be installed to meet the growing demand. The chart also shows that without theproject, the capacity of the existing system would decline slightly with the retirement ofthe old steam and gas turbine units (Annex 7.3 provides details).

Chart 3.2: Capacity Balance

1,600

1.400

1,200 -1l200 * | | T _New geothemal MW

1,000 ! New hydro MW

800 - t New diesel MW

6 7E.isting capacaty with project600 m

2+_-E.isting capacity without400 project MW

-- Forecast system peak MW

200

0

3.11 Chart 3.3 below shows the annual balance between electric energy demand andsupply. The system is not able to meet the current energy demand and the shortage ofenergy would continue until Kipevu II and Olkaria III are commissioned in FY2000.Then, with the other investments under the proposed project - and under average

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hydrology - the system would be able to meet demand until around the year 2004, whenthe demand again starts pressing close on supply.

Chart 3.3: Electric Energy Demand and Supply Balance

7,W /

5IOW

,:~~~~~~~~ ~ tst0 No- U6Q>

Petroleum

3.12 Domestic petroleum products consumption has grown relatively slowly in the pastyears (I% per year on average), and was 2 million tons in 1995 (Chart 3.4). The transportsector accounts for about 67 percent of total consumption; government establishrnents for25 percent; and non-governmental industries, the service sector, agriculture andhouseholds for the balance of 8 percent. Given strong economic growth of at least 5percent per year, future consumption growth levels are expected to be higher than thoseexperienced in the recent past. In addition, LPG consumption is expected to increaseonce the supply constraints are removed.

3.13 Since Kenya does not have its own oil resources, all petroleum requirements areimported. Crude oil is refined at the Mombasa refinery, but due to the simpleconfiguration of the refinery, it is uneconomic to process sufficient crude oil to match thedomestic demand and, therefore, refined products are imported to meet the supplyshortfall. Kenya imported about 2 million tons of crude oil and 500,000 tons of refinedproducts in 1995.

3.14 Refined products are transported via a pipeline from the Mombasa Refinery toNairobi, and after the recent extension of the pipeline, from Nairobi farther to the townsof Kisumu and Eldoret in western Kenya. The pipeline also serves as a transport mediafor about half of the petroleum products requirements of Uganda (the other half istransported via Tanzania).

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CHART 3.4 DOMESTIC DEMAND FOR PETROLEUM PRODUCTS

z5s00,__

2000,~3- U Kerosene

U Petrol115NIOW ~ ~ ~~~IOMP

I I E~~~~~~~~~~~~~MJet Fue

1,000,000, o~~~~~IIIIIII~~I Fuel Oil* Diesel

1983 1986 1989 1992 1995

B. ENERGY PRICING

3.15 Electricity Tariffs. Kenya has had a history of low electricity tariffs. The lowprices led to the deterioration of the power sub-sector's financial viability (paras. 5.8 -5.12). In 1994, however, Kenya started moving towards economic pricing. Under theprogram of tariff adjustments agreed with IDA, the first installment raised the averagetariff by about 60% in March 1994. The resulting average tariff was about 55% ofLRMC. The second installment, effected in October 1996, increased the averageelectricity tariff to about 73 percent of LRMC. An update of the November 1993 TariffStudy to be completed by November 1997, would provide the basis for the Govemrmentto agree with IDA on the magnitude and timing of additional adjustments to cover fullLRMC. The 1994 increases improved KPLC's financial position, and future increaseswould help it to finance a reasonable share of the costs of its investment program andcontribute to more efficient use of electricity. As the sub-sector is moving towardscommercialization and independent power producers (IPPs), bulk supply tariffs forpurchases from IPPs would be based on the ICB process while the tariffs to finalconsumers would be decided by an autonomous ERB (para. 2.6) on the basis of LRMCprinciples and the financial needs of the subsector.

3.16 Petroleum Products Prices. On October 27, 1994, the GoK deregulatedpetroleum products pricing in line with the agreement reached with the Bank in thePolicy Framework Paper for 1994-1996. Taxes account for between 0 percent (jet fuel)and 53 percent (regular gasoline) of retail prices.

3.17 Comparative Household Energy Costs. Table 3.5 below shows that firewoodand charcoal are the lowest cost cooking fuels on an equivalent energy basis. Electricityis substantially more expensive and consequently it is not commonly used for cooking.

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In an effort to promote switching from kerosene and charcoal to LPG, the Government isconsidering standardizing LPG equipment to increase market competition and lowerprices. The proposed project would finance a study to recommend uniform standards forLPG cylinders, valves and pressure regulators including the associated testing,monitoring and regulatory arrangements (para. 4.5 (B)). Additionally, the liberalizationof petroleum prices should increase the availability of fuels even in the more remoteareas. Availability would also improve upon completion of the infrastructure to allowincreased production and/or importation of LPG. The household/rural energy studiesunder the project would assess taxation policies to promote transition to efficient modemfuels (para. 4.5(B)).

Table. 3.5 Comparative Cooking Costs

LPG Kerosene Charcoal Firewood Electricity

Nairobi retail price 667 269 135 31 113US$/ton or US$/MWhNet heating value 44.8 40.5 34.4 16.7 3.4MMBTU/ton or MMBTU/MWhPrice 14.8 6.64 3.93 1.85 33.0US$ per MMBTUStove Efficiency 55% 42% 30% 17% 60%

Efficiency adjusted costUS$ per MMBTU 27.1 15.8 13.1 10.9 55.01/ Exchange rate: I $US =55 KSh

C. KEY ISSUES IN THE ENERGY SECTOR

3.18 The principal issues in the energy sector are: (i) Government involvement in allaspects of energy sector operations (para. 2.5); (ii) low electricity prices in relation to thepower sub-sector's financial requirements and to the economic cost of supply (para.3.15); (iii) complex power sub-sector organizational structure (para. 2.3); (iv) untilrecently, GoK control of petroleum products pricing, marketing and procurementresulting in economic distortions; (v) low demand and supply-side energy efficiency; and(vi) potentially negative environmental effects of energy projects. Because of the longtime it has taken the GoK and the Bank to reach agreement on sector reform policies, ithas proved difficult for the GoK to mobilize resources for the required investmnents, thusresulting in the current electricity supply shortages.

(a) Government Involvement. The GoK has played a dominant role in the sectorthrough ownership of facilities and a significant involvement in strategic andoperations management. It is the main owner of power generation facilities,owner of the oil pipeline and petroleum storage facilities, and has a 50 percentstake in the KPRL. In addition, the GoK takes an active management role in thekey areas of setting and approving electricity prices, approving investmentprograms, and appointing the Boards of the energy enterprises. Prior to theexemption of KPLC and KPC from the State Corporations Act, the GoK alsoprovided the ceilings on staff remuneration and benefit levels under the generalcategorization of parastatals.

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(b) Electricity Pricing. For many years, the average electricity tariffremained substantially below the economic and financial cost of supply(para. 3.15). As a result, the sub-sector experienced financial difficultieswhich impacted on its ability to service external debt obligations, whichthe Government had to meet under guarantee agreements with lenders.However, following recent tariff increases, the industry has reimbursed theGoK. Low prices have also promoted inefficient use of electricity.

(c) Complex Organization of the Electricity Sub-Sector. Power purchasearrangements between the KPLC and the bulk supply companies (KPC,TRDC, TARDA and KVDA) are complex. KPLC purchases power fromthe bulk supply companies under various purchase and lease agreements.A number of unusual practices are apparent in the execution of theseagreements. First, with respect to power purchases from TARDA, theGovernment requires KPLC to remit payments to cover TARDA's debtobligations to the Treasury, instead of making payments to TARDA asenvisioned under the original agreement. Since 1994, KPLC also paysKSh 55 million annually directly to TARDA to cover expenditure oncatchment preservation, dam monitoring and security. In addition, theGoK finances the cost of TARDA's other activities. Second, theownership of the Turkwell power plant implemented in 1991 (developedby KVDA and operated by KPLC) is undefined. Nevertheless, KPLC hassince 1994 paid KVDA KSh 45 million annually to cover operating andmaintenance costs related to the Turkwell dam. In addition to the annualpayments, KPLC also pays the equivalent of US cents 3 per KWh for theelectricity dispatched from Turkwell and covers the operation andmaintenance costs of the power station.

(d) Petroleum Sub-Sector Operations. With the deregulation of petroleumproducts prices and importation in October 1994, the main outstandingissue is the removal of the remaining impediments to full competition: (i)the requirement for the market participants to process at least 1.6 milliontons of crude oil per annum so as to meet the current consumption of LPG;and (ii) the import taxes on fuel products instituted to protect KPRL,initially for two years up to October 1996. Based on estimates by thepresent shareholders, the minimum level of protection that the refinery inits present state would need to be competitive with direct product importsis equivalent to about US$1.5 per barrel imported products. Thistranslates into an annual cost to the economy of about US$22-37 million.These issues are being addressed under the Bank's macroeconomicdialogue with the Government.

(e) Delays in Implementing Sector Investment Programs. Investment,both in new plants and in the rehabilitation of existing facilities to meetthe growing demand for energy has been inadequate. The main reasons

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for inadequate investment have been lack of donor support due to slowimplementation of sector reforns and inadequate self-financing. As aresult, Kenya is now experiencing electricity shortages which are imposinga substantial cost to the economy and restraining economic growth (para1.7). If the required investments are not undertaken quickly, electricityshortages would continue to increase with serious consequences to theeconomy, especially if rainfall is below average and reduces the outputfrom the hydro plants. The sub-sector's aggregate investmentrequirements are estimated to total almost US$1,000 million during FY96-2001, the financing of which would be a heavy burden on the economyunless the Government seeks new ways of mobilizing resources, forinstance from the private sector as well as substantially improving thefinancial performance of the power companies. This in turn requiresincreasing the operational efficiency of the companies and adoption ofsound pricing policies. The proposed project would finance about US$700million (excluding interest during construction) for the next five years.Additional resources would therefore need to be soon mobilized,particularly for financing of transmission and distribution systems.

(f) Demand and Supply-Side Energy Efficiency. Although some effortshave been made to improve energy efficiency, inappropriate energypricing policies and lack of awareness of savings opportunities haveimpeded progress in this area. On the supply side, KPLC has recentlycarried out a loss reduction study, with the assistance of ESMAP, toidentify cost-effective means to reduce distribution losses in the majorload centers. On the demand side, the Kenya Industrial EnergyManagement Programme -- initiated in 1985, and administered by theKenya Association of Manufacturers (KAM) -- focuses on the provision ofinformation and energy audit services on a cost- sharing basis. Currently,ESMAP is providing support to increase the program's commercializationthrough greater cost-sharing by the benefiting industries, and to introducemodem techniques and skills. The outlook for improved demand andsupply-side energy efficiency is more promising today because of the newtariff policy, the power sub-sector reorganization, including greatercommercial orientation and private sector participation. The proposedproject would build on the past experiences and the new incentives andfinance activities to develop the human and institutional capabilities,promote private sector participation and introduce energy efficienttechnologies.

Agenda for Policy Reform

3.19 The dialogue between the Bank and the Government of Kenya on energy sectorreforms has been going on since the preparation of the Geothermal Development and Pre-Investment Project in 1988. The Government fully recognizes the importance of the

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issues discussed above on both sector and macroeconomic performance and has recentlycommitted itself to creating an efficient and viable energy sector.

3.20 The GoK's overall strategic objective is to create enabling conditions for anefficient energy sector and eliminate electricity supply deficits. To accomplish thisobjective, the strategy is detailed in Government's Letter of Sector Development Policy(Annex 3.4). The strategy comprises: (i) macroeconomic measures to create an enablingenvironment for attracting private sector investment and to improve incentives foroperational efficiency; (ii) reforms of the sector's institutional and legal environment; and(iii) least-cost investments in power to eliminate supply deficits in the late 1990s andearly 2000s. Public sector investments are expected to be complemented by privatesector investment in at least two power plants in the next five years.

3.21 Macroeconomic. The macroeconomic measures relate primarily to theadjustment of power tariffs and to the deregulation of the petroleum sub-sector. Onelectricity prices, the objective is to reach economic levels so as to provide appropriateconsumer signals and to enable the sub-sector to become financially viable. TheGovernment agreed in the context of the 1994-1996 PFP, to raise the average tariff to 75percent of the LRMC by 1996, in three installments starting in March 1994. In the firstinstallment, a nominal increase of about 60 percent in the average tariff raised it to about55 percent of LRMC. The second installment, scheduled for March 1995 was postponedsince the average tariff had already reached the 65 percent of the LRMC target due toappreciation of the KSh. The installment on October 1, 1996, raised the average tariff toabout 73 percent of LRMC. In addition, the Government has: (i) given KPLC theautonomy to implement a fuel adjustment clause since March, 1994; (ii) agreed to allowKPLC to automatically adjust tariffs to reflect changes in the cost of external debt servicearising from fluctuation in the exchange rate of Kenya shilling. Further adjustmentswould be determined on the basis of an update of the Tariff Study to be completed byNovember 1997 and recommendations, satisfactory to IDA, would be implementedduring FY1997/98. This issue will also be addressed under the Bank's macroeconomicdialogue, as the agreement between the Government and IDA on an action plan for theimplementation of further tariff adjustments is a condition for the Structural AdjustmentCredit's second trance release.

3.22 With regard to the petroleum sub-sector, the GoK deregulated the importation,marketing and pricing of petroleum products on October 27, 1994. The objective of thederegulation was to create a competitive and efficient market for petroleum products byremoving controls on procurement, distribution and pricing of products. The followingmeasures have been implemented to date:

(i) NOCK's right to import upto 30 percent of domestic product requirementswas rescinded;

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(ii) temporary import tariff of KSh 0.50 per liter on all finished petroleumproducts except kerosene, LPG and automotive diesel, to allow KPRL toprepare for a competitive environment;

(iii) liberalization of retail prices, although, under the Restrictive TradePractices and Monopolies Act Ch. 504, the MoF has powers to fix ceilingprices in areas with inadequate competition;

(iv) a monitoring cell was established in MOE to monitor petroleum products'prices and maintenance of minimum operating stocks of 30 daysconsumption of liquid products and 10 days for LPG by oil companies;and

(v) requirement that the oil companies refine at least 1.6 million tons of LPGrich crude oil at KPRL to secure LPG supply until alternative supplyarrangements have been worked out.

3.23 The Government and other shareholders in the refinery are currently discussingtbe options for the future of the refinery. These include: (i) extension of protection togin e KPRL more time to improve its competitiveness in an open environment, includinginvestment in improving LPG output; and (ii) closure of the refinery with the possibilityo-f converting it into a fuel import facility including importation of LPG. These issues arebeivig addressed under the Bank's macroeconomic dialogue with the Government.

3.24 Institutional and Legal Environment. This aspect of the strategy comprisesrestructuring of the power sub-sector to create arm's length commercial-typerelationships between the companies and reforms of the legal and regulatory frameworko tlacilitate the restructuring of the sub-sector and encourage private sector participation.A ti autonomous regulatory arrangement is particularly important to ensure that decisions

im' electricity pricing, and environmental issues among other things are taken in an,o'bi(ctive manner.

'.X95 On power restructuring, the GoK commissioned a two phase Power SectorP,estructuring Study to recommend an efficient industry structure and an implementationanid financial restructuring plan. Based on the reports' recommendations, theGo vernrnent agreed to restructure the sector entities into two separate companies, one forgeneration and one for transmission and distribution, both to be managed on acommercial basis under the auspices of performance contracts. In addition, new poweroplants would be offered to both the private and public sector generating companies toconstruct, own, manage and operate. Further efficiency gains would be achieved fromst teamlining staffing to levels consistent with industry standards and from contracting outml.2iIlary and other services. Agreement has been reached with the Government on anactiocn plan for restructuring the power sub-sector and implementation of ther-estructuring has started.

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3.26 The Government has also commissioned a study of the legal and regulatoryframework for the energy sector. On the basis of the study's findings, agreement hasbeen reached with the Government on an action plan for implementation of therecommended reforms (including a detailed proposalfor the establishment of anautonomous regulatory arrangement for the power sub-sector). Submission toParliament of the required amendments to the Electric Power Act would be a conditionfor Credit effectiveness (para. 8.2 (i)).

3.27 Investment. The third element of the strategy comprises investments in powergeneration and associated transmission and distribution, designed to eliminate electricitysupply deficits in the late 1990s and early 2000s and to increase supply and demand-sideefficiency. Agreement was reached, during appraisal, on a five-year investment plan forthe power sub-sector. Further, during negotiations, agreement was reachedfor theGovernment to review with IDA its power sub-sector five-year rolling investment plan byMarch 31, of each year. GoK would not undertake any investments of more than US$10 million (including IPPs), outside the agreed least-cost plan without consulting with IDA(para 8.1 (i)). The investment program includes construction by KPC of three powerplants which are critical for meeting power demand in the late 1990s, addition of a 72.5MW unit at an existing power station (Gitaru) and private sector construction andoperation of two other power plants (75 MW Kipevu II Diesel and 64 MW Olkaria IIIGeothermal) which are required under the least-cost investment program, and whichwould increase competition in the sector and improve operational efficiency.

D. WORLD BANK GROUP INVOLVEMENT

3.28 IDA has provided seven loans and credits totaling about US$212.2 million forfinancing power investments in Kenya between 1971-1988. The first two power projects(Ln. 745-KE and Ln. 1147-KE) helped finance hydroelectric development on the TanaRiver. The projects were designed to meet the demand for power in Nairobi and thecoastal area around Mombasa, where most of the industrial and commercial activities ofKenya are concentrated. Five loans and credits were made for the development ofgeothermal power in Kenya. The Olkaria Geothermal Engineering Loan (Ln S-12-KE of1978) financed drilling of additional wells to gauge the productivity of the Olkaria steamfield and to ensure that there was sufficient steam for each generating unit proposed underPhase II of the Olkaria Geothermal Development Project. The Olkaria Geothermal PowerProject (Ln. 1799-KE of 1980) aimed to provide a firm source of power and energywithin the country to meet the growth of demand expected from 1981 to 1985 and toassist in reducing the country's heavy dependence on imported oil. The OlkariaGeothermal Power Expansion Project (Ln. 2237-KE of 1983) was intended to meet thegrowth in energy demand which was projected to exceed the available capacity at thetime. The Geothermal Exploration Project (Ln. 1486-KE of 1984) was to supportacceleration of the geothermal exploration and improve new reserves that could supportadditional power generation during the 1990s. The main objective of the recentlycompleted Geothermal Development and Energy Pre-Investment Project (Cr. 1973-KE of

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1988) was to assist Kenya in preparing a least-cost power generation expansion plan,largely through utilization of indigenous energy resources, and to develop options forenergy pricing policies. It also addressed selected aspects of rural electrification policyand household fuel supply and distribution.

3.29 Three loans were made for reforestation (Loans 641-KE. 1132-KE/Credit 565-KEand 2098-KE/Cr. 1213 -KE). The first loan was implemented satisfactorily, while thesecond loan suffered from cost overruns and implementation problems. In the petroleumsub-sector, the Bank financed the construction of the products pipeline from Mombasa toNairobi (Ln. 1 133-KE) between 1975 and 1981 and two petroleum exploration promotionprojects (Ln. 2065-KE and Cr. 1675-KE). Pipeline construction was completed onschedule. The exploration promotion projects have been successful in helping to attractsix international companies to take acreage in Kenya, but no commercially viable oil orgas reserves have been discovered to date.

3.30 The hydroelectric projects (1971 and 1975) concentrated largely on financing ofconstruction and equipment; execution of the physical components was generally good.In the later years, lending shifted to strengthening the institutions with provision oftechnical assistance and training, particularly for geothermal development. The ProjectCompletion Reports on all power projects concluded that while the objectives of physicalcomponents were generally achieved, there were weaknesses in project design,institutional, environmental and financial aspects, as well as in monitoring, andprocurement. The lessons learned from these operations have been incorporated in thedesign of the proposed project.

3.31 The project has incorporated the recommendations of the Bank's policy papers onelectric power and energy efficiency, which emphasize the importance of transparentregulatory processes, private sector participation, sector restructuring, and promotion ofboth supply and demand side efficiency. ESMAP's recommendations for reducing powerlosses have also been taken into account in the design of the project's efficiencycomponent.

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4. THE PROJECT

A. PROJECT ORIGIN, RATIONALE AND OBJECTIVES

4.1 Origin. A number of studies undertaken with IDA financing provided under theGeothermal Development and Energy Pre-Investment Project (Cr. 1973-KE), the ParastatalReform and Privatization Technical Assistance Project (Cr. 2440-KE) and under a ProjectPreparation Facility - have facilitated the preparation of the project. In the late 1980s, it wasforeseen that new investments were needed in the power sub-sector by the mid 1990's to avoidsupply shortages. However, IDA could not support new investments in the absence of anagreement on sector reform policies and program for implementation. The following issues wereidentified as requiring in the dialogue with the Government: (i) low electricity prices in relationto the power sub-sector's financial requirements and to the economic cost of supply; (ii)complexity of the power subsector organization (para. 3.18); (iii) need for annual update of andadherence to least cost power expansion plan; and (iv) need to incorporate environmentalanalysis in project feasibility studies; and (v) GoK control of petroleum pricing, procurement andmarketing. To address these issues, studies were commissioned on electricity tariffs; powersector organization; least-cost generation expansion planning; and petroleum pricing,procurement and marketing. These studies provided the basis for the policy dialogue whichculminated in an agreement with the Bank on a broad sector reform strategy in the framework ofthe PFP for FY1994-96. The studies also provided the basis for further dialogue with the Bankon the details of the policy reform during the preparation of this project. The project's SectorRestructuring and Reform Component has been designed to assist the GoK in implementing themost critical policy reforms. An Environmental Ranking Study was also carried out with Bankstaff assistance. In addition, environmental assessments have been carried out for three of thefive power generation plants included in the proposed project.

4.2 Rationale for IDA Involvement. IDA's participation in this project would support theGovernment's development objectives and policies towards economic growth and povertyreduction as expressed in the 1996-1998 PFP (para. 1.4). Mirroring the PFP, the Bank's CountryAssistance Strategy (discussed by the Board on January 30, 1996) emphasizes poverty reductionas key to be met by faster growth, improved expenditures and targeted measures. This project isan integral part of the CAS for poverty reduction in terms that it would stimulate economicgrowth by: (i) improving and expanding basic infrastructure, which is critical to both improvingthe efficiency of existing private sector investment and attracting new private investment; (ii)improving public sector efficiency; and (iii) promoting private participation in energy provision.Specifically, the project would eliminate the electricity shortages which are a key bottleneck toeconomic growth, support the implementation of parastatal reforms in the electricity sub-sector,

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create an enabling policy and regulatory environment for private sector investment andmanagement, and improve the human capabilities in the energy sector. In addition, IDA'sinvolvement leverages about US$290 million in cofinancing and is critical in boosting privatesector confidence in Kenya's energy sector.

4.3 Project Objectives. The project's objectives are to assist the GoK in formulating andimplementing major policy and institutional reforms aimed at creating an efficient andenvironmentally sustainable energy sector and to support investments needed to meet powerdemand and increase operational efficiency. The project's specific objectives are to:

(i) finance investments needed to meet power demand and improve the operationalefficiency in the sub-sector;

(ii) reform the organizational structure of the power sub-sector to enable the operatingentities to function efficiently and on a commercially sustainable basis;

(iii) create a legal and regulatory environment necessary for private sectorparticipation in the supply of electricity;

(iv) support the GoK's adoption of economic pricing of both electricity and petroleumproducts and implementation of demand and supply-side efficiency improvementmeasures; and

(v) develop indigenous geothermal energy resources and a strategy for sustainablehousehold and rural energy development.

B. PROJECT DESCRIPTION

4.4 The project would consist of the following six components:A. Sector Restructuring and Reform

B. Other Institutional Support

C. Efficiency Improvements

D. Power System Expansion & Upgrading

E. Geothermal Resource Development

F. Future Project Preparation

4.5 A brief description of the various components of the project is given below, whiledetailed descriptions are provided in the Project Implementation Plan and in Annexes 4.2through 4.2.

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A. Sector Restructuring and Reform (US$3.6 million) - The project would support (i)establishment of a legal and regulatory framework necessary to improve sector efficiency; (ii)reform of the organization, management and financial structure of the power subsectorcompanies, and separation of generation from transmission and distribution functions; and (iii)promotion of private sector participation in the provision and management of operations. Detailsof the program are contained in Annex 4.2.

B. Institutional Support (US$24.6 million) - This component comprises studies, advisoryservices and logistical support to project implementing entities. The studies fall under fourcategories. The first category consists of identified prefeasibility and feasibility studies, andpreparation of tender documents for future projects. The second category assists in determining astrategy for sustainable and affordable household and rural energy development, and includesenergy supply and demand studies and policy and institutional analysis. It will draw upon theresults of the ongoing rural electrification study. The third category addresses consumerconcerns about the quality of solar photovoltaic components and systems and examines theestablishment of quality guidelines, including regulatory incentives to encourage the applicationof minimum norms. The fourth category will seek to promote competition in the supply of LPGto consumers through the development of uniform standards for LPG cylinders, valves andpressure regulators and the associated testing, monitoring and regulatory arrangements '.Advisory services comprise policy, engineering and financial management support to theImplementation Support Group (ISG) in MOE which will be responsible for coordination ofproject implementation. Engineering and financial management support will also be provided toKPC for implementation of the power generation component. Logistic support in the form ofoffice technology and equipment will be provided to the ISG (para. 6.2).

C. Efficiency Improvements (US$11.8 million)

(i) Demand Side Improvements (US$5.4 million) - The project would assist in: (a)developing capacity in KPLC and in the local private sector to design, implementand evaluate efficiency and electricity demand management projects; (b)establishing pricing incentives for energy efficiency, such as time-of-use tariffs,and interruptible rates to complement the agreed tariff reforms; (c) conductingdemonstration programs on energy efficient lighting, air conditioning and otherconsumer equipment in public buildings including KPLC's buildings; (d) mappingout mechanisms for third party financing of efficiency improvement measures; (e)establishing guidelines for energy efficiency labeling and standards for electricappliances and motors.

(ii) Line Loss Reduction (US$6.4 million) - The project will: (a) finance majordistribution rehabilitation and loss reduction programs in the Nairobi and the

The project activities in rural, renewable and household energy development support the recommendations ofthe Bank's Best Practice Paper "Rural Energy and Development", July 1996 (report No. 15912-GLB).

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Coastal areas based on the results of the KPLC/ESMAP loss reduction study; (b)assist KPLC to implement the ESMAP recommended program for the reductionof non-technical losses; and (c) finance the required technical assistance to set upan implementation plan and train a task force. Annex 4.3 details the efficiencyimprovement component.

D. Power System Expansion & Rehabilitation (US$609.1 million)

(i) Power Generation (US$579.1 million) - The objectives of this component are toincrease generation capacity and to install associated transmission facilities. Thecomponent includes financing of: (i) a 75 MW Diesel Power Plant at Mombasa(Kipevu I); (ii) a 64 MW Olkaria North-East Geothermal Power Station atNaivasha (Olkaria II); (iii) a second 75 MW Diesel Power Plant at Mombasa(Kipevu II); (iv) another 64 MW Geothermal Power Plant (Olkaria III); (v) a third72.5 MW unit at Gitaru Hydropower Station; and (vi) connection of twoadditional wells for the existing Olkaria I Geothermal Power Plant. KPLC's least-cost generation plan which has been reviewed and endorsed by independentconsultants indicate that Kipevu I and Olkaria II would be needed to meet demandstarting in FY 1997/98, FY 1998/99 and FY1999/00 respectively. However,because of delays in implementing the investment program (para. 1.7), theseplants are now expected to be commissioned in FY1999/00 and FY2000/01respectively. Because of the urgent need to start construction in order to meetthese commissioning dates, these plants would be financed through traditionalpublic financing sources. Kipevu II and Olkaria III would also be commissionedin FY1999/00 and FY2000/01 respectively. The two power plants are expected tobe constructed by independent power producers. The preparation work leading tothe award of contracts to IPPs is being supported by an IDA Project PreparationFacility advance. A detailed description of the power system expansion andupgrading component is given in Annex 4.4.

(ii) Upgrading of Distribution System (US$30.0 million) - This sub-component wouldcover implementation of a program for the reinforcement of the primarydistribution systems in Nairobi and in the Coastal areas. In the Nairobi area the66 kv ring road around the city would be completed and the 66 kv-11 kvsubstations capacity would be expanded. Reconductoring of some sections of the66 kv lines would also be carried out to eliminate bottlenecks. In the Coastal area,the program consists of increasing the 33-11 kv substation capacity in Mombasaand along the Indian coast. In addition, a 132 kv line would be built betweenRabai and Diani. Details of the program are contained in Annex 4.4.

E. Geothermal Resource Development (US$49.3 million) - This component would assistthe Government in developing geothermal energy resources. The project will also financeresource development activities aimed at supporting production of power at the next power plant(Olkaria IV), and developing resources for future private sector participation. Details of theprogram are shown in Annex 4.5.

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F. Future Project Preparation (US$1.5 million) - This component would supportpreparatory activities for the follow-on projects in support of the GoK's least-cost energyinvestment program.

C. PROJECT COSTS AND FINANCING

4.6 The total cost of the project is estimated at US$699.9 million equivalent, excluding taxesand duties and interest during construction, broken down by component as detailed above. Ofthe total cost, about US$570.1 million or 81%, would be in foreign costs. Total costs includeabout US$36.5 million in physical contingencies or about 6% of total base costs; and US$42.5million in price contingencies or about 7% of total base costs plus physical contingencies.Engineering and construction supervision costs are included in the cost estimates for the physicalcomponents at an average rate of about 10% of base cost. Price contingencies have beencalculated on the basis of estimated international inflation of 2.4% from FY1996/97. Thisinflation rate has been used for both foreign and domestic costs as it has been assumed that anydifferences between domestic and international price will be offset by equivalent adjustments inKenya's foreign exchange rate. A summary of the cost estimates is provided in Table 4.1 below

Table 4.1 - Estimated Project CostsKenyaEnergy Sector Investment Project % % TotalComponents Project Cost Summary (KShs '000) (USS '000) Foreign Base

Local Foreign Total Local Foreign Total Exchange Costs

A. Sector Restructuring ReformSector Reorganization - 235,266.5 235,266.5 - 3,182.7 3,182.7 100 1Deregulation of Petroleum Markets 3,696.0 21,735.7 25,431.7 50.0 294.0 344.0 85 -

Subtotal Sector Restructuring Reform 3,696.0 257,002.2 260,698.2 50.0 3,476.8 3,526.8 99 1B. Institduonal Support 168,870.2 1,516,122.1 1,684,992.4 2,335.4 20,889.6 23,225.1 90 4C. Efficiency ImprovementsDemand Side Improvements 5,895.1 323,751.1 329,646.2 81.6 4,480.5 4,562.1 98 1Line Loss Reduction 61,205.8 350,528.6 411,734.4 847.0 4,849.9 5,697.0 85 1Subtotal Efficiency Improvements 67,100.9 674,279.8 741,380.6 928.6 9,330.4 10,259.0 91 2D. Power Expansion and RehabilitationPower Generation 6,853,352.4 30,040,193.6 36,893,545.9 94,845.5 415,734.8 510,580.3 81 82Upgrading of Distribution Systems 960,960.0 960,960.0 1,921,920.0 13,299.0 13,299.0 26,598.0 50 4Subtotal Power Expansion and Rehabilitation 7,814,312.4 31,001,153.6 38,815,465.9 108,144.5 429,033.8 537,178.3 80 87E. Geothermal Resource Development 323,799.2 2,955,292.0 3,279,091.2 4,481.1 40,899.1 45,380.3 90 7F. Future Project Prepration - 93,139.2 93,139.2 - 1,289.0 1,289.0 100 -

Total BASELINE COSTS 8,377,778.6 36,496,988.9 44,874,767.6 115,939.7 504,918.7 620,858.5 81 100Physical Contingencies 422,279.8 2,218,721.4 2,641,001.2 5,844.1 30,705.5 36,549.5 84 6Price Contingencies 3,849,938.3 16,813,732.1 20,663,670.4 8,026.0 34,497.3 42,523.2 81 7Total PROJECT COSTS 12,649,996.8 55,529,442.4 68,179,439.2 129,809.7 570,121.5 699,931.2 81 113

4.7 Project Financing. An IDA Credit of US$125 million would finance about 17.9% oftotal project costs excluding taxes and duties. Other financiers would be OECF (about US$82.8million); European Investment Bank (EIB) (about US$48.7 million), KfW (about US$20.8million) and private sector investors (about US$262.5 million). KPC and KPLC would financethe balance of US$160.1 million and about US$99.0 million of interest during construction.Table 4.2 below provides the financing plan.

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Table: 4.2 - Project Financing Plan(US$ million equivalent)

Local Foreign TotalIDA 2.1 122.9 125.0OECF 4.9 77.9 82.8EIB - 48.7 48.7KfW 3.5 17.3 20.8Private Investors 51.0 211.5 262.5Government 68.2 91.9 160.1

KPLCKPC

Total Project Costs 129.7 570.2 699.9Interest During Construction 99.0 99.0TOTAL FINANCING REQUIRED 228.7 570.2 798.9

4.8 Project Onlending Arrangements. The IDA Credit would be made to the Governmentof Kenya on standard terms. The Government would re-lend about US$104.6 million andUS$11.7 million equivalent to KPC and KPLC respectively. The balance of about US$8.7million equivalent, not initially re-lend, would include funding for preparation of future projects(US$1.5 million), institutional support (US$3.9 million), and sector reorganization (US$3.6million). Since the preparation activities for future projects and some of the institutional supportactivities cannot be determined in advance, the related funds would be relend to KPC and/orKPLC where the activities concerned are of a commercial nature. The relent funds would beprovided for 20 years including 5 years grace, at an effective interest rate of not less than 7.7percent. KPC and KPLC would bear the foreign exchange risk. Execution of subsidiary loanagreements between the Government and the implementing agencies pertaining to the onlent IDAfunds, on terms and conditions satisfactory to IDA, would be a condition of effectiveness (para.8.2 (ii)).

D. PROJECT SUSTAINABILITY

4.9 The project includes substantive policy and institutional reform components which aredesigned to create a more efficient and sustainable sector. The Sector Restructuring and Reformcomponent includes financing and implementation of three key reforms. First, the power sub-sector is in the process of being reorganized to better establish commercial arm's lengthrelationships between the management of generation assets on one hand and those oftransmission and distribution assets on the other hand. The reorganization will clearly define theownership of power assets and the responsibilities for subsector debt. Second, the Governmentwill separate the responsibility for regulation of the power subsector from policy and fromoperations. This will provide an environment for more objective decisions on important issuessuch as tariff-setting and licensing, thereby making the subsector a more attractive destiny forprivate capital investment. Third, the GoK has committed to opening up the power market to theprivate sector for investment and operations. Under the project, two of the five power plantsaccounting for about 40% of the generation capacity to be installed under the project, have

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already been offered to the private sector. In addition, the project will make significant positivecontributions to the Governments budget through payment of incremental corporate taxes,dividends and interest on funds to be relent to the power companies (para. 7.20).

E. PARTICIPATION

4.10 The project was prepared in a collaborative manner with the GoK taking the lead role.Environmental studies were prepared almost exclusively by local consultants. Local consultantsalso participated in the preparation of the power sector reorganization and the legal andregulatory framework studies. NGOs, both international and domestic, participated in reviews ofenvironmental impact assessments and attended meetings at the Bank's Resident Mission on theproject. Representatives of various civic organizations also participated in the review of tariffincrease proposals. Throughout the preparation process, discussions were held between IDA andthe donors had discussions. In early 1995 the Government briefed donors on the status of theproject followed by a donors' meeting in September 1995. The private sector has also beeninvited to participate in the project through the offer of two power plants for independent powerproducers. Evaluation of private sector bids has been completed and negotiations with successfulbidders are expected shortly.

4.11 During implementation, the following arrangements are foreseen for participation. Withregard to power supply, KPLC will monitor customer satisfaction through repeat surveys. Themonitoring and the implementation of any remedial actions will be supervised by the ChiefManager Customer Care, a recently created position to improve KPLC's customerresponsiveness and service orientation. As part of the efficiency improvement component,stakeholder participation will take place in the context of a number of action-planningworkshops. These workshops will discuss opportunities to improve energy efficiency anddisseminate information. Finally, the program evaluation will include a survey of stakeholderssatisfaction with the efficiency initiatives carried out under the project. TheRenewable/Household Energy component will ensure the participation of a representative groupof medium and low income households, rural industries, service establishments, energy vendorsthrough systematic surveys. In addition, NGOs concerned with rural and renewable energysupply will be consulted. Adequate communication will be maintained with co-financiers, forinstance through shared missions.

F. ENVIRONMENTAL ASPECTS

4.12 The Project is classified as an Environment Assessment Category A. EAs wereconducted for NE Olkaria Geothermal and for the two Kipevu Diesel plants. A sectoral EA wasnot carried out as the components were identified at different times. Instead of a sectoral EA,KPLC decided to rank project components in order of environmental preference. This rankingalso served as environmental/social summaries for project components.

4.13 The geothermal site at NE Olkaria is located within Hell's Gate National Park, a park thatwas created around the existing geothermal plant and with the knowledge that the NE Olkariasite would be developed for geothermal energy. The area is rich with wildlife and serves as a

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grazing area/migration route for Maasai pastoralists. Experience with the existing site shows thatwildlife accommodate quickly to the production wells and pipes and normally groups can be seengrazing or resting in the shade of wells or pipes. The fenced perimeter of the existing plant hasinterrupted livestock grazing although wildlife species are found within the active field. As apart of the mitigation measures, the new facility will be fenced only around the wells andseparators so that wildlife and livestock will have continued access to most of the project area.Since the facility will convert wild lands to other uses, Bank wild lands policy requirescompensatory actions. During negotiations, KPC agreed to take all necessary measures toensure free movement of wildlife within the Olkaria area and between Olkaria and Hells Gateand Longonot National Park in accordance with the agreement dated September 20, 1994between KPC and KWS (para. 8.1, xi). Currently, KPC assists KWS in the maintenance of parkfacilities.

4.14 The EA for the geothermal facility recommended that condensates be reinjected as theywould be more harmful to livestock and wildlife than the condensates produced by the existingplant. The reinjection is a part of the mitigation plan. The EA also closely reviewed waterextraction from Lake Naivasha and concluded that KPC extraction was far less than other presentwater users and that the increased extraction for the new plant will not pose serious threats to thelake levels.

4.15 The Kipevu diesel unit will be designed to meet western air emission standards and liquidwastes will be treated on site. The facility will be built on land adjacent to the existing oil-firedsteam electric plant. The new facility will not require large amounts of water and it is likely thatit will be able to use water from a new waste treatment plant. It will not use Mombasa Municipalwater. The site will not involve relocating people and the land is currently unused and was aformer site of a WWII military installation.

4.16 Execution of the mitigation plans which are detailed in the EAs and in the ProjectImplementation Plan would be monitored by KPC's Environmental Unit. KPC's staff wouldreceive further training, particularly in the area of environmental analysis for hydropower plants.IDA implementation support missions would also include an environmental specialist to monitorimplementation of mitigation plans. During negotiations the Government agreed that adequateenvironmental analysis would be carried outfor allfuture power sub-sector projects andappropriate mitigation plans would be developed and carried out (para. 8.1 (ii)).

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5. FINANCIAL ANALYSIS

A. THE FINANCIAL MANAGEMENT FRAMEWORK

5.1 As indicated in paragraph 2.3, the organization of the power sub-sector iscomplex. The complexities include:

(i) financial rules regarding settlement of the costs of supplying power from theKPLC-managed power stations owned by multi-purpose river developmentauthorities; and

(ii) the pricing system under which KPLC bears the full cost of the operations ofthe two paper companies which it manages (KPC and TRDC), effectivelymaking the two companies mere cost centers.

5.2 Financial Rules. The two hydroelectric power stations owned by TARDA(Masinga and Kiambere) supply power to TRDC and KPLC respectively. 'The originalagreements between TARDA and KPLC and TRDC provided for certain costs to beborne by TRDC and KPLC. In the case of Kiambere, the lease agreement requires KPLCto pay a development surcharge equivalent to 15% of the total cost of Kiambere; debtservice for the loans contracted for construction of the plant; and the cost of replacementsand repairs necessary to maintain efficient operation of the plant. The agreement wasstructured so as to enable TARDA to obtain surpluses for investment on irrigation andrural development projects. Between 1988 and 1990, GOK issued instructions directingKPLC and TRDC to make payments for the cost of supply from the two power plants(primarily debt service) directly to Treasury instead of to TARDA. The debt servicepayments were also to be made on the same terms on which the loans had been providedto TARDA. TARDA was to be compensated for the loss of revenue from the powerindustry through direct payments from the Treasury. Following these changes, TARDAbecame dependent on the Government for budgetary support. However, since 1994, ithas received annual payments of Ksh 55 million from KPLC to cover dam relatedoperation and maintenance expenditures (para 3.18 (c)).

5.3 The power sub-sector organization study has recommended that the revaluedpower generation assets for Masinga, Kiambere and Turkwell power stations betransferred to the generation company together with their related debt. The power

Although the lease agreement for Kiambere is between KPLC and TARDA, since FY1995/96 the debtservice costs for the plant are being in TRDC accounts. TRDC in turn recovers these costs fromKPLC. These anomalies will be corrected when the arrears are transferred to KPC as part of thesector restructuring.

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generation company (KPC) would therefore be responsible for the debt service related tothe assets and for the costs of operating the facilities and would recover these coststhrough tariffs from bulk power sales to KPLC. The Government has accepted therecommendations and developed an action plan for reorganization of the power sub-sector which includes as main features.' the establishment of separate companies forgeneration and for transmission and distribution; the establishment and appointment of aBoard; and appointment of key managers for the new power generation company. InJanuary 1997, the GOK itnplemented the initial step under the plan by appointing aManaging Director, Chairman and Board.for the new Keniya Power Company Limited.The GOK also established a Task Force to oversee the sharing of staff and otherresources between KPLC and the new KPC.

5.4 Cost- Plus Pricing. In the power industry itself, excluding the multipurposedevelopment authorities, KPLC purchases power from KPC and TRDC at an "ascertainedcost" which is calculated as the total costs incurred by the supplier comprising alloperating expenses, debt service and a surcharge to provide a contribution towards newcapital expenditures. Although the two companies are essentially KPLC's cost centers,they incurred substantial losses up to FYI 992/93. These losses are due to revaluation oftheir foreign currency denominated liabilities which are not absorbed in the ascertainedcost calculation until they are realized in the form of increased debt service payments.

5.5 Since the GoK's sub-sector reform objectives include requiring companies tooperate on a commercial basis, the bulk tariffs between the generation company and thetransmission and distribution company would be determined by the ERB on the basis ofLRMC principles and the need to finance at least 20% of the generation company'sinvestment program during FY1997/98 and FY1998/99 and 25% for each fiscal yearthereafter. The responsibilities and duties of the ERB and the timing for its establishmentare spelt out in the action plan for the legal and regulatory framework for the power sub-sector.

B. PAST AND PRESENT FINANCIAL PERFORMANCE

5.6 Performance Targets. Under Credit 1973-KE, it was agreed that the powerindustry would achieve the following financial targets:

(i) self-financing ratios of 25% in FY1988/89, 27% in FY1990/91 and 30% inFYI 993/94 and subsequent years;

(ii) debt/equity ratio of 75% in FYI1990/91 and 70% in FYI1991/92 andsubsequent years;

(iii) debt service coverage ratio of at least 1.5%; and(iv) a current ratio of at least 1. 1.

5.7 In practice, monitoring the performance of the sub-sector proved difficult becauseof the complex pricing arrangements, lack of clarity on such issues as asset ownershipand debt service obligations. However, the weakness in the sub-sector's performance areapparent from Table 5.1 which summarizes the principal financial ratios for the

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individual companies during FY1990/91 through FYl994/95. Actual financialstatements (FY1994/95) are shown in Annex 5.1 which also shows the projectedperformance during FY1995/96 through FY2000/01.

Table 5.1: Principal Financial Ratios for Power Sub-sector Companies2

1990/91 1991/92 1992/93 1993/94 1994/95 1995/96Capital Structure (D/E Ratio)(% ) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

KPLC 52 62 72 56 42 31KPC 79 81 109 92 60 41

TRDC 193 261 776 500 262 191Debt Service Coverage (times)KPLC 0.7 0.8 1.2 2.1 13 5.2KPC 1.4 2.2 4.2 1.6 4.1 4.2TRDC 1.2 1.1 1.0 1.0 0.7 0.8Self-Financing Ratio (%)KPLC -22 -125 -34 94 35 31KPC 9 81 103 54 0 75TRDC 100 100 175 900 0 (18)Liquidity (Current ratio)KPLC 0.9 1.0 1.0 1.0 1.0 1.0KPC 0.9 0.8 0.7 0.6 2.0 4.0TRDC 0.9 0.8 0.8 0.8 0.8 0.9

5.8 As the ratios above indicate, for the fiscal years up to FY1992/93, the financialperformance of the three power companies was characterized by weakening capitalstructures and significant liquidity constraints. In terms of profitability, KPLC'sperformance was fairly good compared to the performance of the other two powercompanies which experienced significant losses. For the power industry as an entity thepoor financial performance was attributable to low tariffs, high levels of debt service andthe depreciation of the Ksh. The average tariff was not regularly adjusted to fully coverincreased revenue requirements arising from higher operating costs and higher debtservice burden caused by exchange rate movements.

5.9 Chart 5.1 below shows the relative proportions of debt and equity in the capitalstructures of the three power companies during fiscal years FY1991/92 throughFY1994/95. The chart demonstrates the weakening financial position of the companiesand the modest recovery that started with the March 1994 tariff increase and theappreciation of the Ksh in 1995. Also noteworthy are the sharp increases in thedebt/equity ratios of both KPC and TRDC in FY1992/93 due to unrealized foreignexchange losses which are not considered a cost in the ascertained cost formula untilrealized and were therefore not compensated through the bulk tariff.

2 These ratios do not fully capture actual performance since they are based on accounting data which doesnot take account of all the operating costs and debt service.

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Chart 5.1: Capital Structures of KPLC, KPC AND TRDC (FY92-95)

KPL.C KPC

6 00010,000 A

6,000,

1,000 ^ _ EllDebt U -2 0 Debt

19921993 1 1995 _

TRDC

4000300020001000

UDebt0

-1000 U Equity I

-2000-3000 d

1992 1993 1994 1995

5.10 Chart 5.2 below compares the total internal funds that were available for debtservice' in each of the years FY1991/92 through FY1994/95 to the actual debt servicerequirements. While both KPC and TRDC were able to meet their debt service costsduring FY1991/92 and FY1992/93, KPLC was able to generate from internal operationsfunds to meet only 80% of its debt service costs in FY1991/92. KPC and TRDC wereable to meet their debt service costs during this period because the ascertained formulaguarantees them an adequate tariff to cover all their costs with the exception of unrealizedforeign exchange losses. Since FY1993/94, the debt service coverage ratios haveimproved significantly for KPC and KPLC.

3 Total internal funds available for debt service is calculated as the difference between total revenues andoperating costs (excluding depreciation) before adjusting for movements in working capital balances

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Chart 5.2: Debt Service Capacity of KPLC, KPC and TRDC(FY1991/92 - FY1995/96)

KPLC KPC

2,000 4.000

1,500 ------- E 3,000

C1,0 0 ---- -- ----- 2,000 ̂ 500 =- 1,0O0 0

1992 1993 1994 1995 1996 1992 1993 1994 1995 1996

4Avail. Funds Debt Servi i -4-Avail. Funds -Debt Servicei

TRDC

1,000800 .60006

400 0-n-I 4I1992 1993 1994 1995 1996

_Avail. Funds r Debt Service +--

5.11 All three companies consistently had low liquidity ratios in the period FY1991/92- FY1994/95. For KPLC this is because of delays in collecting receivables from finalconsumers. As of June 30, 1995 receivables represented about 88 days sales revenue.Some of the delays in revenue collection are due to problems in billing. A new billingsystem has been installed and a contract has been signed with a foreign utility to assistKPLC in strengthening its operational efficiency (institutional strengthening program)including improving the metering and billing system. For KPC and TRDC, the liquidityconstraints are caused primarily by slow payments from KPLC. The increasedcommercial orientation when the sub-sector is reorganized with separate management forgeneration and for transmission and distribution, and KPLC's institutional strengtheningprogram would help to improve working capital management, thus enabling arrears to bemaintained at levels not exceeding 60 days sales revenue..

5.12 Despite the structural issues noted in paras. 5.1-5.5 and the past poor financialperformance, KPLC, KPC and TRDC have sound accounting systems and procedures,and KPLC has competent financial management and accounting staff. Thus, financialstatements have been prepared broadly in conformity with generally accepted accountingprinciples. In spite of this there has been serious delays in submission of auditedfinancial statements to IDA. Significant improvements in financial management andauditing are expected to result from: (i) resolution of structural issues related to assetsownership, debt service responsibility and pricing in the context of the reorganization of

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the sub-sector; (ii) the recent exemption of both KPLC and KPC from the provisions ofthe State Corporations Act which has enabled KPLC to, amongst other things, appointprivate auditors for FYl996/97; and (iii) KPLC and KPC's commitment to endeavor toschedule AGMs promptly following the end of each fiscal year. KPLC and KPC auditedaccounts for FYI 995/96 were submitted to IDA about seven months and eight and onehalf months after the end of the fiscal year respectively. Taking into account pastperformance and the expected improvements during negotiations, agreement wasreached that both KPLC and KPC would submit auditedfinancial statements to IDAwithin six months of the end of each fiscal year (para. 8.1 (v)).

C. PROJECTED FINANCIAL PERFORMANCE

5.13 Taken as entity, the financial performance of the power industry started improvingin FYl993/94 when the first tariff increase under the Government's new policy ofeconomic pricing for electricity was implemented. Projections for the next six yearsindicate that the industry's performance would continue to improve due to the increases intariffs, assumed slower rate of depreciation of the shilling and improvement inoperational efficiency.

5.14 The key assumptions used in projecting the future financial performance for thethree companies are that: (i) the average tariff would remain 73 percent of LRMC; (ii)fuel prices would increase by about 7.5% per annum between FY1996/97 and FY1997/98and 5% per annum thereafter, and a fuel adjustment formula would be applied to recovereffects of fuel price increases through automatic tariff increases; and (iii) domesticinflation rates would be about 7.5% in FY1996/97 and FY1997/98 and 5% per annumthereafter. The financial projections assume further increases in the average revenue ofabout 12% in FY1997 and about 8% in each of FY1998 and FY1999. The financialprojections are also based on the current practice which requires KPLC to finance thelocal currency costs of KPC and TRDC investment programs. These contributions,called development surcharges are treated as part of the generation companies revenues(tariff) and are therefore reflected in the self-financing ratios. On the basis of theseassumptions:

(i) KPC, the main participant in the investment program would generatemodest levels of self-financing, averaging about 20% in the first threeyears and declining thereafter. KPC's financial performance wouldrequire an early review of its bulk tariff especially with the phasing out ofthe development surcharge system as part of the reorganization. Thiswould be upon completion of the tariff study in November 1997.(Similarly KPLC's tariffs to final consumers would require furtheradjustments to enable it to achieve the target self financing levels of 25%in FYl997/98 and FYl998/99 and 30% in each fiscal year thereafter).TRDC has been merged with KPC as part of the restructuring of the sub-sector. The process of merging operations is ongoing.

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(ii) The companies' debt service capacity would remain healthy: the result ofthe March 1994 tariff increase as well as the increase to about 73% whichis built in the projections.

(iii) The overall financial health of the companies would be greatly influencedby the automatic adjustment of tariffs to recover fuel price increases.

During negotiations, agreement was reached with the Government on the date forcompletion of the tariff study (November 30, 1997) andfor implementation of agreedtariff adjustments during FY1997/98. In addition, KPC would generate adequate fundsfrom internal operations to finance at least 20% of its individual investment program forFY1997/98 and 25% thereafter. KPLC would generate adequate funds from internaloperations to finance at least 25% of its individual investment program for FY1997/98and FY1998/1999 and 30% thereafter (paras.8.1 vii and viii). KPLC would also berequired to maintain their accounts receivable at levels not exceeding 60 days salesrevenue at all times (para. 8.1 (ix). During negotiations, it was agreed to revise the self-financing targets downwards for FY1997/98 and FY1998/99 to take into account theheavy investment requirements and the proportion offunding already indicated bydonors.

D. AN ACTION PLAN FOR FINANCIAL REFORM IN THE ELECTRICITY SUB-SECTOR

5.15 What emerges from the analysis of the historical financial results of the threepower companies is significantly weak performance both in terms of failure to meet theagreed financial covenants with lenders and in terms of failure to meet the sub-sectorsfinancing requirements. The financial performance of the power industry sufferedbecause tariffs were not adjusted to meet increasing operational costs and to meetincreases in debt service obligations arising from exchange rate changes.

5.16 The Action Plan for financial reform therefore includes: (i) establishment of aregulatory process to set bulk tariffs for the public sector generation company and retailtariffs to final consumers on the basis of LRMC and financial criteria; (ii) the recent GOKauthorization for KPC to adjust tariffs for changes in price of fuel and in the exchangerate without reference to ERB; (iii) determination of tariffs from IPPs on the basis ofcompetitive bidding; and (iv) implementation of efficiency improvements through lineloss reduction; staff reduction; contracting out ancillary services to the private sector andinstitution of performance contracts for parastatal companies. As a package of measures,this action plan should help the power sub-sector to improve its operational and financialperformance and achieve the targets proposed under the Credit. The status of the actionplan is summarized as follows:

(i) Reorganization of the Sub-sector. (para. 5.3).

(ii) Autonomy to Adjust Tariffs for Fuel and Exchange Rate Changes. In1994, the Electricity Bye-laws were amended to provide KPLC, with theautonomy to adjust electricity tariffs for changes-in-fuel prices. GoK has

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also allowed KPLC to adjust tariffs for changes in the cost of debt servicearising from fluctuations in the exchange rate of the Ksh with effect fromOctober 1, 1996.

(iii) Bulk Tariffs. A newly revised Electric Power Act providing forestablishment of an autonomous electricity regulatory board is expected tobe submitted to Parliament by Credit effectiveness (para. 8.2 (i)).

(iv) Efficiency Improvements. A line-loss reduction component to beimplemented under the project is expected to reduce T&D losses fromabout 16% to about 13.5% of net generation in the next five years, therebyreducing the amount and cost of generation needed to meet demand. Astaff reduction plan implemented by KPLC since 1994 had increased ofKPLC's customer/staff ratio from about 28:1 to 49:1 by the end of 1995.KPLC has contracted out some ancillary services such as line construction,cleaning, security and janitorial services. Further options for contractingvehicle maintenance works, etc., are being considered.

5.17 Implementation of the sub-sector reorganization plan and the financial action planwould be reviewed during IDA implementation support missions and a major reviewwould be carried out during project's mid-term review with cofinanciers by June 30,2000.

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6. IMPLEMENTATION ARRANGEMENTS

A. OVERALL

6.1 MOE has prepared a Project Implementation Plan (PIP) containing a descriptionof the main features of the project; implementation arrangements; implementation plan;and a monitoring and evaluation plan. The PIP would serve as a Handbook to assistproject implementation agencies in the execution of the project. Annex 6.1 shows thetable of contents for the PIP. During project implementation, the PIP would be updatedannually by MOE and reviewed by IDA's implementation support missions. Theimplementation arrangements, implementation plan and monitoring and evaluation planare summarized below.

B. IMPLEMENTATION ARRANGEMENTS

6.2 The Government of Kenya would have overall responsibility for implementationof the project through MOE, KPLC and KPC. KPC which would become the sole publicsector generation company would implement the generation projects and geothermalresource development components. KPLC would be responsible for implementation ofdistribution systems and some aspects of the efficiency component. A GoK task forceestablished in early 1997 is allocating staffing among the two companies. Thereorganization is not likely to disrupt implementation of the project. An ImplementationSupport Group (ISG) has been established within MOE to oversee the implementation ofthe project. The ISG would comprise experts with experience in procurement,contracting and construction of major projects, and financial management. Selection ofconsultants (engineer andfinancial management expert) to complement MOE's own staffwould be completedprior to credit effectiveness (para. 8.2 (iii)). KPC would also, priorto credit effectiveness, select consultants for its Project Management Teams which wouldbe responsible for management of the contracting process andfinancial management ofthe project (para. 8.2 (iii)).

6.3 The specific responsibilities for project implementation would be as follows:

(a) Sector Restructuring and Reform Component. MOE would have theoverall responsibility for implementation of the Sector RestructuringReform Component. The component would be implemented inaccordance with the timetable shown in Annex 2.1.

(b) Efficiency Improvements. The loss reduction and demand managementsubcomponents would be implemented by KPLC. MOE would implement

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the information programs studies and training. Action planningworkshops would be implemented by MOE in cooperation with KPLC.

(c) Power System Expansion and Rehabilitation. KPC would beresponsible for construction of the power stations to be financed fromtraditional public financing sources (Kipevu I Plant, Olkaria Power Plantand the third unit at Gitaru Hydropower Station). Kipevu II and OlkariaIII would be implemented by project companies to be set up by privatesector investors.

(i) Kipevu I would be constructed as a turnkey project. Thecontractor's responsibility would include construction of the power housebuilding and all civil works as well as the supply and installation ofengines, generators, substation equipment; etc. KPC has already selectedthe supervision consultants and received bids from construction firms.KPC would have overall responsibility for project management andcontrol, while providing the required facilities at the construction site.

(ii) Olkaria North-East Geothermal Power Station (Olkaria II).KPC would engage consultants to assist with the contract process and withproject management during the construction of this plant. Contractorswould be required for the following six contract packages: civil works;turbine-generator and auxiliaries; erection of substations; construction oftransmission; steam field development; and relocation of the existing X-2camp. KPC has prepared bidding documents for all the contract packages,however, the documents have to be updated.

(iii) Transmission and Distribution lines would be erected by KPLCexcept those required to link the above generation plants to the grid.Consultants services would be retained to assist with the contracting andsupervision of works.

(d) Geothermal Assessment and Resource Development. MOE wouldcarry out geothermal exploration and pre-feasibility studies as part of thegeothermal resource assessment and development program with theassistance of an Advisory Board of Experts. Consultant firms would becontracted to execute the geothermal feasibility studies included in theprogram. The Advisory Board of Experts would also assist in carrying outthe feasibility studies.

C. PROJECT IMPLEMENTATION PLAN

6.4 The project would be implemented in accordance with the implementation andprocurement schedules in the PIP. The PIP contains the following information:

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(i) detailed descriptions of the project components, budget andimplementation timetable;

(ii) schedule of procurement actions including target dates for each step,including standard procurement documents;

(iii) schedule of disbursements for each component, including financialreporting and audit requirements;

(iv) detailed description of the roles and responsibilities of the implementingagencies;

(v) key monitoring and performance indicators for each component; and(vi) schedule of progress reporting and format of quarterly reports.

D. PROCUREMENT

6.5 Table 6.1 summarizes the project elements, their estimated costs and the proposedprocurement methods. The total value of civil works to be financed under the project isestimated at US$135.6 million of which US$27.6 million would be financed by IDA.Annex 6.3 provides a list of goods, studies and consultants services to be financed by IDA.The goods would include the supply and installation of turbine generator equipment, underICB procedures, for Olkaria II Power Plant for which IDA would finance the foreignexchange costs of about US$41.6 million. Procurement of goods and works in packagesestimated to cost more than US$200,000 would be subject to ICB procedures. Goodsestimated to cost between US$50,000 and US$200,000 up to an aggregate of US$200,000would be subject to national competitive bidding procedures (NCB), while shoppingprocedures would apply to those estimated to cost less than US$50,000 up to an aggregateof US$200,000. Consultant services of US$25.6 million would be financed by the Creditout of total consultants services of US$73.1 million. IDA would also finance studies(US$8.5 million), training (US$1.2 million) and about US$200,000 of incrementalrecurrent expenditures. Of the US$27.6 million in civil works to be financed by IDA,about US$26.79 million would be subject to ICB procedures and the balance of aboutUS$807,000 would be procured through NCB procedures, such packages being less thanUS$200,000 each. For works contracts to be procured under NCB procedures, advertisingincluding explicit bid evaluation criteria and public bid opening would be followed.Interested foreign contractors would not be precluded from bidding for contracts let outunder NCB procedures.

6.6 Consulting Services, Training and Studies. Consulting Services, training andstudies to be financed by IDA are estimated to cost a total of US$35.3 million.Consultants would be recruited in accordance with the Bank's Guidelines for the Use ofConsultants by World Bank Borrowers and by the World Bank as Executing Agency,August 1981.

6.7 Review of Procurement Documentation. During project implementation, IDA-financed contracts for goods and works above a threshold of US$200,000 would besubject to IDA's prior review procedures. Contracts for goods and works subject to priorreview are estimated to account for more than 90% of the total value of the contracts. Allcontracts for consultants services estimated to cost more than US$100,000 for firms andUS$50,000 for individuals and all training proposals would be subject to prior review.

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However, all sole source contracts and extensions within these limits would be subject tomandatory review. The terms of reference would require IDA's clearance. The IDAsupervision missions would selectively review contracts not subject to prior review. Inall cases, the GoK would submit signed copies of the contracts to IDA before requestingdisbursement.

6.8 KPLC's procurement unit which is attached to the Office of the Chief ProjectDevelopment Manager (CPDM) would process contracts for the power generation andupgrading component and would be supported by consultants to be attached to theCPDM. Bidding documents have already been prepared by consultants for two of thefour power stations to be constructed and operated by KPC, but would need to be revisedon the basis of the Bank's new standard bidding documents. Pre-qualification would berequired for the civil works and the supply and erect contracts for the turbine-generatorpackages to be procured on the basis of ICB procedures and to be financed by IDA. TheISG would provide overall coordination support, ensuring that accurate progress reportsare prepared and forwarded to IDA and participating donors, updating the PIP andensuring the use of the Bank's standard procurement documents.

6.9 Standard procurement processing times have been discussed with the borrowerand the project implementation plan has been prepared on this basis. The borrowerwould update the procurement plan annually.

Table 6.1: Summary of Procurement Arrangements(US$ million equivalent)

Description ICB NCB Other Non-Bank TotalFinanced

Civil Works 50.6 0.9 84.1 135.6(26.8) (0.8) (27.6)

Supply & Erect 51.4 89.3 140.7(41.6) (41.6)

Goods 20.4 0.2 0.2 301.3 322.1(19.9) (0.2) (0.2) (20.3)

Consultant 24.5 47.5 72.0Services (24.5) (24.5)Training 1.2 1.2

_______________ ________ ______(1.2) (1.2)

Studies 7.6 18.5 26.1_________________ __________ (7.6) (7.6)

Household Survey 0.2 0.2________________ __________ (0.2) (0.2)

Refunding of PPF 2.0 2.0________________ __________ (2.0) (2.0)

TOTAL 122.4 1.1 35.7 540.7 699.91 (88.3) (1.0) (35.7) (125.0)

Note: Figures in parenthesis are the respective amounts financed by IDA

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E. DISBURSEMENTS

6.10 The IDA Credit would be disbursed against the following categories and on thebasis of the estimated disbursement schedule in Annex 6.4.

Table 6.2: Disbursement Categories(US$ million equivalent)

Category Amount of Credit % of ExpendituresAllocated to be financed

Civil Works 25.5 100% of foreign expendituresSupply & Erect 38.4 100% of foreign expendituresConsultant Services 23.5 100%

Goods 19.1 100% of foreign expenditures and 80% oflocal expenditures.

Training 1.1 100%

Studies 8.6 100%

Household Survey 0.2 100%

PPF Advance 2.0 Amount due

Unallocated 6.6

TOTAL 125.0

6.11 Disbursements for procurement of goods and works estimated to cost up toU$200,000 would be made against statement of expenditures (SOE). Otherdisbursements would be made against standard documentation. To facilitate paymentsfrom the Credit, the borrower would establish a Special Account and would operate andmaintain it on terms and conditions satisfactory to IDA. The account would have aninitial authorized allocation of US$5 million, approximately equal to three months ofexpenditures under the project. The Special Account would be replenished followingapplication for reimbursement by MOE, together with appropriate supportingdocumentation. The amount of IDA replenishment would not exceed the authorizedallocation. The Credit closing date would be June 30, 2004, with physical completion ofworks expected by December 31, 2003. Since MOE would process payments under thecredit it would engage a financial management expert (consultant) to work with ISG to,amongst other functions, facilitate the accounting and the payment process.

6.12 Statements of Expenditures (SOEs) - Disbursements for contracts of goods andworks estimated to cost up to US$200,000 and consulting contracts with firms costing upto US$100,000 equivalent and up to US$50,000 equivalent with individuals would bemade against statement of expenditures.

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F. ACCOUNTING AND AUDITING

6.13 During negotiations, it was agreed that MOE, KPC and KPLC would maintainappropriate records and accounts for expenditures under the project, including SOEs, aswell as the Special Account, in accordance with internationally acceptable accountingstandards, that such records and accounts would be audited by independent auditorsacceptable to IDA, and that the borrower would provide a certified copy of the auditor 'sreport, including a separate opinion on the SOEs, and the Special Account to IDA withinsix months of the end of each fiscal year (para. 5.12 and 8.1 (iv)).

G. MONITORING AND EVALUATION

6.14 MOE and IDA would carry out Project monitoring to ensure that the project isimplemented in accordance with the project implementation plan. It would be based onmonthly and quarterly progress reports to be produced by the implementing agencies andconsolidated and verified by the ISG. The contents and format of the reports werediscussed with the implementing agencies during negotiations, it would include: (i)updated project costs for individual contracts and the total project, including the estimatesof physical and price contingencies; (ii) revised timing of procurement actions includingadvertising, bidding, contract award and completion time for individual contracts; (iii)status of progress for physical works as well as for the institutional and policy reformcomponents; (iv) implementation of environment mitigation plans for the maincomponents; and (v) an implementation completion report within six months of theCredit's closing date.

6.15 IDA would monitor project implementation through field visits, implementationsupport missions, reviews of progress reports and consultations with the borrower,implementing agencies and participating donors. Principal performance indicators(Annex 7.6), were discussed and agreed with implementing agencies during negotiations,and will form the basis for performance evaluation. Estimates of the timing of IDAmissions, areas of focus, skills requirements and inputs are provided in Annex 6.5. ByJune 30, 2000, the Government would convene a mid-term review meeting to be attendedby cofinanciers and implementing agencies. The objectives of the meeting would be toreview the overall status of project implementation, adherence to the projectimplementation plan, and determine any required changes in design or implementationarrangements needed to ensure achievement of the project's developmental objectives.Specifically, the review meeting would focus on the status of progress in: (i) adjustmentof tariffs towards satisfying the power sub-sector's financial objectives and LRMC; (ii)attracting private sector participation in power generation and management of operations;and (iii) restructuring the organization of the power subsector to improve operatingefficiency and transparency in financial relations between operating entities.

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7. PROJECT JUSTIFICATION, ECONOMIC ANALYSISAND RISKS

A. OVERALL

7.1 This project is an integral part of the Kenya CAS, presented to the Board inJanuary 1996. The CAS focuses on reducing poverty through improved economicgrowth. It identified the proposed project as a priority in terms that it would contribute topoverty reduction by stimulating economic growth through: (i) the improvement andexpansion of basic infrastructure, which is critical to both improving the efficiency ofexisting private sector investment and attracting new private investment; (ii)improvement of public sector efficiency; and (iii) promotion of private participation inpower supply.

7.2 In line with the objectives of the CAS, the proposed project aims to: (i) eliminateelectricity shortages which are a key bottleneck to economic growth by assisting infinancing high priority least-cost investments in generation, transmission and distributionfacilities; (ii) support the implementation of parastatal reforms through the restructuringof the power sub-sector and commercialization of existing corporations; (iii) create anenabling policy and regulatory environment for private sector investment andmanagement; (iv) raise tariffs to cost recovery levels and restrict cross-subsidies to onlythe basic needs of the poor consumers; and (v) promote greater efficiency in energysupply and end-use.

7.3 The proposed project is part of Kenya's FY95 - FY2013 least-cost generationexpansion plan required to meet the demand up to FY2004 l. The project is technically,financially and economically sound and is thus justified for financing. Its technicaldesign has been carried out by experienced international consultants and reviewed by theBank. The discounted present value of the project's net economic benefits is US $344million, and the internal economic rate of return (ERR) is 17.3 percent, which is higherthat the opportunity cost of capital (12%). In addition, the project has a positive fiscalimpact (para 7.20). The salient features of the economic analysis for the power sub-sector investments are discussed below.

IThe least-cost generation plan was prepared by KPLC, confirmed by independent consultants, and

reviewed and found acceptable by the Bank (available in project files).

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B. NEED FOR THE PROJECT, ITS SIZE AND TIMING

7.4 Need. The forecasts of electricity demand indicate that there will be sufficientdemand to absorb the output from the project facilities. The reference forecast (Table7.1), which -- in line with the base case macro economic scenario in the CAS -- is basedon a 5.5 percent average annual economic growth, translates into an average increase inelectricity sales of about 5.6 percent per year, and an average annual growth in systempeak of about 6 percent. This is reasonable in light of the historical growth rates of thesame magnitude, and considering that there is currently significant suppressed consumerdemand waiting to be served. The forecast takes account of the growth moderatingimpact of energy efficiency and demand management measures to be implemented underthe project, and tariff increases. A detailed forecast is available in the Project Files.

Table 7. 1. Reference Electricity Demand Forecast (Interconnected System)

Avg. Annual Growth1995/96 1997/98 2000/01 2005/06 2011 1996-2011

Sales forecast with DSM GWh 3,391 3,722 4,346 5,785 7,753 5.6%Losses GWh (Transmission &Distribution Losses & StationUse) 709 730 769 987 1,313 n/aGeneration requirement GWh 4,100 4,452 5,115 6,772 9,066 5.4%System Peak MW 648 755 872 1,157 1,562 6.0%Load factor (%) 72.2% 67.3% 67% 66.8% 66.3% n/a

Source: KPLC

7.5 As Table 7.1 shows, the required generation is expected to rise slightly slowerthan sales, owing to a reduction in transmission and distribution losses from about 16percent of net generation in the interconnected system in FY96 to around 14 percent ofnet generation by FY2002. This would be the result of the installation of two diesel unitsat Kipevu, Mombasa -- to reduce longhaul transmission -, network reinforcement and lossreduction investments under the proposed project.

7.6 Size. The project facilities - five generating plants - will provide a total of 338MW of new capacity and upto 2,200 GWh of electric energy annually. In addition, the60 MW Sondu Miriu hydro plant, to be constructed in parallel with the project, willprovide, on average, some 310 GWh of annual energy. The new facilities will replaceabout 70 MW of old, inefficient thermal plant at Kipevu and Nairobi. With the netaddition of 328 MW, Kenya's power system will, under average hydrological conditions,be sufficient to meet consumer demand through the year 2004, whereafter new capacityhas to be installed (paras 3.10 & 3. 11).

7.7 Timing. The project is critically needed. All the investments are required assoon as possible to prevent continued load shedding (para 1.7 & 3.11).

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C. ECONOMIC RATE OF RETURN AND SENSITIVITY ANALYSIS

7.8 Project economic rate of return (ERR) is calculated at about 17.3 %. The ERRwas calculated for the incremental net benefits after identifying the project's economiccosts and benefits as the difference between inputs and outputs with and without theproject. In the "without the project" case, system demand is not met even at the currentlevel, whereas "with the project", the forecast system peak and energy demand are metthrough the year 2004 (Annex 7.2). In addition to new generation capacity, the energyavailable for sale under the proposed project is augmented by the investments in lossreduction measures. The distribution network rehabilitation and loss reductioncomponents of the project are justified also on a stand-alone basis. According to theESMAP report "Kenya Power Loss Reduction Study" (No. 186/96), the proposedinvestments in the Nairobi and the Coastal areas have benefit/cost ratios of 21 and 27respectively.

7.9 Economic Benefits. The measurable economic benefits of the proposed projectare two fold: (i) increased electricity sales made possible by the planned investments; and(ii) fuel cost savings resulting from the replacement of the old and inefficient steam plantsand gas turbines by modern diesel plants burning lower value fuel. The benefits fromincremental sales are calculated as the difference between the forecast sales with andwithout the project. The value of the benefits from incremental sales includes an estimateof consumer surplus, i.e the benefit of increased consumption because of the availabilityof lower cost electricity, indicated by consumers' willingness to pay for electricity serviceover and above what they actually pay to KPLC. The analysis uses an averagewillingness to pay for all consumer categories equivalent to about US cents 14 per kWhin mid-1995 prices. With KPLC's current average tariff of about US cents 9.1 per kWh,the consumer surplus is estimated at about 4.9 US cents/kWh (Annex 7.3 ). The fuel costsavings are similarly calculated as the difference in fuel costs with and without the projectand valued at border parity prices. These savings are the result of the greater efficiencyof the new plants, and the substitution of the presently used gas oil and jet fuel by lowervalue fuel oil, that will cut the average fuel cost per kWh.

7.10 Economic Costs. The economic costs of the proposed project comprise: (i)investment in generation plant, transmission, and distribution required to meetincremental demand and replace output from retired units. These costs include not onlythe investments under the proposed Project, but also the Sondu Miriu hydro power plantto be financed outside of the project as well as additional transmission and distributioninvestments required for which KPLC will seek financing outside of the project; (ii)incremental operation and maintenance costs; and (iii) incremental fuel costs. Economiccosts are expressed in mid 1995 prices net of taxes and duties (Annex 7.2).

7.11 Switching Values and Sensitivity Analysis. The switching values werecalculated for four critical parameters as noted in Table 7.2. The results indicate thatproject economics are robust with respect to increases in investment, operation and

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maintenance cost, and fuel costs, but that they show sensitivity to the demand forecastand the value of benefits. Given that currently the demand is suppressed because ofsupply constraints, the risk of overestimated sales is small. Regarding the value ofbenefits, the estimated value is between KPLC's current tariff and the cost of alternativesto grid electricity. It is, therefore, considered to reflect the consumer surplus adequately(Annex 7.3).

Table 7.2. Switching Values

Parameter Percent change required to turnNPV negative @12% discount

Electricity sales -18%Capital cost +50%O&M cost +290%Fuel cost +500%Willingness to pay -28% (US$0.10)

7.12 Graph 7.1 below, illustrates the sensitivity of the ERR to various percentage changes infour parameters: capital investment cost, O&M cost, electricity sales; and willingness to pay.

Graph 7.1. Sensitivity of ERR to Various Percentage Changes in Parameters

30.0%

27.0% ; ---- - -- ^0- ---- - - - -- ------ -- --.----

24.0% --a ---- ------ -- - ---- - - -0------ -La i-- 0- -v

21.0% . - - --------

1 8.0% I ---- --- -- ----------- +-Investrnent cost

15.0% -_I ------ &Mcost|z 15.0% :fr 0 X : z__ Sales

12.0% - -- - L-*(--WTP

9 .0 % --a -- - -- -- - - - - - - -- -- -- -- -- - - -- --

6.0% .- - . ..

0.0% I l I

-50% -30% -10% 1 +10% +30% +50%

Percentage change in parameter

7.13 With regard to the impact of possible delays in project implementation, thesensitivity analysis indicated that project economics are relatively insensitive to moderatedelays. Given, however, that the Kenyan economy is already suffering from power

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shortages, a delay in the commissioning of the generating plants would mean continuedelectricity rationing and subsequently lowered prospects for economic growth.Minimizing delays for the diesel and geothermal plants, especially Kipevu I and OlkariaII - planned to be commissioned in 1999 and 2000 respectively - is particularly importantbecause these plants are in the forefront of the investment program. In contrast, a oneyear delay in the commissioning of the hydro plants would have a less critical impact onthe economy, because part of the lost output could be compensated for by the diesels ifthey are installed according to plan, however, at a higher cost.

7.14 The likelihood for delays is largest for plants for which financing has not yet beenidentified, i.e., Kipevu II, and Olkaria III. Although negotiations with successful biddersare expected to start shortly, negotiations may be protracted or rebidding may be requiredin one case. To mitigate the risk of delays, the project preparation facility has financedconsultants to prepare the bidding documents and assist the Government in thenegotiations with the successful bidder (para. 7. 1 8).

7.15 Quantitative Risk Analysis. The quantitative risk analysis produces aprobability distribution for the ERR and the NPV based on the interaction among keyvariables and the shape of the probability distribution of the variables. The main risksaffecting the project's economic outcome include: (i) deterioration in Kenya's economicsituation which would reduce the demand for electricity making the investmentspremature; (ii) the value of benefits; (iii) delays in the commissioning of generationfacilities; and (iv) investment cost. The analysis used probabilistic risk analysis softwareusing Monte Carlo simulation to determine the probability distributions for the ERR andthe NPV. The results of the analysis implied an 80 percent probability of a positive NPV.The probability of a negative return for the project is thus an acceptable 20 percent.Lower than expected electricity sales growth rates, significant delays in thecommissioning of the facilities and lower than expected willingness to pay wouldcontribute to the negative NPV (Annex 7.4).

7.16 Other Benefits of the Project. In addition to the benefits discussed above, thepower restructuring and reform component will contribute to improving the efficiency ofthe sector so as to increase its contribution to the country's overall economicdevelopment. The project will help develop sound energy sector policies and regulatoryframeworks, which will create an enabling environment for private investment andmanagement. The project will assist Kenya to restructure the energy sector for increasedoperational efficiency and establish economic pricing of energy. It will also assist inestablishing two privately owned and operated power generating plants, and to buildinvestor confidence in Kenya's energy sector. Training and technical assistance providedunder the project will help improve the human capabilities in the energy sector.

D. RISK MITIGATION

7.17 Although the risk analysis indicated that the probability of a negative NPV is notsignificant, project design and implementation were formulated to mitigate the risks of

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unfavorable outcomes. With respect to the deteriorating economic performance whichcould result in lower than forecast demand for electricity - the Bank's continued broadpolicy dialogue on the macroeconomic reform program, will help focusing theGovernment's macroeconomic reforms on maintaining stability. Project design allows alimited possibility to delay construction of plants for which contracts have not beensigned, in case of drastically lower than expected demand growth - an unlikely scenario.

7.18 The risk associated with delays in the commissioning of facilities has beenreduced for the publicly financed projects by preparing the bidding documents beforeBoard presentation. In addition, KPC's track record in project implementation is fairlygood. Nevertheless, given the large size of the Project, it will provide consultant andadvisory services for project implementation, engineering and financial management. Forthe privately financed, IPP projects, the risk of delays has been partially reduced, throughfinancing under the Project Preparation Facility for consultant services for the preparationof bidding documents. They were issued in July 1996, and several bids were received atthe bid closing date in November 1996. In addition, the agreed changes in the legal andregulatory framework should contribute to increased investor confidence. Another risk isdelay in mobilizing the corresponding local financing requirements, that could lead toimplementation delays. The agreement on annual reviews of the investment program andrelated financing plans is designed to minimize this risk. The agreed power sectorrestructuring will also assist in improving the operational efficiency and financialsituation of the implementing agencies. Finally, IDA's continued macroeconomicdialogue will help in keeping retail and bulk tariff adjustments on track to insure adequatecounterpart funding. The agreement on an action plan for the implementation ofadequate adjustments based on a Tariff Study - to be completed by November 1997 - is acondition for the second tranche release of the SAC (para 3.21).

7.19 The capital equipment of the project comprise mainly of standard equipment andthe civil works are not significant, indicating a moderate risk for cost over-runs. Tomitigate these risks, the cost estimates include adequate contingencies

E. FISCAL IMPACT AND SUSTAINABILITY

7.20 The proposed project has a positive fiscal impact (Annex 7.5). The net presentvalue of the project's contribution to Government budget is estimated at about US$ 160million over a twenty year period. On average, the annual net revenue to the Governmentis about US $30 million (about 0.5% of GDP). The main source of the revenue to theGovernment from the proposed project is the margin between the interest rates KPLC andKPC pay the Government on the relend proceeds and the concessional interest rates theGovernment pays IDA, EIB and KfW. In addition, the Government would receiveincreased revenue from corporate taxes and VAT on the incremental electricity sales.The project will not crowd out public expenditures on other development programs, suchas health and education, because no counterpart funding is provided from theGovernment budget (it is provided by the implementing agencies from their internal cash

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generation). The proposed project would not affect domestic interest rates, neither wouldit crowd out domestic borrowing: It is roughly estimated that US $50 million of theabout US $260 million in private equity and commercial debt for the financing of theIPPs, would be raised within Kenya. This is a small share of the about US $3 billion inoutstanding credit to the private sector from the financial sector as a whole in mid-1996.Furthermore, on an annual basis, the project's domestic borrowing would be only about1/2 percent of the outstanding stock.

7.21 The structure of the proposed project is favorable for sustainability, because allkey stakeholders have an incentive to see that it succeeds. For instance: (i) the project'spositive fiscal impact should provide an incentive for the Government to solidly supportit; (ii) the project would provide both KPLC and KPC urgently needed financing forpriority investments, thus enabling them to reduce the cost of supply and sell moreelectricity; and (iii) the electricity end-users would gain because of increased and morereliable power supply. Finally, the project would create 3,000 - 4,000 temporaryconstruction jobs.

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8. AGREEMENTS REACHED ANDRECOMMENDATION

8.1 During negotiations agreement was reached on the following:

(i) the Government and IDA would review the power sub-sector's five-yearrolling investment plan by March 31 of each year (para. 3.27) and theGoK would not undertake any single capital investment in new facilities ofmore than US$10 million (including investments by independent powerproducers) outside the agreed plan without prior consultation with IDA;

(ii) adequate analysis of environmental impacts would be carried out for allfuture power subsector projects and appropriate mitigation plans would bedeveloped and carried out (para. 4.16);

(iii) KPC would establish and maintain Project Management Teamscomprising staff (including consultants) with experience in procurement,contract management and project finance, to assist with the managementof its components (para. 6.2);

(iv) KPC and KPLC would maintain adequate accounting records andsupporting documentation for expenditures related to the project (projectaccounts) and would have them audited, within six months of the end ofeach fiscal year, by independent auditors on the basis of terms of referencesatisfactory to the Association (para. 5.12 and 6.13);

(v) KPC and KPLC would submit to IDA, financial statements covering theirrespective total operations, audited on the basis of terms of referencesatisfactory to IDA, within six months of the end of each fiscal year (para.5.12);

(vi) KPC would employ consultants in accordance with the Bank's Guidelines,to assist with the design and supervision of its components (para. 6.2);

(vii) KPC would generate adequate funds from internal operations to finance atleast 20% of its investment program in FYI 997/98 and 25% in each fiscalyear thereafter (para 5.14);

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(viii) KPLC would generate adequate funds from internal operations to financeat least 25% of its individual investment program for FY1997/98 andFY1998/1999 and 30% thereafter (para 5.14);

(ix) KPC and KPLC would maintain their accounts receivable at levels notexceeding 60 days sales revenue at any time (para. 5.14);

(x) the Government shall complete an update of its 1993 Electricity TariffStudy no later than November 30, 1997 and shall implement the agreedrecommendations (para. 5.14); and

(xi) the Borrower shall take all steps necessary to ensure the movement ofwildlife within the Olkaria area and between Olkaria and Hells Gate andLongonot Park in accordance with the agreement between KPC and KWSdated September 20, 1994 (para. 4.13).

8.2 The following are the conditions for Credit Effectiveness:

(i) submission to the Borrower's Parliament of amendments to the ElectricPower Act providing for the establishment an autonomous ElectricityRegulatory Board (paras. 2.6, 3.26 and 5.16);

(ii) execution of subsidiary loan agreements between KPLC and KPC and theGovernment (para. 4.8); and

(iii) MOE and KPC have selected consultants for their PISG and ProjectManagement Teams (para. 6.2).

Recommendation

8.3 Subject to the above agreements and conditions, the project is suitable for a Creditto the Government of Kenya in the amount of SDR 86.6 million (US$125.0 million)equivalent, on standard IDA terms.

Annex 2.1Page 1 of 4

KENYA

Energy Sector Reform and Power Development Project

Action Plan for Restructuring of the Power Sub-Sector

ACTIVITY 1 SPECIFIC ACTION T TIMING

A. Merger of TRDC and KPC I . Obtaining consents from creditors TA. Merger of TRD and KPC I KPC and TRDC

All consents have been obtained. Started on 2/5/96 anid completedon 7/8/96.

2. Obtaining consent from the Minister for 15/7/96-29/11/96Finance in light of the likelyinfringement of the Restrictive TradePractices, Monopolies and PriceControl Act, Cap 504 of the Laws ofKenya by the proposed merger ofTRDC and KPC. This is a four stepprocess entailing:

(i) Leteers from KPC and TRl- toMinister for Finance through theMonopolies and PricesCommissioner requesting for theMinister's approval of theintended merger.

(ii) Consultations, if any betweenMinister for Finance,Monopolies and PricesCommissioner and KPC/TRDCon intended merger.

(iii) Grant of the approval by theMinister

(iv) Publication of approval byministerial order in the Gazette

A. Merger of TRDC and 3. Obtaining approvals of the Treasury 16/8/96-29/11/96KPC. and of the Minister for Energy for

transfer of assets and liabilities ofTRDC to KPC (Sections 11 and 13 ofState Corporation Act, Cap 446). Thisis a two step action entailing:

(i) Letter from KPC and TRDC to 16/8/96-19/8/96Minister for Energy and Minister Done.for Finance for requesting forapproval of intended transfer of

Annex 2.1Page 2 of 4

ACTIVITY SPECIFIC ACTION TIMING

assets and liabilities, inaccordance with the provisionsof Cap 446 (Section 11 and 13).

(ii) Consents of Minister for Finance 20/8/96-29/11/96and Minister for Energy to theintended transfer of assets andliabilities.

4. TRDC Board to pass a resolution for 2/9/96-13/9/96transfer of TRDC's assets and liabilitiesto KPC.

5. An Extra-ordinary General Meeting of 13/9/96-11/10/96TRDC to pass a special resolution for Done.transfer of its assets and liabilities toKPC.

6. KPC Board to pass a resolution of 2/9/96-13/9/96accepting the transfer of TRDC's assets Done.and liabilities to KPC.

7. Joint agreement between KPC and 12/10/96-15/12/96TRDC for the transfer of assets andliabilities to KPC.

8. Joint notice by KPC and TRDC of the 31/12/96transfer of assets liabilities and businessunder the Transfer of Business ACT,Cap 500.

9. An Extra-ordinary General Meeting of By 31/1/97TRDC to pass a special resolution towind the company up and appoint aliquidator.

10 Issuance of Gazette Notice and By 15/2/97Advertisement in the local dailies of thespecial resolution to wind up TRDC.

11 TRDC to voluntarily wind up. 31/3/97

Appointment of new KPC 1. Appointment of a Managing Director Done - January 1997Board. for the new KPC.

2. Appointment of Chairman and other Done - January 1997_ _ _ _ Board members. _ _ _

Appointment of personnel 1. Appointment of a Task Force Done - January 1997for KPC (comprising the Mds of KPLC and KPC

and representatives of MOE, MOF andl ___________________________ l DPM)_to identify appropriate personnel |_l

Annex 2.1Page 3 of 4

ACTIVITY SPECIFIC ACTION TIMING

from existing KPLC staff establishmentfor transfer to KPC.

2. Identify and transfer of identified 1/3/97-31/5/97personnel to KPC from KPLC.

3. Recruitment of staff shortfalls by KPC From 1/6/97 onwardsBoard.

Location of offices for MD for KPC and his key staff to look 1/3/97-30/6/97KPC. for appropriate accommodation for the

company and move in.

Recruitment of Specialists Appointnent of Specialists to assist in 1/3/97-31/5/97the transfer of assets and liabilities andin the preparation of Power PurchaseAgreements (PPAs).

Transfer of TARDA's I . Generating assets belonging to TARDA 1/3/97-31/10/97generating assets and to be transferred to KPC on historicalliabilities to KPC and cost basis as per EDF'sassets transfer pricing recommendations.principle.

2. All existing liabilities associated withTARDA's generating assets to betransferred to KPC at their currentvalues.

3. KPLC will cease to service the debtobligations for Kiambereliabilities to KPC.

Transfer of Turkwell's 1. The Turkwell Gorge multipurpose 1/3/97-31/10/97generating assets and project generating assets to beliabilities to KPC and transferred to KPC on historical costassets transfer pricing basis as per EDF's recommendations.principle.

2. Transfer value of liabilities associatedwith the generating facilities of theTurkwell Gorge project to be based onthe replacement cost of the assets. Thisapproach is being used becauseTurkwell loans are being serviced bythe Treasury and limiting the level ofliabilities to historical costs of the assetswould impact negatively on the fiscal

|__ _ __ budget. l_l

3. Treasury and KPC to work outmodalities for servicing of suchliabilities over a twenty year periodfrom the date of commercial operation |_l

Annex 2.1Page 4 of 4

ACTIVITY 1 SPECIFIC ACTION TIMING

I of the Turkwell Gorge project.

Transfer of assets and I . Transfer of assets between KPLC andliabilities between KPLC KPC to be effected on the basis ofand the new KPC and replacement costs, taking into accountassets transfer pricing useful lifespans of the assets involved.principle. This approach is being used as opposed

to effecting transfer on historical costsbasis because KPLC is not whollyGovcrnment owned.

2. Transfer of liabilities belween the twocompanies to be effected on the basis oftheir current values.

Termination of I1. All management agreements between 1/3/97-31/10/97management agreements. KPLC on one hand and KPC and

TRDC on the other, to be terminatedupon full operation of the new KPC.

2. Agreements between KPLC andTARDA for mianagement of thegene,atitig I sets to he terron?,te(I oplntransfer of assets te and ful' operationot, new KrC.

3. Management of Turkwell generatingassets by KPLC will cease upon transferof the generating assets to and fulloperation of, new KPC.

Rural Electrification KPLC to be fully reimbursed for all capital ContinuousProgramme expenditures and recurrent costs for rural

electrification programme. Thisunderstanding to be reflected in aperformance contract to be signed betweenKPLC and GOK.

Dam monitoring, Both KVDA and TARDA will be fully Already being done on acatchment presentation and compensated on an annual basis for continuous basis.security expenditures on dam monitoring and

maintenance, catchment preservation andsecurity.

Power Purchase PPAs to be prepared by KPLC, negotiated 113/97-30/6/97Agreements (PPAs) with KPC and signed by the two companies.

KENYA Annex 3.1ENERGY SECTOR INVESTMENT PROJECT Page 1 of 1ENERGY BALANCE 1994000 Tonnes of ON EqitAvlent (tool

; , 4'.'$;"', ~ ~ ootilwa cog a !o #.Wy¢o cm odS Cn*O w cm> 0tt, one" Iktewss' ok 1 , . et , y t 'udWr Reskk Co to Traditionalt Commenrcrial oS

SUPPLIES

Indigenous Production 73 0 776 0 0 0 0 0 n 0 0 10,793 0 0 10,793 848 11.642knport 87 2.090 0 132 142 291 (r 2,655 16 0 0 0 0 2.756 2758Export 0 1421 1491 (54) 1231 It) (1to1 0 0 0 0 0 1168) t16SIBunkers 0

IG oss Suppl 73 87 778 2,090 t421 54 Be 268 tl) 2,487 Iff 10,793 n/a ° 10.793 3,439 1-4,232

CONVURSION

P.tro)um Refinkin 0 2.0901 005 533 339 425 31 1S56) 0 0 0 0 0 11561 (1561ChwcodProduction 0 0 0 0 0 0 0 0 0 11,1781 0 252 (9261 0 19261Power Georton Hydro 0 t7761 0 267 0 0 0 0 (5091 (5091Power GwnwOaton 0 ltvnmd 0 0 1631 (01 (201 0 0 (631 24 0 0 0 0 (S8R (581Power genaration Goo tthrm 1731 0 0 25 (48)

Losses 0 0 0 0 0 0 0 0 1431 0 0 0 0 (431 143)ErrorS 0 0 0 0 '0 0 0

CONSU11117"

industry 67 356 47 a 6 5 420 122 481 0 481 629 1.109Transport 0 4 426 372 450 0 1.252 nfl 0 0 0 1.252 1.252Agacutture 0 39 32 4 2 0 78 nl/ 317 0 117 78 395Houselvold 0 0 0 0 223 20 243 90 .8817 199 9.316 333 9,349Connwerc. , Othwr 0 102 II1 25 13 6 256 78 0 52 52 334 386

Total Corsuption 0 67 0 0 501 616 407 693 31 2.249 289 9,615 nts 252 9,867 2.625 12,492

%of TotalEnergy 0% 1% 0% 0% 4% 5% 3% 6% 0% 16% 2% "7% 0% 2% 79% 21% 100%%ofComnwerdaEnerry 0% 3% 0% 0% 19% 23% 16% 26% 1% 86% 11% 100%

Soumces. Mitthbrv of Enrrgy end mission osth,ats

ENERGY COUsJMPYTI DV CONSUMER CATEGORY

% of % ofCategory Total Commercia

Industry 9% 24%Transport 10% 46%Household 75% 13%Commerc & Others 6% 16%

Sum 100% 100% 0W

Per coplt Commercial Energy Consumption: 0.10 toe/capitaPer capit Total tneegy Consumption: 0 48 too/capitaPeo capita Electricity Consumption: 129 kWh/capitaPei capits Patrotoum Products Consumption: 87 kg/capti

Annex 3.2Page 1 of 1

KENYAENERGY SECTOR REFORM AND POWER DEVELOPUAENT PROJECT

1. ELECTRICrTY COMSUMPTION GWh

86/87 87188 88189 89'90 90/91 91t92 92!93 93/94 94/95 9596

Domest c *,aI. conmmocla' and Mdusl'41 633 678 729 780 823 877 928 977 1.026 993Chsnne rfro c*'ous Year % 7% 8% 7% 6% 7% 6% S% 1% 3%Sna'ec lots % 287% 290% 301% 301% 304% 31 8% 320% 326% 332% 3055%

Med,ou, co-rtmca 8r1 -dus¶r,a 536 555 516 554 585 567 564 559 569 660Cnange fron Dov,dous "a' % 4% 7% 7% 6% 3% 11% -1% 2% 16%

Share o! iota % 24.3% 23 7% 21 3% 21 3% 21 6% 20 5% 19 4% 18 7% 184% 20 3%Large co-vmrrcwa and -cuSt'ia 919 985 1046 1130 1178 1198 '281 1326 1 356 1492

Change fro, osraouos weaa % 7% 6% 8% 4% 2% 7% 4% 2% S0%SnhrO ol Iota % 41 6% 42 1% 43.3% 43.5% 43 5% 43 4% 44 2% 44 2% 43 9% 45 9%

OfftDesk III 110 113 117 109 104 115 125 119 92Change from oer",ous Year % .1% 3% 4% -7% -5% 11% 9% *5% .23%Share of tota5 S S 0% 4 7% 47% 45% 4 0% 3 8% 4 0% 42% 3 9% 2 8%

Strea L,ghtrng 9 12 14 14 14 14 13 10 18 15Change from r,av.ous Year % 33% 17% 0% 0% 0% -7% -23% 85% 19%Share of tolai % 0 4% 0.5% 0 6% 0.5% 0 5% 0.5% 0 4% 0 3% 0 6% 0 5%

TOTAL SALES OWh tKPLC) 2.208 2.340 2.418 2.59S 2.709 2.760 2.901 2.997 3.089 3.252Change trom pravous Year % 6% 3% 7% 4% 2% 5% 3% 3% 5%

Rural Electrof.caton aers (REF) GWh 25 36 49 66 76 85 104 138 134 150

GDP growth rate in -FY trmsa 5.2% 1.0% 6.1% 4.7% 2.8% 0.3% -0.2% 2.2% 4.5% 5.0%GOP aluticrny 1.2 0 7 1.6 1.6 6.3 -25.5 1.5 0.7 1 1

2. NtJMEW OF CONSUMERS

Number of Coumr4 (KPLCI 213.600 223.718 234.674 246,348 262.521 277.622 294.520 310.916 321.738 316.024Nua of Consumws (REF) 8.706 11,494 15,132 19.067 24.491 29.513 34.561 40.731 43.718 50.306Ntumberof R AldntsslCoa4umne 177J171 187,159 197,612 206,023 224.611 239.816 256.128 272.217 2UH.116 307,518

Total Popustaon mllional, 21.7 22.4 23.2 23.7 24.5 25.2 26.0 26.B 27.5 28.3t4efcataon rate % of poulation 51.7% 5.8% 6.0% 6.2% 6.4% 6.7% 6.3% 7.1% 7.3% 7.8%

Conwtmt. on perC.pirtsf1Wheai*ts) 102.9 10.1 106.3 112.3 113.7 112.9 115.6 117.0 117.2 120.2

2. GENEATON OWihSS/37 6711111 683 38/30 60K131 31132 32133 3/94 34/1 3195/"6

Hydro 1.793 2.036 2.449 2,517 2.760 2.776 2.972 3.04t 3,103 3.163Imports 211 154 112 174 134 240 273 264 187 149

Od Tharmal (Kiru) I" 206 25 37 74 75 59 140 218 224G.otiaermal lOlkaitl 374 34 322 336 236 272 272 261 291 330Gs TurelNba-cou.h Kpowvl 44 85 21 10 21 3 2 2 47 171otass 5 3 2 2 0.3 3 0.2 0 2 2Wand Tuwb4. I 1 1Total hlntrconr. ctd 2.516 2,lO 2.331 3.136 3.2t7 3.36t 3.578 3,716 3,348 4,100

leotd dysxtm 3 10 11 12 14 1 20 17 17 19

GROU GENERATION 2.604 2.JJ6 2.942 3.118 3.301 3.316 3,St 3.732 3.966 4.113

Auxeryc oaumaaton 23 43 27 3 383 30 2S 3t 45 52

NEtT GENEATIOTM 2.86 2.7 LO .S 3,116 3.6 3261 3.536 3.3 31t21 4.067

System Lte 347 407 448 48 484 51D0 6114 5o 53" 66la as % of nt gan 13.5% 14.E% 15.4% 14.6% 14.8% 16.2% 1$.8% 11.2% 15.7% 16.4%

Sala KPIC 2.206 2.340 2.418 2.5111t 2.708 2.780 2.901 2.937 3.069 3.252Sala REF 21 26 48 67 7 tl 104 13i 134 1S0

3 GENERATION 60tJUl

lvdro 63.1% 72.4% t3.6% 30.3% U4.0% 82.4% t3.1% S 2.0% 60.6% 77.1%hwpu 6.1% 5.5% 3.8% 1.1% 4.1% 7.1% 7.6% 7.1% 4.93 3.6%

04 Th_mal Wapul .5% 7.4% 0.% 3.1% 2.3% 2.2% 1t.% 3.S% B.7% 5.6%G.otheta tOtisrs) 14.4% 12.4% 11.0% 10.7% 9.1% E.1% 7.6% 7.0% 7.5% 9.5%Ga TurIa Itib-south. )Kiparval 1.7% 2.3% 0.7% 0.3% 0.6% 0.1% 0.1% 0.0% 1.2% 4.2%tea 0.2% 0.1% 0.1% 0.1% 0.0% 0.1% 0.0% 0.0% 0.0% 0.0%

Wind Tia 0.0% 0.0%

antacoawactad of total gora gan 3.7% n.6% 33.6% n3.6% 8.6% 33.1% 39.4% 3.5% 911.6% 3.6%solated *natae of total ora at 0.3% 0.4% 0.4% 0.4% 0.4% 0.5% 0.6% 0.5% 0.4% 0.5%

4. SYSTEM MEAt 8W 430 481 480 320 IgO 646 5Uh O12 Ot6 64tChangeft=mpraoeuY.r"% 7% 4% 8% 6% 3% 5% 3% .1% 7%

S. LOAD FACTORt 64.4% 4.3% 6311.3% 64.4% 67.5% 67.7% 63.4% 64.3% 72.1% 71.6%

1/ 113136gm,. p enaSsures: KPLC

Annex 3.3Page lof 1

KENYA

Available Generating Capacity and Generation in 1994/95

Station Owner Installed Capacity Effective Capacity Energy Producedin MW Capacity in MW 1994/1995 in GWh

HydroTana KPC 14.4 12.4 78Wanjii KPC 7.4 7.4 27Kamburu TRDC 91.5 84.0 485Gitaru TRDC 145.0 120.0 704Kindaruma TRDC 44.0 44.0 213Various KPLC 6.2 5.7 22Masinga TARDA 40.0 40.0 200Kiambere TARDA 144.0 144.0 996Turkwel 106.0 106.0 379ThermalKipevu KPLC 93.0 86.0 218GeothermalOlkaria KPC 45.0 45.0 291Gas TurbineNairobi South KPLC 13.5 10.0 16Kipevu KPLC 30.0 30.0 31DieselVarious KPLC 4.0 2.0 2Wind TurbineNgong KPLC 0.35 0.35 1Isolated Stations KPLC 7.3 6.7 17Imports from UEB 30.0 off peak only 187

Total 821.7 743.4 3,866

Source: KPLC

21-NOV.' 96(THU) 17 07 (WB) KENYA DIRECTOR: FAX:254 2 26038? P.002

Annex 3.4Page, 1 of 6

RIEP3BLIC OF KEENYA

NLISTRY OF FINANCE

Tclegraphic Address: ''921 Orrice of the ?MinisterFINANCE - NAMOST P.O. Box 3a007Telephone: 338171 NAG LOBIWben replying please quote XXY A

Ret. Yo. EA/rA 621323/01 15th November, 1996and dae

MvIr. James D. WolfensohnPresidentWorld Bank1818 H Street N.WWashington, D.C.U.S .A

Dear Mr. Wolfensohn,

Kenya: Energy Sector Reform and Power Development ProjectLetter of Power Sub-Sector Policy

Introduction

The energy sector plays an important role in the country's economy, in cerms of itsimpact on the balance of payments, concribution to the govermnent's revenues, and share ofinvestment and employment. The Goverrnent. therefore, accords a high priority to thedevelopment of the sector in a cost-efficient and environmentally sustainable manncr. Thepurpose of this lerter is to highlight the Government's sector development objectives, and thepolicy and institutional reforms being pursued to achieve the objectives. These reforms are anintegral part of the design of the Energy Sector Reform and Power Development Project andunderpin che invesanenrs proposed under the Project.

The Government has undertaken several studies to provide a basis for formulation ofsector policies and strategies. A broad sector stracegy was developed and agreed with the WorldBank and che IMF and this is reflected in the Policy Framework Pacers (PFP) covering theperiods 1993-95 and 1996-98. In the PFP for the period 1996-98, energy seccor reform policieshave been articulated in paragraphs 35, :52, 53 and 54.

Policy Objectives

The sector's stracegic objectives are to improve investment and operational efficiency by:- (i) separating commercial funccions from policy setting, regulatory and coordinaEing functions:- (ii) implementation of power projects on the basis of improved leasc cost-investment planning;

(iii) creating more competitive market conditions in electricity generation and in rhe petroleumsub-secror; (iv) restructuring power companies and requiring them to operate on a commercialbasis supoorted by a system of perfornance contracts and wich transparent financialrelationships; (v) adjusting the struccure of electricity prices to ultimarely reflect long run

21-NOV.' 96(THU) 17:08 (WB) KENYA DIRECTOR: FAX:254 2 260382 P. 003

Annex 3.4Page 2 of 6

t*arrer of Power Sub-Secro' Policl 2

marginal cost of supply and ensuring that petroleum product prices are set by Ehe market whilediscouraging cartetizaLion; and (vi) carrytng outdcmand and supply-side efficiency improvementsin the power sub-sector and in industry.

Role of Government - Sector Restrucruring

The Government's principal role in a restructured energy sector will be t-hat of afacilitator of development by providing a stimulus to invescment and growth through provisionof an enabling environment, policy formulation, regulation, monitoring and coordination. In thisrespect, the Government will strengthen its capaciEy for regulating any market segmentscharacterized by limited competition and will improve the legal framework for che sector so as.co effectively protect the interests of consumers, facilitatc private sector participation andenhance the efficiency of operating companies.

In the power sub-sector, the Government's role will focus on;

i) reviewing bulk and the end-user tariffs and approving adjustments in order tomeet thc financial requirements of thc power-sub-sector;

ii) reviewing power purchasing arrangements to ensure that they meec therequircments of the relevant laws of Kenya;

iii) ensuring system reliabiliry and security;

iv) licensing of power operacions on conditions intended to promote efficiency of theindustry and institution of concrols against non-competitive behaviour,

v) protecting the interest of electricity consumers by ensuring that appropriatestandards for supply are adhered to;

vi) setting up and enforcing standards in respect of safetcy;

vii) setting uo and enforcing scandards in respect of environmental protection;

viii) promoting the developmnen of viable and healthy competition and technologyadvancement of the sector; and,

ix) establishment of an autonomous Electricity Regulacory Board, under the ElectricPower Act, CAP 31.4, to carry out activities (i), (ii) and (v) listed above, amongothcr things, under the general policy advice of the Ministry of Energy.-

nergy Secwor Reform and Power DeOelopmenr Projecr

21-NOV.' 96(THU) 17: 08 (WB) KENYA DIRECTOR FAX:254 2 260582 P. 004

Annex 3.4Page 3 of 6

LcrTCr of PRwe:r SUb-Secror PoUer . 3

Restructuring and Commercializing Power Companies

Thc existing limiced liability companies (KPLC, KPC and TRDC) will be reorganizedby end of October. 1997, to place all the generation assets under one company and all thetransmission and distribution assets in another. The generation assets owned by che multi-purpose authorities will be transferred to the new electric powcr generation company onhistorical cost basis. by end October, 1997. Assers rransfer between the new generationcompany and the transmission. and distribution company will be Rffected on the basis ofreplacement costs, taking inco account the residual life spans of the assets involved.

Liabilities relating to the generation and transmission assets will be transferred betwecnand among the oarganizations on the basis of the current outstanding debts, save for the Turkwelproject. The liabilities for the Turkwel project will be transferred on the basis of thereplacement cosr of the electro-mechanLical components. However, the new generation companyand the Treasury will work out the project's debt service arrangemenc over a period of twentyyears. Debt service for Kiarnbere will be transferred to the new generation company when irbecomes fully operational.

The power comoanies will be required to operate on sound commercial principles. Toimprove the companies' operating and financial performance, a system of performanc_ contractswill be institured by June 30, 1997 for the two new electric powcr companies. Strcamlining ofsraffing levels in KPLC (the only company with staff) has been initiated and the customcr/staffracio improved from about 36: t ac the end of 1994 to 49:1 by the end of 1995. KPLC has alsomade subscancial progress in contracting our non-core services: both the security and janitorialservices are now 100% contracted out; and construction of Kilifi-Malindi 33kV line which wascontracted out in August 1995 was completed in January 1996. KPLC plans to contract outmore line construction work including 66kV lines in Nairobi area. Contracting out of transportworkshops and repair workshops is also planned.

Private Sector Participation

The Government Ehas decided to intoduce competition in the generation segment of theelectricity supply markec, so as to improve efficiency and expand che scope of resourc-smobilization by encouraging private sector participation. In this regard, invitations for privatesector bids for developmenc and operation of two power plants (Kipevu 11 Diesel and OlkariaIIL Geothermal) were issued in July 1996. with November 29, 1996 being the closing date forreceipt of duly completed-bids. In addition co chese two power plants, all future power projects.except multipurpose hydro schemes, will be offered for development, on a competitive biddingbasis, by both che privare and publiv sector companies Private companies, together with theproposed generation parastacal will supply electricity to che proposed cransmissicn anddistribucion company under long-term power purchase agreements (PPAs).

As an interinm measure to redress the current power supply shortfalls, while projectsprogrammed for devclopmcen under the rolling five year least cost development plan are beingconstructed, the Government has decided to have in place a 44-.5 MW oil fired plant developedby an IPP, on a fast track basis. An IPP has already been selected through a competicive

Ener_V Sec:or Refomiw and Power Deve!opmenrt Projecr

21-NOV. '96(THU) 17:09 (WB) KENYA DIRECTOR: FAX:254 2 260382 P. 005

Annex 3.4Page 4 of 6

Le,rer of Po%wr Sub-S cror Po.licy 4

bidding process to develop che plant, on the basis of build-own-operatm (BOO) arrangement.The IPP will scll power to KPLC under a PPA. On its part, KPLC has finalized similararrangemenns for an IPP to develop a 43 MW oil fired plant to replace generation by retireduneconomic thermal capacity at Kipevu.

In the petroleum sub-sector, the procurcmenc, marketing and distribution and pricing ofcrude oil and petroleum products is already being carried our by the private sector. On Ocxober27. 1994 the Government deregulated the petroleum markets and removed the National OilCorporation of Kenya's monopoly rights to procure 30% of the country's crude oilrequirements, and allowed consumer prices to be market-deternined.

Least Cost Investment Planning

The Government will ensure that a rolling five-year energy sector inves;ment program,including a least-cost power system expansion plan is updated annually and rolled over by oncyear. These documents will be submitted to IDA for comments prior to finalization andsubsequent implementation. All investments will bc ranked in tcerms of their imoact on theenvironment and cnvironmental assessments will be carried out in line with the WorldBanJk's/any other donor's guidelines for all planned projects. Mitigation plans will be preparedanrd implemented for all projects with adverse environmental impacts.

Capacity Building

The Gcvernmenc will continue to build its personnel capacicy through training ininstitutions of higher learning, middle level colleges and polyrechnics. and through participationin seminars and workshops including overseas attachments in appropriate institutions to ensureeffective management and development of the energy secror.

Ener,y Pr:icing

The Government's energy pricing policies are aimed at encouraging efficient utilizationof electricity and other commercial fuels, prudent management of resourc:s dedicated to supplyand delivery of energy to consumers, ensuring the financial viability of energy enterprises andgeneration of fiscal revenue.

In the power sub-sector, the government is commitred co adjusting generation tariff andend-user cariff structure so as to ultimately reflecr long run marginal cost (LRMC) of electricitysupply to enable the sub-sector co achieve an operational profit and thus raise adequate capitalto sustain its investment programs and attract IPP invescmcnts in the gcncration segment.

As part of thc tariff adjustments process, in March, 1994 the Government increased theaverage tariff level by 60%, which together with subsequent appreciation d2 the Kenya shillingagainst the US dollar had raised che tariff level from about 54.5% to 67.5% of LRMC.currently. 71 4

Tariffs were raised to 75% of LRIMC wich effecc from October 1, 1996. An update ot 7the November, 1993 tariff study, envisaged to be completed by April 30, 1997, will provide the

Energy Secror Reform nsd Power Development Project

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Annex 3.4Page 5 of 6

Lart'r of Por)w Sub-recror PoIicy 5

basis for che Government to determine the magnitude and phasing of Further adjustmentsrequired to achieve LRMC, after t'aking due consideration of the cost of power from independentpower producers and the sector's overall financing requirements. Scarting in 1994, theGovernment has authorized KPLC to automatically adjust the level of ics tariffs so as co reflectchanges in the cost of petroleum fuels used in thermal generation of electricity. EFfective IstOctober, 1996, KPLC has been authorized to automatically adjust its tariffs to reflect changesin the cost of external debts service arising from fluctuations in the exchange rates of the KenyaShilling.

The bulk tariff for sales of electricity by the public sector generation company will bebased on tie tariffs established through the LRMC pricing principle, as determined through theregulatory proc-ss. In addition, the bulk tariff for sales of electricity by independent powerproducers will be based on prices escablished through international tendering proc-ss.

Eaergy EtTciency

It is the Governmenc's policy to promote che efficient supply and use of energy. On thesupplv side, the policies and institutional reforrns to improve efficient provision of energyinclude the reorganization of the power sub-sector, the planned introduction of private sectorparticipation in power generation, the contracting out of services to the private scctor, theinrroduction of performance contracts for energy enterprises and screamlining of smTffing levels.More specific measures to improve the efficiency of power supply include reduction of losses,particularly in the discribution systems and installation of efficient generation facilities.

On che demand side manacement. the Government will encourage large consumers ofelectricicy to even out demand, time of use and inrerruptible electricity tariffs will soon beintroduced. The Government will also promote energy audirs for commercial and industrialconsumers, develop a demand side management programme, make available information to thepublic on efficient usC of energy and cost-effective technologies and encourage private sectorparticipacion in the delivery of energy efficiency improvemenc measures. Efficiency standardsfor electric equipment will also be developed.

Renewable Energy

On new, renewable and rural energy, the Government will together with the privatesecror promote the economic developmenr of new and renewable energy sources such as wind,solar and biomass, particularly to complement energy supplies in areas not served by the grid.The Government will regularly review its policy on import duties and taxes levied on solar andwind- power equipment in order to ensure that these arc not higher chan those levied onconvencional electrical equipment and will also establish quality standards for phocovoltaic (PV)and wind power equipment.

The Government attaches great importance to rural electrification and in chis respect arural clectrification master-plan is currently under preparation with technical assistance from cheAfrican IDevelopment Bank (ADB) to among other things examine alternative options for theprovision of energy in che rural areas in a cost-effective manner, taking account of GoK's

Energy Scc:or Reforr antd Pov.r Develtoarnenz Projrct

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Annex 3.4Page 6 of 6

Lezlar of Power Sub.Sector PeUicy 6

policies on industrial dispersion. The GoverTnmnen will also review its policies on new andrenewabie cnergy, from Lime to time with a view to promocing widespread use of new andrenewable sources of energy including wood-fuel.

Conclusion

The Government believes that the implementation of the above measures, togecher witilthe other policies spelt out in the current Policy Framework Paper, will bring abouc acceleratedeconomic development and promote the reduction of poverty.

Yours sincerely

MUSALL.A

Copy to:-

Hon. Noah Kataua Ngala, E.G.H., M.P.Minister for Energy.Ministry of EnergyNairobi

Mr. Fares Kuindwa, E.B.S.P.ermanent Secretary, Secretary to the Cabinetand Head of Public ServiceOffice of the PresidentNairobi

Energy Seclor Reform and Power Developmcntr Project

Annex 4.1Page I of 1

KENYA

Energy Sector Reform and Power Development Project

Documents Available in the Project File

Kenya: Electric Power Sector Organization Study Phase I Report ( three Volumes); July 1993, Prepared byLondon Economics in association with Kaplan & Stratton Advocates

Electric Power Sub-Sector Organization Study in Kenya; Final Draft Report ( two volumes), May 1996,Prepared by EDF of France

Kipevu Diesel Power Plant (Phase 2) Feasibility Study, Final Report; August 1994, Prepared by EwbankPreece ( UK)

Electricity Tariff Study, Final Report (three Volumes), Prepared By London Economics Limited (UK),April 1993

Legal Consulting services to review and develop an Appropriate Legal and Institutional Framework for theEnergy Sector in the Republic of Kenya, Prepared bt Oraro & Rachier Advocates (Kenya) Steptoe &Johnson LLP (USA)Volume 1- Petroelum Subsector ReformVolume II- Corporate RestructuringVolume lIl- Electricity Law Reform

Kenya's Energy Sector Investment Programme 1995/96-1999/2000, document presented by theGovernment for discussion at a consultative Donor's Meeting in Paris, September 1995

Petroleum Market Structure and Pricing Study, August 1993, Prepared by Arthur D. Little Inc. (USA)

Feasibility Study for a Geothermal Power Station at North East Olkaria, Final Report, December 1989 (three volumes), Prepared by Ewbank Preece (UK)

Annex 4.2Page I of I

KENYAEnergy Sector Reform and Power Development Project

Description of the Sector Restructuring and Reform Component

Implementation of the Sector Restructuring and Reforrn component is already in progress with financing provided by IDAunder a Project Preparation Facility and supplemented by other IDA credits. The objectives of the component are to supportderegulation of the petroleum subsector, reforms of the organization, management and financial structures of the powersubsector companies, the establishment of a legal and regulatory framework necessary to improve subsector efficiency andthe promotion of private sector investment in the sector. The table below summarizes the relationship among the reformobjectives, the studies included in this component, the costs of the studies, and the outputs.

Reform Objective Activity Specific Objectives Cost Status(US$) ___________________

I. Power subsector (i) Power Sector Propose institutional and Consultant recommendations forreorganization and Organization Study organizational changes needed separation of generation assets fromrestructuring - Phase I in order to maximize efficiency transmission and distribution assets and

and effectiveness and to promote an effective regulatory arrangement haveinvestment. 332,000 been accepted by GoK.

(ii) Power Sector Propose specific steps to be 486,000' Draft final report has been prepared.Organization Study taken to implement the GoK to prepare action plan for- Phase 11 separation of generation from implementation of accepted

transmission assets into separate recommendations. Action plan to becompanies, in particular, the agreed with IDA prior to negotiations.organizational management,assets and financial restructuringof the existing companies andthe required contractualarrangements.

2. Promotion of private sector (iii) Consultants services Pre-qualification of IPPs, 600,000 Bid documents have been issued.participation in generation preparation and evaluation of

Requests for Proposals (RFPs)and assistance to the GoKduring negotiations withqualified bidders.

3. Enhancement of the legal Legal and Regulatory Identify reforms necessary to 250,00 Draft final report has been prepared.and regulatory framework Framework Study achieve a reorganization of the GoK to prepare action plan forfor the sector. power subsector, attract private implementation of recommendations

sector investment and to Action plan to be agreed with IDA priorimprove the sector's operational to negotiations.

_____ ____ _____ ____ ____ efficiency.

4. Deregulation of the (i) Petroleum Market Propose recommendations for 267,000 Study completed. Petroleum SubsectorPetroleum Market Structure and reform of the procurement, deregulated in October 1994. The main

Pricing Study marketing and pricing practices outstanding issue is the future of thein order to create a more refinery which is protected by a tax oncompetitive environment. imports until November 1996. Closure

of refinery would require altemativesourcing of LPG. These issues are beingaddressed in the macroeconomicdialogue.

(ii) Petroleum Import Assist MOE in preparing for the 27,000 Services in progress.Deregulation deregulated market, particularly

with respect to its monitoringrole.

(iii) Staff Training Build capaciht for monitoring 50,000 Training completed.subsector activities after thederegulation of the petroleummarket.

TOTAL COST . 2,012,000

Financed under the Parastatals Reform and Privatization Technical Assistance Project.

Annex 4.3Page l of 5

KENYA

Energy Efficiency and Demand Management Component

Background and Context

I. The Government's overall strategy for energy efficiency, as expressed in its Letter of SectorPolicy, addresses opportunities at four levels. First, the introduction of macro-economic measures relatingto energy pricing and increased reliance on market forces, will foster an enabling environment for energyefficiency improvements. Second, to increase the efficiency on the supply side, the power utilities willimplement a distribution system loss reduction program and install efficient generation facilities. Third.KPLC and the Manufacturers' Association will develop electricity demand management and energyefficiency programs. Fourth, recognizing that an appropriate institutional capacity is required to sustainenergy efficiency programs, the strategy emphasizes local capacity building and technology transfer.

2. As a result of past energy efficiency initiatives, Kenya is probably on a better footing than manysub-Saharan African countries. However, many initiatives have been dependent on donor and Governmentfinancing, so their sustainability has not been granted. The history of low power tariffs has also impededprogress. The situation today is more promising, the new tariff policy, the power sub-sectorreorganization, including greater commercial orientation and private sector participation will provide soundincentives for increased efficiency.

Objectives and Components

3. The objective of the energy efficiency component is to seek to develop and implement marketbased strategies and programs to promote more efficient energy supply and use.

4. The project has five components: (i) the KPLC efficiency improvement and demand management.program; (ii) a study to investigate how the availability, affordability and attractiveness of efficientelectrical technologies could be improved through policy interventions at manufacturing, importing andmarketing levels, for instance through the introduction of efficiency standards and an appliance labelingprogram; (iii) the Kenya Energy Management Program (KEMP), which is ongoing with the help oftechnical assistance by ESMAP (will not be described here); (iv) an energy efficiency workshop; and (v)program evaluation.

1. KPLC Energy Efficiency Improvement Program

IA. Supply-Side Efficiency Improvements (Distribution Loss Reduction)

5. Although KPLC's aggregate system losses (16% of net generation) are not excessive, they arequite high in some parts of the transmission and distribution system, and without improvements, wouldincrease to unacceptable levels. With the assistance of ESMAP, KPLC established an in-house capacity --an Efficiency Improvement Unit -- which has established the level of system losses in Nairobi City and theCoastal Area, which collectively account for 70 percent of total system load, as follows:

6. Nairobi. As a result of a well configured 11 kV system supplied by seven 66/11 kV sub-stations,the peak power and energy losses in Nairobi's medium voltage distribution networks that contain thehighest load concentration appear reasonable at present -- 2.6% for power and 1.8% for energy at presentloading levels. But, in the absence of system improvements, the power and energy losses would increaseto some 6.4% and 4.6% respectively over the next ten years.

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7. Coastal Area. In the Coastal area, where KPLC rely on long 33 kV feeders to supply loadconcentrations in and around the Mombasa Island, the level of peak power and energy losses in themedium voltage distribution networks are some 6.4% for power and 4.4% for energy. In the absence ofsystem improvements the power and energy losses would increase to 11.2% and 8.2%. respectively, in tenyears.

8. Based on the above findings, KPLC has developed a loss reduction program for the Nairobi andCoastal Area systems to be implemented as part of the proposed Project:

(a) Nairobi: (i) upgrading of II kV feeders, and installation of new feeders: (ii) replacementof capacitors on feeders; (iii) new 66/1 I kV substation at Kiambu plus new feeders tolink Kiambu to the LV network; and (iv) reinforcements in the LV networks

(b) Coastal Area: (i) new 33/11 kV sub-stations at three locations -- Rabai, Tiwi. and Galu;(ii) II kV feeders to link the above sub-stations to the existing LV network; and (iii)reinforcements in the LV networks

IB. Demand-Side Efficiency Improvements (Demand Management)

9. The economic viability of loss reduction programs, such as the installation of capacitors toimprove power factor in the MV and LV feeders, usually can be enhanced with the introduction ofelectricity demand management (EDM) measures. To that end, and in order to alleviate the effects of loadshedding, KPLC's Efficiency Improvement Unit are working towards integrating cost effective andcomplementary EDM measures into their operations. The Unit is presently focusing on EDM measures thatwould target industrial and commercial customers to improve power factor, and shift demand away fromthe peak load periods.

10. To enhance the level of KPLC's customer service in energy efficiency, the proposed Projectwould provide technical assistance to KPLC's Efficiency Improvement Unit to: (i) build an in-housecapacity on EDM to complement that for loss reduction; (ii) apply their skills on-the-job, drawing on theextensive information already gathered from the loss reduction work to plan complementary activities onEDM; (iii) design EDM projects; and (iv) implement EDM projects and strategy. The proposed project willfinance consultancy services and training for this purpose. In addition, key energy efficiency personnel atthe MOE would participate in major training events, while ESMAP would finance training to otherorganizations and local consultants under the KEMP program.

11. Training and Capacity Building in EDM. KPLC proposes to build its in-house capacity forEDM work through a "twinning" arrangement with another power utility with an established track recordin designing and implementing EDM programs. The training that KPLC staff would receive under sucharrangement would be supplemented by their participation in seminars and workshops and by visitingresearch and other institutions.

12. On-the-Job Training on EDM Planning and Load Profile Surveys. In order to developcomprehensive EDM actions, KPLC needs to build up a disaggregate demand management database. Tothis end, KPLC needs to complement its feeder level load data with additional information on demandprofiles and end-use practices within the premises of key customers. Therefore, using a similar on-the-jobtraining approach that was successfully applied by ESMAP to build in-house capacity for loss reductionwork, KPLC will to engage EDM experts to assist in designing and carrying out customer load surveys anddata collection activities to yield information on: (i) daily load curves; (ii) load duration curves; (iii) powerfactor at peak periods; (iv) load density; (v) load factors in key markets and customer groups; (vi) marketpenetration rates of electric equipment and appliances; and (vii) impact of power outages. KPLC wouldcarry out most of the required surveys using its own staff so as to enhance its EDM capacity. A number of

Annex 4.3Page 3 of 5

the surveys will also be contracted out to the private sector, including local energy firms, and the ESMAPtrained KAM professionals in order to create business opportunities for increased private enterprisedelivery of energy efficiency services in line with the Government's policy.

13. EDM Program Evaluation and Development. The next step is to develop, evaluate and rankdifferent EDM options according to electricity savings potential and cost-effectiveness to achieve KPLC'ssystem requirements. The options include but are not limited to (i) power-factor improvement, (ii) loadmanagement; and (iii) end-use efficiency.

14. Power-Factor Improvement. The evaluation will identify the customers where power factorimprovement would reduce demand and develop a program to install power factor correction capacitorseither at the customers premises or on KPLC's transmission and distribution system.

15. Load Management. Primary load management techniques include tariff rates (e.g. special tariffsfor "interruptible" or "curtailable" supply) which discourage use at times of system peak; and direct controlof customers' load. The technical and economic viability of re-structuring KPLC's time-of-use tariffs anddirect load control to create incentives for customers to use electricity in a way that minimizes KPLC'ssupply costs will be evaluated.

16. End-Use Efficiency. Depending on the survey results, the investigation would focus on programsto improve the efficiency of lighting, cooling, heating, water pumping, and electric motors. Thesemeasures would generally be implemented and financed by the customers themselves, but to reducetransaction costs, KPLC will design and field test a number of services that it would offer to assist keycustomer groups. Such customer services include: (i) collaboration with local energy efficiency programs,such as the KEMP, to provide diagnostic services of electricity end-use practices; (ii) advice to efficiencyimproving housekeeping measures, and to introduce energy monitoring and targeting systems; (iii) designand implementation of action plans to assist customers eliminate in-plant power losses; and (iv) preparationof specifications for bidding documents that would be applied by customers to procure technical servicesfrom third parties to upgrade end-use efficiency.

17. Study on Financing Mechanisms. Some of the efficiency improvement measures would requireconsumers to invest in retrofit measures or equipment. The low implementation rate of therecommendations of the past energy audits suggest the existence of funding problems and lack ofincentives. As the cost-effectiveness of energy efficiency will improve with the increased tariff levels, theissue of adequate financing mechanisms remains. Therefore, MOE in conjunction with KPLC, will carryout a study to map out sustainable mechanism for third party financing of efficiency improving measures,which may involve, for instance, leasing arrangements with industrial and commercial consumers.

18. EDM Program Implementation. KPLC would initially implement the following EDMprograms that would primarily target the Nairobi and Mombasa areas to integrate them to the program ondistribution loss reduction.

* Nairobi EDM Pilot Demonstration Project. This pilot project would target industrial andcommercial customers in a well defined area, for example those that are supplied from theexisting 66/11 kV sub-stations located at Industrial Area and Nairobi South. The primary aimis to encourage the customers to improve power factor levels, shift operations away fromevening peak periods, and replace obsolete and inefficient end-use equipment.

* Mombasa EDM Pilot Demonstration Project. This pilot project would target mainlycommercial but also industrial customers in the area supplied primarily from the Kipevu sub-station and its network of 33 kV feeders. These include hotels and other commercial loadsthat are supplied from the existing LV network; and

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* Western Kenva. KPLC would study the viability of extending the coverage of EDMmeasures to the Western Distribution areas, where the principal targets would includeindustries that also may have significant potential to contribute energy to the grid through co-generation.

* EDM Promotional Activities in the Commercial Sector. In order to demonstrate the costeffectiveness and economic benefits of energy efficiency improvements in commercial andinstitutional buildings, KPLC's demonstration activities would include: (i) the retrofit ofKPLC's headquarters building, especially the banking hall in Nairobi with energy efficientlighting and promotional exhibits; and (ii) the retrofit of at least two other buildings whichwould be selected to reflect the KPLC customer mix in the Nairobi and Mombasa loadcenters. KPLC would also in collaboration with professional bodies to provide advisory tobuilding owners, management companies and designers.

* EDM Promotional Activities for the Residential Sector. For the residential sector, KPLC'sinitial thrust would be to promote "good practice" in end-use energy efficiency through theactivities of the existing KPLC Demonstration Center in Nairobi, which caters especially towomen and students. The Center would be modernized and equipped with efficient lights andappliances, etc. It would set-up exhibits on efficient lights and other energy saving householddevices.

2. Energy Efficiency Standards and Labeling Program for Electric Appliances and Motors

19. Objectives. This activity will support and expand on activities at the end-use level, in particularto address the question of how the availability, affordability and attractiveness of efficient electricaltechnologies could be improved through policy interventions at manufacturing, importing and marketinglevels, for instance through manufacturing incentives, efficiency standards, and labeling and informationprograms. The objectives are to:

i Analyze the potential energy savings that could be achieved through improving theefficiency of appliances and motors;

- Identify the technical and policy measures needed to improve the efficiency of appliancesand electric motors in Kenya;

* Analyze the implications of implementing such improvements in terms of the productionchanges needed, the effects on prices, impacts on import/export of appliances and motors,and institutional requirements;

* Analyze the cost effectiveness of implementing efficiency standards and a labeling program;

* If implementation of efficiency standards and labeling program is shown to be cost-effective,then select the most promising technologies and strategies (addressing issues such asfinancing and institutional responsibilities) for further action, and develop preliminaryimplementation documents, such as a draft set of appliance/motor efficiency standards and aproposal for a labeling program.

* Propose an effective legal/regulatory framework for implementing the proposed program.

20. Implementation. The activity will be implemented by MOE in collaboration with the Ministry ofTrade and Industries (MOTI). A detailed project implementation plan will be produced following a ProjectPlanning Workshop that will gather the major stakeholders including the Kenya Bureau of standards,

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MOE, KPLC, MOTI, and organizations such as the Kenya Association of Manufacturers. The workplanwill include components to:

* Review international experience with standards implementation;* Review current manufacturing and import activities, and market status; and* Review the national legislative and regulatory context (import tariffs, etc.);

21. Following the completion of the above activities and the production of the draft report, an ActionPlanning Workshop wi]l be held to present and review project outputs and discuss the further curse ofaction with all stakeholders.

3. Energy Efficiency Workshop

22. Once the survey data is available from the KPLC and KEMP energy surveys and audits, and thepreliminary results has been obtained from the Efficiency Standards Study, a workshop will be held todiscuss and disseminate the results and explore further options to improving efficiency. The workshop willtarget major energy users in the industrial and commercial sectors.

4. Program Evaluation

23. At the end of the third year of implementation, an independent audit and evaluation will be carriedout to investigate the programs' effectiveness, customer satisfaction and propose a further course of action.

Implementation Arrangements and Estimated Costs

24. KPLC, MOE and KAM respectively will be responsible for the different sub-components asdetailed in the table below.

Sub-Component Responsible Estimated Costs USS millionAgency (inC. contingencies)

Local Foreign1 Efficiency Improvement and EDM Program

a. Supply Side Efficiency (loss reduction)- Phase I KPLC 0.56 3.2- Phase 11 KPLC 0.4 2.3

b. Demand Side Efficiency- Capacity building & training KPLC 0.1 0.2- Load & market surveys KPLC 0.1 0.3- Design & evaluation of EDM programs KPLC 0.1 0.3- Implementation of EDM programs

.Nairobi Pilot KPLC 0.1 0.6Coastal Pilot KPLC 0.1 0.6

.Westem Kenya analysis KPLC 0.05 0.15Commercial buildings KPLC 0.05 0.2KPLC Demonstration Center KPLC 0.15 0.25

. Other KPLC and MOE 0.2 0.7Study on financing mechanisms MOE 0.25

- Training of MOE staff MOE 0.05- Training of local consultants KAM ESMAP ESMAP2. Guidelines for Appliance Efficiency Standards and Labeling Study MOE 0.05 0.353. Kenya Energy Management Program KAM ESMAP ESMAP4. Energy Efficiency Workshop MOE and KPLC 0.01 0.055. Program Audit and Evaluation KPLC and MOE 0.05 0.25Estimated Total Cost (excluding ESMAP) 2.0 9.8

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KENYA

ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

Description of the Power System Expansion and Rehabilitation Component

A. Power Generation

Kipevu Diesel-Electric Plant

1. Background. The desirability of constructing a large oil fired thermal generating plant on thecoast of Kenya has featured in electric sector planning for a number of years. However, it was not until the1 990s that electricity supply/demand forecasts indicated a need to proceed with this new power projectwithin a definite timetable. Currently loss of load expectation in the Kenyan interconnected system in anaverage hydrological year is such that shedding can be expected every day of the year. The designcriterion is for load shedding to be expected in no more than ten days in a dry year. Consequently thesystem is now considerably less reliable than intended and in the event of a dry period occurring, or majorfailure of units, as has been the case at Gitaru hydropower plant, extensive load shedding will be requiredwith the resulting adverse economic impact. New capacity in the range of 150 MW is therefore urgentlyneeded to return the power system to somewhere near its design level of reliability. Screening analysisdemonstrated that from among the potential candidate generation options considered (oil and coal firedsteam plant; gas turbines in combined and open cycle; medium and low-speed diesel engines; geothermal;and hydro projects) the diesel options are least cost for supporting the power system demand. Theappropriate site for installing this diesel-electric power station is Mombassa given the fuel supplyrequirements.

2. The rationale for the Kipevu diesel-electric project are therefore threefold:

* to add further installed generation capacity in response to the country's projected increase indemand over the short-medium term;

* to help achieve greater reliability, security and stability of power supply within theinterconnected grid; and

* to help produce a more satisfactory balance between energy sources for electricitygeneration.

3. General Characteristics of the Power Plant. The Plant would be developed in two stages of 75MW net each. It is planned that the first stage would be implemented by the public sector (KPC), while thesecond phase would be built, owned, maintained and operated by an Independent Power Producer (IPP).Electric power produced at this second stage would be purchased by KPLC through a Power PurchaseAgreement (PPA).

4. The proposed power station would be located at Kipevu near the existing thermal power station.The area is restricted and hilly. Leveling will be done for both stages of the power station simultaneously.Site investigations, including appropriate borehole drilling, were carried out by a reputable engineeringfirm, and concluded that the hilltop area next to the existing power station has competent foundationcondition for the new power plant.

5. Feasibility studies for the Kipevu Diesel-Electric Power Scheme were carried out by a reputableengineering firm. The feasibility-level design calls for two adjacent power stations each with 12.5 MWmedium-speed diesel-electric sets burning heavy fuel oil (No. 6 HFO). Net capacity of each station wouldbe 75 MW. Fuel oil would be supplied via pipeline, either directly from the Mombassa Port nearby (lessthan 1.0 km) or from Mombassa Refinery (7 km). This provides dual sourcing and gives an enhanced levelof security. Nevertheless, a strategic reserve of 30 days will be kept on site. The confines of the availablesite requires that a central fuel storage area be provided for both stages of the power station, with provisionfor separation within this area. It is proposed therefore that two bulk tanks be provided, each 900 cubicmeters capacity, surrounded by a common bond and with individual designated unloading and forwarding

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facilities. An emergency transfer line interconnecting the two tanks would be provided to enable crosssupply of fuel and to permit tanks to be emptied for maintenance. From the bulk storage tanks, fuel wouldbe supplied to two large service tanks adjacent to the engine room of each stage, to await treatment. Thesetanks would be sized to hold 250 cubic meters. Similar tanks would be provided post-treatment, givingeach stage 1.000 cubic meters on-site storage. Total strategic reserve would amount therefore for bothstages together to 3,800 cubic meters.

6. Each stage of the power station would be self-contained, with separate engine rooms, auxiliariesand step up substations. The diesel engine will be driving directly coupled synchronous generators. Amain supplying water from Mombassa runs near the project site. The quality and quantity of water isconsidered adequate to meet the need of a closed-circuit non-evaporative cooling water system andtherefore it will not be necessary to provide a major water supply, nor a water treatment plant. The coolingsystem would be provided with air blast radiators.

7. Combustion air would be drawn from outside the engines powerhouse building, via intake filtersto minimize intake of airborne dust particles and insects. An exhaust gas system would be provided foreach diesel-electric set, which will include an exhaust heat-recovery boiler to provide steam or pressurizedhot water to supply all fuel heating requirements. After crossing the heat-recovery boiler, the exhaustgases will be conducted to a common chimney stack for each stage of the power station.

8. Fuel oil and lubricating oil sludge would be piped to a station collecting tank (one for each stage).From there it would be treated in a dedicated treatment system. Separated concentrated sludge would bedischarged into an incinerator, while oily water would go to a separator. From this separator clean waterwould pass to the drain system and oil would be returned to the sludge tank for further treatment.

9. The fuel treatnent plant would draw fuel from the two heavy fuel pretreatment tanks. The fueltreatment will comprise two 100% duty fuel treatment modules in parallel. Each module would includefuel heaters and automatic fuel centrifuges.

10. Power generated in each stage of the power station will be stepped up to 132 kV. Generators willbe connected in pairs via two-winding transformers to the gas-insulated 132 kV switchgear.

Within these parameters, specification of the exact unit size will be a matter for the tenderers, solong as the net capacity of each state is achieved. The general plant design must aim for: (i) high operatingefficiency and low generating cost; and (ii) high reliability and long useful life.

II. Concerning the second stage of the power station, the terms and conditions of tender documentwill contain a Minimum Functional Specifications (MFS) for the plant, which will act as guide for bidders.Subject to complying with the MFS parameters, bidders will be free to propose the plant configuration,capacity and design which they wish, subject to space limitations.

12. Environmental Aspects. A comprehensive environmental impact assessment has been carriedout by competent consultants. From this assessment it appears that the project would have the followingadverse environmental effects that would need to be mitigated: (i) emission of contaminants from fuelcombustion; (ii) noise from engines operation and from air-cooled radiators; (iii) oil spill accidents; and(iv) sludge from fuel and lube oil

13. The measures that would need to be taken to mitigate these environmentally undesirable effects,are the following:

* contaminants emissions would have to meet World Bank guidelines; in addition, the exhaustgases after cooling in heat-recovery boilers would be dispersed by means of high stacks(minimum 60 m high); contaminants dispersion would be aided by the fact that the powerstation would be sighted on a high bluff receiving sea breeze;

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* engines air intakes and exhaust would be equipped with silencers adequate to meet noiselevel requirements around the power station building. Control room would be sound-proofed, and sound proof booths would have to be provided in the machine halls. Silencerswould be adapted to air-cooled radiators. In addition, the power plant would be screened byrows of trees;

* oil spills would be contained by appropriate bunds around tanks; and* sludge from fuel and lubricant would be treated and after separation burned in incinerators.

Third Unit at Gitaru Hydropower Plant

14. The existing powerhouse at Gitaru Hydropower Plant is underground with two 72.5 MWgenerating units. Provision was left in the original design for the future addition of a third unit. Penstockwith bolting flange for turbine intake and draft turbine connections including gates have already beinginstalled. The work to be done in order to commission the third unit consists of: (i) Turbine; (ii) Maininlet value; (iii) Generator and exciter; (iv) Concrete for embedded; (v) Low voltage switchgear; (vi) Busduct to main transformer; (vii) Main generator transformer; (viii) Auxiliaries, pumps, etc.; (ix) Controlpanels and relays; and (x) B2kV switchgear with breaker and isolators.

15. January 1995, a fault develop in one of the generators forcing shutdown of the unit. The fault,apparently due to aging of the varnish covering the stator core steel sheets at core joints, thus causing thedevelopment of hot spots due to the eddy currents generated. The stator windings suffered consequentdamage from these hot spots, until failure of the insulation resulted. Repair work took about a year andwas completed in March 1996. The units at Gitaru are the largest in KPLC power system and theprolonged outage of one of the units has adverse effects on the power system ability to meet peak demandand has forced load shedding measures. Moreover, recent tests on the faulty generator have detected flawsin the generators stator core joints. Therefore, on recommissioning, the unit could not be restored to its fullrated output of 72.5 MW without risking further faults. The other generator will also require inspection toascertain the state of the generator stator core. Indications at the moment are that the faulty unit wouldhave to be limited to a maximum load of 60 MW, the KPLC power system would have serious constraints.The installation of the third unit, therefore, becomes an unavoidable necessity. On average, Gitaru PowerStation produces 840 GWh per year with both units in operation. With only one unit, as has been thesituation in 1995, the power station will generate about 500 GWh per year. The loss in energy productionfrom a fault in one unit is a minimum of 340 GWh a year while the defect is corrected.

16. Commissioning of the third unit for Gitaru Hydropower Plant would result in the followingeffective capacity of: (i) 2 x 60 MW plus I x 70 MW= 190 MW; and (ii) 763 GWh from original units plus112 GWh from the third unit for a total of 875 GWh per year.

17. The addition of a third unit at Gitaru would have no detrimental environmental impact.Procurement of the unit would be by ICB. A span of 3 years is foreseen for design, tenderingmanufacturing, transport and installation.

Olkaria II Geothermal Power Plant (2x32 MW)

18. The Olkaria If power plant - with an installed capacity of 64 MW in two units of 32 MW - will belocated at the northeast part of the Olkaria geothermal field. Steam will be collected from the steamfield -already developed with 29 wells (out of which 20 are capable of providing steam for 78 MW - an averageof 3.4 MW/well). Reservoir engineering studies indicate that the geothermal field can support the electricpower generation of 64 MW during the life of plant i.e., 30 years, with pressure and temperature withinthe required values for power generation and without detrimental impact upon the production of theexisting Olkaria I power plant. The non-productive wells will be utilized for the reinjection of the residualwaters. Steam separation will be carried-out at a number of sites around the geothermal field and steamtransmitted through the gathering system to the steam turbines at the power plant. The non-condensablegases will be dispersed through the cooling towers.

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19. The plant will be of a modified modular type. In a modular geothermal power plant, the upwardexhaust turbine, gets to the site tested and assembled in a module, the generator is modularized separatelvwith the rotor assembled in the stator, and the direct contact condenser mounted outdoors, everythinginstalled on a concrete floor using a low level arrangement. The idea is to avoid as much as possible theexcavations and civil works required by the conventional arrangement. KPC and its consultants, as atransition from the conventional design to the modular concept, accepted most of the modularizationexcept in two aspects: (i) all equipment, except the condenser is placed indoors in several buildingscarefully designed to blend with the environment of the Hell's Gate National Park, and (ii) the commonlyused direct contact condenser was changed to a condenser with a barometric leg requiring a seal pit.

20. The designs of the civil works specify a power house superstructure with reinforced concretecolumns and concrete beams for a traveling crane. Deep piled foundations for all major structures arerequired and thus specified. In addition, the project civil works include the provision of 65 staff houses,comprising 36 junior staff and 29 senior staff.

21. The steam transmission or gathering system designs were based on the prediction of the 20 wellsselected for production. The current design proposes the use of separators with integral water drums. Theseparators have been standardized for three steam flow capacities 25, 50, and 100 tones/hour. The designspecifies three separator stations of 25 t/h, seven of 50 t/h, and three of 100 t/h. Using these dispersednumber of separator stations minimizes the amount of two phase flow and corresponding losses. Motorizedwellhead flow control valves will be installed. Discharge silencers will be provided at each separationstation.

22. The design of the reinjection sy'stem comtemplates only cold reinjection of the waters from theseparator stations. The residual waters will be conveyed by steel gravity pipes to two main conditioningand cooling ponds. From these ponds the fluids flow to the main overflow pond and a reinjection sumpfrom which they will be pumped to the reinjection wells. The reinjection system will be refined to includeda hot reinjection system - which will become the primary reinjection system. In the hot reinjection system,the hot waters from the separators will be conveyed directly by steel pipes to the reinjection wells (wellsR2 and R3 are already available), without passing through the silencers and the cooling ponds. With thehot reinjection system, the well head pressures are improved thereby prolonging the life time of the system.A system with both hot and cold reinjection improves the management of the reservoir and providesgreater flexibility of field operations.

23. The designs of the electro-mechanical works include: (a) a single flashed steam condensingturbine cycle; (b) two 32 MW single shaft, single flow turbines, mounted at ground level with thecondenser located adjacently; (c) a barometricalily drained condenser into a seal pit, where vertical shaftpumps will pump the condensate water to the cooling towers; the condenser will incorporate an integral gascooler; (c) a steam ejector or gas extraction system which will disperse the non-condensable gases throughthe cooling tower plume; (d) mechanical induced draught cooling towers aligned parallel to the prevailingwind direction will be provided as well as (e) two electric generators with an output capacity of 32 MW ata power factor of 0.8, that will generate electricity at II KV.

24. The power plant will be connected to the national grid at 220 KV through a 220 KV substationlocated adjacent to the plant. A double circuit 220 KV line will feed power to a new substation in Nairobi(Nairobi North) and the existing Dandora 220/132 KV substation that will be extended with additionalbays. A 132 KV line will interconnect the existing Olkaria I plant through a 220/132 KV, 80 MVAautotransformer with the substation at Olkaria I. Both 132 and 220 KV lines will be strung with CanaryACSR conductors with one conductor per phase giving a rating of 282 MVA per phase at 220 KV. Steellettice towers will be used with vertical configuration for the double circuit 220 KV lines and withtriangular configuration for the single circuit 132 KV lines. The substations will be constructed as doublebusbar with one-and-a-third circuit-breaker configuration. Circuit Breakers will be of the SF6 or minimumoil type.

Annex 4.4Page 5 of 8

Olkaria III Geothermal Power Plant

25. The Olkaria III Geothermal Power Plant, to be implemented in the Olkaria Southwest sector of theOlkaria Geothermal Field (an area of approximately 7 square kilometers), is expected to be similar to theOlkaria 11 Geothermal Project described above'. As indicated before there are 4 productive wells and twoadditional wells (wells OW-308 and OW-102) being drilled by KPC. The electrical connection to thenational grid of Olkaria III will be a simple line interconnection between the Olkaria Ill step-up substationto the 132 KV side of the Olkaria 11 power substation.

26. This project is being offered to independent power producers (IPP's) for development. The projectscope that would be carried out by the successful IPP include: drilling and testing of the production field(includes reservoir engineering studies); design and construction of the power plant and the design of theelectrical interconnection to the Olkaria II substation; and finally the operation of both the well field andthe power plant to comply with the terms of a purchase power agreement that would be entered betweenthe IPP and KPLC.

Support for Olkaria I Geothermal Power Plant

27. The East production field, as indicated before, supports an installed capacity of 45 MW (Olkaria1). As is normal in all geothermal fields there is a decline of pressure and steam rate as a consequence ofexploitation of the resource; the rate of such decline depends on the specific characteristic of the fieldbeing exploited. In the case of the Olkaria Field, the experienced decline is about 4% per year. Theproduction of Olkaria I, as a consequence of the indicated phenomena, decreased to 29 MW some fewyears ago. Now with the connection of several make-up wells, the power output of the power station hasbeen restored to full capacity.

28. The proposed "Support for Olkaria I Geothermal Power Plant Project" consists of: (a) theconnection of two additional wells (already drilled), plus (b) the drilling of four new wells, to be laterconnected by KPC, using its own resources, to the gathering system of Olkaria 1, with an independentcontractor.

Environmental Aspects

29. The Environmental Assessment and related environmental analysis following the Bank policiesand procedures regarding EA's was carried-out by a specialized consulting firm in 1992 to provideinformation on the following matters: (a) the existing environmental baseline conditions; (b) the potentialEnvironmental impacts, both direct and indirect; (c) the identification of preventing, mitigating andcompensating measures; (d) environmental management and training; and (e) monitoring.

30. The environmental impacts of using geothermal energy for power generation are generally relatedto impacts on: (a) air quality; (b) water pollution; (c) land disturbance; (d) aesthetics or visual impacts; (e)noise; and (f) socio-economic aspects. The main findings of the EIA study on these aspects are summarizedas follows:

31. Air Quality. The gaseous elements carried out by the geothermal steam are discharged to the air,depending on the characteristics of the particular resource, problems may arise. In the case of the OlkariaNE resource the non-condensable gases consist mainly of carbon dioxide (up to 96% of volume) and smallamounts of hydrogen sulfide (up to 5%), plus very small amounts of hydrogen, methane, and nitrogen. In

In the area assigned to Olkaria III, the field still has to be explored with additional geoscientific workand exploratory/production drilling. The additional wells will have to be strategically located in thefield in accordance to the conceptual geothermal model. After drilling a sufficient number of wells, adetailed reservoir engineering analysis will have to be executed to determine the generating capacitythat the reservoir in that area can support.

Annex 4.4Page 6 of 8

the Olkaria 11 power plant, these gases will be dispersed through the cooling tower plume. Modelingcalculations indicate that the dispersion obtained is good and the concentrations will be much less thanthose registered with the existing Olkaria I power station.

32. The modeling calculations also indicated that concentrations of H1S in most settlements will reachthe same levels of the current situation, except in the existing X-2 camp in which the threshold for odordetection will be increased by 40%. For this reason it was recommended that the X-2 camp be relocatedoutside the Hell's Gate National Park. This recommendation has been accepted and the cost of therelocation has been included in the cost of the project. Moreover, it is important to note, that ground levelconcentrations were found below those levels that could adversely affect the health of workers and localpopulation. Another minor recommendation on air quality relates to the need for continual monitoring ofthe local flower growing areas.

,3. Water Pollution. The main problem that could be derived from geothermal power stations isrelated to the handling of the geothermal residual fluids. High temperature reservoirs, greater than 2300 C -the case of Olkaria - produce waste water containing an extensive menu of dissolved minerals. Theelements of most concern are fluoride, arsenic, and lead. Although by world standards the Olkariageothermal brines are not particularly toxic, it does exceed health-based water quality goals and needs to bedisposed of in a safe manner. The current method of disposing of the geothermal brines into gullies andnatural drainage lines, currently practiced in the existing Olkaria I station are inappropriate since seriouserosion has been caused in some areas.

34. In the Olkaria 11 geothermal project, as explained before, all residual waters will be reinjected intothe geothermal reservoir, using several non-productive or specially drilled reinjection wells. Reinjectionnot only is an environmental sound way of disposing of the waste water but also has a positive impact onthe maintenance of reservoir pressure and steam rates over a longer period of time.

35. Since the whole geothermal operation depends from abstraction of fresh water from neighboringNaivasha lake, and although the amount taken by KPC is only around 3% of total abstraction, it washowever recommended that KPC monitors the lake level variation (long term).

36. Land Disturbance. As indicated before, the geothermal development is within the Hell's GateNational Park which present a host of animal life. In order to minimize the disturbance of the habitat therewill not be a perimeter fence around the whole complex. Only individual well heads will be fenced, and thepower house and substation will have their own perimeter fences.

37. Where drilling operations have been completed the larger area required to accommodate theequipment will be restored to its original state.

38. No impacts have been experienced with the current operations of Olkaria I on the local flora. Thesituation with Olkaria 11 is further improved since all waste waters will be piped instead of ditched. Thiswill prevent new vegetation to occur in the neighboring areas.

39. Aesthetics or Visual Impacts. The choice of the Site A versus an alternative Site B, for the powerstation was taken despite its greater visual impact. This impact will be mitigated by the construction ofembankments around the station, the planting of trees and appropriate architectural designs of the buildingsthat make up the power complex.

40. Noise. Noise measurements indicate that present drilling operations have a very low noise level inthe range of 24 to 34 DB(A). The power station operation, test drilling, and well head operations willgenerate noise levels above this type of background noise detectable specially at night. The only majorimpact on any residential area is in the existing X-2 camp where noise levels will be increased to about 43-50 dB(A), during the well testing phase, but as mentioned before, the camp will be relocated. There willalso be a noise impact during the construction phase of the power station but it will be a temporaryproblem.

Annex 4.4Page 7 of 8

41. Socio-EconomicAspects. The Environmental Assessment concluded that the project would havea significant impact on the socio economic of the surroundings. It was considered necessary that KPCprovides all necessary accommodation and infrastructure because the local towns would not be able toaccommodate the workforce during construction and later during the operation of the station.

42. The long term impact on tourism was not considered a major problem. Indeed many touristconsidered such a development and attraction rather than a detraction.

43. The recommendations of the Environmental Impact Assessment were incorporated in the..Agreement on Geothermal Development in Hell's Gate and Longonot National Parks" entered betweenthe Kenya Wildlife Service and The Kenya Power Company LTD on September 20, 1994. All activities arenow executed under the terms of the Agreement. However, still pending is the relocation of the existingcamp X-2 outside the boundaries of the park.2 The cost of this relocation are included to be financedwithin the Energy Sector Investment Project. The architectural and civil engineering designs for theOlkaria 1I residences have been adopted for the new X-2 camp.

Implementation of the Geothermal Components

44. Organization. The geothermal components will be implemented by KPC (generation); thetransmission and substations financed with Olkaria II will be implemented under the supervision of KPLC(transmission and distribution). For Olkaria [I a project management team will established under theGeothermal Development Coordinator, who reports to the Chief Project Development Manager. Theproject management team will use the services of the existing units of the Office of the GeothermalCoordinator, namely, the Procurement Unit and the Project Procurement, Monitoring and Control Unit.Through the Office of the Chief Project Development Manager, the project management team obtains theservices of the Finance Department for matters relating to disbursement and payments to contractors andconsultants

45. For the implementation of the Olkaria 11 project, a Consultant Firm will be contracted. This firmselected among a short list firms, previously approved by IDA, will assist KPC during the bidding processas well as for supervision of construction which includes factory inspection, as-built designs and the testingand commissioning of the power plant. The Operation Division of KPC will assigned three engineers towork with the consulting firm in field supervision of construction and assembly of power plant equipment

46. The Implementation Schedule of Olkaria 1I shows that the project requires 39 months or 3 114years of execution after the eligibility of the loan and/or the tendering process are initiated. The criticalpath of execution is conformed principally by the contracting and manufacturing of the electromechanicalequipment, interrelated with the civil works. Because of this fact, project management and engineering iscritical in assuring that the contractors for the civil works contract and the electromechanical equipmentcontractor do not interfere with the schedule of the other.

47. The Implementation Schedule of Olkaria 111, if negotiation with the private sector are successful,considers that it will be executed in parallel and during the same period of time as Olkaria 11.

48. The relocation of the X-2 camp will required three years and half. One year for contracting andengineer/Architect firm to prepare the studies and designs, and the remaining two and half in thecontracting and construction of the works.

B. Distribution Systems Reinforcement

2 Another important requirement is the reinjection of the residual waters from both the field and thecooling system. This however will be implemented during the construction of the power plant and thegathering system.

Annex 4.4Page 8 of 8

49. KPLC intends to carry out a program to reinforce primary distribution (subtransmission) inNairobi and in the Coastal Area, particularly around Mombassa. The program in Nairobi would essentiallycomplete the 66 kV ring around the city and expand the 66/11 kV substation capacity feeding into the IIkV feeders network.

50. Nairobi. The Nairobi System receives power at 132 kV and 220 kV from Juja Road, Ruaraka andEmbakasi substations all located on the outskirts of the city. Transfornation to the primary distributionvoltage of 66 kV is done presently at these three substation. Fifteen 66/11 kV primary distributionsubstations are located in and around Nairobi.

51. The method used to forecast demand was developed by KPLC consultants and used in theNational Power Development Plan. This method relates energy sales for various categories of consumersto the related sectorial GDPs, historical sales and projected tariff increases. By imputing the Nairobi areasales figures and the national economic data up to 1994, and the projected GDP growth rates for futureyears, the area total sales and peak demand were forecasted. From peak demands forecast, the annualgrowth rate for the total area load is obtained. The calculated growth rate is then applied to all theindividual substation loads with appropriate adjustments.

52. Reinforcement required for each of the existing substations was determined on the basis of havinga firm transformer capacity available at each substation, i.e. transformer capacity sufficient minus onetransformer to accommodate the expected load. Location and capacity of new substations was alsodetermined, as well as reinforcement or new 66 kV lines. A number of arrangements for the 66 kV gridwere then compared on the basis of their benefit/cost ratio. The increase in grid capacity is costed at theLong Run Marginal Cost (LRMC) attributable to HV and MV reinforcements. The LRMC in this case hasbeen calculated by KPLC's consultants at USSO.O18 per kWh.

53. Within the selected option for reinforcement of the Nairobi Grid, the program for the period1996/97-2000/01 consist of the following works:

* Limuru 66/11 kV Substation, install 2 x 15 MVA transformers;* Kikuyu 66/11 kV Substation; install second 10 MVA transformer;* Parkland 66/11 kV Substation; install 2 x 45 transformers;* Juja-Parkland 66/kV line; reconductor of 2x6.5 km;* Embakasi - Nairobi West 66 kV line; reconductor of 2x3 km;* Juja - Jeevanjee/Bahati 66/kV line, construct 1.0 km of double circuit line;- Parklands-Catedral 66 kV cable, install 2.5 km of cable;* Nairobi West - Karen - Kileleshwa 66 kV line, construct 5.5 km of line;

* Bahati 66/11 kV Substation; establish new substation with 2x23 MVA transformers; and* Kileshwa 66/11 kV Substation; establish new substations with 2x23 MVA transformers.

54. Coastal Area. The study for the reinforcement of the 33 kV and 132 kV primary distribution gridin the Coastal Area, was carried out by KPLC using the same approach as for Nairobi. The reinforcementprogram thus established for the period 1996/97-2000/01 comprises the following works:

* Nyali 33/11 kV Substation, install 23 MVA transformer;* Gede 33/11 kV Substation, install second 7.5 MVA transformer;* Miritini 33/11 kV Substation, install second 7.5 MVA transformer;* KPR 33/11 kV Substation; install second 7.5 MVA transformer;* Kipevu 132/33/11 kV Substation; install 23 MVA transformer;* Diani 33/11 kV Substation; install 23 MVA transformer;* Rabai-Diani 132 kV line; construct 45 km and install 45 MVA Substation;* Likoni 33/11 kV Substation; install 2.5 MVA transformer;* Kipevu 132/33/11 kV Substation; install second 23 MVA transformer; and* Shanzu 33/11 kV Substation; install 23 MVA transformer.

55. Equipment already in stock, mainly transformers, represents about US$12 million. Some shiftingof transformers between substations would also be done.

Annex 4.5Page 1 of3

KENYA

Description of the Resource Assessment Component

I. The 1992 updated National Power Development Plan prepared by Acres International recommends theaddition of about 493 MW of geothermal power capacity up to the year 2011'. The corresponding least-costDevelopment Plan requires that two units of 32 MW (units # 6 & 7) come in line by the year 2001, and another twounits (units # 8 & 9). of the same capacity, by year 20032. To achieve these ambitious long and short termobjectives, requires a continuous program of surface investigations, drilling and well field development, along withthe design, financing, tendering and construction of power plants. The Geothermal Resource Assessment Programincluded in the "Energy Sector Investment Project" can be subdivided in two sub-components, as follows: (a) FieldDevelopment and Feasibility/Detailed Design for Olkaria IV or Olkaria III & IV, and (b) Advanced Pre-feasibilityStudies at Olkaria Domes and Suswa, and Pre-feasibility Studies at Longonot and a New Area. The descriptions ofthese components follow:

A. Field Development and Feasibility/Detail Designs for Olkaria IV or Olkaria III & IV

2. The Field Development Activities proposed, within the Geothermal Resource Assessment Program, wereestablished to comply with the stated objectives of the National Power Development Plan and the "normalgeothermal development criteria " followed by the geothermal industry in other developing countries.3

3. The proposed Base Field Development Program considers the drilling of 26 wells. This does not complystrictly with the described "normal development criteria", since under normal circumstances only 11 wells wouldhave been required to prove the feasibility of the Olkaria IV geothermal project. The departure from the normalpractice is justified with the following considerations: (a) the need to develop the field of the next geothermal powerplant (Olkaria IV) to ensure its implementation by year 2003; and, more importantly, (b) the need to establish anAlternative Program - with the same cost as the Base Program - as a back-up, in case that negotiations with theprivate sector for Olkaria III are not successful; in this instance, the Govemment of Kenya will be confronted withthe need to prove feasibility for the two projects to secure their financing and implementation.

4. With the proposed Altemative Program, 11 wells will be drilled in each of the two areas assigned for theOlkaria Ill and IV geothermal projects - a total of 22 wells - plus the preparation of the feasibility level studies anddesigns of the corresponding power plants. The Alternative Program thus established follows strictly the described"normal geothermal development criteria" followed by other geothermal developing countries.

B. Advanced Pre-Feasibility Studies at Olkaria Domes and Suswa, and Pre-Feasibility Studies atLongonot and a New Area

I The probable generating capacity that can be supported by the geothermal resources of the country still has to bedemonstrated.

2 Due to the delays incurred in funding the current Program it is doubtful that these additional units can becommissioned by the indicated years.

3 Following common practice or "Normal Process" ,the geothermal fields are developed to a level of 30% of thesteam required for full production of a given generating capacity, and, utilizing the geoscientific data of thedrilling campaign, the surface geoscientific studies are upgraded, thus obtaining an improved geothermalconceptual model and a detail synthesis map of the geoscientific anomalies. The studies related to thegeothermal field, complemented with reservoir engineering studies and power plant and gathering systemsfeasibility level designs - including cost estimates - constitute a feasibility report adequate for seeking thefinancing for the implementation of the project. The detail designs (tender level designs) are prepared duringthe year in which the financing is sought and negotiated.

Annex 4.5Page 2 of 3

5. Surface exploration will be concluded in Olkaria Domes and Suswa and in the areas of Longonot and insome new area in the north (probably Menengai) with KPC own resources. A slim-hole drilling Program will becarried out in Olkaria Domes and Suswa. It includes the drilling, in each of the indicated areas of six temperaturegradient holes (500 meters depth), and 3 deep (2,500 meters) slim holes. These drilling activities will be done with adrilling contractor.

6. To support KPC scientific geothermal activities, it was agreed to include as part of this component, thefinancing of an Advisory Board integrated by six recognized international geothermal experts. The respectivespecialization of the six experts will be as follows: (i ) geothermal exploration in the discipline of geologyvolcanology: (ii) geothermal exploration in the discipline of geochemistry and geophysics, (iii) geothermal fielddevelopment. which includes drilling engineering, well test and reservoir engineering; (iv) geothermal plant designand installation, which includes mechanical, chemical, electrical and construction engineering; (v) management andoperations of geothermal projects, which includes project planning, production engineering, financing and financialcontrol, and (vi ) environmental science, which includes hydrology, meteorology, biology and sustainabledevelopment

7. To support KPC drilling operations, the project would include the financing of the purchase of equipment(vehicles, tractors, scientific instruments, drilling equipment spare parts, excavation equipment, well testingequipment). drilling services and repairs, training and the preparation of feasibility and other geothermal studies,and the contracting of drilling services.

8. KPC with its own resources will purchase local materials and services as spares, environmental materials(trees, plants. etc.), water supply system maintenance (spare and services), water pipeline for drilling operations,and land acquisitions.

Implementation

9. Organization. The Advance Pre-feasibility level studies, and Field Development Program for additionalunits in the Olkaria Geothermal Field, included in the Resource Geothermal Assessment Program, will be carriedout by the Geothermal Development Manager's Office at Olkaria. This Office has under its supervision the Team ofGeoscientists and the Drilling Crew Operations, who will supervise the slim drilling operations that will becontracted with a private drilling company. The Geothermal Development Manager reports to the GeothermalDevelopment Coordinator. As support for the indicated studies, an Advisory Board integrated by six recognizedgeothermal experts in the different disciplines that enter into the studies of a Geothermal Project, will assist KPC inall areas of the Geothermal Program of the Project, but especially in the Resource Assessment and FieldDevelopment Areas. The Advisory Board will review the studies and reports prepared by KPC Geoscientists. Therecommendations of the Advisory Board agreed during the Advisory Board meetings will be mandatory

10. A geothermal consultant firm or firms, following IDA's procedures, will be contracted for carrying out thefeasibility level studies that will be completed, after a pre-approved number of commercial diameter wells havebeen drilled4. The supervision of feasibility level studies fall under the leadership of the Office of the CorporatePlanning Manager. This Office will have the support on geothermal matters of the Offices of the Coordinator ofGeothermal Development and the Staff of Scientists of the Geothermal Development Manager, and of the AdvisoryBoard of international experts. All described arrangements are considered satisfactory for the implementation of thegeothermal components of the Energy Sector Investment Project.

I1. Implementation Schedules. In accordance to the Implementation Schedules the Geothermal Programrequires four year years for its execution and four and half year for loan disbursements, after the loans are declareeffective. The most important aspects of the Implementation Schedules are summarized as follows:

4These wells will be drilled by KPC 's drilling crew, utilizing an existing drilling rig which will be overhauled withresources of the program.

Annex 4.5Page 3 of 3

12. The Implementation for "Support of Olkaria I" and the "Geothermal Resource Assessment" can begrouped as a single program of procurement of services, materials and equipment/instruments. The procurementactivities of this group have been divided in two round of activities, the first round covers the needs ofmaterials/equipment and services for approximately II wells for 2 years. The second round for the remaining twoyears. Under this group the development drilling for Olkaria IV or III and IV and the feasibility studies of theseprojects will be concluded in the indicated four years: the Pre-feasibility level studies of the other geothermal areasare also concluded during the fourth year of activities.

Annex 4.6Page I of 2

ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

RURAL & HOUSEHOLD ENERGY DEVELOPMENT STRATEGY

Introduction

Woodfuel and agricultural residues are estimated to account for about 75 percent of the total primaryenergy use. According to the most recent bousehold energy use survey, which was carried out in 1980. about95 percent of the domestic sector's energy demand was met bv firewood, charcoal and residues. During the1980's a number of bilaterally funded household energy activities have been implemented, including thedevelopment of efficient cooking stoves, agroforestry, and biogas and wind energy development. Currently,however, no reliable data exists of the woodfuel demand and supply situation, or of the impact of the activitiesin the sub-sector. The Government, therefore, has decided to develop a Rural and Household Energy Strategyto accelerate the access to sustainable and affordable energy by lower income rural and urban households.

Objective

The objective of this activity is to develop a Rural and Household Energy Strategy, including apriority investment and technical assistance program to efficiently address the energy related problems ofmedium and low income households.

Activity Description

Tbe project comprises the following three sb- o . (i) Housebold Energy Use Survey; (ii)Energy Supply and Marketing Study; and (iii) Policy, Institutional and Pricing Study.

Household Fnergy Use Survey

Objective. TMe objective of the Household Energ Use Survey is to obtain data of energy use inhouseholds. The survey will target medium and low imcome households in rural and urban areas.Specifically, the survey will estabih te types of energy used (firewood, charcoal, agricultural residues,kerosene, LPG, electicity, solar, etc.), quandties used, type of end-use by fuel, sasonal variatios in fueluse and fuel availability, equmet used, houehold's ener expenditure, whether fuel is purchased orcollected free of charge, where uel is purcsed ad collected, supply constains and other problemsencountered by the households relaed to tei enerV use (health, envirounme). The uv will also seek toobtain information of households enery cosrvation awazeu, use of energU efficiet equipment, andreasons for not usig energy effint equipmt. In addition, the survey will obtain informaton of householdattitudes toward fuel swihing and how the hoseolds perceive the availability of alternative fuels and theirpossibilities to switch to alternative fuels.

Saple and Survey Mehod. About 100 bouseholds will be interviewed in 10-15 districts and 3-5urban centers in order to identify differences between urban and rural households and between differentecological areas.

Energ F S=p, and Makting Sr

Objecnve. The objective of the Energy Supply and Marketing Survey is to establish the seasonalavailability of fuelwood and modern fuels in the areas of the household surveys, the origin of firewood andcharcoal supplies, the fuel supply chai, nd prices. The survey also aims to establish changes in fuel

Annex 4.6Page 2 of 2

consumption and availability over the past years. The study will build on the existing data, for instance theKenya Forestry Master Plan.

Survex Method. Interviews with fuelwood vendors, petroleum products distributors, forestryofficials, NGOs, and others. The interviews will be conducted in parallel with the Household Energy UseSurvey. A sample of the areas will be selected for a second survey to caprure seasonal availabiliny of fuelmore accurately.

Policy. Istitutignal and Pricing Stidy

Objective. The objecti-ve of the Policy, Institutional and Pricing Study is to: (i) identify and evaluatethe policies that influence the household energy sub-sector today; (ii) identify barriers to energy conservationand fuel switching; (iii) evaluate the impact of the policy reforms in the petroleum and power sub-sectors onthe household energy sub-sector; (iv) how can markets be tapped in such a way to encourage a shift fromnon-sustainable, mostly land clearance operations to sustainable tree growing or forest/woodland managementinitiatives; (v) propose changes in the policy, and pricing frameworks to promote sustainable and affordableenergy supplies to medium and low income households (including energy conservation and fuel substitution),and (vi) assess the capacity of the various institutions (GOK, NGOs, private sector) to address householdenergy issues effectively and propose improvements as required. The study will also evaluate the impact ofthe past activities in the household energy sub-sector (both supply and demand side).

The study will result in the development of a strategy for implementing the proposed policy reforms,and in outlining investment and technical assistance programs.

Implementation Armngements

The Ministry of Energy will have the implemenation responsibility. The samplng, interviews,coding of responses, quality control of responses, computerization of responses, and production of results willbe carried out by consultantts and the Central Bure;..i of Stistics. An international household energyexpert(s) will be engaged to asist MOE and CBS m project design, questonnaire design, sampling;enumerator training; repordng; and to cary out the Policy, Instiuonal &ad Pricing Study.

Staffing

Intenmational Experts (household sury specalist ad househol enery specialit)National ExpertsCBSMOE

Anncx 4.7

Page I of I

PROJECTr COMPONENTS B)' FINANCIERS(UJSSmillion)

KenyaEnergy Sector Invfetment ProjectConponens by Finuncimra(USS 000) GOK IDA OECF Pri-te Equity Comn.er.a.I Debt EIB KIW Toal Local (Excl Dules &

Amwnt % Anout % Ameou.t % Amount % Amount % Amount % Amontm % Amoumt For E-ch ianes) tlses

A Sector Restructuring ReformSector Reorgtpmattion 3,2S3 10 100 - - 3283 10 0 5 3,283 10Dercgulation of Petroleum Product -s 343 2 100 - . . . 6 50 6SubtotulSectorRestrucurmgReform - - 3,63130 100 363- - - - - - - u 303 05 3.5S070 506B Insatnut.onal Support 18,48610 751 6,127 10 24 9 . . -. 24613 20 3 5 22143 50 2.469 70C Efficiency ImprovementsDem5A Side Improvememt 0 - 5,369 80 100 - - - - - . 5369 0 0 8 5,28400 85 aLineLotReduction 1425 22 6,30940 978 - - . . , 6,451 90 09 5,49200 9599Subtotal Efficiency Improvement 142 5 1 2 11,679 20 988 11,821 70 1 7 10,776 00 1.045 70D Power Epansmon and RehatiubtuonPocer Generation 93,99360 161 S2,35150 142 82,0740 296 65,62540 113 196.87630 340 36.620 20 63 20,85250 31 S79,12690 827 472.68780 106.43900Upgrading of Distributon Systens 29,943 40 100 - - - - - - - - 29,948 40 4 3 14,974 20 14,974 20Subtotal Pomec E.pamonand Rehtoat,on 123.94210 194 S2,35150 135 82,807 40 285 65,62540 108 196,87630 323 36,62020 60 20.85250 34 609,07530 87 487.662 00 121.41320E eotlhermm1 Resource Dcelopment 17,523 80 35 6 19,709 20 40 - - - 12,053 60 24 5 - - 49.2S6 60 70 44,456 20 4.85040F Future Project Preparation - - 1,503 10 100 1- - - - - 503 10 0 2 1 503 1 -

Total 16borsmeot It0,094.50 21.5 125,001.40 17.9 32,t07.40 25.5 65,625.40 9.4 196,.76.30 9.4 48,673.80 7.0 20,852.50 3.0 69,931,20 IO0 570,121.50 129,809.70

0.41,sJ

Annex 4.8Page 1 of 1

PROJECT COMPONENTS AND EXPENDITURES BY YEAR

(US$ million)KenyaEnergy Sector Reform and Development Project

Totals IncludingContingencies

1997 1998 1999 2000 2001 2002 2003 Total

A. Sector Restructuring ReformSector 1,500.5 891.2 891.4 - - - - 3,283.1ReorganizationDeregulation of Petroleum Markets 348.2 - - 348.2Subtotal Sector Restructuring Reform 1,848.7 891.2 891.4 - 3,631.3B. Institutional Support 12,513.5 5,354.8 1,349.8 1,268.4 3,511.4 615.3 - 24,613.2C. Efficiency ImprovementsDemand Side Improvements 451.3 1,256.9 1,692.2 1,969.4 - - - 5,369.8Line Loss Reduction 12.7 3,910.8 905.3 808.8 814.3 - - 6,451.9Subtotal Efficiency Improvements 463.9 5,167.7 2,597.5 2,778.3 814.3 - - 11,821.7D. Power Expansion and RehabilitationPower Generation 123,517.7 274,009.9 155,174.3 26,425.0 - - - 579,126.9Upgrading of Distribution Systems 11,576.4 6,397.4 2,231.8 4,570.8 5,172.0 - - 29,948.4Subtotal Power Expansion and Rehabilitation 135,094.0 280,407.3 157,406.1 30,995.8 5,172.0 - - 609,075.3E. Geothermal Resource Development 10,551.6 14,648.2 15,475.7 8,611.2 - - - 49,286.6F. Future Project Prepration - - - - 484.2 495.8 523.1 1,503.1Total PROJECTCOSTS 160,471.8 306,469.2 177,720.5 43,653.6 9,981.9 1,111.1 523.1 699,931.2

Fh0.

Annex 5.1FINANCIAL ANALYSIS Page 1 of 9

Konya Povew Company Umit d_.Projected Prndit and Los Statnent_

Actual Actual Projected-Fiscal Year Ending June 30 1*n5 1996 1107 1998 100 200 2001 2002

In Ksh 000 Unless otherwise statdReo"nue I

Bulk sales to KPLC 1,055,673 1,271,322 2,092,200 1,951,983 1,959,406 3,198,953 5,216,974 5,507,031Development Surcharge 2,633,023 2,676,114 1,166,531 2,145,582 1,585,489 584.444 171,830

3,688,696 3,947,436 3,258,731 4,097,565 3,544,895 3,783.397 5,388,804 5,507,031

Opeatng CostbGeneration 132,453 184,000 141,971 153,971 259,228 1,300,879 2,147,083 2,044,794Purchases-imports 205,370 170,609 381,920 400,400 429,542 440,966 452,390 464,576Transmission and Distribution 8,091 9,924 8,899 9,149 9,405 9,668 9,939 10,217Admin salaries and wages 16,082 19,700 21,178 22,766 24,473 26,309 28,282 30.403Other Admin expenses 11,223 58,191 22,677 23,964 26,034 29,075 33,380 39,395Insurance 19,740 20,000 33,788 36,122 86,271 165,588 239,437 234,879Depredabon 106,243 179,229 208,980 227,447 257,531 916,793 1,285,525 1,308,732Total Operating Costs 499,202 641,653 819,413 873,819 1,092,484 2,889,278 4,196,006 4,132,995

Net Operating Income 3,189,494 3,305,783 2,439,318 3,223,746 2,452,411 894,119 1,192,799 1,374,036Interat Chargeable to Operations 98,141 160,717 370,126 304,207 249,841 309,675 1,020,969 1,132,041

Foreign Exchange Losses Chargeable to Operations 96,390 (68,294) (76,654) - 72,180 184,798 421,103 660,586Net Profit for the Year 2,994,963 3,213,360 2,145,847 2,919,539 2,130,390 399,646 (249,273) (418,591)

Performance IndicatorsNat Income Before Int. as % of Sales Revenue 86% 84% 75% 79% 69% 24% 22% 25%Net Income After lnt. as % of Sales Revenue 81% 81% 66% 71% 60% 11%_ -5% -8%

0.* -

FINANCIAL ANALYSIS Annex 5.1Page 2 of 9

Kenya Powur Company Umited I

Projected Balance Sheet Statements

Actual Actual Projected .

Fisca Year Ending June 30 199 1996 1997 1998 1999 2000 2001 2002

In KSh 000 unless otherwi statdFixed AsstsPlant in Sevioe at cost 3,586,337 3.739,154 5,663,420 6,078,780 12,275,104 22,282,501 31,598,365 31,750,621

Accumulated depraecation 1,005,698 1,184,927 1,393,907 1,621,355 1,878,886 2,795,679 4,081,204 5,389,936

Net Boock Value 2,580,639 2,554,227 4,269,513 4,457,425 10,396,219 19,486,821 27,517,161 26,360,685

Work In Progress 3,662,412 3,867,303 8,349,571 18,630,843 21,660,746 16,757,965 9,036.696 9,346,241

Totl Fixed Asets 6,243,051 6,421,530 12,619,084 23,088,268 32,056.964 36,244,786 36,553,857 35,706,926

Cunrent Assebt

Cash - 79.016 1,022,365 1.227,009 1,826,202 2,193,740 2,888.739

KPLC Debt 3,081,985 5,712,490 4,633,137 3,181,641 1,754,756 533,169 869,670 918,022

Otler Debtors 82,500 81,400 83,354 85,354 87,403 89,500 91,648 93,848

Stocks 125,144 96,797 146,611 157,364 317,771 576,836 818,000 821,941

Total Current Assets 3,289,629 5,890,687 4,942,118 4,446,723 3,386,938 3,025,708 3,973,057 4,722,550

Current Liabilies"

Creditor 728,666 938,681 181,868 192,485 241,807 599,938 892,558 862.849

Curent Maturities on Long term debt 657,491 644,319 697,197 624,771 634,716 202,844 418.685 -

Total Current Liablities 1,386,157 1,583,000 879,065 817,256 876,523 802,782 1,311,243 862,849

Net Working Capital 1,903,472 4,307,687 4,063,053 3,629,467 2,510,415 2,222,926 2,661,814 3,859,702

Total Asses 8,146,523 10,729,217 16,682,137 26,717,735 34,567,380 38,467,713 39,215,671 39,566,628

Financed by:

Share capital 152,662 152,662 152,662 152,662 152,662 152,662 152,662 152,662

Reserves 3,344,112 6,557,472 8,703,319 11,622,858 13,753,248 14,152,894 13,903,621 13,485,030

Total Equity 3,496,774 6,710,134 8,855,981 11,775,520 13,905,910 14,305,556 14,056,283 13,637,692

Long Term Debt

Loans 5,307,240 4,663,402 8,523,353 15,566,986 21,296,186 24,365,000 25,578,073 25,928,936

Less Current maturities 657,491 644,319 697,197 624,771 634,716 202,844 418,685 -

4,649,749 4,019,083 7,826,156 14,942,215 20,661,470 24,162,156 25,159,388 25,928,936

Total Financing 8,146,523 10,729,217 16,682,137 26,717,735 34,567,380 38,467,713 39,215,671 39,566,628

Peformance Indicator

DebtVEquity Ratio 60% 41% 49% 57% 60% 63% 65% 66%

Current Ratio 2 4 6 5 4 4 3 5 .'Ch

Annex 5.1FINANCIAL ANALYSIS Page 3. of 9

"an Povwer Company Umftd

Sourn: and Appil4lo of Funds Stltnnt

Actud Ac_al_ Proected.FiscsJ Year Ending June 30 1995 199S 1997 1996 1999 2000 2001 2002

In Ksh 000 unles otherwise st*tb

Funds from Inbnul Oper 'ons

Not Inrome 2.994,964 3,213,360 2,145,847 2.919,539 2,130,390 399,646 (249,273) (418,591)

Items not Involving Movement of Funds _

Foreign Exchange Losses (443,321) (68,294) (76,654) - 388,299 557,948 628,590 683,333

Deprnxiaton 106,243 179,229 208,980 227,447 257,531 916,793 1.285,525 1,308,732

2,657,886 3,324,295 2,278,173 3,146,986 2,776,220 1,874,387 1,664,841 1,573,473

Othr Soures of Funds

Loan Disbursements 336,013 57,853 4,678,121 7,740,831 5,965,672 3,145,583 787,327 86,215

Other

336,013 57,853 4,678,121 7,740,831 5,965,672 3,145,583 787,327 86,215

2,993,899 3,382,148 6,956,294 10,887,817 8,741,892 5,019,970 2,452,168 1,659,688

Appwllcadon of Funds

Loan Amorfization 550,979 633.397 741,516 697,197 624,771 634,716 202,844 418,685

Capitl expenditures (178,854) 357,708 6,406,534 10,696,632 9,226,228 5,104,615 1,594,595 461,801

372,125 991,105 7,148,050 11,393,829 9,850,999 5,739,331 1,797,439 880,486

Not Outflow 2,621,774 2,391,043 (191,756) (506,012) (1,109,107) (719,361) 654,729 779,202

R prntbd by:

Movement in non-Cash Working Capital 2,697,748 2,391,043 (270,773) (1,449,360) (1,313,751) (1,318,554) 287.191 84,203

Movement in Cash Balances (75,849) - 79,016 943,348 204,644 599,193 367,537 694,999

Total Movement in Working Capital 2,621,899 2,391,043 (191,756) (506,012) (1,109,107) (719,361) 654,729 779,202

Performance Indicators

Debt Service Coverage 4.09 4.19 2.05 3.14 3.17 1.98 1.36 1.01

Self-Financing Ratio 0% 75% 20% 24%1 23%, 18% 18% 3%

UA1

0.

FINANCIAL ANALYSIS Annex 5.1Page 4 of 9

Kenya Power and Ughmng Company Umted

Projected Proflt and Loa Statemet

Actual Actual Projected -

Fical year Ended June30 199S 1996 1997 1998 1M99 2000 2001 2002

Kah 000 unles otherwlae statdRennue

Eltridty Sale 12,957,798 14,925,280 16,232,080 18,591,380 20,663,787 22,993,112 25,070,614 28,448,336

Other Revenue 162,321 185,914 206,638 229,931 250,706 284,483

Fuel Clause Adjustment 304,872 1,785.417 2,242,513 2,190,615 2,125,295 1,915,485

12.957,798 14,925,280 16,699,273 20,562,711 23,112,938 25,413,658 27,446,615 30.648,305

Operating Coats

Generton 1,019,593 2,432,915 2,133,403 1,981,824 2,305,327 1,019,302 446,035 447,731Purchased power-KPC 1,055,673 1,271,322 2,092,200 1,951,983 1,959,406 3,226,550 5,155,262 5,886,002

Purchased Power-Turkwell 118,782 595.058 660,760 664,004 681,030 699,221 717,535 737,026Purchased Power-TRDC 3,248,140 2,433,904 2,611,720 2,678,258 2,288,762 1,950,749 1,997,670 1,912,300

Purchased Power-IPPs - - - 3,103,796 3,230,758 4,814,307 4,650,721 6,902.704

Tota cost generated + purchased power 5,442,188 6,733,199 7,498,083 10,379,865 10,465,283 11,710,128 12,967,223 15,885,763

Developmenrt surcharge-KPC 2,633,023 2,676,114 1,166,531 2,145,582 1,585,489 584,444 171,830

development surcharge-TRDC 388,410 868,010 18,688 20,844 23,701 27,572

Total Development Surcharges 2.633,023 2,676,114 1,554,941 3.013,592 1,604,177 605,288 195,531 27,572

REF 259,141 298,515 324,642 371,828 413,276 459,882 501,412 568.967

Transmision and distribution 647,137 860,626 946,689 1,041,357 1,145,493 1,260,043 1.386,047 1,524,651Admin salaries and wages 2,161,731 2,433,995 2,570,299 2,714,235 3,128,768 3,598,471 3,799,986 3,799,986

Insurance 306,669 284,707 300,651 317,487 365,975 420,917 444,488 444,488

Insbtubonal support - 347,848 481,415 585,881 182,232

Depreciation 203,059 335,134 588,463 675,735 770,436 876,994 996,939 1,146,076

Total Operatng Costs 11,652,948 13,970,138 14,265,182 19,099,981 18,075,641 18,931,703 20,291,625 23,397,504

Nat Operating Income 1,304,850 955,142 2,434,091 1,462,730 5,037,296 6,481,955 7,154,990 7,250,801

Net Interest Expenses (268,900) (544,496) 76,790 76,790 76,790 76,790 76,790 270,361

Foreign Exchange Losses 73,948 (15,279) (28,184) - 21,468 15,434 10,157 7,877

Profit Before Taxation 1,499,802 1,514,917 2,385,485 1,385,940 4,939,039 6,389,731 7,068,042 6,972,563

Corporation Tax 9 35% 416,872 396,926 834,920 485,079 1,728,664 2,236,406 2,473,815 2,440,397

Profit After Taxaton 1,082,930 1,117,991 1,550,565 900,861 3,210,375 4,153,325 4,594,227 4,532,166

Dividend on Preference Shares 1,930 1,930 1,930 1,930 1,930 1,930 1,930 1,930

Dividend on Ordinary Shares 35,168 70,336 63,302 63,302 63,302 63,302 63,302 63,302

Retained Profit 1,045,832 1,045,725 1,485,333 835,629 3,145,143 4,088,093 4,528,995 4,466,934

0.Perfornance IndIcatorsNet Income Before Int.& Taxes as % of Sales Revenue+ 10.1% 6.4% 15.0% 7.9% 24.4% 28.2% 28.5% 25.5%

,Profit afterlInterest and Taxes as %of SalesRevenue 8.4%1 7.5%, 9.6%1 4.8%1 15.5% 18.1%1 18.3% 15.9%

FINANCIAL ANALYSIS Anmex 5.1Page 5 of 9

Konya Power and Ughting Company Limited

Balance Sheet

Actual Actual Projected

Fiscal Year Ended June 30 199C 1996 1997 1998 1999 2000 2001 2002

In Ksh 000 unless otherwise stated

Fixed Asset at Cost 6,245,201 6,636,182 8,199,321 9,716,870 11,200,883 12,882,403 14.717,287 17,211,760

Accumulated Depreciation 2,343,182 2,677,835 3,266,298 3,942,033 4,712,470 5,589,463 6,586,402 7,732,478

Net Book Value 3,902.019 3,958,347 4,933,022 5,774,836 6,488,413 7,292,940 8,130,885 9,479,282

Work In Progress 621,320 812,383 843,805 879,893 1,088,007 1,351,809 1,664,713 1,798,837

4,523,339 4,770,730 5,776,828 6,654,730 7,576,420 8,644.749 9,795,598 11,278,120

Investments 4,300 4,300 4,300 4,300 4,300 4,300 4,300 4,300

Deferred Debt 298,056 233,591 175,386 175,386 175,386 175,386 175,386 175,386

Current Asset.

Cash 493,256 374,459 1,633,034 (2,492,294) (2,920,024) (2,961,225) 68,770 1,309,179

Investments 2,882,899 4,097,121 4,097,121 4,097,122 4,097,123 4,097,124 4,097,125 4,097,126

Debtors 4,433,018 5,114,387 2,705,888 3,099,183 3,444,653 3,832,952 4,179,271 4,742,338

Stocks 2,537,327 3,189,427 3,974,769 4,653,058 5,228,021 5,876,266 6,551,438 7,637,905

Total Current Assets 10,346,500 12,775,394 12,410,812 9,357,069 9,849,773 10,845,117 14,896,605 17,786,548

Current LiabilKites

Due to KPC 3,081,985 5,712,490 4,633,137 3,181,641 1,754,756 537,866 859,382 981,197

Due to TRDC 3,229,405 3,053,015 2,725,135 1,972,974 1,144,791 325,190 333,012 318,780

Others 3,529,039 3,152,010 2,474,156 1,686,694 901,531 116,560 119,613 122,862

Tax 230,232 (10,890) 834,920 485,079 1,728,664 2,236,406 2,473,815 2,440,397

Dividends 50,252 113,207 65,232 65,232 65,232 65,232 65,232 65,232

Current Maturities on L-T Debt 332,954 328,582 359,699 307,586 263,177 320,051 247,873

10,453,867 12,348,414 11,092,278 7,699,206 5,858,150 3,601,305 4,098,926 3,928,468

Net Working Capial (107,367) 426,980 1,318,534 1,657,864 3,991,623 7,243,812 10,797,678 13,858,080

Total Assets 4,718,328 5,435,601 7,275,047 8,492,279 11,747,729 16,068,247 20,772,963 25,315,886

Capital and ReservesOrdinary Shares 351,680 351,680 351,680 351,680 351,680 351,680 351,680 351,680

Preference Shares (4%) 36,000 36,000 36,000 36,000 36,000 36,000 36,000 36,000

Preference Shares (7%) 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000

Reserves 2,551,745 3,597,953 5,083,286 5,918,915 9,064,058 13,152,152 17,681,147 22,148,081

Total Share Capital and Reserves 2,946,425 3,992,633 5,477,966 6,313,595 9,458,738 13,546,832 18,075,827 22,542,761

Long-Tern Debt 2,104,857 1,771,550 2,156,780 2,486,269 2,552,166 2,841,463 2,945,004 2,773,120 P

Current Maturities 332,954 328,582 359,699 307,586 263,177 320,051 247,873 03

1,771,903 1,442,968 1,797,081 2,178,683 2,288,989 2,521,412 2,697,132 2,773,120 lbTotal Financing 4,718,328 5,435,601 7,275,047 8,492,278 11,747,727 16,068,244 20,772,959 25,315,881 sn

Performance Indicators 0.DebVEquity ratio 42% 31% 28% 28% 21% 17% 14% 11%

Current ratio 0.99 1 03 1.12 1.22 1.68 3.01 3.63 4.53

Annex 5.1FINANCIAL ANALYSIS Page 6 of 9

K*nya Powe nd Ughtng Company

Sta"nnt of Sources and Application of Fund

Actual Actual Projected

Ficl Year Ended June 30 1S96 1996 1997 1998 199 2000 2001 2002

In Ksh 000 unles oathewae sbtatd

Funda fom Innal OperatonaNet Incom 1.499,802 1,514,917 2,385.485 1,385,940 4,939.039 6,389,731 7,068,042 6,972,563

Adjuant for itrna not Invoving Movemnent of Funds

Depecdation 203,059 335,134 588,463 675,735 770,436 876,994 996,939 1,146,076

Foreign Exchange Loases 73,948 (15,279) (28,184) - 21,468 15,434 10,157 7,877

1,776,809 1,834,772 2,945,764 2,061,675 5,730,943 7,282.158 8,075.138 8,126,516

Ohr Soure, of FundsLoan Disburaements - 799,920 689,188 314,111 488,097 354,125

Deferred debt 80,627 64,465 58,205 - - -

Foreign Exchange Losses - - 37,905 48,943 59,310 68,111

Other 665 6,085 -

Total Sources 1,858,101 1,905,322 3,803,889 2,750,863 6,082,958 7,819,199 8,488,573 8,194,627

Appic aton of Funds

Loan Amorfization 407,510 356,417 386,506 359,699 307,586 263,177 320,051 247,873

Capital Expenditures 979,782 588,608 1,594,561 1,553,637 1,692,127 1.945,322 2,147,788 2,628,597

Taxation Paid 396,926 834,920 485,079 1,728.664 2,236.406 2,473,815 2,440,397

Dividends Paid 72,266 65.232 65,232 65,232 65,232 65,232 65,232

1,387,292 1.414,217 2,881,219 2,463,647 3,793,609 4,510,137 5,006,886 5,382,099

Nat Outiowllnflow 470,809 491,105 922,671 287,216 2,289,349 3,309,062 3,481,687 2,812,528

Movement in non-Cash Working Capital 232,405 609,902 (335,904) 4,412,544 2,717,080 3,350,263 451.692 1,572,119

Movement in Cash balances 238,404 (118,797) 1,258,575 (4,125,328) (427,730) (41,201) 3,029,996 1,240,409

Total Movement in Working Capital 470,809 491,105 922,671 287,216 2,289,349 3,309,062 3,481,687 2,812,528

Parfonnanca IndIcatorDebt Service Coverage 13 (10) 6 5 15 21 20 16

Saf-Financing Ratio 52% 46% 22% 11% 34% 40% 38% 53%

0%

Pt I

0.'h_

Annex 5.1FINANCIAL ANALYSIS Page 7 of 9

Tans River Development Company Llmited .

Projected Profit and Lose Sttments

Actual Actual Projected

Flbcal Years nded June 30 1996 1996 1997 1998 1999 2000 2001 2002

Kah 000 unles otherwiea stabd

Revenue

Bulk sales to KPLC 3,312,140 2,433.904 2,611,720 2,678,258 2,288,762 1,950,749 1,997,670 1,912,300

Development Surcharge . 388,410 868.010 18,668 20,844 23,701 27,572

3,312,140 2,433,904 3,000,130 3,546,268 2,307,430 1,971,593 2,021,371 1,939,872

Ope,abng Costs

generation 94,716 220,370 231,980 244,224 257,134 270,750 285.109 300,253

transmission & distribution expenses 4,123 5.005 5,285 5,581 5.894 6.224 6,572 6,940

admin salaries and wages 23,946 31,500 33,264 35,127 37,094 39,171 41,365 43,681

Other Admin expenses & insurance 117,097 145,663 153,820 162,434 171,530 181,136 191,280 201,991

Masinga Debt ServiCe 47,956 47,956 49,729 48,795 47,860 46,926 45,991 45,057

Kiambere Debt ServiCe 2,331,969 1,171,860 1,297,966 1,451 ,798 1,289.284 1,267,738 1,244,266 1,218,777

Deprciation 43, 104 35,550 36,089 86,425 88,292 90,377 92,747 95,504

Total Operating Costs 2,662,911 1,657,904 1,808,134 2,034,384 1,897,089 1,902,322 1,907,329 1,912,204

Net Operating Income 649,229 776,000 1,191,995 1,511,884 410,341 69,272 114,041 27,668

IntereSt Chargeable to Opeations 188,124 1 52,337 132,338 81,452 39,861 18.795 7,414 96

Foreign Exchange LOsses Chargeable to Operations 214,809 (107,245) (27,408) - 11,516 5,670 2,180 29

Net Profit for the Year 246,296 730,908 1,087,065 1,430,432 358,965 44,807 104,448 27,543

Check Net profit=Depn-debt Service+Dev surch+ Forex var. 1,087,065 1,430,432 358,965 44,807 104,448 27,543

Perfromance Ratios _

Net income Before Interest as % of Revenues 20% 32% 40% 43% 18% 4% 6% 1%

Net inComeAfter Interest aS % of Revenues 7% 30% 36% 40% 16% 2% 5% 1%

O0.

Annex 5.1FINANCIAL ANALYSIS Page 8 of 9

Tsna River Development Company Limited

Projected Balance Sheet Statmet

Fiscal Years Eneded June 30 Actual Actual Projected

19E 1996 1"7 1M99 19m 2000 2001 2002_________ iKah 000 unless otherwise d

Fixed A"ets

Plant in Service d cost 1,677,999 1,881,995 1,698,495 2.931,155 2,949,823 2,970,867 2,994,368 3,021,940Accumulated depreciation 714,954 750,504 786,593 873,019 961,311 1.051,688 1,144,434 1,239,938Net Book Value 963,045 931,491 911,902 2,058,136 1,988,512 1,918,980 1,849,934 1,782,002Work In Progress 713 912 387,815 23,671 24,743 25,869 27,009 28,203Total Fbied Assets 963,758 932,403 1,299,717 2,081,807 2.013,256 1,944,849 1,876,943 1,810,205

Current AssetCash 157 7 68.039 564,523 626,735 670,206 (126,836) (35,986)KPLC Debt 3,229,405 3,053,015 2,725,135 1,972,974 1,144,791 325,190 333,012 318,780Other Debtors 11,306 17,200 35.890 37.900 40,023 42,264 44,631 47,130Stocks 98,151 60,544 109,278 115,398 121,860 128.684 135,890 143,500Total Current Assets 3,339,019 3,130,766 2,938,342 2,690,794 1,933,408 1,166,344 386,697 473,425

Current Liabilities

Creditors 3,315,832 3,106,568 2,774,799 2,446,305 1,649,571 864,237 77,716 71,674Current Maturities on Long term debt 669,521 400,312 567,395 400,244 101,215 168,259 2,180 -

Total Current Liabilities 3,985,353 3,506,880 3,342,194 2,846,549 1,750,786 1,032,496 79,896 71,674Net Working Capital (646,334) (376,114) (403,852) (155,755) 182.623 133,847 306,801 401,751Total Assets 317,424 556,289 895,865 1,926,053 2,195,878 2,078,697 2,183,744 2,211,956

Financed by: _Share capital 120,002 120,002 120,002 120,002 120,002 120,002 120,002 120,002Remrves (1,716,642) (985,734) 101,331 1,531,762 1,890,727 1,935,534 2,039,982 2,067,524Totel Equity (1,596,640) (865,732) 221,333 1,651,764 2,010,729 2,055,536 2,159,984 2,187,526

Long Term Debt _

Loans 2,583,585 1,822,333 1,241,927 674,532 286,364 191,419 25,940 24,429Leu Current maturities 669,521 400,312 567,395 400,244 101,215 168,259 2,180 -

1,914,064 1,422,021 674,532 274,288 185,149 23,160 23,760 24,429Total Financing 317,424 556,289 895,865 1,926,053 2,195,878 2,078,697 2,183,744 2,211,956

Performance Ratios C0Debt as a % of Total Capital 262% 191% 85% 29% 12% 9% 1% 1% OCurrent Ratio 0.84 0.89 0.9 0.9 1.1 1.1 4.8 6.6

Annex 5.1FINANCIAL ANALYSIS Page 9 of 9

Tun River Deopmet Company Umited

Sourcee and Application of Funds ttntActual Acbtal Projected

Fiscal Yea Ended June30 1S6 1996 117 1ns 1999 2000 2001 2002

Koh 000 unhes otherwIs atated

Funds from internal Operations

Not Income 246,297 730,908 1,087,065 1,430,432 358,965 44,807 104,448 27,543

Items not lnvoMng Movemnent of Funds

Foreign Exchange Loses 214,809 (107.245) (27,408) - 11,516 5,670 2,180 29

Depreciation 43,104 35,550 36,089 86,425 88,292 90,377 92,747 95,504

504.210 659,213 1,095,746 1,516,857 458,773 140,854 199,374 123,076

Other Sources of Funds

Loan Disbursement - 22,000 - - - - -

Foreign Exchange Losse - 560 600 600 640

- 22,000 560 600 600 640

504,21 0 659,213 1,117,746 1.516,857 459,333 141,454 199,974 123,716

Application of Funds

Loan Amorfization 501,893 654,007 574,998 567,395 400,244 101,215 188.259 2,180

Capital expenditures 1,468 4,195 403,403 868,516 19,741 21,970 24,840 28,766

503,361 658,202 978,401 1,435.911 419,985 123,185 193,099 30,948

Net Ouflow 849 1,011 139,345 80,946 39,348 18,269 6,875 92.770

Represnted by:

Movement in non-Cash Working Capital 1,359 - 71,313 (415,537) (22,864) (25,201) 803,916 1,920

Movement in Cash Balances (510) 1,011 68,032 496,483 62,213 43,470 (797,042) 90,850

Total Movement in Workig Capital 849 1,011 139,345 80,946 39,348 18,269 6,875 92,770

Perfomance Ratios

Debt Service Coverage 0.7 0.8 1.5 2.3 1.0 1.2 1.1 54.1

Self-Financing 0% -18% 15% 49% 22% 22% 22% 210%

0. Ul

40

Annex 6.1Page I of 4

KENYA

Energy Sector Reform and Power Development ProjectProject Implementation Planl

Table of Contents

Page No.INTRODUCTION .............................................................. ix

Summary of Project Objectives .............................................................. ix

Summary of Projects Description and Components ............................................................... x

SECTION I ................................................................1.0 Energy Sector Policy Framework .I1.1 Policy Objectives for the Energy Sector .1.2 Sector Restructuring .11.3 Least Coast Investment Planning .21.4 Energy Pricing ....................... I...................1.5 Energy Efficiency.31.6 Rural Energy Supply and New and Renewable Energy .4

SECTION 2 ........ 52.0 Detailed Project Description .52.1 Project Objectives ....................... : 52.2 Project Cost Estimates.52.3 Project Scope and Description .122.3.1 Sector Restructuring and Reform .122.3.1.1 Legal and Regulatory Reform .122.3. 1.2 Promotion of Private Sector Participation .132.3.2 Efficiency Improvements .132.3.2.1 Demand Side Management Improvements .132.3.2.2 Industrial Energy Management .142.3.2.3 Energy Efficiency Standards for Electric Equipment .142.3.3 Power System Expansion and Upgrading .142.3.4 Kipevu I and II Medium Speed Diesel Electric Power Plants .142.3.5 Olkaria II 2 x 32 MW Geothermal Power Station .142.3.6 Olkaria III 2 x 32 MW Geothermal Power Station .152.3.7 Distribution Reinforcement and Loss Reduction Program .152.3.8 Distribution Reinforcement Subcomponent .152.3.9 Power Loss Reduction .162.3.10 Development of Indigenous Resources .172.3.10.1 I Make-up Wells Connection .182.3.10.2 Geothermal Resource Assessment Program .182.3.10.3 Relocation of X-2 Camp. 19

PIP will be revised to exclude the petroleum subsector components which have been delinked from the project, andthe Nairobi-Mombasa and Nairobi-Kiambere 220 kv transmission lines for which funding has not yet been secured.

Annex 6.1Page 2 of 4

2.3.10.4 Household Energy Strategy ......................................................... 192.3.10.5 Solar Photovoltaic Standardization Study and Information and Dissemination ................................................... 192.3.10.6 LPG Cylinder Standardization Study ......................................................... 192.4 Project Financing Plan ............. ,,262.5 Major Loan Covenants/Target Dates ......................... 322.6 Detailed Financial and Economic Analysis of the Project ......................... 322.6.1 Economic Analysis of Projects for KPLC/KPC ........................... 322.6.1.8 Risk Analysis of Power Sub-sector Components ......................... 38

SECTION 3..473.0 Projection Organization and Management ............................................................ 473.1 Organization Structure ............................................................ 473.2 Project Management Arrangement ......................................................... 483.3 Management of Various Components of the Energy Sector Investment Project ................................................. 483.3.1 Energy Sector Policy Reform Studies ......................................................... 503.3.2 Efficiency Improvements ......................................................... 513.3.3 Power System Expansion and Upgrading ......................................................... 513.3.4 Development of Indigenous Resources of Energy ......................................................... 53

SECTION 4.564.0 Project Plan and Implementation .564.1 Consolidated Project Implementation Schedule Summary .564.2 Implementation Schedule for each component .564.3 Implementation, Supervision and Control .56

SECTION 5..575.0 Procurement ........ ........................................................................ 575.1 IDA Procurement Guidelines ................................................................................ 575.2 GOK Procurement Guidelines for Goods, Equipment and Services .................................... ............................... 575.3 KPLC Procurement Guidelines ................................................................................ 575.4 Procurement Guidelines for Goods, Equipment and Services for OECF, EIB, etc .............................................. 575.5 Summary of Disbursement Procedures of IDA ................................................................................ 575.6 Disbursement Procedures for OECF, EIB, GOK, KPLC, KPC .575.7 Accounting and Auditing Procedures for IDA ............................................................ 575.8 Accounting and Auditing Procedures for OECF, EIB, GOK, KPLC, KPC ....................................... ................. 575.9 Procurement Methods, Procurement Processes and Expected Time Lapse ......................................................... 575.10 Procurement Processing, Disbursement Procedures, and Accounting and Auditing ...................... ..................... 57

SECTION 6 .......... 586.0 Financial Management ................................................................................ 586.1 Schedule of Disbursements for each Component ................................................................................ 586.1.2 Economic Analysis and Disbursement Schedule of Project Components Implemented by KPC AND KPLC ... 606.2 Funds Flow Chart ................................................................................ 626.3 Work Certificates and Payment Procedures ................................................................................ 626.4 Financial Statements and Reports ................................................................................ 626.5 Audits ................................................................................ 62

SECTION 7..637.0 Monitoring and Reporting .637.1 Key Development Impact Indicators for measuring Progress in Reaching Project Objectives .637.2 Key Indicators for Monitoring Progress in the Physical Implementation of the Project. 637.3 Key Financial Indicators to assess the Project Budgetary and Financial Health .................................................. 63

Annex 6.1Page 3 of 4

7.4 Monitoring and Evaluation ......................................................................... 637.5 Reporting Routines ......................................................................... 637.5.1 Filing Index/Filing/Library ......................................................................... 637.5.2 Protocol for Communication and Copy Distribution . ......................................................................... 637.5.3 Computers and System Management and Operation ............................... .......................................... 637.6 Implementation Completion ......................................................................... 65

SECTION 8.658.0 Environmental Mitigation Plan and Monitoring Arrangements ............................................. 658.1 Environmental Mitigation Plan for KPLC and KPC ............................................. 658.1. I North East Olkaria 2x32 MW Power Development Project ............................................. 658.1.2 Mombasa Diesel Generating Power Plant Project ............................................. 678.2 Environmental Mitigation and Monitoring Arrangement ............................................. 708.2.1 Mitigation and Monitoring Arrangements for KPC and KPLC ............................................. 708.3 Implementation Guidelines ............................................. 718.3.1.1 North East Olkaria 11, 2x32 MW Power Development Project ............................................. 718.3.1.2 Mombasa Diesel Generating Power Plant Project ............................................. 728.3.2 Environmental Guidelines for KPLC and KPC ............................................. 728.3.2.1 North East Olkaria 2x32 MW Power Development Project ............................................. 728.3.2.2 Mombasa Diesel Generating Power Plant Project ............................................. 73

SECTION 9 ....... 789.1 Policy Reform Items, Schedules and Budgets ......................................................................... 789.1.1 Terms of Reference for Study to Update the Electricity Tariff Study Completed in November 1993 ......... ....... 789.2 Institutional Support Items, Schedules and Budgets ......................................................................... 829.2.1 Institutional Strengthening Items for MOE ......................................................................... 829.2.2 Institutional Strengthening Items for KPLC and KPC ................................... ...................................... 89

SECTION 10 ........................................ 107

Capacity Building..10710.0 Human Resource Development (HRD) .10710.1 Transfer of Expertise Guidelines for Power Sub-sector .10710.2 PowerrSub-sector.107

APPENDIX I..I.IDA Procurement Guidelines .. 111A. Use of Consultants by World Bank Borrowers and by World Bank as Executing Agency .111B. Procurement Under IBRD Loans and Credits .114

APPENDIX II .118Government of Kenya Procurement Guidelines for Goods, Equipment and Services .118

APPENDIX III .126KPLC Procurement Guidelines.126

APPENDIX IV.131Procurement Guidelines for Goods, Equipment and Services .131

APPENDIXV V132Summary of Disbursement Procedures for IDA/IBRD .13

APPENDIXVI . ....... I...........144Disbursement Procedures .144

Annex 6.1Page 4 of 4

APPENDIX Vll .................................... 4................................................ 145Accounting and Auditing Procedures for IDA/IBRD .................. 145

APPENDIX Vill ................... 146Accounting and Auditing Procedures .................. 146

Annex 6.2Page 1 of 1

Res

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Annex 6.3Page I of 2

KENYA

IDA-Financed Civil Works

Est'd #. of Description Estimated IDA ProcurementPackages Cost (US$) Funding Method

I Olkaria 11 Power Plant-Civil Works 50,600,000 26,800,000 ICB5 Civil Works for Substations under the Line Loss 950,200 807,300 NCB

Reduction SubcomponentTotal 51,550,200 27,607,300

IDA-Financed GoodsEst'd #. of Description Estimated IDA ProcurementPackages Cost (US$) Funding Method

IDA-Financed GoodsI Olkaria 11 Power Plant-Electromechanical Equipment 51, 376,800 41,615,200 ICB

for 64 MWEquipment for demand Side Management1 4,418,800 4,418,800 ICB

2 Equipment for Line Loss Reduction 5,449,300 5,449,300 ICB2 Connection of make-up wells for Olkaria 1 1,188,400 713,000 [CB2 Office Equipment for MoE's Implementation Support 80,300 80,300 Sh2

GroupI Household Energy Strategy 11,200 11,200 Sh2 Motor Vehicles for Geothermal Resource Assessment 138,000 138,000 Sh2 Drilling consumables for geothermal wells 4,899,300 4,899,300 ICB2 Spare parts for drilling operations 261,700 261,700 ICB2 Spare parts for drilling operations 200,000 200,000 NCB2 Geothertnal drilling equipment 4,136,100 4,136,000 ICB

Total 72,159,900 61,923,600

List of EDA-Financed Studies3Title Estimated Status

mmPower Sector Organization Study-phase 1 20 completed under PPFLegal and Regulatory Framework 15 completed under PPFPetroleum Market Structure and Pricing 18 completed under PPFStudy on Financing Mechanisms for Energy Efficiency 15MeasuresFeasibility Studies and Detailed Design for Olkaria IV 185Prefeasibility Studies for Olkaria Domes/Suswa/Longonot 185Line Loss Reduction 20LPG Clynder Standard Study 10Solar PV and Standard Study 5Preparation of Future Studies 100Total 553

1 To be determined on the basis of the results of demand management programs to be designed by KPLC with theassistance of consultants.

2 Sh = shopping procedures, procurement to be carried out in packages of less than USS50,000.

3 Consultants services for studies will be procured in accordance with the Bank's Guidelines for selection ofConsultants, which generally require shortlisting of prospective firns.

Annex 6.3Page 2 of 2

Listed of IDA-Financed Consultants Service4

Title Estimated Statusmm

Demand Side Management Programs 20Distribution Systems Adviser 3Engineering Contract for Olkaria It Power Plant 920Drilling Services for connection of make-up wells for Olkaria 45

Procurement Services for connection of make up wells for 6Olkaria IDrilling by KPC with own rig 35Engineering Adviser to KPC CPDM 80Financial Adviser to KPC CPDM 80Engineering Adviser to MoE's Implementation Support 80GroupFinancial Adviser to MoE's Implementation Support Group 70Policy Adviser to MoE 48 Ongoing under PPFHousehold Energy Strategy 14Private Sector Participation 40 Ongoing under PPFImplementation Support for Sector Restructuring and Reform 135Support on Petroleum sub-sector deregulation 2 Ongoing under PPFProcurement of drilling services 35Geothermal Advisory Board 50Total 1663

4 Consultants services will be procured in accordance with the Bank's Guidelines for selection of Consultants, whichgenerally require shortlisting of prospective firms.

Annex 6.4Page I of I

KENYAEstimated Schedule of Disbursements

(US$ millions)

Cumulative StandardDisbursement Disbursement Cumulative (%) Disbursement

Fiscal Year Ending (US$ Million) (US$ Million) Disbursement Cumulative %

Fiscal Year 1997/98December 31 3.5 3.5 2.0 0%June 30 10.0 13.5 11.0 6%

Fiscal Year 1998/99December 31 15.0 28.5 23.0 14%June 30 17.0 45.5 36.0 22%

Fiscal Year 1999/2000December 31 20.0 65.5 52.0 34%June 30 17.3 82.8 66.0 42%

Fiscal Year 2000/2001December 31 17.3 100.1 80.0 50%June 30 9.5 109.6 88.0 62%

Fiscal Year 2001/2002December 31 9.5 119.1 95.0 74%June 30 1.4 120.5 96.0 82%

Fiscal Year 2002/2003

December 31 1.2 121.7 97.0 90%June 30 1.2 122.9 98.0 98%

Fiscal Year 2003/2004

December 31 1.1 124.0 99.0 99%June 30 0.5 125.0 100.0 100%

100 . _ _ _ _ _ _ __''_ _ _ _

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Annex 6.5Page 1 of 2

KENYA

Implementation Support Plan and Staff Input

1. The Borrower's supervision activities would be carried out by the Ministry of Energy (MOE), Kenya Power and LightingCompany (KPLC), and Kenya Power Company (KPC). Their supervisory functions would involve the following:

(a) initial review, recording and forwarding of:(i) all procurement orders(ii) all disbursement requests(iii) special accounts expenditures/reimbursements

(b) preparation of an annual project implementation budget(c) preparation of bidding and other project contract documents(d) preparation of monthly financial statements(e) preparation of semi-annual progress reports to IDA in December and June of each year on all aspects of project

implementation(f) preparation of annual project accounts(g) monitor key performance indicators and environmental mitigation plans(h) arranging for the annual audits of project accounts and SOEs(i) liaising with all Bank supervision missions

2. In addition to the regular implementation support missions to be carried out by IDA in accordance with the schedule set outbelow, IDA staff would spend time on dealing with correspondence, reviewing and commenting on procurement documents,disbursement requests, half-yearly reports and audited accounts. The amount of time estimated is as follows:

HQ Time Field Time Total TimeProject Year 1 8 sws 36 sws 44 swsProject Year 2 8 sws 36 sws 44 swsProject Year 3 7 sws 39 sws 39 swsProject Year 4 7 sws 27 sws 34 swsProject Year 5 5 sws 27 sws 32 swsProject Year 6 5 sws 27 sws 32 swsProject Year 6 5 sws 27 sws 32 swsProject Year 7 5 sws 27 sws 32 sws

3. Mid-term Review by the Borrower and IDA would be held not later than June 30, 2000. The terms of reference andbackground papers for the review would be prepared by the Ministry of Energy and the implementing agencies with IDA staffassistance as may be necessary. The principal objective of the implementation review would be to examine the status ofimplementation of the project, determine any required changes in design and implementation arrangements needed to ensureachievement of the project's development objectives. Specifically, the review meetings will focus on the status of progress in: (i)adjustment of tariffs towards LRMC; (ii) attracting private sector participation; (iii) restructuring of organization of the powersubsector; and (iv) the operation of the Electricity Regulatory Board.

Annex 6.5Page 2 of 2

BANK IMPLEMENTATION SUPPORT INPUT (STAFF WEEKS) INTO KEY ACTIVITIES

Fiscal Year Approximate Date Activity Expected SkiHs Staff InputFY1997/98 November 1997 Implementation Support Mission Sr. Financial Analyst 18.0

Power EngineerEnergy EconomistOperations AnalystSector Restructuring Expest

March 1998 Implementation Support Mission Sr. Financial Analyst 18.0Power EngineerEnergy EconomistOperations AnalystEnvironmental Specialist

FY1998/99 November 1998 Implementation Support Mission Sr. Financial Analyst 18.0Power EngineerEnergy EconomistOperations AnalystEnvironmental Specialist

March 1999 Implementation Support Mission Sr. Financial Analyst 18.0Power EngineerEnergy EconomistOperations AnalystEnvironmental SpecialistProcurement Specialist

FY1999/00 October 1999 Implementation Support Mission Sr. Financial Analyst 15.0Power EngineerEnergy EconomistOperations AnalystEnvironmental Specialist

June 30, 2000 Mid-Term Review Sr. Financial Analyst 24.0Power EngineerEnergy EconomistOperations AnalystEnvironmental SpecialistProcurement Specialist

FY2000/01 October 2000 Implementation Support Mission Sr. Financial Analyst 15.0Power EngineerEnergy EconomistOperations Analyst

._________________ _ Environmental SpecialistMarch 2001 Implementation Support Mission Sr. Financial Analyst 12.0

Power EngineerEnergy EconomistEnvironmental Specialist

FY2001/02 October 2001 Implementation Support Mission Sr. Financial Analyst 15.0Power EngineerEnergy EconomistOperations AnalystEnvironmental Specialist

March 2002 Implementation Support Mission Sr. Financial Analyst 12.0Power EngineerEnergy EconomistEnvironmental Specialist

FY2002/03 October 2002 Implementation Support Mission Sr. Financial Analyst 15.0Power EngineerEnergy EconomistOperations Analyst

l__________________________ Envirommental SpecialistMarch 2003 Implementation Support Mission Sr. Financial Analyst 12.0

Power EngineerEnergy EconomistEnvirommental Specialist

FY2003/04 October 2003 Implementation Support Mission Sr. Financial Analyst 12.0Power EngineerEnergy EconomistEnvironmental Specialist

March 2004 Preparation Work for Implementation Sr. Financial Analyst 15.0Completion Report Power Engineer

Energy EconomistOperations AnalystEnvironmental Specialist

Annex 7.1Page 1 of 1

KENYA

Least-Cost Generation Expansion Plan

Fiscal Year Generation Additions Net Installed Critical WeightedCapacity LOLE EUE

l____________ ____________ ___________ (M W ) (d/yr) (GW -h)Hydro Geothermal LS Diesel MS Diesel

1993 - 1994 747 365 191

1994- 1995 747 357 273

1995 -1996 747 365 307

1996 -1997 747 365 438

1997 -1998 6 x 12.5 809 365 250

1998 -1999 2 x 30.7 1 x 50 6 x 12.5 995 4.4 0.5

1999 - 2000 2 x 30 1032 5.5 0.7Sondu Miriu

2000 - 2001 2 x3/07 1094 1.7 0.1

2001 - 2002 2 x 45 1150 1.0 0.4Ewaso A

2002 - 2003 2 x 18 + 2 x 27 2 x 30.7 1297 0.02 0.0Ewaso B

2003 - 2004 1 x 50 1347 0.03 0.0

2004 - 2005 2 x 30.7 1409 0.05 0.0

2005 - 2006 1409 0.4 0.4

2006 - 2007 2 x 30.7 1470 0.6 0.5

2007 - 2008 2 x 50 1539 0.8 0.7

2008-2009 2x30.7 1601 1.3 1.4

2009-2010 1x50 1651 3.2 4.7

2010-2011 2 x 30.7 1 x 50 1762 2.5 3.1

2011 - 2012 1 x50 1812 5.8 9.0

2012 - 2013 2 x 50 1912 6.5 10.5

TOTAL 240 MW 430 MW 450 MW 150 MW

NOTE: Unit deratings and retirements are not shown in the above table.

SOURCE: KPLC andAcres International

Annex 7.2KENYA Page 1 of 3

Energy Sector Reform and Power Development ProjectEconomic Analysis

Year |lectricity Sales |Benef"ts Investment Cost 0 8 M Cost |Fuel Cost |Net Benefits

I iththe Without the Incremental lIncremental Withthe With the Without the Incrermental With the Withoutthe Ilncremental Total Project Total Project Net

Project Sales Benefts Project PProject Project O&M cost Project Project fuel cost Costs Benefts IBenefts|GWh |GWh GWh E USS million USS million USS million USS million USS million USS million 1USS million US$ million USS million US$ million USS million

1997 2,948 2,948 0J 0 165 0 0 0 20 20 0 165 0: -165

1998 3,3401 3,330 10 1 314 1 -3121999 3,401 3,369 32 5 250 12 70 i 5 17 18 -1 255j 5 -2502000 4,124 3,453 671 94 112 28 7 21 28 17 11 144 94 -50

2001 4,346 3,486 8601 120 54 32 7 25 17, 18i -1 78I 120 422002 4 ,579 3,400 1,1801 165 0 33, 7 26 19 161 3 30j 165 135

2003 4,850 3,373 1,477 207 0 35 5 30 141 12 2 321 207 175

2004 5,143 3,389 1,7541 245 0 39, 5j 34 17 13; 5 39' 2451 2072005 5,002 2,816 2,186 306 0 45 5 40 29' 13 16 55 306' 251

2006 5,020' 2 817 2,203I 308 0 45 5 40 30 13 17 571 3081 2512007 50321 2,842 2,190 307 0 45 5 40 33 13! 20 601 3071 2462008 4,860i 2,656 2,205 309 0 43 _ 3 40 - 37- 0 37 77 309 232

2009 4,853; 2,656 2,197 308 0 43 3 - 40 38 0 38 78' 3081 229

2010 4,855 2,656 2,200 308 0 43 3 - 40 39 0 39 791 308 229

2011 4,8481 2,656 2,192 307 0 43 3 40 27 0 27 67i 3071 2402012 4,837 2,656 21811 305 0 43 _ _3 40 27 0, 27 67t 305 238

2013 4,830 2,656 2,175 304 0 43 _ 3 40 27 0 27 671 304 237

2014 4,820 2,6561 2,1641 303- - 43 3- - 40 27 0 27 671 303i 236

2015 4,821 2,656 2,166l 303 0 43 - 3 40 27 0 27 67 3031 2362016 4,811 2,656 2,155 302 0 . 43 3 40 27 0 27 671 302 235

2017 4,797 2,656 2,142 300 0 . 43 3 40 27 0 27 67 300 2332018 4,7891 2,656 2,134 299 0 43 3 40 27 0 27 671 299 232

2019 4,7781 2,656 2,123 297 11 43t 3 40 27 0 27 78! 297i 219

2020 4,770j 2,656 2,1141 296 22 43- 3 40 27 - 0 27 891 296 207Residual value -380 - r -380 01 380

= * I_________ = ..1 . . ll -

PV of costs @12% discount: $926 ..PV of benefits @ 12% discount: $1,269 j .

Net senefts 12Y. discount $343

Rate of Retum: 17.327.6 . I I . . I _ _ _ _ _ _ P_ lb

1/ Eledricity salesan th the projed indude the output of the Sondu Miriu hydro plant, whid is financed outside of the project2V Investment and O&M costs include in addition to project costs the Sondu Miriu hydro plant and required transmission and distribution. I31 ,BenefltsvaluedatUScents14perkWh. I I L

Annex 7.2Page 2 of 3

KENYAEnergy Sector Reform and Power Development Project

Economic AnalysisAssumptions

A. Benefits

Incremental Electricity Sales The benefits from incremental electricity sales are defined as the differencebetween the demand which the system can satisfy with the proposed investments and that it can satisfywithout the proposed investments. It is assumed that these benefits will increase as demand rises, until2013 when they will reach a plateau at the maximum generation capability of the new generation facilities.Thereafter, the benefits will remain constant through 2020, the remaining economic life of the diesel andgeothermal facilities. The analysis has taken account of the longer economic life of the hydro plant and thetransmission and distribution facilities through residual values. For the valuation of incremental sales inGWh, the analysis used a rate of US 14 cents per kWh, which is the estimated average consumers'willingness to pay for electricity.

Estimation of Consumer Surplus and Consumers' Willingness-to-Pay for Electricity The analysisestimated the consumer's willingness-to-pay (WTP) for electricity using estimated demand functions fordifferent consumer categories. The demand functions are defined by two points: The "lower" end of thedemand functions is represented the price-quantity pair denoting the quantity of electricity consumed atKPLC's marginal tariff rates for different consumers. The "upper" end of the demand functions is definedas the upper end of the function representing consumers willingness to pay for higher valued uses ofelectricity (such as lighting); this point is represented by the price-quantity pair of alternative energysources to KPLC provided electricity, in kWh equivalents. For households and small commercialconsumers the alternative is generally kerosene for lighting. Survey data on households' keroseneconsumption and fuel price data were used to establish the kWh consumption that would yield theequivalent amount of lighting prior to the availability of electricity; and to convert the cost of kerosenelighting to an equivalent cost per kWh. For industries the alternative is captive diesel generators and dataon equipment, maintenance and fuel costs were used to estimate the kWh equivalent costs. The averagewillingness to pay by consumer category is calculated as the average of the costs associated with the lowerand upper ends of the estimated demand function. The detailed calculations in Annex 7.3 show that theaverage WTP, in mid- 1995, ranged from US cents 13 per kWh to US cents 18 per kWh. As of October1996, KPLC's marginal tariff rates vary from 2.5 to 10.5 US cents per kWh. KPLC's average tariff is UScents 9.1 per kWh. This implies an average consumer surplus of about 4.9 US cents per kWh.

Fuel Cost Savings These savings accrue from the improved efficiency of the new diesel plants, and thesubstitution of gas oil and kerosene for lower cost fuel oil, that will cut the average cost of fuel per kWh.

B. Economic Costs

General All costs are incremental as compared to the "without the project" case, in which none of theinvestments would have been made. They are expressed in mid-1995 prices net of taxes and duties.Investment costs include on average about 6 percent physical contingencies. The local currencycomponent, which is wages to skilled and semi-skilled labor and materials, is about 24 percent of totalinvestment cost. The analysis used a general conversion factor 0.9 used to convert the local costs frommarket prices to economic prices.

Capital Costs of New Electricity Generating Units The unit cost for thermal generating facilities per kWof installed capacity are as follows: Hydro: US$ 2,240; medium-speed diesel units: US$ 1,100; andgeothermal plants: $2,200-2,300.

Annex 7.2Page 3 of 3

Fuel Costs The analysis uses border parity prices to define the economic cost of fuel used in powergeneration. The forecast border parity prices are derived from the World Bank's forecast of crude oilprices, as of August 1996, taking account of refining margins, freight, insurance, handling, and transportto project site. The World Bank forecasts a declining trend in real crude oil prices.

Annual Operating and Maintenance Costs

Hydro plant: 1.5% of investment cost Existing Geothermal plant:158 per kWhNew diesel plant fixed: $20 per kW New Geothermal plant: $57 per kWhNew diesel plant variable: $0.0105 per kWh Existing steam plant fixed: $37-44 per kWExisting steam plant variable: $0.0038-0.0044/kWh Existing gas turbine fixed: $17-25 per kWExisting gas turbine variable: $0.0081-0.0088/kWhTransmission: 2% of cumulative investment costDistribution: 3.5% of cumulative investment costIncremental consumer cost (billing etc.): $0.003 per kWh

C. Economic Life of Facilities

Hydro plants: 50 yearsLow speed diesel generating units: 25 yearsMedium speed diesel generating units and gas turbines: 20 yearsGeothermal wells and power plant: 20 yearsTransmission and distribution lines: 35 years

D. Fuel Consumption of Generating Units

Kipevu stem plant (existing) 320 liters per MWh (fuel oil)Kipevu gas turbine (existing) 370 liters per MWh (Jet fuel/kerosene)Nairobi gas turbine (existing) 400 liters per MWh (Jet fuel/kerosene)Low speed diesel (new) 220 liters per MWh (fuel oil)Medium-speed diesels (new) 230 liters per MWh (fuel oil)Gas Turbine (new) 260 liters per MWh (fuel oil)

E. Other Assumptions

Discount Rate: 12%Average growth in electricity demand: 5.6 percent per yearGrowth in GDP: 5.5 percent per yearGrowth in real prices of output: ConstantCost recovery: KPLC' s retail tariffs at US cents 9.1 per kWh, as of October

1996, are about 73% of estimated LRMC, and are adequate togenerate a self financing of 22 percent. Further increases tocover full LRMC will be based on a Tariff Study to becompleted by November 1997.

Nature of benefits: Supply of forecast electricity demand, fuel cost savings,environmental benefits from the use of more efficient dieselplants, improved sector efficiency, building of private investorconfidence, improved institutional capabilities.

Main beneficiaries: Industry, commerce, and households

Ano 73Ntge I of 1

KENYAENERGY SECTOR REFORM AND INVESTMENT PROJECTPRELIMINARYESTIMATION OF CONSUMERS WILLINGNESS TO PAY FOR ELECTRICITY

Ksh USS

TYPICAL RESIDENTIAL CONSUMER (about 250 kWb/month)

Kerosene usage for lighting (two kerosene lanps/consumer) 12 kWh/month

Monthly cost of kerosene used for lighting: about 4 literstlamp at KSh 17/1 136 2.47

Cost per kWh equivalent to two 40 Watt bulbs for S bous/day (12 kWho/mo I1 0.20

Electricity use

1995 maginal unit rue KShJkkWh (incl. fixed charge) 4 0.07

A JfWHnugAszs go Pay 7 *.13

TYPICAL SMALL COMMERCIAL CONSUMER (about 250 kWljontb)

Kerosene usage for lighting (two kerose Ianmps/consumer) 12 kWh/month

Monthly cost of kerosene used for lighting: about 4 litershamp at KSh 17M 136 2.47

Cost per kWh equivalent to two 40 Watt bulbs for 5 hours per day (12 kW I1 0.20

Electncity use

1995 rwgina twiff rate Ks/kWh 5 0.09for snall camercia eaaautnpio

SMALL INDUSTRY (abut 1,200 kWLaiih)

*cdowwroVr: 4 wt 5 A ,swk. JRt, N5X

Capitol Cost at USSI 100lkW, auitized at ir% 15 yams 38 161.51

Annual O&M Cost 3% 1485 27.00

Total cost of the above KlHkWh 7 0.1248 wotk, 5 dqycel, 8 ours/ay. g0 % uundI

Fuel eost per kWh at 290g&Wh d KIC 28 pw bltdiuael 9 0.17

Tiul cost afqd nu geowm, 16 0.29

1995 atnld tif rate 5 0.09for lht i d iania emonnptte

Avow wOma'umw* 1Ut All

LARGE INDUSTRIES, WATER PUMIG

Diuuigaaa'uim48malz 4dqMwse* I*&h Nt6pAwfbcw

CApitd eos at USSI 1001kW, m ithizd at I2%, 15 yons 3 161351

Annual O&M Cost 3% 1435 27.00

Total eost perkWh of the above 4 0.03

Fud oost per kWh at 290gikWn ad KSh 23 per liltu a 9 0.16

Total cost of dised guafmt per kWh 13 0.24

6tfdbppWEhWA

1995 weigted mwr l tiff nae for 1 hidmp a & _ dmeW cam 4 0.07(id dm-d dwp)

4Amwub U6 Q15

W9I7GHED A W4GE UTLLINGNW 0PA Y 3EDVAALIS 7o K13Iw: Dadm d' Pkame.muq,a.i4UJpt keftok;__mid a. ZPLSCiI4N U_.frw.e _-

Annex 7.4Page 1 of 4

KENYA

Quantitative Risk Analysis

1. The main risks of this Project relate to three factors: (i) the uncertainties associated with themacroeconomic environment, which could affect consumer demand for electricity, and consequently,output from the project facilities; (ii) possible delays in the commissioning of the generation facilities; and(iii) the value of benefits. In addition, uncertainties related to the costs of equipment and installation couldalso affect the project's net benefits, though not in the same extent as those associated with the demandforecast or the value of benefits. The project is also subject to risks which cannot be hedged in projectdesign. These include risks associated with hydrology which will affect the output quantity from theproject facilities. They also include the impact of international petroleum prices.

2. A quantitative risk analysis was carried out to asses the impact on the project's economic returnsof uncertainty in underlying assumptions and predictions. The primary risks affecting the project'seconomic outcome and the probability distribution to be assigned to each of them were defined based onthe project team's estimates. The stochastic nature of the project implementation was subsequentlymodeled using a commercially available risk analysis program. The expected rate of return and NPV -with their probability distributions - were determined using a Monte Carlo process with a Latin Hybercubesampling technique in the simulation of the model. The major project risks and the probabilitydistributions assigned to each of the risk variables are discussed below.

* Electricity demandforecast. The electricity demand forecast has a major impact on the project'seconomic viability. A triangular distribution with minimum, most likely and maximum values wasassigned to the average annual demand growth rates. The forecast prepared by KPLC and confirmed byAcres International Ltd. was used as the most likely outcome. It predicts an average annual growth ofsome 5.6 percent based on the expected GDP growth rate of 5.5 percent. The Bank's economic forecastprovides three development scenarios: the low growth scenario assumes an average annual GDP growthrate of about 3.2 percent, the high scenario about 7 percent, while the average growth rate is estimated atabout 5.5 percent. To represent the uncertainty in the economic growth rates in the electricity demandforecast, the GDP growth rates were translated into average demand growth rates using the GDP toelectricity demand elasticity. The observed average elasticity for the period 1988-1992 was about 2.Given, however, that the tariffs have (and will) go up and tnat efficiency measures will be introduced, theelasticity is assumed at I in this analysis in line with that used in the demand forecast. This gives theminimum and maximum annual growth rates of 3.2 percent, and 7 percent respectively. The resultingdistribution is skewed towards the low side, that is, the probability for low demand growth exceeds theprobability for high growth.

* Consumers' Willingness to Pay. The value assigned to consumers willingness to pay willdetermine the value of the benefits. A triangular distribution was selected with the average value being theestimated US$ 0.14 per kWh and the maximum and minimum values defined as US$0.16 and US$0.08,respectively. The minimum value coincides with KPLC's current average tariff. The resulting distributionis negatively skewed, i.e., the probability for low values is greater than the probability for high values.

* Commissioning dates for project facilities. The commissioning of the generation facilities isexpected to follow the least-cost investment schedule, where the first facility, Kipevu 1, would becommissioned in 1999, and the two final plants, Sondu Miriu and the Olkaria II in 2001. In case theconstruction of some or all of the facilities is delayed, project benefits would decline and the economywould have to bear an additional cost of not having electricity available. Since the Project includes bothpublicly and privately fnanced facilities and they are at different levels of preparedness, it is expected thatthe probability of delay varies from plant to plant. For the publicly financed projects, bidding documentshave already been prepared so the bidding process could start as soon as the project becomes effective. Inthis case, the main cause of delay in commissioning would be delays in the construction process. However,

Annex 7.4Page 2 of 4

KPC's track record in project implementation is fairly good, so the risk of delay in Kipevu I and Olkaria IIare considered relatively low. For Sondu Miriu, the risk is higher because of the civil works involved.With respect to Gitaru, the risk of delay is related to the ability of KPC to generate the required financinginternally. For the privately financed facilities, bidding document were issued in July 1996, however, thereis the possibility that the selection process and negotiations could drag. An additional cause of delayscould be the lapse in implementing tariff increases, resulting in insufficient counterpart funding. Thefollowing probabilities were assigned for delays in the six generation facilities:

Kipevu 1: one year delay 10 %

Kipevu II (IPP): one year delay 80 %two year delay 70 %three year delay 50 %

Olkaria II: one year delay 20 %

Olkaria III (IPP): one year delay 80%two year delay 70%three year delay 50%

Sondu Miriu one year delay 40%

Gitaru 3rd unit: one year delay 50%

* Hydrology. The annual hydrology determines the output from the hydroelectric plants. As theproject would finance both hydro and thermal plants, dry hydrological conditions would mean lower outputfrom Sondu Miriu and Gitaru and increased use of thermal generation resulting in higher generation cost.Wet hydrological conditions would mean less need for the thermal plants and maximum output SonduMiriu and Gitaru. A triangular distribution representing minimum, most likely and maximum values wasassigned to the annual hydro output based on results from system simulations.

* Project investment cosL The capital equipment of the project comprise, to a large extent, standardequipment and the required civil works are not excessive indicating a moderate risk of cost variations. Thecivil works include tunneling work for Sondu Miriu, erection of power houses for the Geothermal plants,installation of the modular geothermal plants, steam gathering and transmission systems, and the erectionof a new power house for the Kipevu plants, and installation of the Kipevu and Gitaru units. Poorprocurement and supervision performance by the implementing agencies or certain Government actionscould, however, cause cost increases. Cost savings are also possible owing to favorable conditions andstrict cost-control from the side of the private investors. To represent the risk associated with the costestimates, the analysis assigned a triangular distribution to this variable with the minimum and maximumvalues established at, minus 25 percent and plus 25 percent respectively of the estimated value, i.e., totalinvestment costs would vary in the range of US$695 -US$1,160 million

* Petroleum products prices. The analysis assigned a triangular distribution to the petroleum priceforecast. The likeliest annual prices were derived from the Bank's crude oil price forecast of August 1996,which predicts a decrease in real crude oil prices: from about US$ 18 per barrel in 1996 to US$ 15 perbarrel in 2005 (in 1995 prices). The minimum and maximum values were established on either side of thelikeliest values as plus or minus 1.96 times the standard deviations provided in the Bank's forecast. Theinternational prices were adjusted for border parity prices adding the economic cost of transportation andhandling to the FOB prices. Based on historical data, oil prices do not to vary fully randomly from oneyear to another, rather, they tend to be sticky, except for major events such as the Gulf War that caused atemporary, steep increase. A rank-order correlation coefficient of 0.8 reflects the positive correlationbetween the annual prices.

Annex 7.4Page 3 of 4

Results

3. Figure 1. below shows the probability distribution for the expected ERR and indicates a 50 %probability for an ERR of 15.5 percent or more. The expected ERR from the risk analysis is less than thatfrom the deterministic evaluation because the probability distribution for the main variables affectingproject benefits - electricity demand forecast and willingness to pay - are negatively skewed.

Figure 1. Probability Distribution for ERR

0.12 -

0.10 --- - -

0 .0 8 - - - - - - - - - - -- - - - - - - -

0 .0 6 - - - - - - - - - -- - - - - - - -

0rI 0 .0 4 -- - - - - -- - - - -- - - - - - - -a.

0.02 -- - -- ---- o

0.00 I.- ER CD D C

ER(%)

4. Figure 2. below, displays the project's expected NPV (at 12%) and shows that the probability of apositive NPV is about 80%. There is, therefore, a 20% probability that the project would have a negativeNPV. Lower than expected electricity sales, significant delay in the commissioning of the facilities andlower than expected willingness to pay would contribute to the negative NPV.

Figure 2. Cumulative Probability for NPV ((@12%)

1.0 1 0

0 .9 --- -- - --- - -- ----- - ---- -- -- - - - - - - - - - - - --- -- .. >< 0. 7 -- --- --- -- -- - - - - - - - - - --- - - - - - --- ------------------ .-.-

3 0.70 .4 - - -- - - - - -

v . -- -- - -- -- -- - - - - - - - - - - -- - - - - ----- --- ---- - -- - -- - -> 0 .3 -V ---- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

0

0 .1 -- - - - - - -- - - - - - - - -- - - - - - - -

0.0co D CD 0 N CD 0 0 C SD 0)

CD 0) - ? U~) C CI) O 0 UD CD CON -- C') CV) ~

US$ million

Annex 7.4Page 4 of 4

Risk Management

5. The risk analysis indicated that the probability of a negative NPV is not significant. However,project design and implementation were formulated to mitigate the risks leading to unfavorable outcomes.With respect to deteriorating economic performance which could lead to lower than forecast demand forelectricity - the Bank's continued broad policy dialogue on the macroeconomic reform program, will helpfocusing the Government's macroeconomic reforms on maintaining stability. This includes the tighteningof fiscal policies to attract inflows of external assistance to spur economic activity.

6. The risk associated with delays in the commissioning of facilities has been reduced for thepublicly financed projects by preparing the bidding documents well in advance, so that the bidding processcan start as soon as the project becomes effective. Previous experience suggests that KPC is fairly good inimplementing publicly financed generation projects. Nevertheless, given the large size of the Project, theProject will provide consultant and advisory services for project implementation, engineering and financialmanagement to complement KPC's capacity. For the privately financed, IPP, projects, the risk of delayshas been partially reduced, through financing under the Project Preparation Facility for consultant servicesfor the preparation of the bidding documents, which is currently ongoing. The ultimate success willdepend on how attractive Kenya's energy sector is for private investors. The agreed changes in the legaland regulatory framework should contribute to increasing investor confidence. Another risk is delay inmobilizing the corresponding local financing requirements, which could lead to implementation delays.The agreement on annual reviews of the investment program and related financing plans, as well as therequirement to meet at least 30% of investment needs is designed to minimize this risk. Regarding thepotential lack of counterpart funding as a result of delays in implementing tariff adjustments, the agreementon adequate tariff adjustments based on a tariff study, is designed to mitigate lapses. The tariff policy willalso be monitored in the context of IDA's continued macroeconomic dialogue.

7. The capital equipment of the project comprise mainly of standard equipment and the civil worksare not significant, indicating a moderate risk of cost increases. These risks are counterbalanced byincluding adequate contingencies in the cost estimates.

KENYA Annex 7.5Enery Sector Reform and Power Development Project Page 1 of 1

Fiscal I Government Budget Impact Analysis

1997F 19981 1999 2000 2001r 2002 2003 2004 2005 2006 2007 2008 2009 2010 2017 2018 2019 2020Budget Revenue USS million _ i

IbA credit ;3.5 35.0; 46.7 26.8 10.6 1.41 1.0,EIB loan 4.31 16.1 18.6 8.2 1.5 .KfVloan 2.0 9.4 8.4 1.1 -.Interest & repayment on IDA onlend credit I 13.01 13.1 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.21 13.2 13.2 13.2Interest & repayment on EIB onlend loan 2.8 4.5 5.2 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3Interest & repayment on KfW onlend loan 2.11 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.11 2.1 2.1Reduced debt service on behalf of KPLC & KPCVAT on incremental electricity sales -. 0.0 0.0 oo9 1.1 1.5 1.9 2.3 2.9 2.9 2.9 2.9 2.9 2.9 2.80 2.81 2.8: 2.8Incremental corporate tax revenue 0.01 0.0 0.0 0.84 1.0 1.4 1.8 2. 21 2.7 2.7 2.7 2.7, 2.7 2.61 2. 2.6i 2.6Incremental intake from petroleum taxes 0o.0 °° o0 o 0.0 ' 0. 5.2 -4.1 1.1 5.5 13.2 24.6 24.65 24.6 32.3 32.31 32.3 32.3 32.3Total 9.8 6051 76.6 42.2 19.4 30.0 21.2 26.1 31.6 W4 50.7 50. 58.5 58.4 58.3 58.31 58.3

Budget Expenditure USS million I I - I jIDA credit onlending I 1.5 33.0 44.7 24.8 8.6 1.4' 1.01 0.0 0.0 IEIB loan onlending 4.3 16.1 18.6 8.2 1.5 0.0 0.0 0.0 0.0 I 1KfW loan onlending 2.0 9.4 8.4 1.1 0.0 0.0 o.0o 0.0 0.0IDA credit fee 0 | 0.3, 0.61 0.81 0.9 0.9 0.9 0.9 0.9 09 0.9 0.9 0.9o 0.9 0.9i 0.9, 0.9o 0.9Repayment of IDA credit [ 3 3.2 3 t 2.51 2.5 2.51 2;53 53.3: 530 5.01 5.0Repayment of EIB loan principal & interest 24 3 3.3 3.3 3.3 3.3 33 33. 3 3 33 33 33i 3.31 3.3Repayment of KfW loan principal & interest I 1.3 1.3 1.3, 1.3, I3 1.34 1.3 1.3

Total 7.9 58.85 74.8 37.9 14.2 5.6 5.2 4.2 4.2 4.2 8.0 8.0 8.05 8.0 10.5: 10.5' 10.51 10.5

Annual Net Impact on Government Budget USS million 2.0| 1.7 1.8 4.3 5.2 24.4 16.0i 21.9 27.4 35.2 42.7 42.81 42.7 50.51 47.9 47.9! 47.8' 47.8

Present discounted value of revenue @ 12%: 327 US$ million ' 1 1 j

Presentdiscountedvalueofexpenses@12%: 167 US$milion j , I I | iNPV of fiscal revenue @12% 1611 US$ million

0.'-"I-n

Annex 7.6Page 1 of 4

REPUBLIC OF KENYAENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

Summary of Objectives and Key Perfonnance Indicators

OBJECTIVES INPUTS OUTPUTS RISKS AND OUTCOMES AND(Resources provided (Goods and Services CRITICAL IMPACTSfor project activities) produced by the Project) ASSUMPTIONS (of project activities)

(The outcome isdepended on... )

Restructure the *IDA Credit (US$3.0 * study to restructure the *delays in the transfer *KPC Board and MDpower subsector million) power sub-sector into two of assets, allocation of appointed byto increase separate companies; one for staffing and financial December 1996

efficiency and Credit will finance generation and another restructuring *KPC personnel taskattract private phase I of a power sub- transmission & distribution force appointed by

sector sector restructuring * performance contracts February 1997

participation study, consultants to between GoK and the two *Staff transferred to

assist GoK in power companies (KPLC & KPC) KPC by May 1997restructuring, in * power purchase agreement *TRDC to voluntarilysecuring private sector between KPC and KPLC wind up by Marchinvestment and in * non-core activities 1997developing performance contracted out to the private *Transfer of assetscontracts sector between the

* private investors invited to companies by OctoberPhase 11 of the power generate electricity 1997sub-sector restructuring *KPLC managementstudy was financed agreements terminatedunder IDA credit 2440- by October 1997KE. *Performance

contracts betweenGoK and KPLC andGoK and KPC signedby June 1997*Power purchaseagreements betweenKPLC & KPC signedby June 1997*KPC's self-financingratio 20% inFY1997/1998 andFY1998/99, and 25%thereafter* KPLC's selffinancing ratio 25% inFY1997/19998 and1998/1999, and 30%thereafter.*KPC's and KPLC'sdebt service coverageratios at least 1.5 timesstarting in FYI 997/98*customer/staff ratioof 60 for KPLC*accounts receivableof no more than 60days sales* KPLC has identifiedand contracted outadditional non-coreservices to the privatesector by FY1999.*increased privatesector participation inthe subsector's core

Annex 7.6Page 2 of 4

REPUBLIC OF KENYAENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

Summary of Objectives and Key Perfornance Indicators

activities

Create a legal *IDA Credit * legal and regulatory study *delays in *ERB established byand regulatory (US$250,00) to recommend amendments Parliamentary December 1997framework to to the Electric Power Act to approval of the draft *Regulators appointed

commercialize Credit fill finance a create an autonomous Amendments to the by December 1997sector legal and regulatory Electricity Regulatory Board Electric Power Act * electricity tariffsoperations and framework Study and (ERB) based on LRMC andincrease private technical assistance for * technical assistance for *adequacy of staffing cover financial costs ofsector the ERB. ERB of KPC and KPLC supplyparticipation * Further tariff adjustments * the effectiveness of *all power subsector

A tariff update Study will be based on the results the ERB activitieswill be financed under of the tariff update Study to commerciallyIDA Cr. 2440-KE. be completed by April 1996. operated

Meet forecast *IDA Credit (US$82.4 * installation of following * construction delays *Interconnectedelectricity million) generation capacities: * private sector system electricity salesdemand at least *OECF loan (US$82.8 interest will increase fromcost million) * 150 MW at Kipevu in * delays in obtaining 3,402 GWh in FY1996

*EIB loan (US$36.6 FY1999/00 private sector funding to 4,500 GWh inmillion) * 128 MW at Olkaria in * adequacy of internal FY2002*KfW loan (US$20.9 FY2001/02 resources for funding * Number of newmillion) *72.5 MW at Gitaru in of the 72.5 MW at connections will*Private Sector FY2000/01 Gitaru, part of the cost increase annually from(US$262.5 million) of the other plants and 406,300 in FY1996 to

*KPC intemal resources *reinforcement and for the upgrading of 540,000 in FY2002(US$93.9 million) upgrading of distribution the distribution system * private sector owned*KPLC internal lines and installation of * project cost generation willresources (US$29.9 transformers and substations overruns/savings increase by 135 MWmillion) * macroeconomic by 2002

* two power plants offered conditions will affectFunds will be used to to the private sector electricity demandprocure equipment, * hydro plant outputworks, consultants and will depend, inter alia,

technical assistance for on hydrologicalincreasing KPC's and conditionsKPLC's implementation * adequate plantcapacity maintenance measured

as the average annualIDA, EIB and KfW capacity availability infunds will help to %. KPC's targetcofinance construction availabilities inof Olkaria II Power FY2002: hydro 85%;Plant. Private sector geothermal 90%;equity and loans will Kipevu I 80%.finance construction of * internationalOlkaria III and Kipevu petroleum prices11 Power Plants. KPCand KPLC internalresources will financepart of the cost of newpower plants andupgrading of thedistribution systems

Improve the IDA Credit (US$11.7 * upgrading/installation of * timeliness of * Network losses ofefficiency of million) feeders, capacitors and implementation 14.5% or less of netelectricity substations * effort by KPLC staff generation by FY2002supply and use Funds will be used to * electricity demand * cost overruns/savins *KPLC actively

Annex 7.6Page 3 of 4

REPUBLIC OF KENYAENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

Summary of Objectives and Key Performance Indicators

procure equipment, management program offering its customersworks, studies, * study on guidelines on efficiency and demandconsultants, training and energy efficiency standards management advicetechnical assistance. for equipment and labeling and service by 1998

program *at least 2 energy* study on financing efficiency/demandmechanisms for energy management measuresefficiency measures implemented by 1999* expand KPLC's training *KPLC selectprogram in demand personnel trained inmanagement and energy the design andefficiency implementation of* action planning demand managementworkshops programs by 1998* demonstration programs *appliance codes andon efficient equipment and labeling studylighting completed by FY1998

* customersatisfaction measuredthrough annual KPLCcustomer surveys.

Deregulate *IDA Credit * petroleum market and *may take long to * petroleum prices andpetroleum (USS344,000) pricing study develop adequate importation liberalizedmarkets * study to recommend monitoring capacity in November 1994

Credit will finance adequate LPG cylinder * market-determinedstudies, technical standards to promote retail prices forassistance and training competition petroleum productsfor deregulation * adequately trained peronel maintainedimplementation. in the monitoring cell in the * a monitoring cell at

Ministry of Energy the MOE establishedby FY1996* maintenance oftrained personnel inthe monitoring cell* avoidance of anti-competitive behavior* maintenance ofadequate supplies byoil companies

Develop *IDA Credit (US$19 *confirmation of adequate *adequacy of the *.... wells drilled byindigenous million) geothermal resources for a geothermal resource FY2002.energy fourth power plant in the base * private sector invitedresources *EIB loan (US$12 Olkaria area * private sector to develop resources

million) *feasibility study and interest and construct anddetailed designs for the * implementation operate power plants

*KPC internal resources plant delays by FY1998.(US$17 million) *confirmation of adequate * possible costThe funds will finance resources for subsequent overruns/savingsequipment, works, pre- power plant (s) in thefeasibility and feasibility Olkaria Domes/ Suswa andstudies, drilling of Longonot areasgeothermal wells, a *prefeasibility andPanel of Experts, advanced feasibility studiestraining and technicalassistance for capacitybuilding.

Annex 7.6Page 4 of 4

REPUBLIC OF KENYAENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT

Summary of Objectives and Key Performance Indicators

Develop a *IDA Credit * survey of energy end-use * delays in * strategy forstrategy for (US$258,000) * energy supply and implementation household andhousehold and marketing survey * delays in GoK renewable energyrural energy The funds will finance * policy, institutions and approval of strategy agreed by the GoK bydevelopment studies, equipment, pricing study * effort of the local FY1999and promote training and technical * beter trained local professionals. * local analyticalrenewable assistance for capacity professionals capacity developedenergy. building. * study on guidelines for * solar PV information

solar PV standards campaign initiated by* dissemination of 1998information about solar PV * taxes on solar PVsystems. equipment at level

with other generationeqipment starting in

._____________________ __________________ FY 1997.

Victoria FofanahM:\2EIEXCH\JJMAWENI\ANNEXES\ANX7-6NW.DOCDecember 3, 1996 8:58 AM

MAP SECTION

IBRD 28165

K E N YA 40FACILITIES PROPOSED UNDER THE PROJECT EXISTING FACILITIES

LlENERGY SECTOR OLL IV AREFORl M1 AND 0 GEOTHERMAL POWER STATION t OLKARIA GEOTHERMAL FIELD

POWER DEVELOPMENT PROJECT A DIESEL POWER STATIONS HYDRO POWER STATIONSPO W ER DEVELOPMENT PROJECT ~ ~~~~~OTHER PROPOSED FACILITIES: A, DIESEL POWER STATIONS

POW ER SYSTEM 220 kVTRANSMISSIONLINES * STEAM POWER STATION-7 - 132 kV TRANSMISSION LINES KPLC DISTRIBUTION AREAS

S U D A N - 7 POSSIBLE SITES OF HYDRO - 220 kV TRANSMISSION LINES,1 , lPOWER STATIONS 132 kV TRANSMISSION LINES

/ -*,,,_ X - DENSELY POPULATED AREAS 66 kV TRANSMISSION LINESINTERNATIONAL BOUNDARIES 33 kV TRANSMISSION LINES

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