Document of The World Bank

Report No: 32101

IMPLEMENTATION COMPLETION REPORT(IDA-29660 PPFI-P7710 PPFI-P7711 PPFI-P7712)

ON A

CREDIT

IN THE AMOUNT OF US$125 MILLION

TO THE REPUBLIC OF

KENYA

FOR AN

ENERGY SECTOR REFORM PROJECT

June 8, 2005

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CURRENCY EQUIVALENTS

(Exchange Rate Effective )

Currency Unit = Shilling KSh 1.00 = US$ 0.01

US$ 1.00 = KSh78.00

FISCAL YEARJuly 1 June 30

ABBREVIATIONS AND ACRONYMS

FY = Fiscal YearGoK = Government of KenyaGWh = Gigawatt hoursIPP = Independent Power ProducersKenGen = Kenya Electricity Generating CompanyKPLC = Kenya Power and Lighting CompanyMoE = Ministry of EnergyMW = Megawatt

Vice President: Gobind NankaniCountry Director Colin BruceSector Manager Yusupha Crookes

Task Team Leader/Task Manager: Joel Maweni

KENYAKE ENERGY SECTOR REFORM

CONTENTS

Page No.1. Project Data 12. Principal Performance Ratings 13. Assessment of Development Objective and Design, and of Quality at Entry 24. Achievement of Objective and Outputs 55. Major Factors Affecting Implementation and Outcome 126. Sustainability 157. Bank and Borrower Performance 158. Lessons Learned 199. Partner Comments 2010. Additional Information 30Annex 1. Key Performance Indicators/Log Frame Matrix 32Annex 2. Project Costs and Financing 34Annex 3. Economic Costs and Benefits 36Annex 4. Bank Inputs 38Annex 5. Ratings for Achievement of Objectives/Outputs of Components 40Annex 6. Ratings of Bank and Borrower Performance 41Annex 7. List of Supporting Documents 42Annex 8. Disbursements 43Annex 9. Table of Costs and Benefits 44Annex 10. Assumptions 45Annex 11. Financial Indicators 47

Project ID: P001344 Project Name: KE ENERGY SECTOR REFORMTeam Leader: Joel J. Maweni TL Unit: AFTEGICR Type: Core ICR Report Date: June 8, 2005

1. Project DataName: KE ENERGY SECTOR REFORM L/C/TF Number: IDA-29660; PPFI-P7710;

PPFI-P7711; PPFI-P7712Country/Department: KENYA Region: Africa Regional Office

Sector/subsector: Power (79%); Renewable energy (16%); Central government administration (5%)

Theme: Rural services and infrastructure (P); Regulation and competition policy (P); Pollution management and environmental health (P); Climate change (S); Other financial and private sector development (S)

KEY DATES Original Revised/ActualPCD: 02/20/1988 Effective: 07/02/1998 06/23/1998

Appraisal: 09/24/1994 MTR: 02/08/1999 02/08/1999Approval: 06/19/1997 Closing: 06/30/2004 06/30/2004

Borrower/Implementing Agency: GOVERNMENT/KenGenOther Partners: KPLC

STAFF Current At AppraisalVice President: Gobind T. Nankani Callisto E. MadavoCountry Director: Colin Bruce Harold E. WackmanSector Manager: Yusupha B. Crookes Jeffrey RackiTeam Leader at ICR: Joel Maweni Joel MaweniICR Primary Author: Joel J. Maweni; Assefa Telahun

2. Principal Performance Ratings

(HS=Highly Satisfactory, S=Satisfactory, U=Unsatisfactory, HL=Highly Likely, L=Likely, UN=Unlikely, HUN=Highly Unlikely, HU=Highly Unsatisfactory, H=High, SU=Substantial, M=Modest, N=Negligible)

Outcome: S

Sustainability: L

Institutional Development Impact: M

Bank Performance: S

Borrower Performance: U

QAG (if available) ICRQuality at Entry: S S

Project at Risk at Any Time: Yes

3. Assessment of Development Objective and Design, and of Quality at Entry

3.1 Original Objective:

3.1.1 The objectives of the project were to assist the Government of Kenya in formulating and implementing major policy and institutional reforms aimed at creating an efficient and environmentally sustainable energy sector and to support investments needed to meet power demand and increase operational efficiency. The project's specific objectives were to:

finance investments needed to meet power demand and improve the operational efficiency in the 1.sub-sector;reform the power sub-sector's organizational structure to enable the operating entities to function 2.efficiently and on a commercially sustainable basis;create a legal and regulatory environment necessary for private sector participation in the supply of 3.electricity;support the Government's adoption of economic pricing of both electricity, and petroleum and 4.petroleum products, and implementation of demand and supply-side efficiency improvement measures; and develop indigenous geothermal energy resources and a strategy for sustainable household and rural 5.energy development.

3.2 Revised Objective:

3.2.1 There was no major change in project objectives. However, because of the shortage of financing, a reduction in the scope of the Efficiency Improvement component (objective 4 above), including loss reduction, and distribution upgrading (Part D), and deferment of the Geothermal Resource Assessment component, Part E, (objective 5 above) affected the extent to which the original objectives could be fully achieved.

3.3 Original Components:

3.3.1 The project consisted of the following six components:

A. Sector Restructuring and Reform (US$3.6 million), supporting: (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 sub-sector companies, and separation of generation from transmission and distribution functions; and (iii) promotion of private sector participation in the provision and management of operations.

B. Institutional Support (US$24.6 million), comprising: (i) identified prefeasibility and feasibility studies and preparation of bidding documents for future projects; (ii) determining, based on ongoing rural electrification study, a strategy for sustainable and affordable household energy use and rural energy development, including carrying out supply and demand studies and policy and institutional analyses; (iii) examining the establishment of quality guidelines for solar photovoltaic components and systems, including legal incentives to encourage application of minimum norms; and (iv) promoting competition in the supply of LPG through the development of uniform standards for LPG cylinders, valves and pressure regulators, and relevant monitoring and regulatory arrangements. The Institutional Support Component was also to provide: (a) engineering and financial management advisory services and logistical support, in the form of

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office technology, to the Implementation Support Group (ISG) in MOE, which was to coordinate implementation of the Project; and (b) engineering and financial management support for the implementation of the generation component, to the Kenya Power Company Limited which later became the Kenya Electricity Generating Company (KenGen). C. Efficiency Improvements (US$11.8 million) had the following two subcomponents:

(i) Demand Side Improvements (US$5.4 million) was to assist in: (a) developing capacity in the Kenya Power and Lighting Company Limited (KPLC) and in the local private sector to design, implement and 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) conducting demonstration programs on energy efficient lighting, air conditioning and other consumer equipment in public buildings including KPLC's buildings; (d) mapping out mechanisms for third party financing of efficiency improvement measures; and (e) establishing guidelines for energy efficiency labeling and standards for electric appliances and motors.

(ii) Line Loss Reduction (US$6.4 million) was to be assisted by the Project through financing: (a) technical loss reduction programs identified by KPLC and by an ESMAP study for the Nairobi and Coastal areas; (b) implementation of ESMAP recommended nontechnical loss reduction measures; and (c) the technical assistance required to set up an implementation plan and to train a task force.

D. Power System Expansion & Rehabilitation. This major investment component to implement the findings of the Least Cost Development Plan, comprised:

Power Generation (US$579.1 million)

(i) a 75MW Diesel Power Plant at Mombasa, Kipevu I, targeted for commercial operation in fiscal year 1997/98-99;

(ii) a 64MW Geothermal Power Plant at Naivasha, Olkaria II, targeted for commercial operation in 1999/2000;

(iii) a second 75MW Diesel Power Plant at Mombasa, Kipevu II with an expected commissioning date of January 2000;

(iv) another 64MW Geothermal Power Plant at Olkaria III, planned for commercial operation in FY 2000/01; (v) a third 80MW unit at Gitaru Hydropower Station with anticipated completion date of January 2000; and

(vi) connection of two additional make-up wells for the existing Olkaria I Geothermal Power Plant.

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Upgrading Distribution (US$30 million) was to support (a) Reinforcement and reconductoring of distribution lines, including line interconnectors, in the Nairobi area; (b) Upgrading and construction of new power substations in the Nairobi area; (c) Upgrading of power substations in Mombasa, Nyali, Malindi, Makande, Kipevu and Diani; and (d) Construction of new power substations in the Mombasa and coastal area, including associated interconnection lines.

E. Geothermal Resource Development (GRD) ($49.3 million) was designed to assist the Government in developing geothermal energy resources, including the production of power at the next power plant (Olkaria IV) through private sector participation.

F. Future Project Preparation (US$1.5 million) was to support preparatory activities to develop candidate projects identified in the Government's least cost energy investment program.

3.4 Revised Components:

3.4.1 The scope of the project was reduced because of: (i) the need for additional funding to meet the increased cost of the Olkaria II geothermal power plant (over 35%) including the additional cost for related engineering services; and (ii) the non-materilization of financing to support the GRD component, Part E of the Project. The combined effect was to reduce the scope of the Efficiency Improvement component, Part C of the Project, and to defer implementation of the GRD component. IDA's original allocations were US$19.7 million and US$11.8 million for the GRD (Part E) and Efficiency Improvement (Part C) components respectively. Credit/Loan reallocations by the IDA and the EIB were also necessary to cover a large portion of the funding that was initially to have been provided from KenGen's internal resources, but could not be generated due to KPLC's poor financial performance and inability to meet its obligations for power purchases from KenGen.

3.4.2 During 2002, the Bank and GoK teams undertook an in depth review of the project with a view to restructuring it to reduce its scope given the financing constraints, and to revise its performance indicators. The main driver for the restructuring exercise was the perceived need to realign the financial performance covenants to achievable stretch targets anchored in the plan that was then being developed for KPLC's financial and operational recovery. Completion of an adequate financial and operational recovery plan proved difficult during the previous government. Thus, a sound plan evolved only in early 2003, after the current administration had taken over. However, before the project could be restructured the government decided to implement an aggressive financial restructuring plan, involving debt-equity conversions and write-offs of debts and interest to the utilities. These measures enabled the utilities to have adequate debt/equity ratios and to meet the original financial covenants (except the covenant relating to receivables) starting in FY2002/03. With the main reason for restructuring no longer relevant, and only a few months remaining before project completion, it was not considered cost effective to undertake the restructuring for the sole purpose of amending the project's scope. 3.4.3 The project had initially envisaged financing two advisers (financial and engineering) to support the ISG at the Ministry of Energy in coordinating project implementation. However, for most of the life of the Project, the ISG operated with only the technical adviser after termination of the financial consultant for nonperformance. The financial function was fully assumed by the Ministry of Energy staff thereafter.

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3.4.4 Overall monitoring of project implementation and preparation of consolidated cost and financing plan tables on a regular basis by the Ministry of Energy was not effective for most of the implementation period. Annex 2 gives original cost estimates and actual costs to completion of all components of the Project.

3.5 Quality at Entry:

3.5.1 The design of the Project was based on a number of studies and reviews of the Least Cost Power Development Program regularly updated by the Government with the advice of reputable consultants. The Feasibility Study for a Geothermal Power Station at North East, Final Report 1989, prepared by Ewbank Preece (UK consultants) formed the basis for the core component of this Project. Organizational, tariff and sub-sectoral studies also assisted in formulating the Project. The QAG has rated the Quality at Entry satisfactory.

4. Achievement of Objective and Outputs

4.1 Outcome/achievement of objective:

4.1.1 Objective 1: Finance investments to meet power demand and improve operational efficiency. The objective of providing finance for the project was largely met with the assistance of the Bank's Credit 2966-KE (accounting for 55% of US$195.8 million disbursement made per Annex 8), and contributions for the geothermal power plant at Olkaria II by other lenders notably the EIB (about 20%) and KfW (6%), as well as KenGen (13%) and the Government (4%). KPLC also contributed about 2% for the distribution component of the project. The insufficiency of funds, due in part to cost increases, and in part to the inability of the Implementing Agencies (KPLC and KenGen) to generate funds, on a timely basis, from internal sources resulted in deferment of the Geothermal Resources Development (Part E) component and reduction in the scope of the Efficiency Improvements component (Part C). Both of these components form part of the ongoing Energy Sector Recovery Project (ESRP) declared effective on November 4, 2004. Nevertheless, the main component for the Power System Expansion, accounting for 82% of the total original cost estimate (or about 96% of the actual costs at completion) was satisfactorily implemented. Overall the project added 312 MW of generation capacity to the power system compared to 350MW planned at appraisal, or 89%. The public sector financed plants accounted for 217.5 MW or 102.8% of the planned capacity of 211.5 MW, whereas the private sector plants contributed 87MW instead of the 139MW envisaged at appraisal. The shortfall on the private sector portion was attributable to the fact that, out of the original target of 139MW, 64MW was predicated on availability of geothermal steam for which production drilling was to be carried out by the IPPs during project implementation. Steam field appraisal by the IPP subsequently proved steam availability for 48MW of which 12MW has already been installed and addition of the balance is under discussion between the Government and the IPP. Thus, the project succeeded in this objective of mobilizing substantial funding for a large investment program designed to help the Government meet power demand. 4.1.2 Objective 2: Reform the organizational structure of the power subsector. The objective for the organizational restructuring of the power sector was achieved in 2000 with the separation of the vertically integrated Kenya Power and Lighting Company into generation as one part, and transmission and distribution as another. KenGen was established to manage and operate the generation assets while KPLC was to manage and operate the transmission and distribution assets. The completion of the restructuring was a major achievement that created separate companies along functional lines, with separate revenue streams and accountabilities, operating on an arms length business relationship. Thus, the performance measurement problems which had been complicated by opaque inter-company transfer pricing practices

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were eliminated, and so were the soft subsidies to which the sector had been accustomed. In addition, the restructuring paved the way for further unbundling of transmission and distribution functions which will be initiated, through the creation of business units, under the ESRP. With the prospects of growing interconnection of regional power systems, the transmission system, being a common carrier for a number of power providers and users, both internal and external, will be governed by a special code (grid code etc.) and regulations distinct from distribution with which it is presently linked.

4.1.3 Objective 3: Create legal and regulatory environment for private sector participation in power supply. The Electricity Regulatory Board (ERB) was established and empowered to set up electricity tariffs and rules governing participation of private operators in the subsector. In addition to supporting the re-organization of the sector and the creation of a regulatory infrastructure, to create conditions for improved operational and financial performance and for private sector participation, the Bank played a role (through funding advisory services) in the contracting of two Independent Power Producers (IPPs) for a 75MW Diesel plant at Kipevu, commissioned by Tsavo Power Company in 2001, and an initial 8MW geothermal capacity at Olkaria III commissioned by OrPower Company in August 2000, and subsequently increased to 12 MW in December 2000. The latter is expected to be increased to the ultimate capacity of 48 MW by 2007. Further, the dialogue on liberalizing the sector also indirectly led to the contracting of the first IPPs, 44MW gas turbines at Kipevu, commissioned by Westmont in 1997, and another 44MW Diesel at Nairobi South, commissioned by Iberafrica in August 1997. The Bank had no direct role in the procurement of these IPPs and did express concerns about the procurement process used to select the contractors, the short terms of the power purchase agreements (7 years) and resultant high costs to KPLC.

4.1.4 Investor perceptions of high country risks, a weak legal and regulatory framework, lack of transparency, and KPLC default risks appear to have contributed to the requirement by sponsors and their financiers for substantial security packages and Government guarantees against political and commercial risks, leading to high costs for these first IPPs. Although the Bank financed advisers to support the Government in the negotiations with IPPs, the lack of relevant experience and qualifications of the Kenyan negotiating team and probable interference by Government organs might have compounded the difficulties. The high tariffs negotiated with the IPPs and the related arrangements for mitigation of risks faced by the IPPs were perceived by the Government and other domestic stakeholders as onerous, leading to a revised strategy towards private sector participation with more emphasis on up-front work to strengthen the structural and regulatory characteristics of the sector prior to inviting additional private sector investors or privatizing existing assets This strategy which also takes into account both country and international experience with IPPs in recent years has been built into the design of the ESRP.

4.1.5 Despite the high costs of the initial IPPs, the project did lead to private sector investments which accounted for about 12% of total system generation capacity at project completion and provided valuable lessons of experience, thus contributing to the design of a revised strategy for further restructuring and reforms of the regulatory environment which is being supported under the ESRP.

4.1.6 Objective 4: Support economic pricing of both petroleum products and electricity. As part of the commercialization strategy, the new power sector structure provided for a separate bulk tariff at which KenGen sells power to KPLC, eliminated the previous cost-based transfer pricing system and included a commitment from the Government to subject the companies to hard budget constraints. At the same time, a program of tariff increases raised the average tariff from about 30% of Long Run Marginal Cost (LRMC) in 1993 to nearly 100% by 1999. An adjustment mechanism was built into the tariff schedule to allow KPLC to pass on fluctuations in fuel prices and exchange rates to consumers without reference to the regulator. In the petroleum subsector, the project also supported the deregulation of the importation, marketing and pricing of petroleum products thereby attracting new importers and distributors and

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increasing competition. Implementation of the demand side efficiency improvement and loss reduction measures was, however, constrained by availability of resources. For the demand side measures only studies were undertaken while the scope of the loss reduction measures was substantially reduced, and thus limited the extent to which this aspect of objective could be achieved.

4.1.7 Objective 5: Develop indigenous geothermal energy and a strategy for household and rural energy development The implementation of the Olkaria II geothermal power plant was satisfactorily achieved despite financial problems and procurement delays. The actual plant output of 70MW exceeded the designed capacity of 64MW by 9.4%. This increase coupled with the lower specific consumption of steam compared to Olkaria I makes the plant technically viable and more economic. A household energy survey has been carried out but rural energy development has not progressed due to lack of financial support. French assistance is being secured under the ESRP and major developments are expected as a result.

4.1.8 Overall Assessment on Achievement of Project Objectives. The achievement of project objectives and, therefore, of the project's outcome is rated satisfactory. This is based on the project's success in: (i) financing all the generation investments included in the project, except the Olkaria III geothermal power plant whose ultimate installed capacity was dependent on the availability of quantum of steam from the outset and is still the subject of ongoing discussions between the Government and the private sponsor (para.4.1.1 above); (ii) facilitating substantial structural, legal, regulatory and pricing reforms, and introducing private independent power producers into the sector; and (iii) enabling a partial deregulation for the petroleum subsector which liberalized the importation and pricing of petroleum and petroleum products. The areas in which project objectives were not fully achieved and for the reasons described above are being addressed under the successor project, the Energy Sector Recovery Project approved by the IDA Board on July 13, 2004. It is worth noting that the project achieved these objectives under extremely difficult circumstances when Kenya was in a low-case lending scenario, overall Client-Bank relations had deteriorated to an all-time low, and virtually no other activities were succeeding in the country portfolio. Further, the positive changes that took place in the last year or two of the project, particularly the formulation of a financial recovery plan for KPLC and the approval of a comprehensive energy sector policy by the Government, if fully implemented, will help to make the project benefits sustainable.

4.1.9 Although the results framework which is now the norm was not used at the time of project preparation, the mix of output, outcome and impact indicators designed at the time, is adequate to assess the project's success. Annex 1 provides a comparison of the indicators projected at appraisal to the results at the project's exit from the portfolio and supports the satisfactory rating. The financial indicators given in Annex 11 also show an improvement in performance in FY2002/03 reflecting the results of the financial restructuring undertaken by the current government after assuming power at the end of 2002.

4.2 Outputs by components:

4.2.1 The outputs of the project at exit from the portfolio are summarized by component and compared to the original expected outputs at entry in the table below which also gives the implementation ratings by component.

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Summary Table of Outputs by Components (including ratings)Part Component

DescriptionPlanned Outputs at Entry Actual Outputs at Exit Component

RatingA Sector

Restructuring & Reform (US$3.6 million)

•Power subsector restructuring study•Legal and regulatory study •Power purchase agreement between KPLC and KenGen•Non-core activities contracted out to private sector•Private investors invited to generate electricity•Petroleum market and pricing study•Establishment of a petroleum monitoring cell in the Ministry of Energy

•Power subsector study completed and implemented•Study completed & regulator established•Interim power purchase agreement established•Number of activities, (e.g.construction of LV lines) contracted out •Petroleum market and pricing study•Kipevu II and Olkaria III Power plants bid out to private sector •Petroleum Monitoring Unit established and staff trained

S

B Institutional Support (US$24.6 million)

•Household energy strategy study completed•Study on guidelines for PV solar standards•Study on LPG equipment

•Household energy strategy study completed•Study on guidelines for PV solar standards•Study on LPG equipment standards

S

C Efficiency Improvement (US$11.8 million)

•Demand-side management studies•Financing mechanisms study for energy efficiency measures•Demand side management training program and demonstration programs on efficient equipment and lighting

•Energy audits•Energy market research studies

MS

D Power System Expansion and Upgrading (US$609.1 million)

Power generation outputs:•150 MW installed at Kipevu I and II•128MW installed at Olkaria II and III•80 MW installed at GitaruDistribution system upgrading outputs:•Upgrading and reinforcing distribution network and substations

•150 MW installed•82 MW installed•80 MW established

S/gen.

NR/dist.

E Geothermal Resource Development (US$49.3 million)

•Confirmation of adequate geothermal resources for Olkaria IV Power Plant and for subsequent plant•Feasibility study and detailed designs for Olkaria Power IV and Pre-feasibility study for the subsequent plant

•Component deferred due to funding constraints

NR

F Future Project Preparation (US$1.5 million)

Were to be determined during implementation •Allocation used reallocated to cover deficits on Olkaria II and to support restructuring activities during the drought emergency of year 2000-01

NR

NR = Not Rated; S/gen = Satisfactory for Generation Part; NR/dist. = Not Rated for Distribution

4.2.2 Sector Restructuring and Reform, Part A. All the outputs envisaged under this component have been completed as shown in the summary table. Execution of the power subsector portion of the component, thus facilitated the achievement of the objective of assisting the Government in formulating and implementing a policy and institutional policy framework for efficient and sustainable development of the energy sector. In the petroleum subsector, the petroleum marketing and pricing studies were carried out to facilitate the design of a deregulation scheme. As a result, a partial deregulation of the importation, marketing and pricing of petroleum products was implemented. This has led to the entrants of new importers and distributors and increased competition. The deregulation was limited in that the Kenya Petroleum Refineries Limited (KPRL) was given tariff and quantitative protection, to allow it to continue operating and producing the minimum domestic requirement for LPG which could not be imported, in

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sizeable quantities, due to the lack of import handling facilities at Mombasa Port. Financing of import handling facilities was originally to be included in the project so as to allow full deregulation of the petroleum subsector. When the project design was finalized this component had to be deleted because the Bank objected to the non-transparent manner in which the Government wanted to select its joint venture partner. Thus, at the conclusion of the appraisal process the component design was limited to achieving a partial deregulation. Discussions on the removal of the refinery protection was expected to continue under the Bank's macro-economic dialogue with the Government. With the deregulation and entrants of new participants, the project supported the establishment of a Petroleum Monitoring Unit in the Ministry of Energy to facilitate government monitoring of anti-competitive behavior, including price collusion and staff training was provided.

4.2.4 The Institutional Support Component, Part B of the Project: The following main activities were undertaken: (i) the establishment of the Petroleum Monitoring Unit in the Ministry of Energy; (ii) the Study for the standardization of LPG Cylinder Valves and Regulators; (ii) the Energy Needs Study for Household and Small Scale Services and Industrial Establishment; (iii) Energy Audit and Market Research on Energy Demand through selection of targeted industrial and small commercial enterprises; (iv) procurement of vehicles, computers for capacity building of the staff of the MOE; (v) Study on information dissemination on photovoltaic; (vi) Engineering support for the implementation of the generation projects; (vii) environmental impact assessments and implementation of mitigating measures for the power plants constructed under the Project. Most of these activities have been successfully completed; in particular the engineering services and the Environmental aspects for the generation component have been satisfactorily achieved. 4.2.5 The Efficiency Improvement Component, Part C: was designed to improve the operational performance of electricity distribution, and had provisions for advisory services in project management including studies and for customer related activities. Technical efficiency improvement through investment targeted at loss reduction was also included. However, due to financing constraints, the amount of US$9.3 million earmarked from the IDA Credit had to be reallocated to cover the financing shortfall for the Olkaria II power plant. KPLC was able to invest only US$ 4.0 million on this subcomponent. Consequently, the limited implementation of loss reduction measures and distribution improvement, depressed general macroeconomic conditions which increased incentives for power theft and meter tampering, and inadequate management attention by KPLC resulted in an increase in system losses from about 16.5% at appraisal stage (FY1994/95) to a peak of about 21.7 % in FY 2002/03. The increases in system losses occurred also in part due to higher rate of customer connections (190,000 new connections over project’s construction time, equivalent to 250MW peak load) than originally envisaged. More recently KPLC has started installing electronic meters with its own financing to arrest theft of electricity. This will help to reduce nontechnical losses. The installation of statistical meters in the KPLC system, which is at initial stages, will help to segregate transmission and distribution losses, and will determine the exact value of losses at transmission and distribution voltage levels. This will enable KPLC to better target loss reduction measures. The ESRP includes a substantial component for upgrading the distribution system and for installation of electronic and statistical meters. These measures and KPLC's ongoing efforts are expected to reduce system losses from about 18.7% in FY2003/04 to 14.5% by FY2008/09. As of March 2005, the system losses had improved to 17.7%.

4.2.6 Power System Expansion and Upgrading component, Part D comprises:

Olkaria II Geothermal Power Plant, the core component under this Project, was designed for an ladditional capacity of 64MW and commissioned in August 2004 with a capacity of 70MW. This provides an additional annual energy capability of 550GWh at 92% (on the low side) availability

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and 98% plant factor. The higher cost of Olkaria II than originally estimated which were due to high bid prices is largely compensated by the additional plant output and also by the relatively low specific steam consumption of the new units compared to Olkaria I. The connection of two additional make-up wells at Olkaria I, carried out using the Credit's funds, provided additional steam equivalent to 16.4MW and helped maintain the Olkaria I's output at the rated 48MW.

Kipevu Diesel Plant I was designed with name plate capacity of 6x12.5 MW. Delivery of the lpower plant in October 1999 greatly contributed to minimizing the impact of power shortages during the 2000/2001 drought period, and reduced the size of the additional diesel plants (99MW capacity compared to original estimate of 105 MW when the emergency plan was designed) leased under the Emergency Power Supply Credit.

Kipevu II Diesel Plant (75MW IPP carried out by TSAVO Power Company Limited) was delayed lby almost two years due to protracted negotiations that took over three years to complete. The delay was mainly due the difficult discussions on security packages and government guarantees. The delay meant that the plant was not completed prior to or during the drought of 2000/2001 when 99MW diesel units had to be leased with financing provided through a special IDA Emergency Power Credit.

The third unit at Gitaru hydro plant with 80MW capacity started commercial operation in January l2000, and contributed to meeting peak demands during the drought period of 2000/2001.

Olkaria III Geothermal Power Plant. The privately funded Olkaria III geothermal plant lcommissioned an 8MW pilot plant, subsequently expanded to 12 MW during the FY2000/01 power crisis. The original ultimate capacity target of 64 MW, was predicated on proving adequate steam resources. Based on the proven resources, the targeted capacity has been revised to 48MW. Discussions on contractual and financing issues between the private operator and the Government are in progress to realize this revised capacity objective.

4.2.7 The generation capacity planned for installation under the Project was stated at 350.5MW in the Staff Appraisal Report (SAR). The actual capacity installed under the project was 312 MW, almost 89% of the original estimate. For the core component - Part D per DCA - the estimated installed capacity was 211.5MW (Kipevu 75, Olkaria II 64 and Gitaru 80). The corresponding actual installed capacity at completion was 217.5MW or 102.8%. This is a high level of achievement, and is due to the output of the geothermal power plant at Olkaria II that has exceeded the designed capacity of 64MW by over 9% reaching 70MW. The specific steam consumption is also much lower than that of Olkaria I. The 2 make-up wells undertaken under this Project have also provided 16MW additional geothermal power.

4.2.9 Geothermal Resource Development, Part E: This was cancelled due to lack of financing, as the IDA Credit had to be reallocated to cover the increased costs of Olkaria II Geothermal Power Plant and is now included as a component in the ESRP. Implementation performance for this component is, therefore, not rated.

4.2.10 Preparation of Future Projects, Part F: The original funding was reallocated, partly to cover the cost of studies which were intended to inform the formulation of an action plan for KPLC's recovery as part of the response to the power crisis of FY2000/01, and partly to cover the increased costs of the Olkaria II Geothermal Power Plant. Thus, implementation of this component is also not rated.

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4.3 Net Present Value/Economic rate of return:

4.3.1 The SAR had included Kipevu I (with planned on-line date - OLD - of August 99, actual realized December 99), Kipevu II (with planned OLD of January 2000, realized September 2001), Gitaru ( with assumed OLD January 1999, realized January 2000), Sondu Miriu (planned July 2002 with probable one year delay then, now to be realized in December 2007) as well as Olkaria II (with due date September 2001, realized August 2004) and Olkaria III (IPP with due date of January 2002, realized 12MW pilot plant in August 2000 and uncertain for the on-line date of the remaining capacity). The DCA as stated in paragraph 4.2.2 included Kipevu I, Olkaria II and Gitaru Unit III as the Generation components.

4.3.2 In view of the wide gap of over four years in the on-line dates between Olkaria II and Kipevu and Gitaru, the analysis of costs and benefits of the Project is based on costs incurred from 1998 through June 30, 2004 of the Olkaria II geothermal power scheme, and the benefits accruing from mid 2004 through the lifetime of the Project.

4.3.3 The revised economic rate of return of the Energy Sector Reform and Power Development Project is 18% based on an estimate of USc 12/kWh for consumers' willingness to pay. This estimate has been derived by averaging the seemingly high figure of USc 14/kWh in the SAR and the seemingly low figure of USc 10/kWh of the PAD for the Energy Sector Recovery Project. The SAR figure for consumers' willingness to pay is derived from consideration of prices for alternative fuels, whereas the PAD figure has used the average electricity tariffs as proxy for consumers' willingness to pay. With a NPV of US$728 million at a discount rate of 12%, the benefit to cost ratio is 3.64. The SAR's economic rate of return and NPV at 12% discount rate are lower at 17.32% and US$343 million respectively. In the SAR the NPV and economic rate of return analysis had included the estimated costs and benefits of Kipevu I diesel, commissioned in November 1999, Kipevu II diesel (September 2001) and Gitaru hydro, commissioned in early 2000, Sondu Miriu and Olkaria III (IPP) with probabilities for delays ranging of 10% to 80%. A comparison of assumptions used at the appraisal stage and during the ICR revised economic analysis is given in Annex 10.

4.4 Financial rate of return:

The financial covenants of the implementing agencies, especially the self financing ratio of 25% for KenGen and 30% for KPLC, were not complied with in the earlier years of project implementation, and not until 2003 for KPLC. KPLC also did not comply with the receivables covenant of 60 days for most of the years until 2002 and after. The debt service coverage (covenanted 1.5 times) of KenGen was generally satisfactory. KPLC's productivity - measured in terms of customers per employee - has improved from 63 at project inception to 103 in 2003 and is part of the operating cost reduction measure discussed with Bank's supervision missions. The substantial increase in system losses from 18.6% in 1998 to 21.5% in 2000 contributed to the unsatisfactory financial performance. These were discussed with the supervision mission of April/May 2000 and were accepted to have been mainly due to non-technical losses towards which KPLC had proposed the measures acceptable to the Bank to reduce them. Additional information on operational indicators is given in Annex 11.

4.5 Institutional development impact:

4.5.1 The unbundling of generation, transmission, distribution assets into two companies - one for generation (KenGen) and another (KPLC) for transmission and distribution - has had a notable impact on

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the institutional development of the power sector. Accountabilities for performance are clearly defined, thus making monitoring more feasible. Thus, although operational performance improvements did not materialize during the project implementation period, due to drought conditions in FY2000/01, KPLC's unsustainable cost structure and governance issues under the previous corporate management, the fundamentals for improvement were put in place through the project policy and institutional reform. This has led to the decision to further unbundle the transmission and distribution functions with the medium term objective of privatizing the feasible activities of the distribution functions when the appropriate market conditions are attained In the petroleum subsector, the deregulation has led to an increased number of marketers and distributors and increased penetration of petroleum product's to previously unserved areas in the rural areas. It has, however, created regulatory issues related to product quality and safety and adulteration of fuels. These issues are being addressed under the ESRP.

4.5.2 Participation in workshops of institutions involved in the energy sector reform helped to foster an understanding of the need to reform the energy sector in general and the power sector in particular, including the role of private sector participation. The Sessional Paper on Energy (May 2004), an offshoot of the emerging consensus, has been approved by Parliament in 2004. It sets out strategies in all areas and lays down principles and legislative actions to deepen and broaden the sector restructuring reforms.

5. Major Factors Affecting Implementation and Outcome

5.1 Factors outside the control of government or implementing agency:

5.1.1 The consultant that initially designed the Olkaria II geothermal power plant and drafted bidding documents for the Major Civil Works and Electro-mechanical equipment was replaced by another consultant following a competitive process for the supervision consultancy of Olkaria II. The terms of reference provided for review of the design which recommended substantial changes to the initial design. The draft bidding documents did not also follow the latest version of the Bank's SBD, especially the Bidding Document for Supply and Installation of Plant and Equipment. Redoing the design and the bidding documents resulted in substantial delays estimated at about 7 months. The prequalification exercise and the bid evaluation phase for the major contracts also encountered delays mainly because the consultant's interpretation of certain clauses was not in line with that of the Bank. These latter delays totaled four months. The change in design cannot be considered to have been within the control of the Implementing Agency or the Government. However, the Implementing Agency should have exercised control on the consultant's procurement recommendations prior to submission to the Bank. On balance the design and procurement delays of at least one year were outside the control of the Government or the Implementing Agency (KenGen).

5.1.2 The bid evaluation report for the two major contracts of Olkaria II, namely the Main Civil Works and the Electromechanical equipment, resulted in a substantial unexpected increase over the original estimate, as shown below.

Contract Estimated Bid Price, USD equivalent

OG 101, Civil Works 41,377,754OG 02, Electro-mechanical 76,817,879

Total contract price 118,195,633Original financial plan (IDA:65,346,300; KenGen

33,492,600) 98,839,900

Shortfall in financing plan 19,361,733

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5.1.3 This increase in bid prices, created an impasse for KenGen that was outside its control. This was exacerbated by the financial position of KPLC - the sole purchaser of power generated by KenGen - which was unable to make timely payments for its purchases. Deferring investments on the GRD and the KPLC components, IDA helped in bridging the financing gap pending revenue flows from KPLC after the drought of 2000. This was done by temporarily modifying the 50/50 sharing arrangement in financing the supply and installation of plant and equipment for Olkaria II (OG102) until the Government came up with a plan addressing the financing of this Project. It will be seen from Annex 8 (Disbursements) that KenGen began disbursing in the third Quarter of 2000 compared to IDA's disbursement commencement in Quarter of April - June 1998. While the failure of KPLC to meet its payment obligations to KenGen was outside KenGen's control, it was within the control of the Government to address the governance issues which were at the core of KPLC's performance problems.

5.2 Factors generally subject to government control:

5.2.1 To mobilize adequate domestic resources, the DCA covenanted self financing ratios of 25% and 20% for KPLC and KenGen respectively. The Government was slow in taking corrective action through tariffs and/or restructuring of KPLC in order to address its declining financial performance. This exposing the project to financing shortfalls. The Bank had to suspend the Credit in 1999 before the Government adjusted tariffs and before the ERB approved a bulk power supply agreement under which KenGen could sell power and collect revenues from KPLC. However, a severe drought during period of 1999/2001, the worst over the previous 50 years, rendered the tariff adjustment inadequate in addressing the financial performance issues as power sales decreased and the hydro generation had to be supplemented with higher amounts of more costly thermal power. While the impact of the drought was outside the Government's control, it had full leverage as the largest shareholder of KPLC to effect corporate governance and management reforms which would have lessened the severity of the financial crisis in the subsector. A beginning to resolve these issues was taken soon after the current government took over power following the 2002 elections. A new Chief Executive was appointed and investigations into the operations of the key sector utilities were launched The government has also approved a financial restructuring plan as part of a broader corporate recovery effort for KPLC (paras 7.5.2, 7.5.3).

5.3 Factors generally subject to implementing agency control:

5.3.1 Due to financial difficulties faced by the Implementing Agencies and procurement delays, disbursement delays were significant. Less than 40% was disbursed by February 2002 - the period when the mid-term review on the Project took place. By June 30, 2004 - the Closing Date of the Project - only 83.60% of the Credit was disbursed. On June 7, 2004 the Bank had notified the borrower that the Credit's Closing Date of June 30, 2004 would not be extended, but that further disbursements from the Credit could be made for withdrawals received at the Association's Headquarters by close of business on October 31, 2004, in respect of eligible expenditures made before the Closing Date. The Bank's communication did help in accelerating requests for disbursement. Nevertheless, an amount of about US$9,7 million (8.27% of the Credit) remained undisbursed after the deadline of October 31, 2004.

5.3.2 During periods of financial crisis, the Implementing Agency sought and obtained the support of other cofinanciers (notably the EIB) and IDA in reallocating funding to Olkaria II Power Plant, the main physical component of the project. However, the reallocations have not been fully used, particularly for contracts OG 101 (Civil Works) and OG 102 (Electromechanical equipment). Timely action to redress the situation, fully within the Implementing Agency's control, was not taken. Poor financial management of the project by KenGen, apparently the result of weak coordination between financial and technical staff, was

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responsible for this problem. The ESRP has laid substantial emphasis on strengthening financial management capacity within the implementing agencies through targeted training and support from the Bank's Country Office financial management specialists.

5.4 Costs and financing:

5.4.1 The table below summarizes the original cost estimate per Component, and the cost, in USD equivalent, at the completion of the Project.

Original Cost Estimate Component at completion

A. Sector Restructuring 3,600,000 595,810 B. Institutional Support 24,600,000 16,245,661 C. Efficiency Improvements 11,800,000 4,023,354 D..Power System Expansion (i) Generation 579,100,000 532,135,175 (ii) Distribution Upgrade 30,000,000 E. Geothermal Resource Development 49,300,000 - F. Future Project Preparation 1,500,000 -

Total 699,900,000 552,999,999

Table: Original & Estimate to Completion Costs

5.4.2 The original cost of US$699.9 million, excluding interest during construction, was expected to be financed by: IDA (US$125 million, 17.9%) ; the EIB (US$ equivalent 48.7 million, 7%); KfW (US$ equiv. 20.8 million, 3%); OECF (US$ equiv 82.8 million, 11.9%); KenGen KPLC & GOK (US$ equiv 160.1 million, 22.9%) and private investors for power plants (US$ equiv 262.5 million, 37.6%). The percentage of investment of 38% that was assumed to be funded by the private sector matches their share of capacity addition of about 39%. It is difficult to assess whether country risk premiums had been adequately factored in the cost estimates for the private sector projects. Since data on the actual investment costs by the private sector are not available, the project costs to completion in the above table reflect the original cost estimates for these investments. The reduction in project scope (notably Part D (ii), Part E and Part F totaling US$80.8 million) is the main explanation for the reduction in total project costs at completion.

5.4.3 Excluding the amount of US$262.5 million for the private investors and the JBIC (formerly OECF) original contribution of US$83.04 million equivalent for Kipevu I Diesels, and based on the disbursement information provided by the Borrower for financiers other than that of the IDA, the actual financing plan of the resulting total of US$195.8 million, in USD equivalent at completion is as follows:

IDA 107,968,107 (55.1%)lEIB 38,886,270 (19.9%)lKfW 11,734,880 (6.0%)lKenGen 24,755,411 (12.7%)lGOK 8,400,000 (4.3%)lKPLC 4,023,000 (2.0%) l

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6. Sustainability

6.1 Rationale for sustainability rating:

6.1.1 The unbundling of the power sector - the rationale for which is discussed in and 4.2.1 above - into generation, and transmission and distribution, and its ownership arrangements and the establishment of an autonomous regulatory body (ERB) are major steps forward towards ensuring the sustainability of power sector operations. A vision encompassing customer focus is emerging as evidenced by the much faster rate of connections (from average 5.8% up to 2001 to almost 10% since) per year, and the increasing productivity measured in terms of number of customers per employee (up from 73 in 2000 to 110 in 2004) are concrete signs of changes for the better. The near term action to establish business and cost centers to ensure more efficient delivery of service and accountability, and the establishment of a more transparent and risk aversive environment to encourage private sector participation are steps that will support the GoK's policy objective of providing cost-effective, affordable and adequate energy services on a sustainable basis.

6.1.2 The unbundling of KPLC into a 100% state-owned transmission entity [the rationale for which is discussed in paragraphs 4.2.1 above] and one or more entities for private-owned distribution is enunciated in the Sessional Paper on Energy (May 2004). The gradual privatization of KenGen over time by initial public offering of 30% of the equity through the National Stock Exchange is also included in this policy document, and so is the Enactment of an Energy Act to succeed the existing Electric Power Act which provides for, amongst other things, the establishment of a single independent regulator to rationalize and succeed the existing ERB. The regulator's powers on energy pricing and on Power Purchase agreements will enhance the decision making process and encourage private sector participation in the sector. The introduction of private shareholding into KenGen is aimed at mobilizing resources rather than improving corporate performance which has so far been reasonable. The resources raised will be used to support the program of developing geothermal resources or for general budgetary objectives or both.

6.1.3 These actions are indicative of the Government's commitment to provide sustainable energy services.

6.2 Transition arrangement to regular operations:

The institutions are in existence and will be restructured to meet the changing needs of the energy sector. There is therefore no need for a transition arrangement to regular operations.

7. Bank and Borrower Performance

Bank7.1 Lending:

7.1.1 Project preparation was based on a Feasibility Report prepared for Olkaria II geothermal power plant and a number of other studies that addressed the institutional and sectoral issues. The Bank also used the services of an independent expert on geothermal resource utilization to ensure that the design is robust and cost effective and environmental mitigating measures are appropriately addressed. The cost estimates were also checked against international prices for similar projects.

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7.1.2 In view of the large size of the investment program, helping the Government to mobilize financing resources was a major activity of the Bank staff involved in the Project. The procurement, financial and project management aspects were addressed during appraisal. With hindsight, the project team should have insisted on a project management team supported by external consultants for the duration of the project implementation team in KenGen. It should also have provided up-front training on procurement and project management.

7.1.3 Apart from the technical preparatory aspects, substantial Bank staff time was spent on the policy dialogue which eventually led to an agreement on an energy policy reform matrix upon which the operation was ultimately anchored. In addition, the Bank facilitated the access of Kenyan government officials to international experience with private sector participation and with regulation, through study tours and workshops.

7.2 Supervision:

7.2.1 At appraisal, a detailed plan for supervision by Bank staff was prepared and agreed upon with the Borrower. Generally, an appropriate skill mix assisted in providing timely consultation on implementation aspects, especially during its initial phases, to ensure that monitoring progress and ensuring compliance to obligations under the Credit were adhered to. The normal practice of about two missions per year was adhered to during the implementation period of the Project. Progress reporting more or less in line with Bank's requirement was done for the Major investment component - the Olkaria II power plant engineering consultant being responsible for the reporting. Cost update in US$ terms does not appear to be regular in the Progress reports. Reporting on the other components relied heavily on supervision missions. Consolidated reporting of all components was not done due to the fact that the Institutional Support Group (ISG) included in the Project was not fully effective.

7.2.2 The fruitful dialogue with the Government on sector reform and governance issues during supervision missions has made significant contribution to restructuring the energy sector in general and to the formulation of energy sector policy to guide Kenya in its medium and long term vision on energy.

7.2.3 Bank's cooperation with the EIB and KfW was instrumental in developing a cooperative approach with the Borrower without which the realization of the Project would not have been possible. In particular, Bank's dialogue with cofinanciers, notably the EIB, and the Borrower at times of financial crises has helped to ensure the realization of the Project, despite cost increases and delays.

7.2.4 Overall Bank performance during the supervision phase is rated satisfactory, particularly for the following reasons: (i) staff continuity since some key staff, including the Team Leader stayed with the team from preparation to completion, a factor which facilitated communication with government and development partners; and (ii) proactivity. With respect to the latter, the Bank's insistence on continuation and completion of reforms, and the ultimate act of suspension of disbursements in 1999 kept the reform process alive leading finally to the completion of a comprehensive energy policy in 2004; and its collaboration with EIB assisted the Government to assure completion of Olkaria II, the flagship of the project, despite financing shortfalls that had threatened to halt construction.

7.3 Overall Bank performance:

Overall the Bank's performance from preparation through supervision is considered satisfactory.

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Borrower7.4 Preparation:

7.4.1 The Borrower was assisted by consultants employed under a Bank PPF to undertake several technical and policy related studies in preparation for the project. The technical studies included the design of the Olkaria II power plant, accounting for over 85% of the original cost estimate of the Project. The policy studies covered the legal and regulatory framework, petroleum deregulation, power tariffs and organization restructuring. It will be noted that the Bank prepared a Project Concept Document in February 1988, thus marking the beginning of the project preparation process. However, it was not until December 1994 that project appraisal commenced and not until 1996 that it was considered complete after agreement had been reached with the Government on all key policy actions considered by the development partners as essential for supporting the sector. The Government's initial unwillingness to consider substantial reforms necessary for efficient least cost expansion of the power sector and mobilization of private capital was a key determinant of the protracted project preparation process. While the Government's contribution to the technical design of the project was satisfactory, the overall borrower's performance during preparation is rated unsatisfactory for two reasons. First, it took about six years from project conception (1988) to reach agreement with the Government on a broad policy program (1994) because of the government's reluctance to embrace substantive reforms. The agreement on an energy sector policy reform matrix and the execution of some initial steps triggered project appraisal in 1994. However, it took an additional two years before the appraisal process was considered complete as the Government moved slowly in implementing key steps under the energy sector policy matrix. It also took about two years for the Government to provide the Bank with a draft letter of sector policy. Second, delays were encountered when the it emerged that the Government had awarded a management contract to a domestic company without following competitive procedures for liquefied petroleum import handling facilities which were to be installed at Mombasa with IDA and EIB financing. Financiers could not agree to finance the installation of the LPG facilities under those circumstances. Finally, the entire petroleum subsector component, other than the deregulation measures which had already been implemented with PPF funding had to be removed from the project scope in order not to delay power sector investments which would have exacerbated power shortages in later years. Hence, the Government's performance during preparation is rated unsatisfactory.

7.5 Government implementation performance:

7.5.1 The response of the Government to the financial difficulties faced by the sector was slow and politically laden prior to the coming into office of the current government after the 2002 elections. Prior to 1993, the Government avoided tariff adjustments and instead opted to provide investment and operating subsidies so as to avoid negative political implications of increasing tariffs. Thus, with low electricity tariffs, there was serious deterioration in the financial viability of KPLC (and its sister companies KPC and TRDC). Resulting form the policy dialogue with development partners, between 1992-1996 KPLC base tariff was increased from Kshs.2.79/kWh to Kshs.4.46/kWh or 75% LRMC tariff. The increases generated huge cash surpluses in KPLC between 1994-1997.

7.5.2 To complete the separation of generation assets, and transmission and distribution assets and pool them into KenGen and KPLC respectively, it was necessary for a contractual seller/buyer relationship to be established between the two. As agreed during the policy dialogue, it was also necessary to ensure, based on recommendations of a tariff study, that both the bulk and retail tariffs were adequate to ensure financial viability of the two utilities. As the Government was reluctant to implement these measures, and was also slow in reaching agreements with other financiers to complete the project's financing package, the Bank had to suspend disbursements under the Credit in 1999. The ERB subsequently approved tariff adjustments and the two companies signed an interim power purchase agreement. It further approved a bulk tariff

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(non-fuel) of Kshs.2.36/kWh and an 18 per cent average increase in the non-fuel retail tariff for KPLC. Thus, despite the agreement with development partners on a policy framework, the Government continued to show ambivalence to the reform agenda during the project implementation period. The critical drought between 1999-2001 resulted in massive load shedding, an economic downturn, and substantial deterioration in the financial condition of KPLC. As a result of low revenues and increased thermal generation, operations and administration costs, KPLC suffered huge after-tax losses between 1999-2003 ranging between Kshs.1.6 billion to Kshs.2.9 billion. KenGen also suffered huge cash-flow problems as KPLC was unable to pay KenGen adequately and on time, and therefore the latter could not meet its financial obligations towards the construction of Olkaria II, thus delaying this project by almost two years. Despite the risk of failure to complete the Olkaria II Power Plant, the Government was reluctant to take strong measures to address KPLC's performance issues. The Bank and the EIB engaged the Government on Olkaria, leading finally to an agreement to re-allocate funding by the two development partners from other components. The Government agreed to provide USD$8.4 million through a supplemental budget and a further US$13.4 million from its escrowed balance under the Emergency Power Supply Project.

7.5.3 The current government took swift action after winning elections at the end of 2002 to start addressing the problems of the power subsector. In July 2003, after a series of meetings with the utilities and the Bank, the GoK indirectly injected Kshs.19.2 billion in KenGen and KPLC, through conversion of several long-term loans into preferential shares, with moratorium on dividend payments for the next seven years. With this arrangement KenGen could reduce its bulk supply charge to KPLC by about Kshs.0.60/kWh and KPLC could further reduce its debt servicing costs considerably. In addition, the Government moved speedily to institute investigations into the operations of the utilities with a view to putting in place new systems to avoid similar problems in future. The final results of these investigations are not yet available. The GoK also appointed new Chief Executives for the utilities and a new Permanent Secretary for the Ministry of Energy.

7.5.4 The Borrower's overall performance during the project is rated unsatisfactory for three reasons. First, as described above during the first four and half years, the Government under the previous administration was reluctant to address the performance issues of KPLC, despite the fact that this performance reduced the sector's ability to implement critical investments in the sector. The last tariff adjustments in 1999 and the effective separation of generation form transmission and distribution assets were completed only after the Bank had suspended the Credit. Subsequently the Bank had to suspend the Emergency Power Supply Credit in 2001 when the Government dragged its feet on implementing the measures for restructuring and management reforms in KPLC agreed under that Credit. Second, despite the importance of completing Olkaria II Geothermal Power Plant, an efficient base load plant, when KenGen failed to provide local counterpart funding and contractors slowed down, the Government preferred to use the bulk of the balance of resources under the Emergency Credit to pay hefty separation packages under KPLC retrenchment plan, than to use these resources to cover the financing shortfall on the plant. It was only after the Bank and EIB agreed to reallocate their Credits/Loans that the Government was persuaded to reluctantly allocate some funds under its budget as well as a small amount from the balance of the escrow account under the Emergency Credit. Thus, although the Government performance for the past two years under the NARC administration is laudable, the borrower's performance is rated unsatisfactory, as it was so during the greater part of the implementation period.

7.6 Implementing Agency:

7.6.1 KPLC did not comply with the self financing covenants for four out of six years of the Project's implementation period. The required 60 days for receivables was never met. This situation impacted the financial performance of KenGen - the major supplier of bulk sales to KPLC under a provisional PPA

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between the two companies. Although KenGen faced the major problem of financing its investment program, including this Project, the main financial covenants for most of the years are complied with. The direct impact on Olkaria II was a delay of about two years in contributing funds to the Letter of Credit for the Electromechanical contract.

7.6.2 Although the professional skills for design and operation are adequate, the experience on project management spanning mainly over supervision was weak. KenGen's supervision was heavily dependent on the Engineering consultant. Progress reports by the Consultant were sent to the Bank without KenGen's comment or without reference to discussions with the Consultant prior to sending them to the Bank. Weakness in consolidated Disbursement Monitoring and in updating costs led to misunderstanding in estimating amounts for reallocation, and is probably the main reason for KenGen's failure to fully utilize the Credit Funds. Considering the calibre of the staff, Bank supervision staff did not expect this to happen. KenGen's performance is thus marred by its performance on disbursement control, and is hence rated unsatisfactory.

7.6.3 KPLC did not play a major role in project management since the credit funds were diverted for use in the implementation of the Olkaria II power plant. Its effort was limited to carrying out part of the Efficiency Improvement activities. However, its noncompliance to most of the financial covenants, understandably made worse by the drought period of 2000/01, makes its overall performance unsatisfactory.

7.7 Overall Borrower performance:

The overall performance of the Borrower is therefore unsatisfactory as summarized in paras. 7.4 and 7.5 above.

8. Lessons Learned

8.1 A major element of the reform program initiated in the mid-1990s was to attract private sector investment both to help the country mobilize the substantial resources required for investment and to help improve operational efficiency. While several IPPs are now operating in the sector, the GoK is concerned with the contractual terms under the PPAs, particularly the tariffs and escrow accounts arrangements, which it considers onerous. Kenya’s inability to secure more favorable terms under the PPAs can be attributed to several factors, such as a fragile macro-economic environment, poor governance of the sector, weak financial performance of KPLC as the power offtaker under the PPAs, an inadequate track record with implementation of an autonomous regulatory framework, and perceptions of high resource risk in the case of geothermal power development. All these factors gave rise to a perception of the sector as high risk for private sector investment, thus resulting in low competition and demands for high risk premiums from those who submitted bids. A lesson learned from this experience is that while the private sector may be desirable to help a country mobilize large investment capital for infrastructure, it is necessary to ensure the overall political, macro, fiscal and regulatory environment are not perceived by the private sector as unduly high risk. A gradual reform approach, based on a comprehensive sector policy may have higher payoffs in the long-term. This approach has now been adopted in the design of the Energy Sector Recovery Project. A comprehensive energy sector policy has been approved by Parliament and the reform road map includes short term measures to improve KPLC corporate performance while simultaneously putting in place the building blocks for further unbundling of the utilities and for privatization when the market and other conditions are ready.

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8.2 Another important lesson was the recognition that, for projects involving substantial resource risk, a public-private partnership approach may be necessary to ensure successful implementation. Olkaria III Geothermal Power Plant was offered to the private sector on a competitive basis based on the requirement that the developer would conduct geothermal drilling to prove the bulk of the resource and then develop the plant to full capacity. The Government had insisted that the private sector should also take substantial risks in return for high returns, while the Bank had doubts that the private sector would respond with reasonable tariff proposals. While the developer has proven resources adequate to complete sizeable capacity (48MW instead of the original 64 MW), contractual disputes revolving around tariff levels, security package and financing are impeding progress towards full development of the plant. With hindsight, the Government has now accepted, and incorporated in its energy policy, the Bank's earlier recommendation for a public-private partnership involving public and concessional funding of exploration and steam production.

8.3 During its seven years of existence, the ERB has experienced a high turnover of its top management amid disputes with the Government about entity's managerial practices. Irrespective of the merits of either side's viewpoint, these differences undermine the perception of regulatory independence. It has been acknowledged that the ERB should not fall under the auspices of the State Corporations Act which limits its managerial and financial autonomy.

8.4 The setting up of a dedicated project implementation team, including external experts, if needed, at an early stage of project formulation is also a lesson to be drawn from the implementation of the Project. Changes in staff, especially at the early phases of implementation, will disrupt continuity of project management and must be avoided to the extent possible, especially by the Borrower. With hindsight the Bank should not have acceded to the Borrower's insistence on utilizing an all in-house staff. KenGen's use of external engineering and financial experts was discontinued after a short period, and in the Ministry the financial management specialist was terminated after only one year and not replaced. 8.5 Considering the difficulties encountered in the Implementation of this Project, especially in procurement delays and disbursement lags, recognition needs to be given to Project Launch, including training at initial phases of project implementation, whereby the following are discussed and clearly understood: (i) the objectives and the scope of the Project; (ii) performance monitoring systems and progress reporting formats; (iii) procurement guidelines and implementation schedules; and (iv) project cost formats and disbursement monitoring; (v) the provisions of the legal documents; (vi) timing and frequency of supervision missions.

8.6 Other lessons learned are the importance of: (i) having separate special accounts operated by the Project Executing Agencies (PEAs) to expedite processing of payments and avoid interest costs on delayed payments; (ii) establishing a clear arrangement for the PEAs to provide local counterpart funding, such as dedicated project accounts; and (iii) upfront training in procurement, and particularly contract administration for staff of the PEAs involved in large infrastructure projects.

9. Partner Comments

(a) Borrower/implementing agency:

THE IMPLEMENTATION COMPLETION REPORT

3.0 Assessment of Development Objective and Design, and of Quality at Entry.

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3.1 Original Objective

1. The objective of the project was to assist the Ministry of Energy in formulating and implementing major policy and institutional reforms aimed at Creating an efficient and environmentally sustainable energy sector and to Support investments needed to meet power demand, and increase operational efficiency.

The project's specific objectives were to:

· Finance investments needed to meet power demand and improve operational efficiency in the sub-sector;

· Reform the organizational structure of the power sub-sector to enable the operating entities to function efficiently and on a commercial sustainable basis;

· Create a legal and regulatory environment necessary for private sector participation in supply of electricity;

· Support the GoK's adoption of economic pricing of both electricity and petroleum products and implementation of demand and supply-side efficiency improvement measures; and

· Develop indigenous geothermal energy resources and strategy for sustainable household and rural energy development.

3.2 Revised ObjectivesNot applicable

3.3 Original Components

1. Energy Sector Restructuring and Reform: This was to support establishment of a legal and regulatory framework necessary to improve sector efficiency, reform power sub-sector including separation of generation from transmission and distribution and promotion of private sector participation in energy provision and management

2. Institutional Support: This was to support carrying out studies, advisory services and logistical support to project implementation entities.

3. Efficiency Improvements: This was to assist in reducing power losses in the KPLC system and to assist in alleviating load shedding.

4. Power System Expansion and Upgrading: This was meant to increase generation capacity and to install associated transmission facilities and reinforcement of primary distribution systems in Nairobi and coastal areas.

5. Geothermal Resource Assessment: This was meant to help develop geothermal energy resources.

6. Studies for Preparation of Future Projects: This was to support preparatory activities for the follow up projects to support least cost energy investment programme.

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3.4 Revised Components

Efficiency Improvement Component

1. Loss Reduction

· After a review carried out in 1999 on the Energy Sector Management Assistance programme (ESMAP) recommendations by the Distribution adviser for the project, the original scope of works for phase 1 of the project that included major distribution rehabilitation and loss reduction programmes in Nairobi and the coastal areas was reduced to construction of two 66/11kV substations in Nairobi, together with associated feeder links to the LV network.

· At the peak of the electricity rationing program in the year 2000, and the need to introduce Emergency power generation, the scope of the distribution component was expanded to include distribution-upgrading works that were necessary for evacuation of power from the Emergency Power Plants.

2. Upgrading of Distribution System (USD 30M)

· The slump in the tourist industry between 1998 and 2003, a major consumer of electricity in the coastal region, led to system load changes in the area, where anticipated load growth did not occur, leading to re-prioritization of project activities. At the same time the company was experiencing major liquidity problems making it difficult to provide counterpart funding for project activities, thus the scope of this component was scaled down to sixteen in Nairobi and three in the coastal region, at a total cost of USD 18.3M out of the original total of nineteen projects targeted for Nairobi area, and twelve for the Coastal region.

3. Electricity Demand Management

The KPLC expanded the scope of the Demand Management sub-component by introducing three new items to the original scope namely; Customer connection policy, prepayment metering consultancy and procurement of electronic meters to reduce losses.

3.5 Quality at Entry

The rating for quality at entry is satisfactory. The Borrower, the Bank and Co-financiers for the components agreed on contracts to be adopted for each sub-component, financing plan, and implementation arrangements for each.

4.0 Achievement of Objectives and Output

1. Energy Sector Restructuring and Reform

(i) Reform of organization, management and financial structure of power subsector:

· The operations of the KPLC and KenGen were separated in 1997 each with board, management and operational staff. KPLC assumed responsibility for transmission and distribution of electricity, while KenGen took the responsibility for public sector electricity generation.

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· KPLC was reorganized according to Price Waterhouse and Coopers (PWC) report, thus reducing divisions from 15 to 7 and regions from 6 to 4 and the general staff reduced from 7,500 to 6,500. Recruitment for the division and regional managers were done competitively.

(ii) Establishment of legal and regulatory framework necessary to improve sector efficiency. Electric power Act was revised and enacted in 1997 thus creating Electricity Regulatory Board (ERB) to perform all regulatory functions hitherto undertaken by MOE.

2. Institutional Support - Ministry of Energy

(i) Advisory Services to MoE. A Chief Economist/Policy and a Technical Adviser were recruited to provide professional and technical advisory services and support to the MoE on the Energy Sector Reform and policy activities of the project. The Financial Adviser worked for two years and his contract was not renewed. The Chief Economist was later appointed Permanent Secretary in the Ministry and no replacement was made. The Technical Advisor (Power Engineer) worked up to end of June 2004 when his contract ended.

(ii) Capacity Building for MoE. Officers from the Ministry and other project implementation support groups attended short courses as part of the capacity building efforts. The training covered 7 areas including energy assessment and regulation, project management, financial management, human resource management, procurement, environmental management and information technology. By the close of the credit, a total amount of USD 847,372 had been utilized to meet training expenses. The training was quite helpful in terms of enabling officers linked to the Credit acquire relevant and necessary skills and knowledge.

(iii) Acquisition of Vehicles and Equipment. Nine (9) computers, nine (9) printers, nine (9) Uninterruptible Power Supply and one fax machine were purchased at a cost of USD 19,864.27 under the credit through a competitive bidding process. Also three (3) Toyota Land Cruiser (Prado) were bought by the credit at a total cost of USD 72,789.90.

(iv) Study on the Standardization of LPG Cylinder Valves and Regulators. The Consultancy for this study was awarded to Sycon Frigo Consult of Denmark. The study was completed and the full amount of USD 190,554 was paid as per the contract Agreement.

(v) Solar Photovoltaic Studies. A four-month Study on solar market penetration and quality guidelines was carried out. The consultancy contract was awarded to a consortium of BCEOM of France and Energy Alternatives Africa of Kenya on October 24, 2000 for US$51,875. The firm submitted its final report in September 2001.

(vi) Household and Small Scale Services and Industrial Establishment Energy Study. A Ten-month consultancy contract was awarded to Kamfor Company Limited on December 19, 2000 for US$336,195. The final contract of the final report was received at MoE in March 2002.

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3. Efficiency Improvement

a) Loss Reduction

· Two key substations were constructed in Nairobi. By the close of the credit, procurement process for the construction of another two substations in Nairobi and four smaller substations (two each) in the Western and Mt. Kenya regions was at advanced stage. The implementation of these substations is still ongoing under a bilateral agreement between KPLC and KENGEN.

· System losses were to be reduced from 16 % to 14.5%, however the losses stood at 18.7 % by the close of the programme in 2004. Due to the non-achievement of this original objective, the company has incorporated reduction of system losses from the current 18.7% to the original target of 14.5% as a key expected outcome of the Energy Sector Recovery Project. Most of the distribution system and loss reduction projects earlier earmarked under the Energy Sector Reform Project has been incorporated into the new project.

b) Electricity Demand Management (EDM)

Two key activities were implemented, namely Energy Audit and Market Research projects. The Energy Audit project targeted sixteen selected facilities covering industrial and small commercial enterprises while the Market Research project targeted residential customers.

In addition an EDM Working group was established to assist in the implementation of the EDM program. The group received eight weeks practical training by participating in energy audit activities and a one-week classroom- workshop conducted by the Energy Audit Consultants.

KPLC staff attached to the program gained valuable knowledge in identification and quantification of energy savings and use of energy measuring instruments, use of energy saving measurements and have been able to provide post-project energy audit services to customers. Thus capacity presently exists as earlier envisaged within KPLC on energy efficiency services, and the working group has been engaged in the provision of these services since the start of EDM activities in 1999.

The Market survey carried out also provided information on customer perceptions on the company’s operations and the company has set up measures to address issues raised by customers.

There has also been an increased awareness of benefits of Energy Efficiency programs among KPLC customers and a number of them have approached the company for advisory services on energy efficiency.

4. Power System Expansion and Upgrading

· 75 MW Diesel Power Plant at Mombasa: Six diesel generators were in commercial service between 20th August 1999 and 6th October 1999 with a total output of 73.5MW. The delivery of the units was on schedule and greatly improved KenGen ability to meet system power demand especially during the 2000 drought period, which coincided with completion of the plant.

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· 80MW Gitaru 3rd Unit Hydropower Project: The unit was put in commercial service on 20th November 1999, which was 30 days from the guaranteed completion period at an output of 80 MW. The completion of the unit assisted in reducing the demand constraint in the system.

· 64 MW Olkaria II Geothermal Power Plant: The initial conceptual design envisaged a 2x32 MW plant. However, the final output realized a 2x35 MW plant. The plant units were commissioned in November 2003. The realization of the project was an achievement in development of indigenous geothermal resources.

· Connection of Two Additional Make-up Wells at Olkaria 1: The connection of the two additional wells was successfully completed. This enhanced the ability of the steam field system maintaining the plant output at the rated maximum of 48 MW. Additional steam equivalent to 16.4 MW was connected.

Thus, the implementation of the component has:(i) assisted the GoK in the expansion of the power system capacity to meet the growing demand by providing 223.5 MW; (ii) facilitation of GoK improvement of the operational efficiency in the sub-sector; (iii) contributed to GoK harnessing of the indigenous geothermal resources and provision of additional steam equivalent to 16.4 MW to run Olkaria 1 at maximum rated output.

Thus the objectives of the power system expansion component were achieved though substantial time and cost overruns were experienced during the projects implementation.

5.0 Major Factors Affecting Implementation and Outcome

The following factors affected implementation and outcome of the project:

5.1 Factors Outside the Control of Government or Implementing Agency

· The main factors which affected Olkaria II project implementation and outcomes were; the engineer's failure to issue civil drawings on timely manner and poor project management, material and labor costs increase, and some of the contractors' deployment of defective equipment at site.

· Poor telecommunication infrastructure. Telephones lines access took up to 8 months to be acquired which hindered information and data exchange.

· US Government advisory on its citizens against visiting Kenya due to perceived terrorist activities, leading to delays in the commencement of Energy project activities between April and July 2003.

· Prolonged drought which affected water levels at the hydro dams leading to severe power rationing in the year 2000, and subsequent suspension of project activities for at least one year.

· Prolonged delays between requests for No Objection and Bank responses, with a cumulative total of approximately 14 months during the project life, leading in long delays in the procurement process.

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5.2 Factors Generally Subject to Government Control

· Shortfall budget allocation for the project foreign component, delays in processing payments due to contractors, delay in granting tax exemption on materials/equipment consigned to the project, changes in interpretation of tax regulations and delays in clearance of debt repayment on past financing by donors (EIB).

· At the signing of the contracts for the project, there were adequate funds in the Credit to see the project to completion. However, the IDA funded components OG101 and OG102 had funding deficit of USD 26 Million. It took over two years to reallocate funds from EIB to IDA components and establish the necessary letters of credit to OG 102 contractor.

· The Government annual budget limits on the amount of the foreign component that was allocated for the MOE was inadequate to cover the payments anticipated from the project schedule.

· There were persistent delays in payment to contractors as document passed through Government processing system. The average delay was about 2 to 3 weeks. This resulted to cost increase to the implementing agency in form of interest penalties.

· The granting on timely manner of exemption from duties and taxes has been a major bottleneck in the efficiency of procuring project materials. This was evident during implementation of Olkaria II, Gitaru unit 1 and Kipevu I. Though the scheduled release of exemption letters to the contractors was usually within 14 days prior to goods arrival, the letters were released from periods ranging from months and others to over a year. This in effect placed additional burden to the implementing agency through additional costs on bonds and consequential attendant costs associated with delays.

· At the start of implementation of the project, the implementing agency, KenGen used to get Duty and VAT exemption. However, in the middle of the process, it was given a new interpretation of the VAT Act which required KenGen to pay VAT on its imports. KenGen being in cashflow crisis due to non-receipt of payments from its debtors, was unable to fulfill its obligations in the project leading to delays on the project and additional costs.

· Unfavorable macroeconomic and governance issues that led to the poor performance of key economic sectors such as the tourism industry, affecting anticipated load growth and leading to the re-prioritization of projects.

· Delays in the enactment to revise electricity tariffs by the Government which led to credit suspension for 3 months in the year 1999.

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5.3 Factors generally subject to implementing agency control

· The implementing agency inability to raise counterpart funds to finance the local component or agreed foreign component affected the implementation of the project. Delays in payment to contractors' resulted in slowdown on their works activities and this being a multi-contract project, interfacing became a major challenge to project manager.

· Lack of adequate personnel and skills to undertake project management affected the implementation of the project. There were only three key personnel allocated to the project which had five contract packages. The complexity of the project associated with funding problems, Government requirements to clear the goods exacerbated the management challenges to the lean project team with inadequate training.

· Poor financial performance by KPLC that made it difficult for the company to meet its financial obligations for the project.

· Expansion of the project scope by the company to meet new priority areas. This led to a request for reallocation of funds causing long delays in implementation.

· Internal restructuring process during the better part of the project life that led to frequent transfer of project functions across company departments, affecting original implementation arrangements and project implementation effectiveness.

6.0 Sustainability

6.1 Rationale for Sustainability Rating:

6.1.1 Efficient Improvement. The project was intended to sustain the technical and financial performance of KPLC through improvement of network efficiency and distribution system upgrade. By reducing network losses by 1% per annum, an estimated Kshs 200M would be recovered and this new income will be available for system reinforcement and expansion ensuring the sustainability of KPLC’s operations. KPLC system losses currently at 18.7% are still above the original target of 15% and additional measures are being undertaken to ensure continued sustainability of the company’s operations. 6.1.2 Power Expansion and Upgrading. The project component was intended to provide additional power capacity. In addition, the project was to make significant positive contributions to the Government’s budget through payment of incremental corporate taxes, dividends and interest on funds to be re-lent to the power companies. The objectives intended under the power system expansion were satisfactorily achieved. Thus the additional 223.5 MW into the system will likely continue to offer sustainability of the sector's operations and meet the objectives over the economic life of the plant. The sustainability of Gitaru unit 3 will largely be dependent on the hydrological pattern in the catchment area. The Olkaria II sustainability is likely to be realized through drilling of make-up wells for additional steam and prudent field management. The Kipevu I plant is unlikely to continue providing the intended benefit at the originally anticipated operational cost. This arises from frequent outages occasioned by technical problems on the units. The additional 16.4 MW equivalent of steam at Olkaria I will sustain the operation of the plant at the rated maximum output. Olkaria I being a base load plant with high availability, the sustainability of intended objectives now and over the economic life of the plant is highly likely. Environmental issues related to these sub-components were addressed and incorporated in all the phases of implementation taking cognizance of their future impacts.

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6.2 Transition Arrangement to Regular Operations

Transitional arrangements to regular operations for all the sub-components were put in place during the implementation and take-over of the plants. Implementing agency staff who were to man the completed plants were identified, attached to the project during implementation, and trained locally and at manufacturers works in their respective disciplines in operating the plants. Additional staff was recruited to help in the management of the plants. Adequate initial mandatory spares to commission and run the plants were procured under each contract.

7.0 Bank and Borrower’s Performance

8.0 Lessons Learned

A number of lessons were derived from the implementation of the projects under the power system expansion components. These are described below:

(i) Types of Contracts: The management of multiple interfaces across multiple contracts is difficult and expensive. More modern practice in this industry is to arrange for the contractor to manage these cross-discipline matters through the use of a single large contract, resulting in an improved risk structure and lower costs. However, it is important that a main contractor confined his direct activities to his area of expertise. For example, the OG101 contractor confines his direct activities to his area of builder, yet constructed 34 houses himself, with poor results.

(ii) Financing. This has been a project that suffered badly from the effects of a financial crisis that was mostly avoidable. It is of utmost importance on any project to have the finances fully allocated and confirmed before any contracts are signed. Failure to do so will result in time and cost overruns.

(iii) Expectations and Inter-relationship:. The project owner of needs to clearly define his expectations for the project and his project managers. Cost and time are fundamental to the main contract(s), but there are other aspects such as safety, HR, Public relations, interfaces with other government agencies, interfaces with financiers or relationships between consultants and Owner’s personnel that may not be well understood. A policy on such matters and clear statements on where responsibilities and decisions lie will assist smooth implementation.

(iv) Agency requirements for the importation process have to be better defined, with clear statements on where costs lie, the responsibilities and the risks.

(v) Closer attention to the detail of reporting requirements will avoid misunderstanding and repeat work. The Olkaria projects had two owners (KenGen and KPLC), and four financiers (GOK, IDA, EIB, KFW) with differing needs.

(vi) A policy is needed on the management of foreign exchange rates for reporting purposes, as many difficulties arose from confusion over the changing rates. This is particularly important for multiple currencies and for project duration exceeding one year.

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(vii) E-mail is a very successful powerful tool for the management of documents from various places around the world. This project has shown that the technology and techniques are mature and allow for a significantly faster and improved design review process than the traditional methods. Naturally however, the more robust the telecommunications infrastructure is, the better the result to be expected.

(viii) Successful multiple-use development of natural geothermal resources is easily achieved with careful attention to the needs of the various stakeholders.

(ix) This project had a long gestation period, and there was some reluctance to change or review 10-year-old design philosophies or decisions. Technological advances should be continually be monitored and applied to the project for the benefit of the Owner.

(x) The application of the geothermal science is now well understood. Attention to the detail of maintaining high steam purity at the turbine interface will result in long term benefits in turbine availability.

(xi) Many of the details of the interfaces between KenGen and the contractors need to be better defined, and to be consistent across contracts. For example, construction power was sold to one contractor, but was free to the others.

(xii) It is important that communication and consultation are enhanced among all teams in the project to enhance information sharing. This will greatly assist in allaying fears on the unknown (e.g. cashflow problem) and productivity can be enhanced.

(xiii) Disbursement: There were some delays in the disbursements of paid vouchers to the World Bank due to lack of competence by officers involved from the start of the project making it difficult for one to reconcile the World Bank figures and MOE figures. Later, officers were trained on how to handle the disbursement and thereafter there was a big improvement. The Project Accountant should be connected to the E-mail and have direct access to the World Bank data capture/disbursement office in order to monitor the postings of withdrawal application forms for proper reconciliation and urgent communication. A sound communication protocol is necessary to ensure that vital information is copied to relevant stakeholders as necessary.

(xiv) Financial management: It is advisable to prepare the project implementation team in advance of the project implementation especially on disbursement and accounting procedures satisfactory to the borrower and the donor.

(xv) Project Implementation Team: Accounting Officers should try to maintain their project staff for the purpose of smooth implementation of the project.

(b) Cofinanciers:

Not available.

(c) Other partners (NGOs/private sector):

Not applicable.

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10. Additional Information

26TH MAY, 2005

BORROWER'S COMMENTS ONTHE KENYA SECTOR REFORM AND POWER DEVELOPMENT PROJECT

CR 2966-KE IMPLEMENTATION COMPLETION REPORT

Part A

Overall, the report presents an accurate reflection of implementation of the Kenya Sector Reform and Power Development Project, CR 2966 – KE. The major attributes to the project include the following:

1. Both Kipevu I (75MW) plant and Sondu Miriu (60MW) hydropower plant were as result of the Project engineered reforms. It is notable that Kipevu I power plant, commissioned in 1999 greatly contributed to minimizing the impact of power shortages during the 2000/01 drought period.

2. The Electric Power Act No. 11 of 1997 came as a result of the project leading to:

· The creation of the Electricity Regulatory Board (ERB) to perform all the regulatory functions hitherto undertaken by MOE. It is now anticipated that the current ERB will be transformed to become Energy Regulatory Commission once the new Energy bill has been enacted by parliament; and

· Unbundling of KPLC into two independent entities one for generation (KenGen) and the other for transmission and distribution (KPLC). Today, the implementation of the on-going Energy Sector Recovery Project is facilitated by these new institutions. Further, it is planned that KPLC will further be unbundled into a separate transmission company to create competition in power supply to be fully owned by the Government, and a distribution company.

3. The 1999-2000 drought worsened the financial positions of both KPLC and KenGen which contributed to noncompliance with their financial covenants. Subsequently, KenGen experienced a two years’ delay in meeting its counterpart obligations, which had a direct impact on timely Olkaria II completion. The Ministry of Energy appreciated the timely intervention by both the Bank and EIB to raise the funding for Olkaria II to ensure its completion without much delay.

4. Under the Credit, support was provided to the Ministry of Energy (MOE) through training of its staff and consultancy services for the implementation of the Project. The training acquired under the project enhanced participation of staff in the policy formulation process leading to the preparation of the Sessional Paper on Energy approved by the Cabinet on May 13th , 2004 and subsequently by Parliament in October, 2004. 5. As part of the energy sector reforms under the Project, the average tariff reached nearly 100% of the Long Run Marginal Cost (LRMC) in 1999 compared to 30% in 1993. Further, KPLC was allowed to recover additional costs associated with fuel price and exchange rates fluctuations to consumers without reference to ERB.

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6. Management weaknesses in KPLC hindered full utilization of the funds provided under the Project for enhancing the efficiency of the distribution system.

(Part B, consisting of editorial comments, has already been incorporated in the main text.)

Ministry of Energy

Nyayo House

NAIROBI

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Annex 1. Key Performance Indicators/Log Frame Matrix

Outcome / Impact Indicators:

Indicator/Matrix

Projected in last PSR1

Actual/Latest Estimate

KPC Board and MD to be appointed by December 1996ERB established by December 1997 1997 1998

Regulators appointed by December 1997 1997 1998

Electricity tariffs based on LRMC and adequate to cover financial costs of supply

30% 100%

All power subsector activities commercially managed

no commercial management commercial management

Interconnected electricity sales to increase from 3,402 GWh in FY1996 to 4,500 GWh in FY2002

3,402 3,900

Number of new connections to increase annually from 406,300 in FY1996 to 540,000 in FY2002

406,300 503,400

Private sector owned generation to increase by 135 MW by 2002

135

Network losses of about 14.5% or less of net generation by FY2002

16.2 20.5%

KPLC to actively offer its customers efficiency and demand management advice by 1998at least 2 energy efficiency/demand management measures to be implemented by 1999KPLC select personnel to be trained in the design and implementation of demand management programs by 1998Appliance codes and labeling study completed by 1998

1998 2003

Customer satisfaction to be measured through annual customer surveys by KPLC petroleum prices and importation liberalized in November 1994

uncontrolled uncontrol

market-determined retail prices for petroleum products maintained

controlled prices 1994

a monitoring cell established in MoE in 1996 none 1996avoidance of anti-competitive behavior monitoring continuous monitoringmaintenance of adeqaute petroleum products supplies by oil companies

periodic shortages no shortages

invite private sector by FY1998 to develop resources and construct and operate power plant

PSP 2 IPPS in operation

strategy for household and renewable energy to be agreed with the GoK by FY1999

strategy strategy developed in 2000

local analytical capacity to be developed

Solar information campaign to be initiated by FY 1998Taxes on solar PV equipment at level with other generation equipment starting in FY1997

high taxes comparable taxes

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Output Indicators:

Indicator/Matrix

Projected in last PSR1

Actual/Latest Estimate

No information on such matrix in the PSR

1 End of project

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Annex 2. Project Costs and Financing

Project Cost by Component (in US$ million equivalent)AppraisalEstimate

Actual/Latest Estimate

Percentage of Appraisal

Component US$ million US$ millionA. Sector Restructuring Reform Sector Reorganization 3.60 0.54 15 Deregulation of Petroleum markets 0.34 0.39 114.7B. Institutional Support 23.23 16.25 69.95C. Efficiency Improvements Demand Side Improvements 4.56 0.37 8.11 Line Loss Reduction 5.70 3.32 5.61D. Power Expansion and Rehabilitation Power Generation 510.58 532.13 104.22 Upgrading of Distribution Systems 26.60 0.00 0E. Geothermal Resource Development 45.38 0.00 0F. Future Project Preparation 1.29 0.00 0

Total Baseline Cost 621.28 553.00 Physical Contingencies 36.55 Price Contingencies 42.52

Total Project Costs 700.35 553.00Total Financing Required 700.35 553.00

Project Costs by Procurement Arrangements (Appraisal Estimate) (US$ million equivalent)

Expenditure Category ICBProcurement

NCB Method

1

Other2 N.B.F. Total Cost

1. Works 50.60 0.90 0.00 84.10 135.60(26.80) (0.80) (0.00) (0.00) (27.60)

2. Goods 20.40 0.20 0.20 301.30 322.10(19.90) (0.20) (0.20) (0.00) (20.30)

3. Services 51.40 0.00 0.00 89.30 140.70Supply and Erect (41.60) (0.00) (0.00) (0.00) (41.60)4. Services 0.00 0.00 24.50 47.50 72.00

(0.00) (0.00) (24.50) (0.00) (24.50)5. Training & Studies & HES

0.00(0.00)

0.00(0.00)

9.00(9.00)

18.50(0.00)

27.50(9.00)

6. Refunding of PPF 0.00(0.00)

0.00(0.00)

2.00(2.00)

0.00(0.00)

2.00(2.00)

Total 122.40 1.10 35.70 540.70 699.90(88.30) (1.00) (35.70) (0.00) (125.00)

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Project Costs by Procurement Arrangements (Actual/Latest Estimate) (US$ million equivalent)

Expenditure Category ICBProcurement

NCB Method

1

Other2 N.B.F. Total Cost

1. Works 30.60 0.00 0.00 37.09 67.69(23.00) (0.00) (0.00) (0.00) (23.00)

2. Goods 48.03 0.20 0.20 294.44 342.87(38.03) (0.20) (0.20) (0.00) (38.43)

3. Services 29.10 0.00 19.16 29.30 77.56Supply and Erect (9.30) (0.00) (17.32) (0.00) (26.62)4. Services 0.00 0.00 16.50 27.46 43.96

(0.00) (0.00) (16.50) (0.00) (16.50)5. Training & Studies & HES

2.13(2.13)

0.00(0.00)

9.00(0.00)

8.50(0.00)

19.63(2.13)

6. Refunding of PPF 1.29(1.29)

0.00(0.00)

0.00(0.00)

0.00(0.00)

1.29(1.29)

Total 111.15 0.20 44.86 396.79 553.00(73.75) (0.20) (34.02) (0.00) (107.97)

1/ Figures in parenthesis are the amounts to be financed by the IDA Credit. All costs include contingencies.2/ Includes civil works and goods to be procured through national shopping, consulting services, services of contracted staff

of the project management office, training, technical assistance services, and incremental operating costs related to (i) managing the project, and (ii) re-lending project funds to local government units.

Project Financing by Component (in US$ million equivalent)

Component Appraisal Estimate Actual/Latest EstimatePercentage of Appraisal

Bank Govt. CoF. Bank Govt. CoF. Bank Govt. CoF.A. Sector Restructuring and ReformSector Reorganization 3.28 0.32 0.54 16.5 0.0Deregulation of Petroleum products

0.35 0.39 111.4

B. Institutional Support 6.13 18.49 15.81 0.44 257.9 2.4C. Efficiency ImprovementsDemand-side Improvements

5.37 0.54 10.1

Line Loss Reduction 6.31 0.14 0.00 4.02 0.0 2871.4D. Power ExpansionPower Generation 82.35 91.99 404.78 90.69 73.80 367.68 110.1 80.2 90.8Distribution Upgrade 29.95 0.0E. Geothermal Resource Development

19.71 17.52 12.05 0.00 0.00 0.0 0.0 0.0

F. Future Project Prep. 1.50 0.00 0.0TOTAL 125.00 158.09 414.83 107.97 86.4 0.0 0.0

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Annex 3. Economic Costs and Benefits

1. Following the discussions on the Feasibility Study Update of the Kipevu Combined cycle gas turbine and during the pre-appraisal of the ongoing Energy Sector Project, the exercise on thermal generation sources ranked geothermal as the least cost thermal option. This was based on cost comparison of the following thermal and diesel plants in the Kenya system: (i) gas turbines; (ii) combined cycle gas turbines; (iii) medium and low speed diesel plants installed at Mombasa; and (iii) oil and coal fired steam turbines. Using the screening curve method, geothermal power is the least cost power source taking account of the life cycle cost comprising the capital expenditures, O & M costs, fuel and variable costs. Based on this approach, the ranking determined at appraisal of the Energy Sector Reform project, is the following:

- geothermal (100%, @c0.0551) -combined cycle gas turbine (151)- medium speed diesel (153) -oil fired steam (160)- coal fired steam (163) -gas turbine (189)

2. The average and dry year energy balances for the next ten years, updated annually by KPLC, take into account the utilization of the full energy capability of Olkaria II. This has also been the experience on the 45MW Olkaria I geothermal power plant.

3. Costs. The total cost of the Project to completion is US$195.8 million (para 5.4.3) excluding taxes and interest during construction. The yearly current expenditure for the project cost is based on the Bank’s disbursement figures for the Credit, and from disbursement figures obtained for the EIB and KfW, KenGen and KPLC and the Government. Provision of US$ 3 to 4 million is made for interim investments, typically for make-up wells and for statutory major overhauling needs for Olkaria II units. In addition to keep the loss level at the current figure of 18.7% and supply power to customers through the lifetime of the Project, an annual investment of US$ 500,000 is included in the investment column to maintain the integrity of the distribution system and mitigate its deterioration. 3.1. O & M costs for the investment are estimated at 3 % of the total investment cost. This figure may appear low for the generation component but is compensated by the provision of interim replacement amounts in the cost column.

3.2. Benefits. The main benefit of Olkaria II is the electricity demand served at least cost. This accrues from the additional 2x35MW capacity of the geothermal power plant, equivalent to about 550GWh (conservative in relation to average availability of 95% and plant factor 96% for the old Olkaria I) additional annual energy capability. The make up wells executed under this project are rated at providing 16MW additional capacity to Olkaria I. This translates to at least 100GWh annual capability.

3.3. From the introductory paragraph, it is reasonable to assume that the Olkaria II output will be operated as base load station, utilizing its full energy capability in topping up the cheaper hydro sources from day one of its operation to the end of its lifetime. The net energy production (after losses) is arrived at on the assumption that the 18.7% loss figure as at 2004 will apply for the lifetime of the Project. No quantifiable benefits can be made to the Distribution Component, and the little investment done must have helped arrest the unavoidable increase in technical losses with growing demand. No quantifiable benefits accrue from the technical assistance (Sector Reform and Institutional Capacity Building) component except for the Engineering Services for Olkaria II plant the benefit of which is included in Olkaria II. The benefits are valued at the consumers' willingness to pay, estimated, the average of the SAR's 14 USc/kWh and the PAD for the Energy Sector Recovery Project of USc 10/kWh.

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3.4. The costs and benefits are tabulated in Annex 9. Annex 10 is a comparative table of assumptions.

3.5. Based on the above assumptions, the NPV is US$804 million at discount rate of 12%, and the benefit to cost ratio is 3.68. The economic rate of return is 19%. The SAR's economic rate of return and NPV at 12% discount rate are 17.32% and US$343 million respectively.

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Annex 4. Bank Inputs

(a) Missions:Stage of Project Cycle Performance Rating No. of Persons and Specialty

(e.g. 2 Economists, 1 FMS, etc.)Month/Year Count Specialty

ImplementationProgress

DevelopmentObjective

Identification/Preparation2/20/19883/14/1994

Appraisal/Negotiation11/21/199411/08/1996

Supervision

03/17/1998 5 MISSION LEADER (1); ENERGY ECONOMIST (1); OPERATIONS OFFICER (1); PRIVATE SECTOR DEVELOP (1); CONSULTANT (1)

S S

06/09/1999 3 TEAM LEADER (1); FINANCIAL ANALYST (1); OPERATIONS OFFICER (1)

U U

05/11/2000 3 POWER ENGINEER (2); OPERATIONS OFICER (1)

S S

03/22/2001 2 FINANCIAL ANALYST/TL (1); OPERATIONS OFFICER (1)

S S

02/11/2002 3 POWER ENGINEER (1); OPERATIONS OFFICER (1); MANAGEMENT CONSULTANT (1)

U U

02/21/2003 4 TEAM LEADER (1); POWER ENGINEER (1); OPERATIONS OFFICER (1); ECONOMIST (1)

S S

12/19/2003 3 TEAM LEADER, FA (1); OPERATIONS (1); ECONOMICS (1)

S S

ICR12/06/2004 4 TEAM LEADER (1);

FINANCIAL ANALYST (1), ECONOMIST (1), CONSULTANT (1) (POWER ENGINEER)

S S

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(b) Staff:

Stage of Project Cycle Actual/Latest EstimateNo. Staff weeks US$ ('000)

Identification/PreparationAppraisal/Negotiation 1,244,025.29Supervision 143.72 882,374.39ICR 7.00 28,500Total

SAP does not provide a breakdown of lending stage costs.

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Annex 5. Ratings for Achievement of Objectives/Outputs of Components(H=High, SU=Substantial, M=Modest, N=Negligible, NA=Not Applicable)

RatingMacro policies H SU M N NASector Policies H SU M N NAPhysical H SU M N NAFinancial H SU M N NAInstitutional Development H SU M N NAEnvironmental H SU M N NA

SocialPoverty Reduction H SU M N NAGender H SU M N NAOther (Please specify) H SU M N NA

Private sector development H SU M N NAPublic sector management H SU M N NAOther (Please specify) H SU M N NA

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Annex 6. Ratings of Bank and Borrower Performance

(HS=Highly Satisfactory, S=Satisfactory, U=Unsatisfactory, HU=Highly Unsatisfactory)

6.1 Bank performance Rating

Lending HS S U HUSupervision HS S U HUOverall HS S U HU

6.2 Borrower performance Rating

Preparation HS S U HUGovernment implementation performance HS S U HUImplementation agency performance HS S U HUOverall HS S U HU

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Annex 7. List of Supporting Documents

The following documents used in the preparation of the ICR are available at AFTEG:

Staff Appraisal Report No. 16001-KE: Kenya Energy Sector Reform and Power Development 1.Project, May 12, 1997Kipevu Combined Cycle Power Project (Kipevu CCPP): Update of Feasibility Study Report Final 2.March 2004 by Fichtner for KenGenDraft Sessional Paper on Energy (Kenya), May 20043.Draft Least Cost Development Plan 1997 and Draft of 20044.Project Appraisal Document Report No. 28314-KE on Energy Sector Recovery Project, June 10, 5.2004Feasibility Study for Geothermal Power Plant at Olkaria II, Final Report, December 1989, 6.prepared by Ewbank Preece of U.K.

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Additional Annex 8. Disbursements

ICR Kenya TOTAL -Credit 2966-Ke Yearly Disbursements

117,831,799 41,000,000 12,782,297 8,400,000 22,100,000 3,000,000

IDA EIB KFW GOK KENGEN KPLC

Quartely Cummulative

01-Apr-98 30-Jun-98 1,831,578.31 - - - - - 1,831,578.31

01-Jul-98 30-Sep-98 2,500,278.89 - - - - - 4,331,857.20

01-Oct-98 31-Dec-98 1,188,329.97 - - - - - 5,520,187.17 Year 1 total 5,520,187.17 - - - - -

01-Jan-99 31-Mar-99 497,754.68 - - - - - 6,017,941.85

01-Apr-99 30-Jun-99 85,340.13 - - - - - 6,103,281.98

01-Jul-99 30-Sep-99 - - - - - - 6,103,281.98

01-Oct-99 31-Dec-99 529,933.41 - - - - - 6,633,215.39 Year 2 total 1,113,028.22 - - - - -

01-Jan-00 31-Mar-00 - - - - 6,633,215.39

01-Apr-00 30-Jun-00 1,379,504.95 - - - - - 8,012,720.34

01-Jul-00 30-Sep-00 1,255,822.85 - 1,869,417.84 - 243,894.79 84,967.51 11,466,823.33

01-Oct-00 31-Dec-00 1,154,521.05 - 222,333.83 - 80,733.66 - 12,924,411.87 Year 3 total 3,789,848.85 - 2,091,751.67 - 324,628.45 84,967.51

01-Jan-01 31-Mar-01 11,992,998.53 5,670,173.51 599,578.97 - 360,533.09 - 31,547,695.97

01-Apr-01 30-Jun-01 6,764,320.38 - 350,634.99 8,400,000.00 146,876.74 120,586.95 47,330,115.03

01-Jul-01 30-Sep-01 4,056,968.50 - 1,289,146.05 - 592,721.55 37,758.46 53,306,709.59

01-Oct-01 31-Dec-01 6,292,539.08 - 1,249,856.80 - - - 60,849,105.47 Year 4 Total 29,106,826.49 5,670,173.51 3,489,216.81 8,400,000.00 1,100,131.38 158,345.41

01-Jan-02 31-Mar-02 8,084,320.69 - 2,085,203.33 - 1,685,725.49 64,004.58 72,768,359.56

01-Apr-02 30-Jun-02 8,061,290.82 - 384,284.01 - 2,536,360.66 66,829.93 83,817,124.98

01-Jul-02 30-Sep-02 6,454,346.51 7,093,052.71 283,603.97 - 1,612,937.88 130,578.43 99,391,644.48

01-Oct-02 31-Dec-02 3,300,461.16 9,708,864.66 687,126.29 - 2,282,342.25 156,921.84 115,527,360.68 Year 5 Total 25,900,419.18 16,801,917.37 3,440,217.60 - 8,117,366.28 418,334.78

01-Jan-03 31-Mar-03 1,913,417.52 - 266,786.16 - 1,186,150.80 245,469.64 119,139,184.80

01-Apr-03 30-Jun-03 8,590,976.29 - 244,052.15 - 1,611,947.52 688,926.53 130,275,087.29

01-Jul-03 30-Sep-03 3,673,563.10 - 677,857.97 - 567,031.00 927,668.32 136,121,207.68

01-Oct-03 31-Dec-03 3,779,319.74 - 410,208.63 - 2,472,198.44 217,056.08 142,999,990.57 Year 6 Total 17,957,276.65 - 1,598,904.91 - 5,837,327.76 2,079,120.57

01-Jan-04 31-Mar-04 9,068,882.37 - 346,337.25 - 1,275,632.73 235,527.74 153,926,370.66

01-Apr-04 30-Jun-04 6,051,237.44 - 192,077.34 - 874,406.54 58,386.00 161,102,477.98

01-Jul-04 30-Sep-04 2,965,095.92 - 183,266.69 - 3,311,735.20 856,682.75 168,419,258.54

01-Oct-04 31-Dec-04 6,495,305.01 16,414,175.16 393,108.72 - 3,914,183.64 131,989.08 195,768,020.15 Year 7 Total 24,580,520.74 16,414,175.16 1,114,790.00 - 9,375,958.11 1,282,585.57

107,968,107.30 38,886,266.04 11,734,880.99 8,400,000.00 24,755,411.98 4,023,353.84 195,768,020.15

% of total 55.15 19.86 5.99 4.29 12.65 2.06 100.00

Quarter USD equiv

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Additional Annex 9. Table of Costs and Benefits

0.813 0.12

Year 0.025

Current Constant O and M Gross Net after losses Total Benefits Total Costs Net Benefits

1997

0.98522 1998 5,520,187.2 5,438,598.8 5,438,598.8 (5,438,598.80)

0.97066 1999 1,113,028.2 1,080,372.0 1,080,372.0 (1,080,371.97)

0.95632 2000 6,291,196.5 6,016,397.0 6,016,397.0 (6,016,397.02)

0.94218 2001 47,924,693.8 45,153,688.0 45,153,688.0 (45,153,688.00)

0.92826 2002 54,678,255.2 50,755,637.2 50,755,637.2 (50,755,637.18)

0.91454 2003 25,873,725.0 23,662,556.4 23,662,556.4 (23,662,556.44)

0.90103 2004 52,768,029.6 47,545,577.7 47,545,577.7 (47,545,577.70)

0.88771 2005 500,000.0 443,855.0 4,755,344.94 294,000,000 239,022,000 28,682,640 5,199,199.9 23,483,440.06

0.87459 2006 500,000.0 437,295.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,192,639.9 52,172,640.06

0.86167 2007 500,000.0 430,835.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,186,179.9 52,179,100.06

0.84893 2008 500,000.0 424,465.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,179,809.9 52,185,470.06

0.83639 2009 500,000.0 418,195.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,173,539.9 52,191,740.06

0.82403 2010 2,000,000.0 1,648,060.0 4,755,344.94 588,000,000 478,044,000 57,365,280 6,403,404.9 50,961,875.06

0.81185 2011 500,000.0 405,925.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,161,269.9 52,204,010.06

0.79985 2012 500,000.0 399,925.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,155,269.9 52,210,010.06

0.788803 2013 500,000.0 394,401.5 4,755,344.94 588,000,000 478,044,000 57,365,280 5,149,746.4 52,215,533.56

0.77639 2014 2,000,000.0 1,552,780.0 4,755,344.94 588,000,000 478,044,000 57,365,280 6,308,124.9 51,057,155.06

0.76491 2015 500,000.0 382,455.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,137,799.9 52,227,480.06

0.75361 2016 500,000.0 376,805.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,132,149.9 52,233,130.06

0.74247 2017 500,000.0 371,235.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,126,579.9 52,238,700.06

0.73150 2018 2,000,000.0 1,463,000.0 4,755,344.94 588,000,000 478,044,000 57,365,280 6,218,344.9 51,146,935.06

0.72069 2019 500,000.0 360,345.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,115,689.9 52,249,590.06

0.710044 2020 500,000.0 355,022.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,110,366.9 52,254,913.06

0.69954 2021 500,000.0 349,770.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,105,114.9 52,260,165.06

0.68921 2022 500,000.0 344,605.0 4,755,344.94 588,000,000 478,044,000 57,365,280 5,099,949.9 52,265,330.06

IRR 18%

190,213,797.62 1,003,892,400.0 275,808,009.6 728,084,390.4

file:ICR Annex 3 Costs and Benefits.xls Benefit/Cost 3.64

Project Cost

IMPLEMENTATION COMPLETION REPORT CREDIT 2966-KE

ANNEX 3: COSTS AND BENEFITS OF THE PROJECT

Generation Olk II kWh

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Additional Annex 10. Assumptions

Item SAR Assumption ICR Assumption RemarksThe investment

-Total investment comprising:-Sector restructuring and Institutional -Generation Expansion of which:(i) Kipevu I diesel(ii) Olkaria II (iii)Kipevu II IPP (iv) Olkaria III (IPP) (v) Other IPPs(vi) Gitaru 3rd unit(vii) Sondu Mirriu

GRA

Distribution Upgrade

Total investment of US$928 million including Sondu Miriu hydro :

US$40 million

US$82.7 millionUS$112.7 millionUS$65.6 millionEstimate for IPPs, Gitaru 3rd unit and Sondu Miriu total US$627 million

US$49.3 million

US$29.95 million

Total investment of US$195.8 million comprising:

US$20.9 million

NilUS$174.9 millionNilNilNilNilNil

Nil

Nil

Includes Olk II eng of US$16.2 million

Commisioned 9/00

Commissioned 9/01Olkaria III uncertainGitaru 3/00

Not yet due until 12/07

Additional RemarkKipevu II, Sondu Mirriu, Olkaria III, other IPPs not included in DCA

Benefits The benefits from incremental electricity sales will increase as demand rises until 2013 when they will reach a plateau at the maximum generation capability of the new generation facilities, thereafter remaining constant through 2020 – the remaining economic life of the diesel and geothermal facilities. Incremental sales are valued at US cents 14 the estimated average consumers’ willingness to pay.

Based on the PAD (June 2004) for the Energy Sector Recovery Project, that made cost comparisons of thermal and diesel plants, the ranking in terms of life cycle costs comprising the capital expenditure, O & M costs, fuel and variable costs is the following:

-geothermal (100% @0.0551USc/kWh);-combined cycle gas turbine (151%); -medium speed diesel (153%) -oil fired system (163%)

The SAR’s estimate for GDP and hence demand growth appears optimistic.

The figure of USc14 for consumers to pay, though clearly explained in the SAR, appeared on the high side compared to the corresponding figure of USc10/kWh of the ESRP PAD. The average of USc12/kWh has been used in estimating benefits.

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-gas turbine (189%). The hydro plants, the cheapest sources of power do not cope with the base load either during average or dry year periods. Geothermal has been and will continue to be the energy source to supply after hydro the base load of the Kenya system. The energy output of Olkaria II is assumed to be fully utilized from day 1 of commissioning to the end of the lifetime of Olkaria II. This assumption is supported by the operational experience of Olkaria I which has a plant factor of over 95% since its commissioning.

Discount rate and willingness to pay

12% and USc14 per kWh

12% and USc12 per kWh

USc12 is average of USc14 (per SAR) and USc10 (per June 2004 ESRP’s PAD)

Concluding Remark on Costs and Benefits: 1. Plants that have either started operation before construction commencement of Olkaria II and others like Sondu Miriu to be commissioned long after commissioning of Olkaria II have been excluded. Costs to completion in 2007 are unlikely to be available but have not in any case been requested.2. It will be seen that diesel or thermal units are not included in the ICR version as explained in 1. This in part explains why the rate of return of the SAR is lower owing to higher investment costs and much higher O & M costs due to fuel costs. 3. SAR’s demand forecast was optimistic. The forecasts for 2002/03 and 2003/04 were GWh5,454 and 5,773 compared to actual GWh of 4,750 and 4,956 respectively. Corresponding figures for 2007/08 are 7,298GWh and GWh6,540 (PAD for ESRP of 6/04); and for 20014/15 GWh10,818 (SAR) and GWh10,343 (PAD). The loss figures assumed, reasonable based on past figures, were 3% to 5% lower than the resulting loss figures.

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Additional Annex 11. Financial Performance Indicators

THE KENYA ELECTRICITY GENERATION COMPANY1997/98 1998/99 1999/00 2000/01 2001/02 2002/03

Sales (GWh) 4,011 3,846 2,559 3,230 3,656 4,294 Profits before tax and dividend ('000 KSh) 184,185 5,347,168 2,475,223 3,300,223 3,300,063 3,789,213 Profits after tax and dividend ('000 KSh) 257,030 5,347,168 2,475,223 3,300,063 3,789,213 2,150,904 Profit (as above)/net fixed assets in service 6% 17% 8% 11% 14% 9%Profit (as above)/capital employed 1% 11% 4% 5% 5% 3%Cash balance 100,198 (418,715) 434,468 1,773,594 4,497,812 58,000,854 Current ratio (current assets/current liabilities) 2.5 1.4 1.5 3.0 2.4 3.0 Debt Service covenanted 1.5 times (net revenue/debt service requirements) 0.4 1.4 3.3 3.2 2 5.9Internal Cash Generation (PA: 20% for FY1997/98 & 25% thereafter) 14% 16% 26% 19% 66% 77%Detailed Financial Statements are in files

THE KENYA POWER AND LIGHTING COMPANY

Financial Performance IndicatorsFinancial Year commencing July 1998 1999 2000 2001 2002 2003

Sales (GWh) 3,564 3,366 3,091 3,498 3,654 3,940 Losses % of Net Generation 18.6 19.2 21.5 21.3 20.5 20.0Profit before tax and dividend 1,721,924 (4,155,863) (4,105,915) (2,849,115) (4,112,193) 873,684 Net Cash Balance (1,254,928) (1,978,682) (1,435,978) 788,473 1,431,626 2,453,152 Debt Service Coverage (covenanted 1.5) 5.8 (1.6) (1.4) (0.6) (0.5) 3.0 Self Financing Ratio (covenanted 30%) 82% -221% -177% -108% -138% 59%Day's Receivable (required 60) 84 76 64 63 83 70Current ratio (Current assets/Current liabilities) 2.0 1.0 0.8 1.3 1.2 1.5 Average Tariff level Usc/KWh (LRMC estimate Usc 8.65/kWh) 7.98 9.28 11.62 9.03 8.55 7.68Total customers connected 452,963 472,671 505,951 537,079 593,621 643,274 Total number of employees 7,168 7,100 6,973 6,900 6,423 6,260.0 Number of customers per employee 63 67 73 78 92 103

FINANCIAL PERFORMANCE INDICATORS FOR CREDIT 2966-KE

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