Document of The World Bank FOR OFFICIAL USE ONLY Report No: 54147-KE PROJECT APPRAISAL DOCUMENT ON A PROPOSED CREDIT IN THE AMOUNT OF SDR 217.4 MILLION (US$330 MILLION EQUIVALENT) INCLUDING SDR 19.7 MILLION (US$30 MILLION EQUIVALENT) IN PILOT CRW RESOURCES TO THE REPUBLIC OF KENYA FOR AN ELECTRICITY EXPANSION PROJECT May 3, 2010 Energy Unit Sustainable Development Department Africa Region This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENTS (Exchange Rate Effective April 12, 2010) Currency Unit = Kenya Shilling (KSh) US$1 = KSh77.25 KSh1 = US$0.012 SDR1 = US$1.5182 US$1 = SDR0.6581 FISCAL YEAR July 1 ­ June 30 ABBREVIATIONS AND ACRONYMS AFD French Development Agency AfDB African Development Bank AICD Africa Infrastructure Country Diagnostic APL Adaptable Program Lending BADEA Arab Bank for Economic Development in Africa CAS Country Assistance Strategy CDM Clean Development Mechanism CIPA Climate Change Investment Program in Africa CPS Country Partnership Strategy CRW IDA Crisis Response Window EAC East African Community EIB European Investment Bank EIRR Economic Internal Rate of Return EPC Engineer, Procure and Construct ERC Energy Regulatory Commission ERS Economic Recovery Strategy ESIA Environmental and Social Impact Assessment ESMF Environmental and Social Management Framework ESMP Environmental and Social Management Plan ESRP Energy Sector Recovery Project FM Financial Management FY Fiscal Year GAC Governance and Anti-Corruption GWh Gigawatt Hour GDC Geothermal Development Company i GDP Gross Domestic Product GIS Geographical Information System GOK Government of Kenya GPOBA Global Partnership on Output Based Aid ICB International Competitive Bidding IDA International Development Association IDC Interest During Construction IFC International Finance Corporation IFMIS International Financial Management Information System INT Integrity Vice Presidency of the World Bank IPP Independent Power Producer IPPF Indigenous Peoples Planning Framework ISO Independent System Operator JICA Japan International Cooperation Agency KAPAP Kenya Agricultural Productivity and Agribusiness Project KENAO Kenya National Audit Office KenGen Kenya Electricity Generating Company KETRACO Kenya Electricity Transmission Company KfW German Development Cooperation KJAS Kenya Joint Assistance Strategy KPLC Kenya Power and Lighting Company kW Kilowatt kWh Kilowatt hour KWS Kenya Wildlife Service LCPDP Least-Cost Power Development Program LV Low Voltage MIGA Multilateral Investment Guarantee Agency MoE Ministry of Energy MoF Ministry of Finance MoU Memorandum of Understanding MW Megawatt MV Medium Voltage NEMA National Environmental Management Authority NCB National Competitive Bidding OFID OPEC Fund for International Development OPIC Overseas Private Investment Corporation O&M Operations and Maintenance PAP Project Affected Person PCT Project Coordination Team PIT Project Implementation Team PPIAF Public-Private Infrastructure Advisory Facility PPA Power Purchase Agreement PPARB Public Procurement Administrative Review Board PPOA Public Procurement Oversight Authority PRG Partial Risk Guarantee RAP Resettlement Action Plan REA Rural Electrification Authority REMP Rural Electrification Master Plan RPF Resettlement Policy Framework SAP System Applications and Products SCADA System Control and Data Acquisition ii SDB Standard Bidding Document SHE Safety, Health and Environment department of KPLC SIL Specific Investment Loan SME Small and Medium enterprise SSA Sub-Saharan Africa SWAp Sector Wide Approach SWG Sector Working Group T&D Transmission and Distribution US cents United States Cents US$ United States Dollars VOMCR Variable Operation and Maintenance Charge WTP Willingness to Pay Vice President: Obiageli Katryn Ezekwesili Country Director: Johannes Zutt Sector Director Inger Andersen Sector Manager: S. Vijay Iyer Task Team Leader: Paivi Koljonen Program Assistant: Lily Wong Chun Sen This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. iii KENYA Electricity Expansion CONTENTS Page 1. STRATEGIC CONTEXT AND RATIONALE ................................................................. 1 A. Country Background and Sector Strategy........................................................................... 1 B. Rationale for Bank Involvement ....................................................................................... 11 C. Higher-Level Objectives to Which the Project Contributes ............................................. 13 2. PROJECT DESCRIPTION ............................................................................................... 14 A. Lending Instrument ........................................................................................................... 14 B. Project Development Objective and Key Indicators ......................................................... 14 C. Project Components .......................................................................................................... 15 D. Lessons Learned and Reflected in the Project Design ...................................................... 18 E. Alternatives Considered and Reasons for Rejection ......................................................... 19 3. IMPLEMENTATION ........................................................................................................ 20 A. Partnership Arrangements ................................................................................................. 20 B. Institutional and Implementation Arrangements .............................................................. 21 C. Communications Strategy ................................................................................................. 25 D. Monitoring and Evaluation of Outcomes/Results ............................................................. 25 E. Critical Risks and Possible Controversial Aspects ........................................................... 26 F. Credit Conditions and Covenants ..................................................................................... 31 4. APPRAISAL SUMMARY ................................................................................................. 32 A. Economic Analysis ........................................................................................................... 32 B. Financial Analyses ............................................................................................................ 35 C. Technical ........................................................................................................................... 36 D. Fiduciary ........................................................................................................................... 38 E. Financial Terms ................................................................................................................ 40 F. Social Impact .................................................................................................................... 41 G. Environment ...................................................................................................................... 43 H. Safeguard Policies ............................................................................................................. 46 I. Disclosure of Safeguards Documents ............................................................................... 47 J. Policy Exceptions and Readiness...................................................................................... 48 iv Annex 1: Country and Sector or Program Background ......................................................... 49 Annex 2: Major Related Projects Financed by the Bank and/or other Agencies ................. 60 Annex 3: Results Framework and Monitoring ........................................................................ 62 Annex 4: Detailed Project Description ...................................................................................... 70 Annex 5: Project Costs ............................................................................................................... 83 Annex 6: Implementation Arrangements ................................................................................. 84 Annex 7: Financial Management and Disbursement Arrangements ..................................... 96 Annex 8: Procurement .............................................................................................................. 113 Annex 9: Economic and Financial Analysis ........................................................................... 124 Annex 10: Environmental and Social Safeguard Policy Issues ............................................ 148 Annex 11: Assessment of Governance Risk in the Kenyan Power Sector ........................... 165 Annex 12: Project Preparation and Supervision ................................................................... 171 Annex 13: Documents in the Project File ............................................................................... 175 Annex 14: Statement of Loans and Credits ............................................................................ 177 Annex 15: Country at a Glance ............................................................................................... 179 Annex 16: MAP IBRD 37769 and MAP IBRD 37774 ........................................................... 181 TABLES Table 1: Lessons Learned and Reflected in Project Design ........................................................ 18 Table 2: Financial Partnership Arrangements by Financier and Component .............................. 21 Table 3: Implementation Responsibility by Agency and Project Component ............................. 22 Table 4: Summary of Partnership Arrangements by Generation Subcomponent ........................ 23 Table 5: Environmental and Social Safeguards Management by Implementing Agency ........... 24 Table 6: Critical Project Risks ..................................................................................................... 27 Table 7: Critical Financial Management Risks ............................................................................ 30 Table 8: Summary of EIRR Analysis for the Generation Component ........................................ 33 Table 9: Summary of EIRR Analysis for the Transmission Component..................................... 34 Table 10: Summary of EIRR Analysis for the Distribution Component ..................................... 35 Table 11: Highlights of the Financial Management Assessment................................................. 39 Table 12: Re-lending Amounts and Terms .................................................................................. 40 Table 13: Social Safeguards: Policy Documents Disclosed by Project Component .................. 43 Table 14: Environmental Issues, Potential Impacts and Proposed Mitigation Measures ............ 45 v Table 15: Status of Implementation of 2004 Energy Policy ........................................................ 49 Table 16: Electricity Sector Key Performance Data for 2009 ..................................................... 50 Table 17: Electricity Access Investment Program and the Project by Investment Category ...... 52 Table 18: Financial Projections for the Electricity Access Investment Program ........................ 53 Table 19: Supply and Demand Outlook 2004 -- 2015 ................................................................. 56 Table 20: Status of Committed Power Generation Projects to be Commissioned 2009 -- 2016 . 57 Table 21: Results Framework ...................................................................................................... 62 Table 22: Arrangements for Results Monitoring ......................................................................... 64 Table 23: First Year`s Rural Electrification Investments by Province ........................................ 76 Table 24: Connection Cost Break-down ...................................................................................... 78 Table 25: Allocation of Implementation Responsibility in KenGen ........................................... 85 Table 26: Allocation of Implementation Responsibility in KPLC .............................................. 88 Table 27: Construction Responsibility for Subcomponent C1 .................................................... 90 Table 28: Allocation of Implementation Responsibility in REA................................................. 92 Table 29: Financial Management Risk Assessment and Mitigation ............................................ 97 Table 30: Actions to Strengthen Financial Management ........................................................... 102 Table 31: Audit Reports and Due Dates .................................................................................... 111 Table 32: Results of EIRR Analysis for Generation Component .............................................. 125 Table 33: Generation Component: Economic Cost-Benefit Analysis -- Base Case .................. 126 Table 34: Economic Costs for Transmission Component ......................................................... 128 Table 35: Transmission Component -- Economic Cost-Benefit Analysis -- Base Case............ 130 Table 36: Economic Analysis Distribution Component ............................................................ 131 Table 37: Consumer Benefits for Distribution Component ....................................................... 134 Table 38: Investment Costs for Distribution Component .......................................................... 134 Table 39: Assumptions for Economic Analysis of Distribution Component ............................ 135 Table 40: Sensitivity Analysis for Distribution Component ..................................................... 135 Table 41: KPLC Income Statement, FY2004 -- FY2009 .......................................................... 141 Table 42: KPLC Technical and Commercial Performance Indicators, FY2004 -- FY2009 ..... 142 Table 43: KPLC`s Financial Performance Indicators, FY2004 -- FY2009 ............................... 143 Table 44: KPLC Performance Indicators, Forecast FY2010 -- FY2014 ................................... 144 Table 45: KenGen Income Statement, FY2004 -- FY2009 ....................................................... 145 Table 46: KenGen`s Financial Indicators, FY2004 -- FY2009 ................................................. 146 Table 47: KenGen Performance Indicators, FY2010 -- FY2014 ............................................... 146 Table 48: Assessment of Electricity Sector Regulatory and Institutional Framework .............. 166 FIGURES Figure 1: Electricity Generation (GWh) from 2002 to 2009 ......................................................... 3 Figure 2: Institutional Framework of Kenya`s Energy Sector ....................................................... 8 Figure 3: Location of Geothermal Resources .............................................................................. 59 Figure 4: Operation of the Revolving Fund ................................................................................. 91 Figure 5: Illustration of Consumer Surplus Method Calculation............................................... 132 Figure 6: Demand Curves of Peri-urban and Rural Consumers ................................................ 134 vi Boxes Box 1: Overview of Least Cost Planning for Electricity Access Scale-Up ................................. 54 Box 2: Rural Electrification linkages with Agriculture and Social Sectors ................................. 95 vii KENYA ELECTRICITY EXPANSION PROJECT APPRAISAL DOCUMENT AFTEG Date: May 3, 2010 Team Leader: Paivi Koljonen Country Director: Johannes C.M. Zutt Sectors: Power (59%); Renewable energy (36%), Sector Manager: S. Vijay Iyer Public Administration (5%) Sector Director: Inger Andersen Themes: Infrastructure services for private sector development (52%); Climate change (36%); Rural services and infrastructure (8%); Education for the knowledge economy (2%); Health system performance (2%) Project ID: P103037 Environmental category: Full Assessment Lending Instrument: Specific Investment Loan Joint IFC: No Project Financing Data [ ] Loan [X] Credit [ ] Grant [ ] Guarantee [ ] Other: For Credits: Total Bank financing: US$330 million (SDR 217.4 million). The amount includes US$30 million from the Crisis Response Window. Proposed terms: Standard IDA terms: 40 years maturity, including 10 years` grace period Financing Plan (US$m) Source Local Foreign Total BORROWER/RECIPIENT 40.00 129.70 169.70 International Development Association (IDA) 0.00 330.00 330.00 EIB: European Investment Bank 0.00 168.00 168.00 FRANCE: Agence Française de 10.00 210.00 220.00 Développement Global Partnership on Output-based Aid 5.00 0.00 5.00 JAPAN: Japan International Cooperation 0.00 323.00 323.00 Agency (JICA) GERMANY: Kreditanstalt für Wiederaufbau 0.00 84.00 84.00 (KfW) Local Sources of Borrowing Country 90.95 0.00 90.95 Total: 145.95 1,244.70 1,390.65 Borrower: Republic of Kenya. Responsible Agencies: viii Kenya Electricity Generating Company Ltd. (KenGen) Stima Plaza, Kolobot Road PO Box 47936-0100, Nairobi, Kenya Tel: (254-20) 3666000 Fax: (254-20) 3741172 Kenya Power and Lighting Company Ltd. (KPLC) Stima Plaza, Kolobot Road PO Box 30099-00100, Nairobi, Kenya Tel: (254-20) 243366 Fax: (254-20) 250067 Ministry of Energy Nyayo House PO Box 30582-00100, Nairobi, Kenya Tel: (254-20) 310112 Fax: (254-20) 240910 Rural Electrification Authority (REA) The Chancery, Valley Road P O Box 34585-00100, Nairobi, Kenya Tel: (254-20) 2341400 Fax: (254-20) 2710944 Estimated disbursements (Bank FY/US$m) FY 2011 2012 2013 2014 2015 2016 2017 Annual 4.7 39.0 90.0 96.0 66.0 22.0 12.3 Cumulative 4.7 43.7 133.7 229.7 295.7 317.7 330.0 Project implementation period: Start: June 1, 2010 End: March 31, 2016. Expected effectiveness date: September 30, 2010. Expected closing date: September 30, 2016. Does the project depart from the CAS in content or other significant respects? [ ]Yes [X] No Ref. PAD I.C. Does the project require any exceptions from Bank policies? Ref. PAD IV.J. [ ]Yes [X] No Have these been approved by Bank management? [ ]Yes [ ] No Is approval for any policy exception sought from the Board? [ ]Yes [X] No Does the project include any critical risks rated substantial or high? [X]Yes [ ] No Ref. PAD III.E. Does the project meet the Regional criteria for readiness for implementation? [X]Yes [ ] No Ref. PAD IV.J. Project development objective Ref. PAD II.B., Technical Annex 3 The Project has two development objectives: (a) increase the capacity, efficiency, and quality of electricity supply. (b) expand access to electricity in urban, peri-urban, and rural areas. ix Project description Ref. PAD II.C., Technical Annex 4 Component A -- Geothermal Generation. This component will construct 280 MW of geothermal generation capacity in Naivasha (140 MW expansion at the existing Olkaria I power station and 140 MW in the Olkaria Domes field (Olkaria IV). Component B -- Transmission. This component will extend Kenya`s electricity transmission network and construct new 132/33 kV substations. Component C -- Distribution. This component will: (a) strengthen and extend electricity distribution networks in urban, peri-urban and rural areas; (b) electrify priority loads (public facilities) in rural areas; (c) electrify urban slums; and (d) expand deferred payment mechanism for electricity connection fees. Component D -- Sector Institutional Development and Operational Support. This component will support institutional development, training, project monitoring and evaluation, and provide project implementation support. Which safeguard policies are triggered, if any? Ref. PAD IV.H., Technical Annex 10 OP 4.01 Environmental Assessment; OP 4.04 Natural Habitats; OP 4.10 Indigenous Peoples; OP 4.12 Involuntary Resettlement. Significant, non-standard conditions, if any, for: Ref. PAD III.F. Credit effectiveness: (a) The Project Agreements and Subsidiary Loan and Grant Agreements have been executed on behalf of the Recipient, the Project Implementing Entities and the Rural Electrification Authority. (b) Recipient has finalized and adopted a Project Implementation Plan satisfactory to the Association. Disbursement condition: (a) For Component B (transmission): KPLC and KETRACO have entered into and executed a Mutual Cooperation and Provision of Services Agreement, satisfactory to the Association. Financial Covenants: The financial covenants for KenGen and KPLC are the following: KenGen will meet the following annual targets: Self financing ratio 25% Debt service cover ratio 1.2 Current ratio 1.0 KPLC will meet the following annual targets: Self financing ratio 25% Debt service cover ratio 1.2 Current ratio 1.0 Accounts receivable 50 days of billings x Dated Covenants: Financing Agreement (a) The co-financing deadline for the effectiveness of the co-financing agreements is December 31, 2011. (b) The Recipient will ensure that KenGen implements Part A (6) of the Project on behalf of KETRACO and to this end, KenGen and KETRACO shall not later than September 15, 2010 enter into a KenGen-KETRACO Implementation Agreement satisfactory to the Association (the substance of this covenant is repeated in the KenGen Project Agreement). (c) In implementing Part C (3) of the Project, the Recipient shall cause KPLC to prepare and adopt not later than January 31, 2011 a Slum Electrification Output-Based Manual satisfactory to the Association. Project Agreement with KenGen KenGen shall not later than September 15, 2010, enter into an Implementation Agreement with KETRACO acceptable to the Association for the implementation of Part A(6) of the Project (this condition is the same as (b) above in the Financing Agreement. Retroactive Financing: Withdrawals up to an aggregate amount not to exceed US$3,000,000 equivalent may be made for payments made prior to this date but on or after January 1, 2010, for eligible expenditures. xi 1. STRATEGIC CONTEXT AND RATIONALE A. Country Background and Sector Strategy Economic Context 1. Kenya has substantial potential for economic growth and during the past decade most Kenyans saw a modest increase in their incomes. The country`s population of about 40 million is relatively well educated; a strong middle class is emerging; and Kenya`s geographical location is favorable to trade. Kenya`s economy is far more diversified than the economies of most other countries in Sub-Saharan Africa, which depend principally on agriculture. About 55 percent of GDP comes from services -- transport, finance, tourism, information and communications technology (ICT) and trade. Several of Kenya`s economic sectors, including services, are operating at international standards.1 An important vehicle for boosting Kenya`s economic growth and reducing poverty during the past decade was the Government`s Economic Recovery Strategy (ERS) for Wealth and Employment Creation (2003 -- 2007). The strategy emphasized job creation through sound macroeconomic policy, improved governance, and the establishment of a favorable environment for private sector development. For years prior to the ERS, the economy barely expanded, with average annual growth hovering at around one percent. In fact, between 1996 and 2001 the poverty rate actually increased -- from 48 percent to 56 percent. However, during the implementation period of the ERS, Kenya`s economy grew at an average annual rate of more than 5 percent and the latest poverty assessment (2008) shows a reduction in poverty to 47 percent.2 2. Vision 2030, Kenya's long-term development strategy, targets expanded infrastructure access as a key element in achieving higher levels of economic growth. This strategy focuses on transforming Kenya from a low-income country, at present, to a strong middle-income country by 2030. The Government has prepared a Medium-Term Plan (MTP) to implement the first phase of the strategy, covering 2008 to 2012.3 A key element in attaining Vision 2030, is reaching an average annual economic growth rate of 10 percent between 2013 and 2030. This significantly higher economic growth will require modern, efficient infrastructure facilities to expand the productive sectors of the economy and improve access to markets. To upgrade the infrastructure platform, the MTP calls for rehabilitating the road network, upgrading the railways, improving urban public transport, and expanding access to electricity and safe water. In an effort to improve equity of opportunity, the overall program gives a special emphasis to expanding the access of the rural and urban poor to basic services such as electricity, water, and sanitation. 3. A series of crises in 2008 and 2009 has impeded an initial strong trajectory in economic growth toward achieving Vision 2030. In 2007, the end-point of the ERS, the economy grew by an impressive 7 percent, showing signs of achieving the planned 10 percent average annual growth over the next two decades. However, in 2008, political unrest interrupted trade flows and discouraged tourism, which the global economic downturn, beginning in the 1 Kenya Economic Update, World Bank, December 2009. 2 Kenya Poverty and Inequality Assessment, World Bank, July 2008, report No. 44190-KE. 3 First Medium-Term Plan, 2008-2012, Kenya Vision 2030, Office of the Prime Minister, Government of the Republic of Kenya 2008. 1 same year, has exacerbated. In 2009, a severe drought diminished domestic food production and disrupted electricity supply. Higher levels of food imports increased food costs and reduced the purchasing power of the poor, leaving four million people in need of food aid. In 2008, the economic growth rate plummeted to only 1.7 percent, well below the population growth rate of 2.7 percent. However, economic growth estimates for 2009 show a rise to 2.3 percent and projections for 2010 and 2011 are 4 percent and 5 percent, respectively. Assuming full economic recovery, forecasts show economic growth of 6.3 percent in 2012. 4. The crises have led to a worsening public finance situation that has made it difficult for the government to fully implement its development program. The spillover effect of the global financial crisis also slowed export growth, tourism receipts, remittances and private capital inflows. Tourism revenues, which account for about 5 percent of GDP, declined by 35 percent in 2008 and the sector is still operating below its 2007 level. The horticultural industry (cut flowers, fruits, vegetables) one of the fastest growing agricultural sub-sectors, contributing more than 10 percent of total agricultural production -- has weathered the political crisis but not the global crisis. Production contracted by 7 percent in the first half of 2009. These factors combined have reduced Government revenues and for 2009/2010, the Government projects a budget deficit equivalent to 6.6 percent of GDP, compared to only 1.7 percent in 2006/2007. Noting this surge in the deficit, the IMF Staff Report for the Article IV Consultation (January 2010) expresses concern for Kenya`s fiscal position. While recognizing the need for additional expenditures to support economic recovery and protect the people most vulnerable to the economic downturn, the IMF has recommended that such expenditures not increase the deficit to the equivalent of more than half a percentage point of GDP. Consequently, concessional loans and grants, including resources from the IDA Crisis Response Window (CRW), have become a more important part of the Government`s budget to protect core spending on infrastructure, health, education, social safety nets, and agriculture. 5. Kenya's vibrant private sector has been the main source of economic growth, driven by expanding services, but the country faces serious infrastructure constraints. The private sector has been particularly active in telecommunications and transport. In transport, Kenya`s geographical location is a considerable advantage. A major asset is the country`s port of Mombasa, which serves as a distribution hub for manufacturers in landlocked, neighboring countries. Kenya also has benefitted from the introduction of the East African Community (EAC) Customs Union, with exports to the EAC doubling over 2002 to 2007 and imports quadrupling over 2004 and 2007. Nevertheless, internal infrastructure bottlenecks, especially in electricity supply and transport, have prevented Kenya from maximizing its potential for private sector-led growth. Of particular concern is that the manufacturing sector, which represents 11 percent of total economic activity, and whose competitiveness depends heavily on such infrastructure, is showing signs of stagnation. 6. Unreliable electricity supply lowers the annual sale revenues of Kenyan firms by about 7.0 percent and reduces Kenya's annual GDP growth by about 1.5 percent. This finding of the multi-donor Africa Infrastructure Country Diagnostic in 2008, noted Kenya`s underinvestment in the power sector. The resulting lack of reliable generation capacity increases the cost of doing business, undermines competitiveness, and diminishes trade prospects. Without infrastructure constraints, manufacturing would likely provide employment opportunities for nearly one million Kenyans entering the labor market every year. In addition, 2 the Bank`s Poverty and Inequality Assessment of 20084 concluded that improved infrastructure access is associated with movement out of poverty. Yet the capacity of electricity infrastructure to support a major expansion in Kenya`s economy has been declining. As Figure 1 indicates, rapid demand growth has led to a supply shortfall in recent years. Planned additions to generation capacity have not been sufficient to meet the shortfall. Consequently, since 2006, "emergency" high-cost diesel units have been contracted increasing the share of such electricity generation in the total to 14 percent in 2009. Figure 1: Electricity Generation (GWh) from 2002 to 2009 Source: KPLC annual reports 7. Kenya has a mixed record on governance but the overall trend in developing a culture of accountability is positive. In comparison to the country`s peers, Kenya scores well on voice, regulatory quality, revenue mobilization, public administration, and macroeconomic and budgetary management. However, on rule of law and control of corruption, Kenya scores well below the norm for lower-income countries and for Sub-Saharan Africa5. On the positive side, public financial management, particularly audit capacity, has improved. Kenya also has made progress on public sector reform and results-based management. However, poor governance, particularly corruption, remains a source of risk for any investment in Kenya. Episodes of grand corruption in the last two decades illustrate the difficulties that elite capture presents in Kenya, and prosecution at the highest level has not been forthcoming. At the same time, the ongoing National Dialogue and Reconciliation Process has created the opportunity and some momentum for needed governance reforms. The Government has established many 4 Kenya Poverty and Inequality Assessment, World Bank, July 2008, report No. 44190-KE. 5 See Kenya`s Actionable Governance Indicators (AGIs), which draw on the Bank`s CPIA ratings, the Worldwide Governance Indicators, Doing Business, PEFA indicators and other sources. 3 entities dedicated to implementing the reforms and the technical work has already begun.6 In addition, the Government has passed a considerable amount of legislation to combat corruption7, including an Anti-Money Laundering Law but not a much-needed reform of information bill. Many of these programs have yet to produce concrete results. However, Kenya`s independent media and strong civil society are major assets in the drive for improved governance and accountability of public officials. Key Issues in the Electricity Sector 8. Heavy dependence on hydropower for electricity does not provide the reliability needed for an expanding economy. Currently, of the total installed capacity of 1,310 MW, hydropower accounts for about 56 percent, with thermal capacity at 31 percent and geothermal capacity at 13 percent. However, due to extreme drought during 2007 -- 2009, nearly half of the hydro capacity was not available for part of 2009. As a result, extensive load shedding in the public electricity system occurred between August and October 2009. In order to meet demand, the Government has contracted with providers of emergency generation capacity. This capacity -- consisting of containerized units running on diesel oil -- has a relatively rapid installation time but the cost of power from emergency units is more than double that of geothermal units. In FY2008/2009, the cost averaged about 23 US cents per kWh compared to 9.2 US cents per kWh for power from geothermal units. Thus, the recent power crisis has underscored the high cost of reliance on hydropower and the consequent need to diversify sources of power supply. 9. Kenya's abundant geothermal energy is a viable alternative to hydropower as the main source of power but most of the resource base remains undeveloped. In addition to being a renewable energy source, the main advantages of geothermal energy are its reliability, absence of fuel cost, and long plant life. Kenya`s geothermal resources potentially could support power generation capacity of about 7,000 MW. However, after 25 years of development, geothermal generation capacity is currently only about 198 MW (including a 35 MW unit scheduled for commissioning in May 2010). The Project will boost the power sector`s ability to support Kenya`s economic growth by adding 280 MW of geothermal capacity, which will more than double the current capacity. As a result, by 2015, Kenya`s electricity generation capacity from geothermal power will amount to 478 MW and will be equivalent to nearly 20 percent of the country`s total installed capacity, reducing Kenya`s dependence on drought-prone hydropower. 10. The present capacity of the electricity transmission and distribution (T & D) systems is inadequate to support major increases in connections without substantial 6 These include the Committee of Experts on the Constitution, the Truth Justice and Reconciliation Commission, the Independent Interim Electoral Commission, the Independent Interim Boundaries Review Commission, and the National Cohesion and Integration Commission. 7 These include the 2003 Public Officer Ethics Act, which introduced a code of conduct and asset declaration for public officers; the 2003 Anti-Corruption and Economic Crimes Act, which established the Kenya Anti-Corruption Commission; the 2004 Government Financial Management Act; the 2004 Public Audit Act; the 2005 Privatization Act, which increased accountability and transparency in the privatization process; the 2006 Statistics Act, which established an independent statistics bureau; the 2005 Public Procurement and Disposal Act, which established the Public Procurement Oversight Authority; and the 2009 Proceeds of Crime and Anti-Money Laundering Act. 4 investments. The T & D networks have limited coverage and inadequate capacity to transmit electricity from power plants to customers. This has led to unreliable electricity service and unnecessarily high technical losses in the public electricity system. The reasons for these conditions include underinvestment over a long period of time and the narrow focus of service expansion to rural areas without a matching effort to strengthen the backbone transmission and distribution networks. In a 2007 survey, manufacturing firms cited the lack of reliability coupled with the high cost of service as the third highest barrier (after tax and transportation) to business in Kenya. The ongoing Bank-financed Energy Sector Recovery Project (ESRP) is helping to upgrade the distribution networks in major demand centers and other development partners have recently provided financing for transmission lines. However, a much greater effort will be necessary to increase reliability and reduce losses in line with international best practice. 11. The low level of electricity access constrains the achievement of national socioeconomic objectives, which emphasize greater equity of opportunity. Electricity access in Kenya is extremely low when compared to the country`s peers. The countrywide access rate (defined as households with a connection to the national power grid) is presently about 20 percent, which is far below that of other African countries with a similar income level. For example, Ghana has per capita income of US$590, which is 4 percent lower than that of Kenya (US$680) but more than 50 percent of its population has access to electricity. The Government has set a target of 40 percent household access by 2020 to enable the planned level of economic development and to reduce imbalances among regions and between urban and rural areas. 12. The high cost of electricity service is an obstacle to the expansion of electricity access to lower-income households. The increased access of lower-income households to electricity will help to improve equity in the opportunity to raise incomes and enhance the quality of life. However, many households will not be able to pay for access without programs to make electricity affordable. The cost of household connection, paid up-front to KPLC, starts at around KSh 35,000 (about US$460), which is prohibitive for many of the target households. In addition, once connected, a modest amount of grid electricity (200 kWh per month) costs about 19 US cents equivalent per kWh, which can absorb an estimated 20 percent of the monthly budget of lower-income households. The costs are high because of the substantial investments needed to build new generation, transmission and distribution facilities, combined with the high operating cost of electricity supply, as discussed earlier. Sector Strategy, the Government's Electricity Access Program, and the Project 13. The Government's strategy for expanding electricity infrastructure to support the achievement of Vision 2030 simultaneously addresses all of the above issues. The guiding principle of the Government`s strategy for expanding infrastructure in the electricity sector, which the Project's design reflects, is to "promote equitable access to quality energy services at least cost while protecting the environment. The strategy has three elements: (a) an increase in electricity generation capacity to eliminate supply shortages; (b) the expansion and upgrading of the transmission and distribution networks to enhance the quality and reliability of supply to customers; and (c) the extension of affordable household electricity access, with particular attention to reducing regional imbalances in the country. Furthermore, in line with global environmental concerns, a cross-cutting theme of the strategy is promoting the use of green 5 energy (low-carbon sources) for electricity generation where feasible, along with improving efficiency in the supply and end use of electricity. 14. To implement the strategy, the Government has prepared the Electricity Access Investment Program 2009 -- 2014 (the Program). The Program integrates the results of three separate planning studies: the Least-Cost Power Development Program (LCPDP) 2009 -- 2029 (for generation capacity development); the Rural Electrification Master Plan; and the Kenya Electrification Investment and Policy Prospectus. The investments included in the Program cover all three elements of the Government`s strategy for electricity development simultaneously -- capacity expansion, enhanced security, and increased access. The cost estimate for the Program, over a five-year period, is US$4.9 billion (see Table 17 in Annex 1). 15. The Program is transformative on several levels and takes a sector-wide approach in its support. There are two aspects to the transformative nature of the Program. First, it focuses on gradually changing the base source of electricity from hydropower to geothermal power, also a renewable energy source but more secure than the drought-prone hydro-based system. Second, it recognizes the need to incorporate, in new connection programs, a process of continuously evaluating the capacity and operational requirements of the generation, transmission and distribution systems as the number of customer connections increases. In the past, the access expansion program has focused on new connections without sufficient, parallel attention to the new capacity needs. 16. The Program addresses the affordability of electricity access. A three-pronged approach, which the Project supports, will help make electricity access more affordable. First, concessional financing for investments in expanding the capacity of geothermal-based generation will help mitigate medium-term increases in the cost of electricity. Over time, geothermal capacity is less costly to run than the current, fossil fuel-backed, hydro-based system. Second, concessional financing for extending transmission and distribution lines combined with improved operational efficiency should help contain the cost of electricity service to the consumer. Third, the sector policy has facilitated several measures to meet the Government`s social objective of increasing the affordability of electricity without compromising the sector entities' profitability, which is a prerequisite for sustainable energy services. These include the establishment of the Revolving Fund for deferred connection fee payments with donor funding, commercial bank loans for connection fees, and a life-line tariff for household consumption of less than 50 kWh per month, the cost of which is covered from other electricity consumers. 17. The Program is financially viable. The preparatory work for the Project included a detailed assessment of the financial viability of the overall investment Program that the Project supports. This assessment concluded that, based on current real tariff levels, the public sector electricity companies will generate enough income to contribute to the capital costs of new investments and service future loans from operating cash flows (see Annex 1, Table 18). 18. The Government has secured financing for about 72 percent of the Program's total cost. The Project will finance US$1.4 billion or about 28 percent of the Program's cost. The Government's contribution to the Program will be around US$1.5 billion (between US$250 million and US$300 million per annum). This is a small share (3 percent annually) of the Government`s budget, which is about US$10 billion per annum. KenGen and KPLC will finance 6 about US$0.5 billion from their own resources. The investments by independent power producers, estimated to be US$0.5 billion, will support the construction of various generating plants in the LCPDP. 19. Following a donor conference on October 22, 2009, at which the Government presented its Prospectus for the Program, development partners confirmed funding of US$1.5 billion for the Program in addition to their contributions to the Project. There is a residual funding gap in the Program of about US$1.5 billion. The Government is confident it will be able to fill the gap through its own resources combined with contributions from its development partners, KenGen and KPLC. Most of the financing from development partners will be on concessional or semi- commercial terms. The projected repayment obligations on these loans are below the sector entities` net operating cash flows in the medium term, indicating the financing risks are relatively low. The alternative, to raise non-concessional financing, would pose significant risks since the repayment terms for commercial borrowing would be significantly above the net operating cash flows. 20. The Project supports key components of the Program critical to the expansion of electricity access. In deciding which investments of the Government`s Program to support, the project team first took into account the need to ensure sufficient and timely capacity expansion and then considered which investments in T & D would contribute significantly to the Government`s five-year target of connecting one million new customers. The geothermal capacity additions that the Project will support are the most urgent public sector generation investments up to 2015. Unlike other generation projects in the Program, concessional financing amounting to about US$900 million (IDA inclusive), which IDA will help mobilize, is essential to these capacity additions. For the other projects in the LCPDP a combination of private financing, guarantees, and local capital should be sufficient. Electricity Sector Reforms 21. Major reforms in the electricity sector have established an efficient, transparent, institutional framework to manage the Program. The reform of the electricity sector in Kenya has progressed much farther than reform programs in most other Sub-Saharan countries and provides a firm foundation for a major expansion of electricity service. The Government established its long-term vision and policy framework for the sector in the late 1990s and early 2000s, culminating in the 2004 Energy Policy and the 2006 Energy Act. These two milestones in sector development have established an effective framework for enabling the commercial viability of electricity companies and have opened the door for competition in the electricity market. 22. The elimination of the Government`s monopoly on the power industry in the late 1990s led to the creation of the Kenya Electricity Generating Company, Ltd. (KenGen) for power generation and the Kenya Power and Lighting Company, Ltd. (KPLC) for electricity transmission and distribution. These public companies, which are listed on the Nairobi stock exchange, operate on a commercial basis and have private share capital, although the Government holds the majority of shares. A further separation of functions led to the creation of the Kenya Electricity Transmission Company (KETRACO), in late 2008, with a mandate to plan, build, and operate new transmission assets. The independent Energy Regulatory Commission 7 (ERC), created in 2007, regulates wholesale and retail tariffs and issues licenses. The ERC also formulates and enforces environmental, safety, and quality standards. A separate Energy Tribunal hears appeals to the decisions of the ERC. 23. In addition to KenGen, KPLC, and KETRACO, two specialized companies have emerged in recent years. The Rural Electrification Authority (REA), established in 2006, is in charge of planning and implementing rural electrification. The Geothermal Development Company (GDC), which began operations in 2009, has the primary responsibility for determining the viability of geothermal resources through exploratory drilling and technical studies. Figure 2 illustrates the institutional framework and Annex 1 describes the key sector institutions in more detail. Figure 2: Institutional Framework of Kenya's Energy Sector Policy & Ministry of Energy Planning Licensing & ERC Regulation Geothermal Rural GDC Exploration & Electrification REA Development Planning & Construction Electricity Electricity Transmission Generation & Distribution KenGen Power Purchase KPLC KETRACO Agreements IPPs CUSTOMERS 24. The reform program already has resulted in major operational improvements. The annual rate of new electricity connections increased from 43,000 per year in 2003/2004 to around 200,000 in 2008/2009. Kenya now has five Independent Power Producers (IPPs) that account for about 25 percent of installed capacity. Tariffs are set to recover costs and there is a special feed-in-tariff to promote renewable energy generation. Due to more efficient operations, losses in the power system declined from 18.8 percent in 2003/2004 to 16.3 percent in 2008/2009. 25. Complementing a successful reform of the domestic electricity market is the Kenya Joint Assistance Strategy (KJAS) for better management of external assistance. This strategic framework, set up in September 2007, currently consists of 17 major development partners, including the World Bank, who have agreed to channel their assistance to all sectors of the economy through a common strategy between 2007 and 2012. The KJAS partners have signed agreements with the Government on partnership principles. The KJAS Working Group 8 on Energy, currently chaired by Agence Française de Développement (AFD), is an effective forum for enhancing the development impact of available resources through better alignment of assistance programs with Government`s priorities and for dialogue with Government on the implementation of its energy strategy. The Working Group on Energy has helped to mobilize financial support for the Project from five donors and coordinate agreements on project design, harmonization of conditions, and the preparation process. Governance and Social Accountability in the Project 26. The overall governance situation in Kenya is fragile but in the electricity sector governance risks are considered moderate. Kenya is one of the priority Governance and Anti- Corruption (GAC) countries where the Bank is supporting work on strengthening country systems and accountability in financial management. This work has produced excellent initial results with the Government playing a leadership role. The Government has improved its audit capacity. Fiscal planning, and management reforms, such as an integrated payroll and personnel database have improved macroeconomic management8. In some sectors, the capacity to hold the executive accountable remains low and the control of corruption is a challenge. However, the project team, with advice from the Preventative Services Unit of the Integrity Vice Presidency (INT), has assessed the governance risk in the electricity sector as moderate (Annex 11), for the following reasons: The regulatory framework is robust and resistant to interference. The negotiations for tariff-setting and power purchase agreements are transparent and ensure the pass-through of non-controllable costs, such as fuel costs, to ensure financial sustainability. Recent bid invitations under ESRP have resulted in a good number of bidders and competitive prices. For example, an invitation to bid for the construction of substations resulted in a large number of bids, including Kenyan companies and foreign companies from Asia, Europe, Northern Africa and Southern Africa. Most bid prices were at or below budget estimates, though some bids were much higher. A recent request for expressions of interest in conducting a feasibility study attracted responses from 20 reputable companies. Bid prices were slightly below budget estimates. Procurement oversight mechanisms have been invoked on several major contract awards, leading to greater confidence in the procurement processes. The partial privatization of KenGen and KPLC and their listing on the Nairobi stock market have created conditions for improved corporate governance and management. Furthermore, any regulatory decision that would impair their financial performance is market assessed and is reflected in their bond and stock prices. 8 Kenya Country Partnership Strategy for 2010 - 2013, Report No. 52521-KE. 9 27. The Project's design incorporates elements for improved governance and social accountability, including a strategy for enhancing communications among stakeholders. The Project`s anti-corruption measures take account of the Bank`s 2006 Anti-Corruption Guidelines. The principal governance and anti-corruption measures, by functional area of the Project, are as follows: Procurement of goods and services. The procurement of most of the Project`s materials and works will be through International Competitive Bidding (ICB). As indicated in the agreed procurement plan in Annex 8, the Bank`s prior approval is required at all key stages of the procurement process. International consulting engineers will assist the implementing agencies in the procurement of major contracts and supervise implementation (including certification of contractor payments). The use of supervisory consulting engineers in addition to the Bank`s prior reviews will help assure integrity in procurement by checking that specifications used for the various procurement packages are not biased or limit competition. Furthermore, the Bank has engaged an independent procurement consultant to review the procurement plans, and assist in the review of bid documents and bid evaluation reports. Increased transparency in bidding will result from advertising the bidding in local newspapers and on the websites of the implementing entities. Development partner-financed procurements will be advertised also in UNDP Development Market, Dg Market, and European development journals. All bids will be opened in public. IDA-financed contracts under the Project will use the World Bank`s procurement guidelines.9 Financial management. The Bank will closely monitor the action plans of the implementing entities in response to financial management issues raised in the FY2009 Management Letters.10 The Project will provide the implementing entities with training in financial management. In addition, the Bank`s Implementation Support Plan for the Project envisages enhanced monitoring of financial management and procurement. The budget will include five staff weeks per year of both financial management and procurement specialists. Anti-corruption measures. All sector entities have established corruption prevention committees and trained Integrity Assurance Officers, which Government policy requires under the Public Sector Integrity Program. The main sector institutions also have established, in easily accessible public areas, reporting boxes and telephone hotlines for corruption-related tips and complaints. The annual performance contracts between the Government and KenGen, KPLC, KETRACO, REA and MoE require these entities to report on anti-corruption measures they have taken. 9 The Bank`s energy sector team has fully decentralized to Kenya and is working closely with the client. World Bank staff will review all key stages of the procurement process, contract management, including proposed variation orders, and will be alert to red flags of collusion/bid steering and other behavior leading to mis-procurement and poor contract management. The Bank`s supervision team will require that the consultants monitor and ensure compliance with contract specifications. The supervision team, where necessary, shall request for independent technical audits at various stages of implementation such as at reviewing of the factory and site acceptance tests in addition to site inspections. The Bank`s technical staff will inspect, at least once a year, progress at the various Project sites. 10 A report compiled by the entities` Auditors on internal control issues of the entities. 10 Communications strategy, citizen voice, and accountability. The communications strategy focuses on providing timely and accurate information to the Kenyan public. Summaries of the Project`s quarterly progress reports will be available to the public. The Project will strengthen citizen voice and accountability in the provision of electricity service through third party monitoring and reporting of the Project`s progress. The Project will support the work of ERC, the key oversight agency in the energy sector, in promoting transparency. KPLC already conducts annual customer satisfaction surveys and plans to make summaries of them available to the public. Finally, KenGen and KPLC will engage independent evaluation panels to monitor the progress of the implementation of their respective resettlement action plans. Analytical work. The Bank, as part of its overall macroeconomic dialogue, plans to conduct an evaluation of potential governance impediments to achieving the sector`s development objectives. B. Rationale for Bank Involvement 28. The Bank has been deeply engaged in the electricity sector since 1981 when it supported the inception of geothermal generation development. The Bank also was closely involved in the design of the reform program in the power sector, which the Government launched in 2003. The Bank has excellent working relationships with the main sector entities who have gained good experience of Bank processes and procedures, most recently through the ongoing Energy Sector Recovery Project (ESRP). Under ESRP, the Bank is supporting similar investments to those of the Project, though on a smaller scale. ESRP`s performance indicators show satisfactory progress in achieving the Project`s development objectives. All these factors demonstrate that the Bank`s past engagement in the sector has been a force for positive change and that it can continue to be influential in maintaining the sector on a sustainable development path. 29. IDA support for the project will mobilize significant additional concessional financing. IDA`s provision of US$330 million will attract financing from four development partners and the implementing entities to support a major power development project costing US$1.4 billion, achieving a leverage ratio of 1:4. EIB, KfW, JICA and AFD have pledged about US$800 million equivalent in co-financing for the Project. 30. The Project's technical assistance component will facilitate the next phase of sector reform. The key technical assistance activities will help increase private sector investment through the preparation of model power purchase agreements and outreach. It also will enable the establishment of an independent power system operator, strengthen investment planning through the transfer of know-how in the application of planning tools, improve tariff design and facilitate medium-sized renewable generation through feasibility studies and regulatory support. 31. In addition to improving the performance of Kenya's power system, the Project will facilitate regional integration of Eastern Africa's power systems. The Project`s support to regional power trade will be two-fold. First, it will help develop the capacity of KETRACO, which will be the company in Kenya in charge of operation of the interconnecting transmission lines. Second, it will develop geothermal resources, allowing Kenya to become an active energy 11 trader in the region, instead of just a buyer. The Uganda-Kenya Interconnector, supported by AfDB and JICA, will be the first phase in the creation of a transmission line backbone for inter- country power transfers in Eastern Africa. Regional interconnection will eventually increase power purchase and sales options for Kenya and other Eastern African countries such as Uganda, Ethiopia, and Tanzania. 32. The provision of IDA funding for the Project will leverage several programs that the World Bank Group has launched for supporting private sector participation in the power sector. These initiatives consist of the following: The Climate Change Investment Program in Africa (CIPA), which is promoting energy efficiency, renewable energy, and cleaner production through financial intermediaries. The IFC/World Bank Lighting Africa Initiative, which is supporting the private sector to increase uptake of off-grid lighting products by households11. The IFC`s support of private sector development in the power sector, coordinated with IDA`s assistance and the Government`s overall strategy. IFC financed the first independent power producer (IPP) in Kenya, following support from IDA in the late 1990s to introduce the participation of private electricity producers. IFC currently has a mandate to arrange debt financing for a thermal IPP, and it will potentially be involved in the financing of a second IPP. IDA is considering a Partial Risk Guarantee (PRG) for these IPPs. IFC also expects to play a role in financing one or more of wind powered IPPs. IFC could provide KPLC with its first loan on commercial terms. MIGA`s guarantee for the country`s only private geothermal project developer (Ormat`s 48 MW in the Hell`s Gate National Park)12. 33. The use of concessional IDA financing for the Government's Electricity Access Investment Program is justified in light of the very low rate of household access. The low access rate (20 percent) reflects the state of underdevelopment of the electricity transmission and distribution networks. The Government`s Electricity Access Program will not be financially sustainable without concessional financing of almost US$1 billion from donors over the next five years. 34. The Project will benefit from the Crisis Response Window (CRW) resources designed to mitigate the impact of the global financial crisis. CRW resources (US$30 million) will support the Project`s Distribution Component. This component targets the connection of households in urban, rural and slum areas. The use of CRW resources and IDA funds will allow the Government to retain provisions of the tariff policy that will make electricity affordable to poor customers. These are the lifeline tariff of 2 KSh (equivalent to 2.6 US cents) per kWh of consumption for households consuming less than 50 kWh per month and the 11 This initiative aims at reducing market barriers and providing market information, capacity-building services, and financing for the production and marketing of renewable energy-based lighting products for low-income consumers. Kenya is a pilot country for this initiative. 12 It may consider additional guarantees for an expansion of geothermal capacity. 12 connection charge of KSh 1,160 (equivalent to US$15) for households in slums. An analysis of the financing options for the Electricity Access Investment Program (see Annex 1) found that residential electricity tariffs would need to increase by 10 percent to meet repayment obligations in the sector if only commercial lending sources financed the Project. C. Higher-Level Objectives to Which the Project Contributes 35. The Project is in line with the need for infrastructure improvements necessary to support Kenya`s Vision 2030 for economic and social development. To compete in the world economy, Vision 2030 recognizes the need to reduce the cost of doing business in Kenya. This is especially important in the sectors expected to be the key drivers of economic growth, which include offshore services for global corporations and light industrial developments for the regional (East African) market, particularly in agro-processing and tourism. By improving the quality of electricity supply, the Project will reduce the cost of doing business in these key sectors. Furthermore, the Project`s priority attention to the expansion of renewable energy will contribute to supporting the Government`s environmental objectives. 36. The Project supports all of the economic and social development themes of the Bank's Country Partnership Strategy (CPS) for 2010 - 201313. The Project is the flagship operation in the Bank`s program for Kenya in FY2010 and the largest project the Bank has ever prepared for Kenya. It contributes to advancing the theme of unleashing Kenya`s growth potential by expanding electricity infrastructure that is constraining growth. By targeting public facilities and low-income, peri-urban and rural households for electrification, the Project supports the theme of reducing inequality and social exclusion. By promoting renewable energy, the Project supports the CPS theme of managing resource constraints and environmental challenges. The Project will contribute to the achievement of the following CPS outcomes: (a) improving core infrastructure, especially in roads, electricity and water supply (Outcome 1.2); (b) expanding access to health care, education and basic infrastructure services (Outcome 2.1); and (c) adapting to climate change (Outcome 3.2). 37. The Project's technical assistance activities are consistent with the CPS theme of the Bank's role in transmitting global knowledge. The training and transfer of power planning models will enhance system-planning capability within the MoE, ERC and the power companies. The assistance will also provide a sound foundation for decisions on the future economic development of the power system. 38. The electrification components of the Project will help to improve the quality of life, particularly in poor areas of Kenya. This improvement will come from either direct electricity access or indirect access to improved services resulting from the Government`s program to electrify priority loads, including clinics, schools, and trading centers. The consequent improvements in these social services could include improved instruction through the use of computers and other equipment in schools; extended hours for health clinics, due to electric lighting; and improved services in trading centers, such as battery charging, machines for the grinding of grain, etc. 13 Report No. 52521-KE. 13 39. The Project is aligned with the World Bank`s Clean Energy for Development Investment Framework. It supports all three pillars of the framework: (a) meeting energy needs of developing countries and widening access to energy services for their citizens in an environmentally sustainable way; (b) reducing greenhouse gas (GHG) emissions and speeding the transition to a low-carbon economy; and (c) helping countries adapt to climate change risks. 2. PROJECT DESCRIPTION A. Lending Instrument 40. The lending instrument is Specific Investment Loan (SIL). B. Project Development Objective and Key Indicators 41. The Project has two development objectives: Increase the capacity, efficiency, and quality of electricity supply. Expand access to electricity in urban, peri-urban, and rural areas. 42. The Project will meet the first objective through an increase in generation capacity (Component A) and transmission capacity (Component B), as well as improvements to the distribution system (Component C). The achievement of the second objective will take place through measures to increase electricity connections, especially programs to make them more affordable for lower-income households (Component C). 43. In addition, the Project will help sustain the policy, institutional and regulatory environment, created by earlier operations, necessary for the Project`s results to materialize (Component D). 44. The core indicators for measuring the achievement of the Project`s objectives are the following: Electricity generation from renewable geothermal capacity constructed (GWh). Average power system interruption frequency per year (number). Electricity transmission and distribution losses per year (%). People provided with access to electricity (number, assuming five people per household connection). Direct project beneficiaries (number), of which female (%). 14 C. Project Components 45. The Project has four components. The first component is the expansion of geothermal power generation capacity at Olkaria. This is the largest component, accounting for 73 percent of total Project cost. The second component is the construction of three new transmission lines and related infrastructure to deliver power to areas, which have economic growth potential but low access and unreliable supply. The third component also supports expanded electricity access by augmenting distribution capacity, primarily through the building of additional substations and distribution lines, and the launching of electrification programs targeted at improving the economic opportunities and quality of life of people living in urban, rural, and slum areas. The fourth component consists of activities for institutional development and capacity building. The estimated cost of the Project is US$1,391 million of which IDA financing is US$330 million14 (see Annex 4 - Detailed Project Description and Annex 5 - Project Costs, for more information). Component A: Geothermal Generation (US$1,035 million: IDA, US$120 million; JICA, US$323 million; AFD, US$210 million; EIB, US$168 million; KfW, US$84 million; KenGen, US$ 130 million). 46. This component will finance the construction of 280 MW of geothermal generation capacity, consisting of: (a) an expansion of the capacity of the existing Olkaria I power station by 140 MW; (b) a new power station, Olkaria IV, with a capacity of 140 MW; and (c) connection of steam wells to the two power stations with associated facilities for transmitting the power to the national grid. The Component will also finance consulting services for design and supervision, and the installation of construction infrastructure and facilities required to operate the plants 15. 47. The expansion of the existing plant and the new plant will both be located in the Greater Olkaria Geothermal Area in Naivasha, Rift Valley16, where KenGen has completed considerable geophysical exploration to prove the resource. The Olkaria I expansion will be situated adjacent to the existing geothermal plants in the Hell`s Gate National Park, whereas Olkaria IV will be located just outside the borders of the Park. A feasibility and reservoir optimization study17, completed in August 2009, has confirmed the technical and economic viability of the proposed plants. An independent group of geothermal experts has endorsed the recommendations of the feasibility study18. The study includes a conceptual design along with site selection for the two plants, based on the topography of the area, reservoir simulations, and proximity to steam wells. The drilling of production wells through January 2010 secured 50 percent of the steam required. To obtain the rest of the steam required for the Project, drilling will take place over two and a half years during the construction of the power plants19. 14 US$30 million of IDA financing is from the Crisis Response Window (CRW) and will support the distribution component. 15 Access roads, water and electricity supply, borehole roads and offices. 16 About 120 km west of Nairobi. 17 Feasibility Study Report for New Units of the Optimization Project, West Japan Engineering Consultants, Inc., with sub- contracted services to GeothermEX, Inc. (USA) and Global Synergy Link (Kenya), August 2009. 18 Observations regarding the planned optimization of the Greater Olkaria Geothermal Area, Report of the Board of Consultants to KenGen, 7th August 2009. 19 The cost of drilling the outstanding wells is about US$273 million. Of this KfW may finance US$15 million, the Exim Bank of China US$95 million, and GOK US$163 million. 15 Component B: Transmission (US$72.5 million of which IDA US$64.5 million; and KETRACO US$8 million) 48. This component will construct 132 kV transmission lines as well as substations that step down the voltage from these lines to the distribution system. Component B will help meet additional electricity demand, reduce losses, improve reliability, and enhance the quality of service. The component will build three new transmission lines between the following locations: (a) Kindaruma-Mwingi-Garissa; (b) Eldoret-Kitale; and (c) Kisii-Awendo. These lines are among the eight 132 kV transmission lines that the Government has designated as priorities for construction during the period 2010 to 2015. Component C: Distribution (US$272 million: IDA, US$134 million; AFD, US$10 million; KPLC, US$30 million, GPOBA, US$5 million, REA US$2 million; users US$91 million) 49. This component will have four subcomponents that will support the expansion and upgrading of the distribution network along with the connection of an additional 300,000 customers over the period of 2011-2016. About 17 percent of household connections will be in urban slums. In areas of the Project where the distribution investments will take place, an increasing number of new customers will come from lower-income urban areas and rural areas. Therefore, Component C also will support measures to enhance the affordability by households of new connections. 50. Subcomponent C1 -- Strengthening and Extension of Distribution Networks (US$210 million: IDA, US$95 million; KPLC, US$25 million; users, US$90 million). This subcomponent will support the reinforcement and extension of KPLC`s distribution networks in the greater Nairobi metropolitan area and in the Coast, Mt. Kenya, and Western and Nyanza provinces. Investments in this subcomponent are expected to result in 250,000 new connections over the period 2011 -- 2016, improved system reliability and reduced losses. In addition, the Project will finance an engineering consultant to help KPLC implement the investment program. 51. Subcomponent C2 -- Electrification of Priority Loads in Rural Areas (US$36 million: IDA, US$34 million; REA, US$2 million). This subcomponent will contribute to the implementation of the Government`s Rural Electrification Master Plan (REMP) by electrifying at least 450 priority loads (i.e. public facilities such as schools, clinics, district headquarters, as well as all key trading centers), mainly through grid connection. The electrification of these priority loads will in turn enable the electrification of an estimated 30,000 nearby, rural households. However, not all of these connections will take place during the Project`s implementation period because household connections typically lag behind the electrification of public facilities and trading centers. The subcomponent also will assist REA in developing and testing off-grid electrification models, such as rural mini-grids powered by renewable energy technologies. 52. Subcomponent C3 -- Slum Electrification (US$16 million: GPOBA, US$5 million; IDA, US$ 5 million; KPLC, US$5.3 million, users US$0.7 million). This subcomponent will finance, through an output-based mechanism, the connection of about 50,000 low-income customers in Kenya`s slums. The investments in the first year of the Project will focus on connections in the Kibera area of Nairobi. In subsequent years, the investments will support the electrification to slums in other parts of the country. 16 53. Subcomponent C4 -- Revolving Fund for Deferred Connection Fee Payments (US$10 million, financed by AFD). This subcomponent will support the re-capitalization of the Revolving Fund, which is helping to finance deferred payments of connection fees. The electricity connection rate in Kenya is currently skewed towards higher-income households. About two-thirds of households with access to electricity are in the top income quintile. The bottom-three income quintiles account for only 10 percent of households with access. One of the reasons for this imbalance is the high connection fee of KSh 35,000 (about US$460), which prospective customers must pay upfront. The Revolving Fund will allow lower-income customers to pay the connection fee over time. Component D: Sector Institutional Development and Operational Support (US$11.5 million). 54. Studies, capacity building and training activities in this component are designed to help sustain the policy, institutional and regulatory environment that the Government has created with the support of earlier Bank-financed operations. These activities are necessary for the expected results of the Project to materialize. Component D has three subcomponents. 55. Subcomponent D1 -- Institutional Development and Studies (US$7 million). Building on the institutional development component of ESRP, this subcomponent will support the next phase of electricity sector reforms in the development of the electricity market. The subcomponent will support analytical work to: (a) advance the wholesale electricity market; (b) facilitate private sector investment in the electricity sector; (c) assist ERC to determine system charges such as wheeling charges and rates for the various categories of consumers, which recover costs and send appropriate price signals to customers about the cost of electric service; (d) improve KPLC`s and REA`s supply-chain logistics and content, seeking opportunities to reduce the cost of procuring materials and equipment; and (e) identify and evaluate physical risks to power infrastructure assets and make recommendations for risk management. Furthermore, the subcomponent will conduct pre-feasibility and regulatory studies for medium-sized renewable energy and prepare feasibility studies for new investments. 56. Subcomponent D2 -- Training (US$2.9 million). The subcomponent will provide the sector entities (KenGen, KPLC, KETRACO, GDC, REA, ERC and MoE) with training in: management of environmental and social impacts; sector operations; use of computerized planning models; project management, including procurement and financial management; and other areas, as required during project implementation. In addition, the subcomponent will support a comprehensive training program for KETRACO`s management and staff in order to enhance their skills in efficient operation and management of transmission networks, expansion planning and design, and negotiation with contractors and financiers. 57. Subcomponent D3 -- Project Implementation Support and Monitoring and Evaluation (M & E) (US$1.6 million). This subcomponent will strengthen MoE`s project implementation and coordination teams through short- and long-term experts. It will also support MoE in the design and implementation of a methodology for evaluating the Project`s impact. In addition, the subcomponent will support activities to strengthen demand-side accountability mechanisms in the Project, including third-party monitoring of project activities. 17 D. Lessons Learned and Reflected in the Project Design Table 1: Lessons Learned and Reflected in Project Design Component/Lesson Reflection in Project Design Generation Component Procurement of the facilities organized as a single EPC The design of the geothermal generation component has contract (including design, steam field development, civil reduced the risk of a similar situation under the Project works, power plant, and substation modification) can by separate contracts for steam field, power plants, and limit competition. This type of packaging, used for ESRP transmission lines. This should result in more resulted in the receipt of only one bid with a relatively competition (for more simple, less risky contracts). high price. Furthermore, the agreements between KenGen and the financiers will include appropriate provisions to address the risk of cost fluctuation. Transmission Component Thorough feasibility studies, particularly concerning The design of this component has been developed from environmental impact, are crucial to timely thorough feasibility studies. The Project will use implementation. turnkey contracts. ESIAs and RAPs have been disclosed. Turnkey contracts are efficient for large-scale projects when the implementing entities have strong in-house project management capacity. They engage contractors to do the construction on a turnkey basis and engage supervision consultants to ensure oversight. Distribution Component Overall Approach A broad-based approach, linking electrification with other The electrification program will build linkages to the infrastructure developments and including financing electrification requirements of the agriculture, health schemes and educational programs including support for and education sectors, in which the Government has productive uses of electricity, can greatly enhance overall designated institutions for connection based on their development benefits for end-users. potential development impact. Contract Packaging When the construction works are located in widely Contract packaging will group construction work in dispersed geographical areas, it is more cost effective and relatively small geographical areas so that any one time saving to arrange them such that the contractors do contractor is not required to undertake work scattered not have to move across the country to access the widely across the country. different sites. Design of the Connection Program A systematic impact study for electrification during The monitoring and evaluation plan for the Project will project implementation -- particularly during mid-term study which factors are the key determinants in uptake review -- can provide important feedback for a rolling and use of electricity. program of electricity connections and allow for design improvements that can enhance the development impact. 18 Component/Lesson Reflection in Project Design Affordability of Connections If household electricity connections are not affordable, KPLC offers a deferred payment plan for connection investments to bring the electricity to a specific area may charges. To further enhance affordability, the Project remain unused or under used and not reach the ultimate will re-capitalize KPLC`s Revolving Fund for deferred beneficiary. payments of connection fees. Through this fund, KPLC will be able to charge a small initial connection fee, with the balance to be recovered by installment payments included in customers` monthly electricity bills. The use of pre-paid meters also will improve the affordability of electricity consumption, as low-income consumers will be able to buy electricity in smaller quantities. Financial Viability of the Utility Company Large electrification projects can seriously undermine the Kenya`s realistic tariff regime and aggressive loss financial viability of a utility unless tariffs are at least at reduction program (including disconnection for non- (financial) cost recovery level and collection discipline is payment) are factors that will contribute to the enforced. profitability of KenGen and KPLC. E. Alternatives Considered and Reasons for Rejection 58. In designing the Project, the Bank and the Government considered and rejected the alternative of private rather than public sector financing for development of Olkaria I and IV. The planned 140 MW power plant at Olkaria I is an expansion of the existing plant that KenGen owns. In the case of Olkaria IV, the Bank considered providing IDA funding to the Geothermal Development Company (GDC) for geothermal resource development with GDC subsequently offering proven steam resources to the private sector for development on a competitive basis. The Bank rejected this alternative design for several reasons. First, the large size of the Olkaria IV part of the Project, costing about US$0.5 billion, makes it extremely risky for the private sector. Second, the Government would be constrained in providing the level of security that the private sector would demand to develop Olkaria IV. Third, KenGen has a license for the development of geothermal resources at the site and thus has the rights for development of geothermal power capacity there. Transferring those rights to the private sector, having already carried out development of the geothermal resources, would have delayed the construction of the plant. 59. The Bank also considered and rejected Adaptable Program Lending (APL) as an alternative to a Specific Investment Loan (SIL) for supporting Kenya's electricity sector expansion. The Bank rejected the APL option because the Project`s three components for generation expansion, transmission, and distribution are complementary and each cannot be easily scaled down without compromising the Project`s outcome of increasing access by 300,000 new electricity customers and improving the efficiency and quality of electricity supply. Progress in achieving Vision 2030 will require connecting one million new customers in five years to achieve the target of 40 percent access by 2020. This increase in customers will necessitate 420 MW of additional capacity, of which the Project is financing 280 MW and IPPs 19 and KenGen the remainder20. The transmission of electricity from the additional generation plants will require strengthening the transmission backbone. At the same time, delivering electricity to these new customers will require the strengthening and extension of medium and low-voltage distribution networks. 3. IMPLEMENTATION A. Partnership Arrangements The Sector-Wide Approach to the Development Partner Participation 60. Given Kenya`s need for enormous investments in the energy sector, concessional financing from IDA and other development partners is essential to complement resources from the Government, KenGen, KPLC and private sources. To mobilize and coordinate these resources, the Ministry of Energy has established a sector-working group (SWG) for the energy cluster of development partners. This group, currently chaired by the Agence Française de Développement (AFD) includes the African Development Bank (AfDB), the European Investment Bank (EIB), the German Development Cooperation (KfW), the Japan International Cooperation Agency (JICA), the Swedish International Development Agency (SIDA), the Embassy of Spain, the United States Agency for International Development (USAID), United Nations Industrial Development Organization (UNIDO) and other development partners. The objective of the SWG is to increase a programmatic flow of donor funds for the energy sector, consistent with the 2005 Paris Declaration on aid effectiveness. The declaration calls for the harmonization of donor funding with a common results framework, to foster joint ownership and mutual accountability. This sector-wide approach (SWAp) led to the preparation of the Electricity Access Investment Prospectus (2009 -- 2014) by the Government. Co-Financing Arrangements 61. The Project will have five external development partners: IDA, AFD, EIB, KfW and JICA. IDA is financing a part of all of the components. The other four external partners are all financing the Generation Component because of its large size and importance to the success of the overall program of electricity access expansion and improved security of supply. The operational entities in the electricity sector (KenGen, KETRACO, KPLC, and REA) will provide about 12 percent of the total cost; new users of electricity, 7 percent; and the external development partners the remaining 81 percent. IDA will fund about 12 percent of the Generation Component, 88 percent of the Transmission Component, 49 percent of the Distribution Component, and 100 percent of the Technical Assistance provided. Table 2 shows the financial partnership arrangements for the Project. 20 The connections under the project will require about 140 MW of generation capacity. 20 Table 2: Financial Partnership Arrangements by Financier and Component Financier Project component (financing in US$ million) Geothermal Transmission Distribution Technical Total Assistance KenGen 130 130 KPLC 30 30 KETRACO 8 8 REA 2 2 JICA 323 323 AFD 210 10 220 EIB 168 168 IDA 120 64.5 134 11.5 330 KfW 84 84 GPOBA 5 5 Users 91 91 FINANCING 11.5 1,035 72.5 272 1,391 AVAILABLE TOTAL COST 1,035 72.5 272 11.5 1,391 * Costs exclude duties and taxes. 62. The development partners have appraised the components jointly, harmonized their procedures and reporting requirements to the extent possible and followed the World Bank`s environmental and social guidelines. All of the Project`s co-financiers have representatives in Nairobi. Furthermore, they all have a good existing working relationship with the Government and KenGen, gained through work in the SWG and the ongoing ESRP. B. Institutional and Implementation Arrangements Overall Project Coordination 63. MoE will coordinate the execution of all project components through a Project Coordination Team (PCT). The PCT will consist of the team leaders of the Project Implementation Teams (PITs) of the implementing entities. MoE will organize quarterly meetings of the PCT and will share the minutes of the meetings with the heads of the implementing entities and the co-financiers. The Ministry also will be the implementing agency for the Project`s component for Institutional Development and Operational Support. 64. Through its Project Coordinator, MoE will prepare quarterly progress reports on the Project`s implementation with inputs from the implementing entities. The reports will review progress in the Project`s implementation, costs and financing, and achievement of the agreed key indicators of progress. The Project Coordinator will provide these reports to the permanent secretaries for Energy and Finance, the chief executives of the implementing entities, and the co- financiers. MoE will publish a summary of these reports on its website. 21 Responsibilities of the Implementing Entities 65. The Project will have four implementing entities -- KenGen, KPLC, REA and MoE. Table 3 shows the responsibilities of each entity. Table 3: Implementation Responsibility by Agency and Project Component Agency Component/Subcomponent KenGen All of Component A: Geothermal Generation Part of Component D: Subcomponent D2 (a) -- KenGen's training program KPLC All of Component B: Transmission (on behalf of KETRACO) Part of Component C: Distribution Subcomponent C1 -- Upgrading and expansion of KPLC's distribution networks Subcomponent C3 -- Slum electrification Subcomponent C4 -- Revolving Fund for deferred connection fee payments Part of Component D: Subcomponent D2 (b) -- KPLC's training program REA Part of Component C: Subcomponent C2 -- Electrification of priority loads in rural areas Part of Component D: Subcomponent D2 (c) -- REA's training program MoE Part of Component D: Sector Institutional Development and Operational Support Subcomponent D1-- Institutional development and studies Subcomponent D2 except for D2 (a), D2 (b), and D2 (c) -- Training Subcomponent D3 -- Project implementation support and M & E 66. KPLC will execute the Transmission Component on behalf of KETRACO, which is a new institution that does not yet have in place the requisite financial and procurement systems required for an IDA-financed project. A Mutual Cooperation and Provision of Services Agreement between the two entities will govern KPLC`s execution of the component. KETRACO will be the owner and operator of the transmission assets constructed under the Project. 67. The overall responsibility for each of the components rests with the implementing entity`s Chief Executive Officer and in the case of MoE, the Permanent Secretary for Energy. Each entity will have a PIT tailored to the needs of the component or subcomponent that it will implement. The PITs will all have adequate, qualified staff. Each PIT will have a Team Leader responsible for the day-to-day management of associated project activities, assisted by technical specialists, accountants, procurement specialists and other specialists as needed. The implementation arrangements are modeled after those in the ongoing ESRP, which have worked well. The implementing entities have prepared a Project Implementation Plan for each component, which defines the specific activities that form the component and their timing. Annex 4 (Project Description) and Annex 6 (Implementation Arrangements) provide the details on project components and their implementation. Implementation Arrangements for the Generation Component 68. The packaging of the various items required for the construction of the two geothermal plants takes into account the Bank`s implementation experience with ESRP, which has 22 demonstrated that bundling all project components in to one turnkey contract can reduce competition, resulting in higher costs and delayed implementation. The agreed packaging arrangement will promote competitive contracting for the various project items. 69. The design of the Generation Component has streamlined implementation arrangements to the extent possible. The financing arrangements ensure that no more than two co-financiers will finance any single contract. The co-financiers will provide parallel financing under separate financing agreements with KenGen (JICA and KfW) and GoK (IDA, EIB, and AFD). The timing of the implementation schedule is closely synchronized with the co-financiers` loan processing.21 Table 4 summarizes the partnership arrangements by subcomponent. Table 4: Summary of Partnership Arrangements by Generation Subcomponent Subcomponent Financier/Joint Financiers Subcomponents with Single External Partner Construction of substations and transmission lines EIB Part of the local infrastructure at the project site, such as access roads and a Panel of IDA Experts to advise on geothermal development Construction of Olkaria I power plant expansion JICA Engineering and supervision consultant to assist KenGen with implementation KfW Subcomponents with Joint External Partnerships Construction of Olkaria IV power plant AFD and EIB Construction of the geothermal steam-field systems serving Olkaria I and Olkaria IV IDA and KfW 70. The five development partners have agreed to a common procurement and implementation strategy in order to facilitate KenGen`s execution of the Component. Procurement for the expansion of Olkaria I will follow the guidelines of the financier, JICA, and use the agency`s standard bidding documents. AFD and EIB, the co-financiers for the Olkaria IV power station, will follow EIB`s guidelines and use procurement documents modeled after the Harmonized Multilateral Development Bank`s master bidding documents. KfW has agreed to the use of the World Bank`s procurement guidelines for the development of the geothermal steam field, which IDA and KfW are financing jointly. This means that IDA will provide all no-objections, which will expedite the approval process because KenGen will not have to request separate no-objections`` from KfW. Management of Special Programs to Support Accelerated Electrification 71. Launching of an output-based slum electrification program. KPLC will procure the materials required for connecting consumers in slums using its own procurement procedures.22 The company`s technical staff will install the connections. An independent verification agent 21 The co-financiers have scheduled the Board presentations of their loans between January and June 2010 (JICA`s Board approved US$323 million for the Project in January 2010 and AFD`s approval took place in April 2010). In line with this schedule, the procurement process will start with the pre-qualification for all contracts during May-July 2010. Following the bidding and bid evaluation periods, the award of contracts is scheduled to take place during the first half of 2011. 22 The Bank`s Procurement Specialist has reviewed KPLC`s procurement procedures and found them satisfactory. 23 will certify the quantity and technical quality of connections based on a representative sample of connections realized during an agreed payment period. IDA and GPOBA will pay for the outputs achieved, i.e., each will reimburse KPLC approximately US$100 per connection, after confirmation of qualifying criteria by the verification agent. KPLC will pay the difference between the actual cost and the combined contributions of customers, GPOBA, and IDA. GPOBA and IDA will disburse the funds quarterly or when KPLC has achieved a critical number of connections (e.g. 5,000). A Slum Electrification Output Based Manual, which IDA will approve, will set out the procedures for calculating the connection costs, the criteria for selecting the slums for inclusion in the Project, and the verification and payment arrangements. 72. Re-capitalization and operation of the Revolving Fund. The Fund will be used to pre- finance 70 ­ 80 percent of the connection fee for lower-income customers. Customers will pay the 20 ­ 30 percent upfront and repay the borrowed amount (70 ­ 80 percent) to the Revolving Fund in 24 installments after the connection, at an interest rate of 5 percent. The Fund has a dedicated Manager and its operations are overseen by a committee comprising KPLC`s Chief Managers for Finance, Commercial Services, Distribution, Information Technology and Telecommunications, and Internal Audit. Financial Management Issues of the Implementing Entities 73. The Permanent Secretary (PS), MoE, will be the Accounting Officer for the Project, assuming the overall responsibility for accounting for the project funds. The Chief Executive Officers of KenGen, KPLC and REA will report to the Accounting Officer on matters concerning the accountability of the Project`s funds. Annex 7 provides details of the financial management arrangements, the identified risks and mitigation measures as well as the flow of funds and arrangements for financial reporting. Environmental and Social Safeguards Management 74. KenGen, KPLC and REA will be responsible for implementing environmental and social management plans associated with the components for which they are responsible. KenGen and KPLC have good capacity for responsible execution and REA will strengthen its capacity during the Project`s implementation. Table 5 summarizes the implementation arrangements and the capacity of each implementing agency in these areas. Sections F and G of the Appraisal Summary respectively outline the Project`s expected social and environmental impacts while Annex 10 provides a more detailed analysis. Table 5: Environmental and Social Safeguards Management by Implementing Agency Agency Arrangements KenGen KenGen has adequate capacity to manage the environmental and resettlement aspects of the Generation Component. It has gained this experience in the ongoing ESRP and other projects it has implemented recently. The company`s Environment, Safety, Quality and Liaison Unit, which has qualified staff in the fields of EIA, air quality, waste management, safety, environmental resource management etc., will execute the Environmental Management Plan. A dedicated RAP Implementation Committee will manage the Resettlement Action Plan. An Independent Evaluation Panel will monitor progress in the RAP`s implementation. KPLC KPLC`s Safety, Health and Environment (SHE) Department will manage the environmental and social aspects of the distribution and transmission components. The Department has 24 Agency Arrangements adequate capacity for this. It has received environmental training under the ongoing ESRP and has managed the safeguards issues of that project satisfactorily. The company`s Resettlement Unit (RU) will be responsible for the management of compensation and resettlement matters. It has experience with similar activities of other projects that KPLC has implemented. An Independent Evaluation Panel will monitor the implementation of the transmission line RAPs. REA REA`s capacity to manage environmental and social aspects of projects is still developing because it has been in existence only since 2007. Therefore, it has contracted with KPLC`s SHE and RU to manage environmental safeguards and eventual resettlement and compensation cases for its components while it builds its own capacity under the Project. C. Communications Strategy 75. Although there are great economic and environmental benefits to developing geothermal energy in Kenya, the resettlement of some communities could entail a reputational risk for the Bank and its development partners. The Project`s communication strategy focuses on publicizing the benefits of geothermal energy as a clean, renewable energy source. The Bank and other development partners will draft a fact sheet on the Olkaria development showing that geothermal is a low cost, reliable electricity source for Kenya. The fact sheet will cover commonly asked questions and contain information on the application of the resettlement policy and explain that the affected communities will receive alternative lands, community improvements, and financial compensation to offset their losses. The fact sheet will be distributed to community groups, NGOs, businesses in the area and other interested parties in national and local languages. The Bank plans to feature the Olkaria development on its external homepage and climate change blog to highlight the organization`s commitment to low-carbon projects in Africa. 76. Regarding the expansion of electricity access, KPLC and KenGen both have very good communications teams and will promote their respective roles in the Project. The Bank will support the implementing agencies` communications capacity, as needed, through the Project`s technical assistance component. D. Monitoring and Evaluation of Outcomes/Results Overview 77. There are four levels to the Project`s performance monitoring. The first is the monitoring of the Project`s outcome and intermediate outcome by tracking progress in the implementation of the project`s four components and the achievement of key outcome indicators. The second level consists of financial performance indicators for the implementing entities. The third level concerns the environmental and social indicators. The fourth level is third-party monitoring and evaluation of the Project`s progress in improving economic opportunities and raising living standards. 25 Project performance 78. The implementing entities will review the Project`s outcome indicators quarterly. MoE will coordinate this review as part of its reporting on the project`s implementation progress. A mid-term review will take place approximately 24 months after the effectiveness of the IDA credit for the project. MoE will complete its quarterly progress reports no later than 30 days after the end of each quarter. Table 21 of Annex 3 lists all 16 indicators (five outcome indicators and 11 intermediate outcome indicators). Table 22 of Annex 3 provides baseline values for the indicators in 2010 and yearly targets from 2011 through 2016 along with the implementing entity agency responsible for gathering data and evaluating each indicator. Financial performance of the implementing entities 79. The Project`s performance places considerable emphasis on the continued financial viability of the key implementing entities -- KenGen and KPLC. The Project`s legal agreements will contain financial performance targets that MoE will monitor in the quarterly progress reports. Monitoring of environmental and social impacts 80. Each of the Project`s investment components has an environmental and social monitoring and evaluation plan. The generation and transmission components have resettlement action plans (RAPs), which the designated implementing agencies will monitor and evaluate. Data collection will be the responsibility of the implementing agencies, which already have experience with the reporting requirements for World Bank-financed projects. The implementing entities will compile the data and produce quarterly impact reports. Independent Evaluation Panels will monitor progress of the RAPs implementation. Third party monitoring and impact evaluation of the Project 81. An external consultant, contracted by MoE, will assess the extent to which the Project generates small business development, enhances agricultural production, and raises living standards. The implementing entities could use the results obtained during the Project`s implementation to improve program design where necessary. KPLC will continue to monitor electricity customers` satisfaction levels through annual surveys. Annex 3 discusses the approach in more detail. E. Critical Risks and Possible Controversial Aspects 82. The Project`s overall risk rating, with proposed mitigation measures, is moderate reflecting a mixture of mostly low-to-moderate project risks. However, when taking into account the substantial country-specific risks, the overall risk rating is substantial. 83. Table 6 and Table 7 summarize the critical risks along with existing mitigating factors and planned mitigation measures under the Project. 84. The Project is complex in the breadth of its components, covering nearly all aspects of the power system (generation, transmission, distribution, electricity access expansion, policy and 26 planning). However, the individual components are clearly defined and will use proven technologies. The design and implementation arrangements for the generation, transmission, and distribution components, which will account for 95 percent of the Project`s costs, are similar to those under the ongoing ESRP. The remaining five percent of Project costs will support the electrification of priority loads in rural areas and selected slum areas. These subcomponents, though a small part of project costs, have riskier implementation arrangements because they will involve a relatively new implementation entity (REA) for rural electrification and an output- based disbursement method for slum electrification. 85. The Project`s largest component -- the Generation Component -- involves five external co-financiers and five construction contracts. The management of this component, therefore, will increase the need for effective coordination among the co-financiers and strong project management capacity of the implementing entity, KenGen. The Project also has some risks related to the implementation of the social and environmental safeguards in the generation and transmission components. Specifically, the Project`s activities will affect about 10,000 people, although physical relocation is limited to about 3,300 people. To mitigate the risk of social unrest related to community relocations and the loss of land/incomes in the generation component, KenGen has developed a RAP through extensive consultation with communities and fair and equitable compensation agreements. In the Transmission Component, the final design of the line routes (and way leaves) will avoid crossing sensitive areas, thus minimizing the number of affected people, including indigenous peoples. With regard to indigenous peoples, the Government has prepared an Indigenous Peoples Planning Framework (IPPF), which has identified four vulnerable groups that may be affected. The environmental risks are moderate and the Environmental and Social Management Plans (ESMPs), completed for each component, have proposed adequate mitigation measures. Table 6 summarizes the key country, sector, stakeholder and project-specific risks. Table 6: Critical Project Risks (L=low; M=Moderate; S=substantial; H=high) Risk Rating Risk Mitigation Factors or Measures to be Taken With (Without) Mitigation Country Risks The governance situation in The Bank will continue to improve its understanding of Kenya's political S(S) Kenya is fragile and there is economy through active engagement with donors and its counterparts on a risk of instability leading the ground. up to the presidential elections in 2012. In line with the Bank`s governance and anti-corruption framework, the Bank will promote good governance as a cross cutting theme by helping to build more capable and accountable government at the national, local and agency levels and to strengthen core governance systems in procurement and public financial management. 27 Risk Rating Risk Mitigation Factors or Measures to be Taken With (Without) Mitigation Stakeholder risks Stakeholders may reverse Government, Bank, and financing partners are fully aligned behind the M(M) their support to the project. objectives and design of the operation. The objectives fit with the Government`s strategy and the Bank`s and co-financiers` mandates. The operation could be Civil society also agrees that electricity expansion should be a priority delayed due to: (a) fiduciary for the Government and partners. issues in the Bank or co- financiers` portfolios or (b) The project includes robust mechanisms for dealing with financial issues raised by local or management and resettlement and compensation issues. international stakeholders related to resettlement and compensation for lost assets. Sector risks Political or business The annual performance contracts between the Government and each of M(S) interests interference in the the sector entities will reduce the possibility of political and business sector. interests negatively influencing the performance of the entities. The partial privatization of the utilities and their listing on the stock exchange appear to have created the conditions for improving corporate governance and management practices. Private ownership has also created a constituency in the country in favor of maintaining the financial solvency and profitability of the utilities (the stock and bond prices would provide an immediate negative feedback in case of a regulatory decision that would threaten the solvency of the utilities). Inability to mobilize Despite the global financial crisis, to extensive regulation by successful Activities in the sector are subject the Government has been ERC, an S(H) financing to meet access in obtaining financing for agency. independent and credible infrastructure projects through two local program gap. public infrastructure bond offers. At a donor conference in October 2009, donors confirmed funding of approximately US$1.5 billion in support of the Government`s Electricity Access Investment Program. Inability to fill gap between IPP projects for an additional 240 MW, currently in the bidding stage M(S) electricity demand and should help to close this gap. supply. Deterioration of financial The regulatory environment mitigates the risk of sector entities assuming M(M) outlook for implementing debt that would undermine their financial position. entities. The financial forecast for both KenGen and KPLC between 2010 and 2014, shows that both companies will remain profitable despite taking on increased debt to finance power system expansion. Project specific risks Numerous donors and Donors share a joint partnership strategy and have agreed to harmonize M(S) multiple procurement/ their approval processes in order not to delay Project execution. contracting arrangements in Packaging of contracts has taken account of co-financiers preferences the generation component. and each contract will have no more than two financiers, to minimize administrative work and streamline the approval process. Most co- financiers have agreed to use the World Bank`s standard bidding documents to simplify processing. One consulting firm will coordinate the procurement and implementation of all contracts. 28 Risk Rating Risk Mitigation Factors or Measures to be Taken With (Without) Mitigation Low human resource Key mitigation measures under the project include: (a) the financing of M(S) capacity within design and supervision consultants for the investment components; (b) implementing institutions. the provision of procurement and financial management support to all implementing entities, as needed; (c) the signing of a cooperative agreement between KPLC and REA to ensure adequate coordination in providing connection services; and (d) the signing of a Mutual Services Agreement between KPLC and KETRACO to ensure adequate capacity for the implementation of the transmission investments. Technical design not The Project will use well-tested technologies. Project preparation work M(S) flexible enough to has paid close attention to costing, and the procurement strategy will accommodate to cost strive for a high degree of competition. The design of the distribution increases. and rural electrification activities allows scaling-down and scaling-up as necessary. Inability of project To enhance the affordability of electricity connections, the Project`s L(M) beneficiaries to afford design incorporates measures to reduce the initial costs. Also the Project electricity connections. will finance prepayment meters that will allow customers to pay for electricity in small increments and control their consumption. Environmental degradation A thorough ESIA has been completed as part of the Project`s L(M) at Olkaria site. preparation. KenGen is experienced in the application of the World Bank`s environmental safeguards and will continue to monitor the development at Olkaria. The potentially adverse impacts of geothermal power generation are far less than alternative generation options. Social unrest related to An ESIA or an ESMF has been completed for each Project component M(S) community relocations and and where necessary (generation and transmission) a RAP has been loss of land/incomes. developed. These plans were prepared with extensive consultation with local stakeholders and offer compensation as per policy for the affected communities. The RAPs not only offer land compensation; they also contain provisions for improving the community services available to the relocated communities and compensate the villagers financially for both loss of income and loss of cultural sites. Project affected people may Government has prepared an Indigenous Peoples Policy Framework M(S) claim the status of (IPPF) and if it is determined that indigenous people are affected, the Indigenous Peoples thus appropriate policies will be applied. delaying implementation because the Government has no clear national resettlement policy (although a draft exists). Overall rating M(S) 86. Table 7 shows the critical financial management risk that the Project may face in achieving its objectives. The table also provides a basis for determining how the Project should mitigate/address these risks. 29 Table 7: Critical Financial Management Risks (L=low; M=Moderate; S=substantial; H=high) Risk Rating Mitigation Factors or Measures to be With Risk Taken (Without) Mitigation23 Internal control systems: The Auditors` Internal controls systems: MoE, KPLC, MoE and Management Letters for all the implementing KenGen and REA are addressing internal REA -- entities have identified weaknesses in internal control issues (including fixed asset register). S(S) control systems. The issues that led to the MoE will address audit qualification issues. qualification of MoE`s audit report need to be The Bank will monitor these as part of followed up and addressed. MoE needs to put in financial management supervision of the KenGen place a fixed asset register. ongoing ESRP project as well as supervision and KPLC of the project. -- M(S) Audit committees: The Bank will work with MoE`s audit committee to strengthen its capacity. Under the Public Financial Management Reform Program, the Audit committees: MoE`s audit committee is weak Government is strengthening audit and its capacity needs to be strengthened. committees in all the government ministries. Funds flow: Kenya portfolio is disbursing slowly. The Bank will provide capacity building and M(S) training to the Project Implementation Teams. Training and video-conference meetings are being held between the Bank and the disbursement section of Treasury (MoF) to improve on the processing of disbursements. The Project will use Special Commitments and Direct Payments to increase the disbursement rate. External auditing: External audit arrangements are The methodology of KENAO will be S(S) in place (see auditing arrangements in Annex 7) but strengthened through capacity building. The the audit methodology of the Kenya National Audit Bank will liaise with all key stakeholders i.e. Office (KENAO) needs to improve. First, auditors Treasury and the Controller and Auditor need to discuss issues raised in the management General to address this issue. letters with clients before finalizing the audits. Secondly, the external auditors sent to the Ministry of Finance to audit the Designated Accounts need to consult with the external auditors sent to the project to avoid a situation where the Designated/Special accounts reflect amounts withdrawn and not claimed that has led to qualification of almost all Bank funded projects in Kenya. Financial reporting: REA has no experience in REA has agreed on the format of the Interim M(S) preparing Interim Financial Reports to the World Financial Report with the Bank. Bank. The Bank will provide training to REA`s staff in World Bank Financial Management and Disbursement Guidelines. Information systems: KPLC and MoE have KPLC: The company has hired a consultant KPLC challenges with their accounting information to resolve the interfacing issue of the SAP M(M) 23 Risk rating with mitigation refers in this case to the effect of the mitigation measure before project effectiveness. 30 Risk Rating Mitigation Factors or Measures to be With Risk Taken (Without) Mitigation23 systems. KPLC`s system is facing interface accounting software. challenges between the Financial Module and MoE S(S) Revenue Collection Module while MoE is using the MoE: Although the Government is IFMIS, which the Controller and Auditor General addressing IFMIS issues broadly under the found to produce unreliable accounts. Hence, MoE Public Financial Management Reform is facing challenges of reconciling differences Program, as a mitigation measure for this between the trial balance and existing project Project, MoE will prepare the project financial statements. In addition, the IFMIS does not accounts and the budget manually using have a module to prepare the budget. Microsoft Excel until the IFMIS issue is resolved. 87. Overall Risk Rating is Substantial. Despite predominantly moderate sector and project-level risks (after mitigation), the overall risk rating for the Project is substantial due to high and substantial country-level risks. F. Credit Conditions and Covenants 88. Anti-Corruption Guidelines: The Guidelines for Preventing and Combating Fraud and Corruption in Projects Financed by IBRD Loans and IDA Credits and Grants, dated October 15, 2006, will apply to this Project. 89. Credit effectiveness: (a) The Project Agreements and Subsidiary Loan and Grant Agreements have been executed on behalf of the Recipient, the Project Implementing Entities and the Rural Electrification Authority. (b) Recipient has finalized and adopted a Project Implementation Plan satisfactory to the Association. 90. Disbursement condition: For Component B (transmission): KPLC and KETRACO have entered into and executed a Mutual Cooperation and Provision of Services Agreement, satisfactory to the Association. 91. Financial Covenants: The financial covenants for KenGen and KPLC are the following: KenGen will meet the following annual targets: Self financing ratio 25% Debt service cover ratio 1.2 Current ratio 1.0 31 KPLC will meet the following annual targets: Self financing ratio 25% Debt service cover ratio 1.2 Current ratio 1.0 Accounts receivable 50 days of billings 92. Dated Covenants: Financing Agreement (a) The co-financing deadline for the effectiveness of the co-financing agreements is December 31, 2011. (b) The Recipient will ensure that KenGen implements Part A (6) of the Project on behalf of KETRACO and to this end, KenGen and KETRACO shall not later than September 15, 2010 enter into a KenGen-KETRACO Implementation Agreement satisfactory to the Association (the substance of this covenant is repeated in the KenGen Project Agreement). (c) In implementing Part C (3) of the Project, the Recipient shall cause KPLC to prepare and adopt not later than January 31, 2011 a Slum Electrification Output-Based Manual satisfactory to the Association. Project Agreement with KenGen (a) KenGen shall not later than September 15, 2010, enter into an Implementation Agreement with KETRACO acceptable to the Association for the implementation of Part A (6) of the Project (this condition is the same as (b) above in the Financing Agreement). 93. Retroactive Financing: Withdrawals up to an aggregate amount not to exceed US$3,000,000 equivalent may be made for payments made prior to this date but on or after January 1, 2010, for eligible expenditures. 4. APPRAISAL SUMMARY A. Economic Analysis Overview 94. The Project`s appraisal evaluated the economic justification for each of the three main components, covering the expansion or upgrading of generation, transmission, and distribution systems, to establish the economic merit of the Project as a whole. The Economic Internal Rate of Return (EIRR) of the base case scenarios for each of the three components is satisfactory ranging between 21 and 32 percent. Sensitivity analyses show that even under the most unfavorable conditions foreseen, the EIRR for each component remains above the estimated 12 percent cost of capital. The following sections outline the methodology and results of the evaluations by component. Annex 9 provides a detailed discussion of the analysis of justification. 32 Generation Component 95. This component, which accounts for about 74 percent of the Project`s cost, is the main driver of the Project. The evaluation of its economic justification was a three-step procedure. First, it analyzed the need for additional generating capacity and the timing required to meet projected energy demand in the interconnected power system. Second, the evaluation determined whether the expansion of the existing Olkaria I geothermal plant and the construction of a new generation plant (Olkaria IV) provided the least-cost solution to generation expansion. Third, the evaluation conducted a cost/benefit analysis to determine the economic viability of the investment in the incremental generation capacity, measured by the EIRR. 96. A review of the demand/capacity balance of the public electricity system determined that additional generating capacity by 2014 will be necessary to ensure adequacy of supply, including the reserve margin. The need for additional capacity coincides with the timing of the proposed expansion of the Olkaria I power station and the installation of the new Olkaria IV power station. Without these capacity additions, the power system would not be able to meet demand in 2015. 97. The evaluation confirmed the finding of the long-term, least-cost generation expansion study by MoE and ERC (in collaboration with the power utilities) of December 2008, considering the merits of other generation options. Alternatives to the additional geothermal units included oil-fired thermal units; wind-based power generation; additional hydropower capacity; and coal-fired steam units. A life-cycle cost comparison illustrates the relative cost advantage of the proposed Olkaria I and IV developments over the other options. 98. The determination of economic viability followed a standard approach of comparing costs and benefits to arrive at the EIRR. The costs consisted of: (a) the capital costs of drilling of steam wells and steam field development, construction of the power stations, associated transmission and substation, consultancy services for engineering procurement and supervision of construction, owner`s cost, and compensation and resettlement; and (b) the operating costs, consisting of the annual expenditures for additional steam production wells, hot and cold water re-injection wells, and fixed and variable costs of operation and maintenance. The benefits consisted of the net energy output of the power stations -- 2,057GWh/year -- valued at the estimated economic cost of supply of US$0.206/kWh. 99. Table 8 summarizes the results, showing a base case EIRR of 23 percent. Considered separately, cases of major increases in capital cost, decreases in output and considerable construction delays, lowered the EIRR only a few points. In the case of all unfavorable conditions occurring simultaneously, the EIRR declines to 13 percent. Table 8: Summary of EIRR Analysis for the Generation Component Scenario Net Present Value EIRR (%) (US$ million) Base Case: Benefits valued at LRMC of generation -- US$0.2064/kWh 841 23 Sensitivity Case 1: 20% real capital cost increase 662 19 Sensitivity Case 2: 20% decline in plant output 481 19 Sensitivity Case 3: two-year construction delay 575 19 Sensitivity Case 4: combined effect of 20% capital cost increase, 126 13 20% output decline, and two-year construction delay 33 Transmission Component 100. The three transmission lines that the Project will finance are the highest priorities among the eight priority transmission developments in the Government`s Electricity Access Investment Prospectus, 2009 - 2014. The selection of the transmission voltage has resulted from a detailed, load-flow analysis. An evaluation of alternative designs and a configuration analysis has established the selected transmission lines as the least-cost options. The assessment of economic viability has used a cost/benefit analysis. The costs consist of (a) the capital cost of construction of transmission lines and substations; (b) the cost of consultancy services for engineering, procurement and supervision of construction; and (c) annual operation and maintenance costs. The analysis has assumed an economic operating life of 40 years for both the lines and substations. The benefits consist of: (a) reductions in losses, valued at the long-run marginal cost (LRMC) of generation; (b) incremental energy consumption made possible by the improved power transfer capability, valued at the bulk-level LRMC of transmission; and (c) incremental energy savings from reductions in outages and improved reliability of supply, valued at the economic cost of un-served energy. Table 9 summarizes the results of the evaluation. Table 9: Summary of EIRR Analysis for the Transmission Component Scenario Net Present Value (US$ million) EIRR (%) Base Case 182.4 32 Sensitivity Case -- 20% reduction in expected benefits 135.9 27 101. The base case EIRR for the Transmission Component is 32 percent, well above the cost of capital. The sensitivity analysis of a possible 20 percent reduction in benefits only lowered the EIRR a few points, to 27 percent, indicating the robustness of the Transmission Component`s economic viability. Distribution Component 102. This component will support the connection of 300,000 customers in urban, peri-urban and rural areas. Out of the 300,000 new connections, about 50,000 will be slum dwellers. Based on demand surveys, 90 percent of new connections will be residential, while 10 percent will be businesses and institutions. The economic analysis for the Distribution Component used a consumer surplus methodology, a common practice in the economic analysis of electrification projects. This analysis has used demand curves to estimate the increase in consumer surplus that is likely to result from higher energy consumption at lower price, following electrification. 103. The determination of the EIRR has resulted from a cost/benefit analysis. The benefits include: (a) consumer benefits due to the increased consumer surplus, calculated separately for urban/peri-urban and rural customers due to different consumption patterns, and (b) benefits from reducing system losses as a result of upgrading of the sub-stations, which the Project will finance. On the cost side, the analysis has included investment costs for Components C1 and C2, averaging US$960 per connection, the cost of energy, operation and maintenance of the distribution investments and an estimate of transmission losses. Table 10 summarizes the results of the base-case EIRR analysis and sensitivity testing of unfavorable conditions that could lower the EIRR -- a 20 percent increase in investment costs and, on the benefits side, a 20 percent 34 decrease in consumption by electrified households. The base case EIRR of 21 percent is significantly higher than the cost of capital and in the case of each unfavorable condition evaluated, the EIRR remains satisfactory. Table 10: Summary of EIRR Analysis for the Distribution Component Scenario EIRR (%) Base Case 21 20% increase in investment costs 15 Willingness to Pay (WTP) of non-electrified households reduced by 20% 13 Consumption of electrified households reduced by 20% 18 B. Financial Analyses 104. Kenya`s electricity sector, overall, is in good financial condition, which is evident in the financial statements of KenGen and KPLC. Over the past five years, these companies have been profitable, maintaining adequate liquidity and cash reserves, as well as manageable levels of debt. As implementing agencies under the ongoing, Bank-financed ESRP, both companies have complied with the Project`s financial covenants. As publicly-listed companies, the transparency of their operations has increased, because both KenGen and KPLC are required to produce regular financial reports for their investors. Due to Kenya`s major investment needs in the power sector both KenGen and KPLC face the challenge of maintaining profitable operations as they become significantly more leveraged in the future. The two utilities have recently taken steps to strengthen their balance sheets in order to facilitate the financing of their investment programs. 105. For KenGen, a key factor in meeting the future challenge is increasing the company`s return on its assets. Although profitable, the company has a low return on its existing assets due to the calculation of the tariff using historical costs for a large portion of the asset base. However, as KenGen acquires new assets through the Project and other investments -- with the price in power purchase agreements for new generation linked to current investment costs -- the company`s return on its asset base should increase over time. 106. KPLC, which currently has higher returns on its assets than KenGen, will face the challenge of maintaining this level of profitability while implementing a large investment program to extend service as in the future, especially because an increasing portion of its customer base is likely to be lower-income customers. However, two factors will help protect KPLC`s profitability. First, the next KPLC tariff review (covering FY2012 to FY2014) will likely take into account the higher cost of service for newly -- connected customers. Second, KPLC is deploying new metering and billing technologies to mitigate the risk of non-payment or delayed revenue recovery (prepaid meters, electronic payments). 107. The financial forecast for both companies between 2010 and 2014 -- the timeline that coincides with the Project`s implementation period -- shows that they will remain profitable despite taking on increased debt to finance power system expansion. KenGen will begin the period with substantial liquidity from its bond issue in 2009. Gradually the company`s current ratio is projected to decline to a minimum of 1.3, and then to increase due to the cash flow from 35 new generation investments. The projection for the debt service cover ratio (DSCR) shows a decrease from the current level of 2.2 to a minimum of 1.3. KPLC is expected to improve its liquidity due to a capital increase later this calendar year, increasing the company`s current ratio to a comfortable 2.1. In spite of its investment program, KPLC is likely to maintain a DSCR of 1.4 or above throughout the forecast period. Since both companies are generating cash flows that are secured by existing tariff regulation, the financial ratios forecast throughout the period are appropriate for capital-intensive businesses generating predictable cash flows. 108. Increased investments by both KenGen and KPLC will require both utilities to increase their revenues. Thus, the cost-of-capital component of electricity tariffs (for generation and for network assets) will tend to increase over the next few years, because the regulatory asset base of both utilities will rise faster than the volume of energy sold (especially in the case of KenGen). In contrast, the fuel-cost component of electricity tariffs should decline due to the increase in the share of geothermal power in the generation mix. In addition, further improvements in efficiency and productivity by both utilities could lessen the requirement for a tariff increase. 109. Annex 9 provides a detailed financial analysis, which discusses the sector context of the investment program that the Project supports, the historical performance of KenGen and KPLC, and results along with key assumptions, of the projected financial statements for 2010 -- 2014. C. Technical Geothermal Resource Base 110. Current geothermal generation activities are located in one area -- the Greater Olkaria Geothermal Area in the Rift Valley. Resources in all known prospective areas could possibly support about 7,000 MW of generation capacity. These estimates are only preliminary and require confirmation by drilling. Kenya is among 10 nations worldwide and the only country in Sub-Saharan Africa that has developed geothermal energy on a large scale. However, drilling equipment is old and investments in new equipment will be necessary for further proving of the resource base. GDC and KenGen are in the process of acquiring drilling rigs to conduct further drilling. The future development of geothermal resources for power generation will depend on availability of financing for exploration. 36 Geothermal Power Plant 111. Design Features. The technology, unit size, and power plant configuration are based on detailed feasibility study, which recommended a unit size of 70 MW, taking account of the current geothermal technology and the size of the power system. The conceptual design and plant configurations are similar to those of the existing Olkaria II power plant, which has received IDA financing. To increase competition, KenGen and the co-financiers have agreed that bidders can propose alternative unit sizes if they lower the overall plant cost. The Olkaria I and IV power stations will use the same flash technology (single flash condensing type) to convert hydrothermal fluids to electricity as do the existing Olkaria plants.24 A reservoir analysis by international engineering consultants has established a quantitative model that integrates geological, geochemical, and geophysical characteristics of the reservoir in the eastern Greater Olkaria Geothermal Area (GOGA). The analysis has confirmed that the GOGA could sustain the exploitation of steam required for the existing plants (198 MW) and the planned power plants (280 MW) for 25 years. 112. Location. The Project is located 120 km northwest of Nairobi, in the Naivasha district of the Rift Valley Province. The Olkaria I expansion is located in the Hell`s Gate National Park. The construction of Olkaria IV plant will require the acquisition of private land, near the main steam production area for the plant, just outside the borders of the National Park. The specific plant locations were selected based on topography (a flat area is necessary) and proximity to steam wells to minimize the length of piping and thus the impact on the landscape. The Olkaria I expansion is located a short distance from the existing Olkaria I plant. 113. Associated Transmission System. Approximately four kilometers of 220 kV transmission line is required to connect the Olkaria I expansion to the existing Olkaria II substation, also in the Hell`s Gate National Park, where its power enters the national grid. From Olkaria II a double-circuit, 220 kV line of 25 kilometers will be constructed to a new substation at Suswa. The electrical energy from Olkaria IV will be delivered to the grid by a 20-kilometer double-circuit 220 kV transmission line to the new substation at Suswa. Transmission Component 114. The transmission line design includes a fiber-optic based telecommunications system to enable automated monitoring and control of system performance. Distribution Component 115. Optimization of the Sub-Transmission Network. KPLC`s distribution network consists primarily of 11 kV lines with the 33 kV network mainly used for sub-transmission voltage. The design of the proposed distribution network expansion will focus on optimizing system voltages by upgrading some of the existing 11 kV lines to 33 kV in order to: (a) increase the power transfer capacity and the distances of the lines without exceeding the voltage drop limits; and (b) eliminate the need for 33/11 kV substations in future system expansion to reduce 24 Flash technology is one of three types of technologies used to convert hydrothermal fluids to electricity. It uses water at temperatures above 360 degrees Fahrenheit (182 degrees Celcius) pumped under high pressure to generation units. (Source: United States Department of Energy). 37 costs and ease future expansion. The component will upgrade some of the 11 kV lines to 33 kV, replace some existing distribution transformers with others that have higher ratings and install auto re-closures and load break switches at strategic points along the lines, in order to minimize supply interruptions. 116. Changes in Substation Design. Most KPLC substations have outdoor, 33 kV switchgear. This standard design feature has been in use for a long time. However, it has several disadvantages. One is the large space requirement. Another is that outdoor switchgear is not conducive to system automation (automated switching and remote control). For the substations that the Project will build and refurbish, the supply and installation of indoor switchgear and tele-control equipment will enable them to be linked to the National System Control Centre, from where they can be remotely operated and monitored on a real--time basis through the System Control and Data Acquisition (SCADA) system. Slum Electrification 117. KPLC has been fine-tuning its service delivery model to slum areas since 2006. Based on the experience KPLC gained from pilot operations in Nairobi and Kisumu, and taking account of international best practice, KPLC will expand use of pre-payment meters and smaller transformers (25 KVA) that serve about 17 customers each. These design features will: (a) reduce electricity theft by using insulated low voltage connection cables which cannot easily be hooked onto; (b) lower technical losses due to reduced network loading of the low--voltage lines; and (c) higher quality of electricity service as there will be reduced outages arising out of fuse blow-outs or transformer failures due to overloads. A financial analysis has confirmed that the increase in the investment costs due to the use of anti-theft technology will be offset by the reduced electricity losses. D. Fiduciary 118. Financial Management (FM). A Public Expenditure and Financial Accountability (PEFA) assessment for Kenya was completed in March 25, 200925. Annex 7 provides details about its findings and conclusions. The Government has a Public Financial Management Reform Program under the IDA-financed Institutional Reform and Capacity Building Project, which is helping in addressing the risks identified in the PEFA. 119. The Financial Management Assessment that the Bank has carried out for the Project concluded that the financial management arrangements meet the Bank`s minimum requirements under OP/BP10.02. With the implementation of the financial management action plan, the financial management arrangements for the project will be further strengthened. The residual risk rating for KenGen and KPLC is moderate while for REA and MoE is substantial. Table 11 provides the highlights of this Assessment. 120. Three of the four implementing entities (KenGen, KPLC, and MoE) have considerable experience of World Bank`s financial management procedures having implemented several IDA- 25 Carried out by multilateral and bilateral development agencies. The Bank serves as the secretariat. 38 financed projects in the past. Their performance in meeting the financial covenants of the ongoing ESRP has been satisfactory. Table 11: Highlights of the Financial Management Assessment Function Strengths and Shortcomings Budgeting Budgeting arrangements are adequate except for MoE that has to prepare its budget using Microsoft Excel, as it has no information system to prepare the budget. Accounting All entities: All implementing entities are using acceptable accounting standards to prepare their Standards and final accounts for auditing. All implementing entities have adequate Financial Management Systems Manuals (FMM) documenting the financial management arrangements including internal controls to be used for the Project. KenGen, KPLC and REA have adequate accounting information systems except that KPLC has to address an issue concerning interfacing between Financial Module and Revenue Collection module to strengthen the system. MoE is using IFMIS, which is producing unreliable accounts as pointed out by the Controller and Auditor General. Hence MoE will need to mitigate this risk by preparing project accounts using Microsoft Excel. Auditing All entities: (a) strong internal auditing functions (except that MoE`s audit committee is weak and needs strengthening through capacity building). (b) external auditing adequate but strengthening needed in auditing designated accounts and consultations with clients on audit findings before the audit report are finalized. (c) The Bank`s review of the external audit reports of the implementing entities suggested weaknesses in internal control systems. The issues raised in the qualified opinions of the June 30, 2009 audit report for MoE need to be addressed. Financial All implementing entities have adequate Financial Management Manuals documenting the Management financial management arrangements including internal controls to be used for the Project. Documentation Financial Financial Reporting arrangements for KenGen, KPLC, and MoE are satisfactory for preparation of Reporting Interim Financial Reports. REA`s staff will need training in World Bank Financial Management and Disbursement Guidelines to strengthen their capacity in this area. Staffing Staffing arrangements are adequate for all implementing entities. KenGen, KPLC, REA, and MoE will have to ensure that appropriate staffing arrangements are maintained throughout the project life. Funds Flow The Kenya portfolio has been experiencing slow funds flow process. The Bank and the Ministry of Finance are addressing this issue for all ongoing projects in evaluating the overall project portfolio for Kenya. 121. Procurement. The Project`s IDA-financed components will be subject to World Bank`s Guidelines for Procurement under IBRD Loans and IDA Credits, Guidelines for Selection and Employment of Consultants by World Bank Borrowers (dated May 2004, revised October 2006), and the provisions stipulated in the Financing Agreement. The parallel financiers will follow their own procurement rules but they may agree with the Government to use the World Bank`s standard bidding documents. The implementing entities, as well as contractors, suppliers and consultants, will be expected to observe the highest standard of ethics during procurement and execution of contracts financed under this Project. The Guidelines for Preventing and Combating Fraud and Corruption in Projects Financed by IBRD Loans and IDA Credits and 39 Grants, dated October 15, 2006 will apply to the IDA-financed components of the Project. The overall procurement risk for the Project is substantial because of its large size. 122. KenGen, KPLC, MoE have substantial experience of World Bank`s procurement guidelines having implemented several World Bank-financed projects in the past. These entities and REA have established procurement units and relevant tender committees in accordance with the provisions of the Public Procurement and Disposal Act of 2005 and the Public Procurement and Disposal Regulations of 2006. In order to provide mechanisms for procurement oversight and dispute resolution, the Government has also established the Public Procurement Oversight Authority (PPOA) and the Public Procurement Administrative Review Board (PPARB). The oversight function is further strengthened through the web-based system for reporting of any wrongdoing, including fraud and corruption, without fear of victimization. 123. The procurement arrangements of KPLC, KenGen, and MoE are satisfactory. These entities already have demonstrated their procurement management capacity under the ongoing ESRP. The Project Implementation Teams (PIT) in these entities are all adequately staffed with qualified and experienced procurement specialists and have access to appropriate tools and knowledge, including continuing assistance from the Bank`s Country Office, which will enable them to execute their functions effectively. 124. REA`s staff, however, requires training in the Bank`s procurement procedures because they do not have prior experience of working in an IDA-financed project. The Bank`s assessment of procurement capacity has concluded that based on the number of procurement staff and their background in procurement, REA has the capability to implement procurement under Component C2 of the Project (10 percent of the IDA credit). However, due to its lack of experience in World Bank procurement procedures, REA`s procurement risk is high. Project design will mitigate this risk through providing training in both public procurement and in the Bank`s procurement processes. The ongoing ESRP has already started this training. E. Financial Terms 125. The Bank will provide the IDA Credit to the Recipient at standard IDA terms, with a maturity of 40 years, including 10 years of grace. Out of the US$330 million Credit, the Recipient will re-lend US$215 million to KenGen and KPLC under a Subsidiary Loan Agreement with each entity with the terms shown in Table 12 below. In addition, the Recipient will provide, with project funds, a US$34 million grant to REA under a Subsidiary Grant Agreement. The balance of US$81 million will cover the cost of the transmission and institutional development components and contingencies that will not be re-lent through Subsidiary Loan Agreements. Table 12: Re-lending Amounts and Terms Entity Re-lent amount (US$) Term Interest rate KenGen 115,000,000.0 25 years, including 7 years of grace 3.5% p.a. KPLC 100,000,000.0 25 years, including 7 years of grace 3.5% p.a. Total 215,000,000.00 40 F. Social Impact 126. By providing affordable electricity to more people and improving the quality of supply, the Project will promote greater economic growth and equity. The expansion of the power grid will allow Kenya to provide electricity service to areas and groups of people that previously were unreachable due to KPLC`s limited electrification program. With increased access to electricity, the Project is expected to improve security (e.g. more street lighting); provide opportunities for the development of small businesses (tailor and seamstress shops, food stalls, small kiosks selling cold refreshments and food, workshops for small repairs, etc.); expand access to communications and technology (radio, television, internet); and increase employment and incomes, thereby helping to improve overall quality of life. 127. The transmission and distribution components will address community needs and services by expanding services to urban and peri-urban areas in greater Nairobi metropolitan area and in eastern, western and northeastern regions. The Project will strengthen social inclusion through adoption of priority loads for energizing key institutional facilities such as night-time services for schools and health centers, and provision of energy for pump irrigation and water supplies. The 132- kV transmission line from Kindaruma through Mwingi to Garissa, will expand grid electrification to a disadvantaged region in the Northeastern Province, and by replacing diesel generation, make energy more affordable and reliable. The multiplier effects of electricity expansion in Western and Nyanza Provinces are likely to spur growth in the production of commercial wheat, maize, tea, and sugar, dairy farming and small businesses. 128. KenGen and KPLC have established corporate programs for social responsibility, which provide better education, health, water and electricity supply to poor households. Both companies annually set aside one percent of their after-tax profits to finance such activities. In addition, since awareness and prevention programs are an integral element of the Environmental and Social Management Plans for all project components, both KenGen and KPLC have corporate policies for reducing the spread of HIV/AIDS. 129. The Project`s design incorporates the World Bank`s operational policies on Involuntary Resettlement (OP 4.12) and Indigenous Peoples (OP 4.10) due to expected impacts on land and human settlements. The Generation Component will require the acquisition of 3,600 acres of land for Olkaria IV and some yet undetermined number of acres for the Olkaria-Suswa transmission line. Under the Transmission Component, KPLC and KETRACO have identified the impacts as the potential loss of agricultural land, structures, access to other means of livelihood along the right-of-way (RoW) for the three planned transmission lines: Kindaruma- Mwingi-Garissa, Eldoret-Kitale and Kisii-Awendo. 130. Under the Distribution Component, KPLC and REA will construct about 26 substations and medium-voltage lines to connect to rural and urban households and rural schools and clinics to the power grid. The construction of these facilities may require some land acquisition or result in loss of assets or access to assets and loss of income sources or means of livelihood. Because the location and scope of investments will not be known until after completion of the detailed designs, it is difficult to estimate the social impact at this time. However, typically these facilities do not have major adverse social impacts. 41 131. Annex 10, Section II, discusses social safeguards in detail. Up to 10,683 project-affected persons (PAPs) will be entitled to compensation in the entire Project. The main impact will be the loss of assets, including those required to maintain livelihood. Under the Generation Component an estimated 93 households (685 persons) will require relocation due to land acquisition. The affected community has been involved in extensive consultations, which highlighted their specific relocation conditions. The major condition is that suitable land for relocation be found and that the PAPs agree to the selection of the land before they are required to move. Other conditions relate to improved housing and community services, as well as compensation for means of livelihood and cultural losses, which have been incorporated into the RAP. 132. The Transmission Component will require the compensation of about 1,400 households (10,000 persons). Extensive stakeholder consultations already have taken place with residents along the proposed routes, local administrative officers, and non-governmental organizations (NGOs), community-based organizations (CBOs), and faith-based organizations. In order to avoid or minimize the physical relocation of PAPs, the corresponding RAPs have recommended partial changes to the design of the transmission lines. The majority of PAPs whose assets are affected by the construction of the transmission lines have expressed preference for cash compensation since they generally can move/build in the same or adjacent plots of land. When the stated preference is to be physically relocated, the Project will cover the costs of both resettlement and compensation. 133. The World Bank`s screening has found that the planned routes for the transmission and distribution lines that the Project will construct may traverse areas where vulnerable ethnic groups are located. The Sengwer, Ogiek, Waata, and Boni peoples, currently living in some of these areas, meet the criteria for indigenous peoples, as defined by OP 4.10.26 The current list of indigenous peoples is preliminary. Further screening in the field and consultations with the Government of Kenya may result in the addition of other groups to the list of indigenous peoples. Given the likelihood that indigenous peoples are present in, or have collective attachment to, project lands, the Government has prepared an Indigenous Peoples Planning Framework (IPPF). 134. The guidelines of the IPPF provide for (a) a social assessment of indigenous communities and (b) free, prior and informed consultations leading to broad community support. In addition, the framework provides for the preparation of an Indigenous Peoples Plan (IPP) to avoid potentially adverse effects of the project on indigenous peoples. If avoidance is not feasible, the IPP will specify measures to minimize, mitigate, or compensate for such effects. Furthermore, the IPP will ensure that the indigenous peoples identified receive social and economic benefits that are culturally appropriate, taking into account gender concerns and the needs of different age groups. 26 The Kenyan people and the Government of Kenya use several terms for indigenous peoples, including minority or vulnerable people, and marginalized ethnic groups. However, for the purposes of the Project, the Bank`s screening process, in line with OP 4.10, defines indigenous peoples as those who meet one or more of the following criteria: (a) self identification and identification by others, as distinct, social and cultural groups; (b) collective attachment to ancestral lands and their natural resources; (c) customary cultural, economic, social and political institutions distinct from dominant society; and (d) an indigenous language that may differ from the official language of the country. 42 135. Consistent with the World Bank`s safeguards policies, the Project`s implementing entities have prepared the required safeguards instruments and have publicly disclosed them as required. Table 13 summarizes these documents by component. Table 13: Social Safeguards: Policy Documents Disclosed by Project Component Project Component Documents Disclosed Generation Environmental and Social Impact Analysis (ESIA) for the Olkaria I and Olkaria IV power plants and Resettlement Action Plan (RAP) for the Olkaria IV power plant. Transmission Draft ESIAs and RAPs for three transmission lines. Distribution Draft Environmental and Social Management Framework (ESMF) and Resettlement Policy Framework (RPF). Overall project Indigenous Peoples Planning Framework (IPPF). G. Environment Impact Evaluation and Mitigation Measures 136. The Project`s components will result in environmental benefits as well as adverse impacts that will require mitigation. Due to the likely reduction in fossil fuel use, the Generation Component, which will build new geothermal-based capacity for electricity generation, will help Kenya to earn carbon credits under the Clean Development Mechanism (CDM), the post-2012 Carbon Partnership Facility, or other sources of carbon finance. Moreover, the planned transmission lines, distribution substations and household electricity connections will allow a greener expansion of electricity access, by replacing isolated diesel units with grid-based electricity. 137. At the same time, the Project`s generation, transmission and distribution components are likely to cause relatively minor air and water pollution during the construction phases and, once the works are completed, limited loss of non-critical animal and plant habitats. There are four main issues of concern associated with project areas, most of which relate to the Generation Component. First, the construction and operation of the generation facilities will result in some loss and degradation of wildlife habitat. Second, both Olkaria I and IV will rely on water from Lake Naivasha, resulting in potential impacts on water availability and quality. Third, there will be some soil and water pollution caused by brine water discharge and sludge disposal. The other key environmental concern relates primarily to the transmission lines, and the need to take appropriate measures in their design and construction in order to minimize the risk of electrocuting raptors and nesting birds known to inhabit the Hell`s Gate Park, which the transmission lines connected to the Olkaria I and IV power plants will traverse. 138. The Olkaria I expansion will be situated adjacent to the existing geothermal plants in the Hell`s Gate National Park whereas Olkaria IV will be just outside the borders of the Park in a private land. About 54 hectares of land, out of a total 1,452 hectares that KenGen will acquire for the construction of Olkaria IV will come from the Kedong Ranch Limited, which owns 79,500 hectares. The land acquisition will amount to only 0.07 percent of the Kedong Ranch, and therefore result in a minimal loss of habitat. KenGen has agreed to monitor the impact of 43 fauna in the Hell`s Gate Park, and implement mitigation measures to limit habitat loss and degradation, in particular during drilling and construction stages, in accordance with a Memorandum of Understanding (MoU) signed between KenGen and Kenya Wildlife Service (KWS) in 2008. 139. The Project is not expected to have any negative effect on wildlife because animals can move freely in Hell`s Gate Park27. In the case of Olkaria I, KenGen will liaise with KWS in the implementation of the Environmental Management Plan, periodically monitoring the effect on wildlife (if any) attributed to construction of the power station and associated facilities. KenGen will continue to erect barriers around construction areas to enable wildlife to freely and safely bypass these areas. Moreover, KWS has not observed significant reduction in wildlife and no alteration in habitats caused by the existing geothermal projects and drilling activities (KWS performs two annual counts of wildlife, in the wet and dry seasons). As an additional precautionary measure, KWS and KenGen are collaborating on re-routing of the steel pipelines that transport steam to avoid wildlife corridors. 140. The Lake Naivasha Riparian Association (representing users of the lake waters) is conducting hydrological studies to determine water abstraction rates, including measures adopted by KenGen to harmonize water abstraction from all users around the lake. The findings of the latest studies have been included in the revised ESIA. The association of water users and KenGen will continue monitoring water use and water levels and recycling water when feasible. In addition, KenGen has agreed not to use lake water in landscaping and will undertake rainwater harvesting. 141. The estimated water requirement for the combined operation of the existing and planned geothermal power plants (Olkaria I, II, III & IV) is minimal relative to water used for irrigation (flower farms, etc) which is 64,000,000 m3 (cubic meters), or about 97 percent of water use from Lake Naivasha. In 2008, KenGen`s abstraction was 1,300,620 m3 during drilling activities, most of which, according to KenGen, was for the provision of water to the Maasai community in the project area. The current consumption is 1,400 m3 per day during drilling. Consumption will increase to 2,500 m3 per day for the cooling towers when the new plants are in operation, while drilling is in progress. After the completion of drilling, water use should decrease to 200m3 a day for each of the two new plants. The water used in the plants will be re-circulated and refilled once a year during maintenance operations. KenGen`s water use could decline even further in the likely event that there is less demand for water due to the resettlement of the local community. 142. Before discharging brine water to any water body, KenGen will analyze it to ensure that the quality complies with NEMA`s Environmental Management and Coordination (Water Quality) Regulations of 2006. The Project`s progress reports will incorporate the results of the water analysis. Where possible, KenGen will use concrete piping for brine transport and re- inject it. 27 The lack of negative impact on wildlife expected as a result of the project was confirmed in meetings held with the Deputy District Commissioner (DC) Naivasha, with the KWS representative for Naivasha, and in meetings with the Maasai community living within the vicinity of the project site, KWS states that KenGen`s provision of troughs for wildlife, at water pumps, has had a positive impact on wildlife, as the animals` access to watering points at Lake Naivasha has been closed off by the flower farms. 44 143. Sludge, including toxic non-biodegradable substances will be removed from condensers and cooling towers during major overhaul activities. Though the frequency and the quantity of sludge are likely to be small, KenGen will manage the sludge properly by drying it, encasing the sludge in concrete, and burying it. KenGen has confirmed that it will discharge the sludge in accordance with Environmental Management and Coordination (Waste Management) Regulations 2006 of NEMA. 144. To minimize bird collisions in the Project`s Transmission Component, wire-marking, in bird migration areas, will alert birds to the presence of power lines. KPLC will take appropriate measures in the design and construction of the transmission lines to minimize the risk of electrocution of raptors and nesting birds. Nature Kenya, the Ornithology Department of the Museums of Kenya and KWS will provide guidance on which specific actions are appropriate. Bird-friendly transmission lines will be used on the 20-kilometer stretch from Olkaria IV to the existing grid. KenGen has signed a MoU with the National Biodiversity Institute to this effect. 145. Table 14 below summarizes other project impacts common to all components and proposed mitigation measures. Table 14: Environmental Issues, Potential Impacts and Proposed Mitigation Measures Issues/Potential Impacts Mitigation Measures Air Pollution Avoid excavation during periods of strong winds. Cover Degradation of air quality due to dust generated vehicles and reduce their speed to prevent leakage of materials by breaking hard ground during construction and into the air. Monitoring of air quality standards to ensure that chemical emissions from equipment. they meet the environmental, health and safety guidelines of NEMA and the World Bank. Water and Soil Pollution (a) Minimize clearing and disruption to riparian vegetation; (b) Siltation of soil during construction activities, analyze water quality to ensure compliance with environmental eventually leading to aquatic habitat damage. regulations; (c) ensure that all construction materials are stored Both soil and water pollution could result from and ultimately disposed of in an appropriate manner; (d) use the unsafe disposal of creosote-treated poles and soils excavated for the erection of pylons to refill areas where polychlorinated biphenyls (PCBs). Excavations removed; and (e) avoid the exposure of loose, dry, bare soil to and the use of quarries and borrow pits could wind or water for long periods. reduce soil cover. Loss of Vegetation Clear trees selectively and re-vegetate areas with indigenous Land clearing could diminish indigenous species grasses, shrubs, and flora. of vegetation and degrade soil quality. Waste Products and Disposal Issue guidelines for waste disposal, monitoring of compliance Solid wastes produced by construction activities and rehabilitation of quarry sites/borrow pits. could pollute the project area. Health and Safety Conduct an education campaign on health and safety aspects of People in the vicinity of the power plants risk plant operation and the prevention of HIV/AIDS and other electrocution from live power lines, exposure to sexually transmitted diseases to construction and maintenance fumes, noise pollution, and a higher risk of staff. sexually transmitted diseases. 45 Borrower's Capacity to Implement Environmental and Social Safeguards 146. KenGen has ISO14000 and ISO9001 accreditation. The company`s Environmental Inspection Unit regularly monitors the environmental and social aspects of its operations. As indicated earlier, KenGen also cooperates closely with the KWS, which manages the Hell`s Gate National Park. In view of its large expansion program, KenGen will recruit additional personnel to its Environmental and Social Department. The company`s training program in environmental management targets skills development in environmental auditing and monitoring, along with mainstreaming environmental impact mitigation measures in project development. KenGen currently has adequate number of staff with experience in the fields of environmental assessment, air quality monitoring, waste management, safety, environmental resource management, etc. The company`s Environment, Safety, Quality and Liaison unit at Olkaria has modern equipment and tools for environmental monitoring such as hydrogen sulfide sampling and analysis. KenGen also has experience in resettlement, having relocated 140 households that were displaced in the Sondu Miriu Hydro Power project. 147. KPLC has ISO9001 accreditation. It has managed the safeguards work under the ongoing ESRP satisfactorily. The company`s Safety Health and Environment (SHE) Department will recruit additional staff persons to handle the increased workload of managing safeguards for the Transmission and Distribution Components. KPLC also has experience in resettlement, having managed the relocation of about 500 persons affected by the Rabai Thermal Power Project in Mombasa. Furthermore, to enhance their safeguards management capability, staff of KPLC, KETRACO and REA will receive training in environmental management systems and impact assessment, the implementation of the environmental and social screening process, hazardous waste management and pollution control, and occupational safety and health. KPLC will conduct REA`s environmental and social work until REA has built sufficient capacity of its own in these areas. H. Safeguard Policies 148. The Project has triggered OP 4.01, OP 4.04, OP 4.10, and OP 4.12, and has received a Category A rating, assigned to projects that are likely to have significant adverse environmental impacts that are sensitive, diverse, or unprecedented. 46 Safeguard Policies Triggered by the Project Yes No Environmental Assessment (OP/BP 4.01) [ X] [] Natural Habitats (OP/BP 4.04) [ X] [] Pest Management (OP 4.09) [] [ X] Indigenous Peoples (OP/BP 4.10) [ X] [] Physical Cultural Resources (OP/BP 4.11) [] [ X] Involuntary Resettlement (OP/BP 4.12) [ X] [] Forests (OP/BP 4.36) [] [ X] Safety of Dams (OP/BP 4.37) [] [ X] Projects on International Waterways (OP/BP 7.50) [] [ X] Projects in Disputed Areas (OP/BP 7.60)* [] [ X] I. Disclosure of Safeguards Documents Project component/Safeguards document Disclosed in Kenya Disclosed in InfoShop Generation component Draft ESIAs for Olkaria I and Olkaria IV October 23, 2009 January 25, 2010 Draft RAP for Olkaria IV January 6, 2010 January 25, 2010 Transmission component Draft ESIA for Kindaruma-Mwingi-Garissa line January 11, 2010 January 11, 2010 Draft ESIA and RAP for Kisii-Awendo line January 14, 2010 January 14, 2010 Draft ESIA for Eldoret-Kitale line January 24, 2010 January 24, 2010 Draft RAP for Kindaruma-Mwingi-Garissa line January 21, 2010 January 25, 2010 Draft RAP for Eldoret-Kitale line January 24, 2010 January 26, 2010 Distribution component Draft ESMF for distribution November 17, 2009 January 8, 2010 Draft ESMF and RPF for rural electrification December 23, 2009 January 12, 2010 Draft RPF for distribution November 17, 2009 November 25, 2009 Overall project Indigenous Peoples Planning Framework January 25, 2010 January 26, 2010 ** The final safeguards documents will be disclosed in Kenya and at the Bank`s InfoShop. Stakeholder Consultations 149. Generation Component. The preparation of the Environmental and Social Impact Assessment (ESIA) for the Olkaria I plant included 11 public consultation meetings with key stakeholders28 in 11 locations in September 2009. Similarly, the preparation of the ESIA report for Olkaria IV included consultations in 10 locations with relevant stakeholders during the month of September 2009. KenGen held follow-up meetings with senior community members, the Provincial Administration, and other stakeholders in October and December 2009. The Project`s potential positive and negative impacts, as well as mitigation measures, were clearly explained to * By supporting the proposed project, the Bank does not intend to prejudice the final determination of the parties' claims on the disputed areas. 28 District commissioners, district Officers, chiefs, sub-chiefs, village chiefs, and villagers. 47 the relevant stakeholders in both Swahili and English using maps and figures. Key environmental concerns voiced by stakeholders were the possibility of increased odor, and damage to tin roofing caused by hydrogen sulphide emissions. It was explained that the improved technology for the Project will significantly lessen odor and hydrogen sulphide emissions. Air dispersion and noise modeling was undertaken to address potential health impacts in the Project Area. Within areas identified as high impact, resettlement of Project Affected Persons will take place. 150. Transmission Component. Extensive stakeholder consultations were held with residents along the proposed routes, local administrative officers, NGOs, CBOs and Faith-Based Organizations. For the Kindaruma-Mwingi-Garissa line, consultative public meetings were held in each of five project districts. For the Kisii-Awendo line, consultations were held in three districts in October 2009. In the case of the Eldoret-Kitale lines, eight consultative meetings were held over the months of September and October 2009. 151. Distribution Component. Consultations with affected communities will take place as part of the environmental and social screening process of sub-projects, and the results will be communicated in an understandable language to potentially affected persons and beneficiaries. J. Policy Exceptions and Readiness Policy Exceptions 152. The Project does not involve any exceptions to Bank policies. Readiness for Implementation 153. The following actions taken by the implementing entities and co-financiers illustrate the Project`s readiness: Key implementation personnel are in place in all implementing entities; The procurement plan for the first 18 months is in place; Financial management arrangements are in place; Conceptual designs for the generation, transmission, and distribution investments have been prepared; KenGen signed a contract with a design and supervision consultant in January 2010. The consultant has finalized the procurement strategy for the generation component and has prepared the draft pre-qualification documents for all contracts in the generation component; KPLC has initiated the selection for a design and supervision consultant for the transmission component and has begun preparing technical specifications for the distribution strengthening components; REA has identified the first year`s investments and has initiated procurement of the implementation support consultant; and All co-financiers have appraised the Project. The JICA loan agreements were signed in March 2010 and AFD`s Board approval was in April 2010. KfW and EIB expect to present the Project to their respective Boards for approval in May and June respectively. 48 Annex 1: Country and Sector or Program Background KENYA: Electricity Expansion A. Sector and Policy Background 1. The Government`s Policy for the energy sector (National Energy Policy, Sessional Paper No. 4, 2004) defines the Government`s vision as follows: to promote equitable access to quality energy services at least cost while protecting the environment. The Policy has resulted in far- reaching energy sector institutional restructuring, legislation, and regulation. Table 15 below enumerates these and their status. It is clear that the Government has already made substantive progress in implementing the reform agenda. Table 15: Status of Implementation of 2004 Energy Policy 2004 Energy Policy Commitments Status in 2010 Enactment of an Energy Act to facilitate prudential The Energy Act was promulgated in 2006. It provided for regulation and enhance stakeholder interests. the establishment of the Energy Regulatory Commission and also provided for the establishment of the Energy Tribunal to hear appeals arising from the decisions of the Commission. Establishment of a single energy regulator with The Energy Act defines the functions, powers and liabilities adequate mandate to regulate all sector players. of the Energy Regulatory Commission (ERC). It is a decision making body with its own budget. In the three years of its existence its track record on contested and key issues including approval of PPAs and tariff reform has demonstrated its professionalism. Establishment of a State owned Geothermal The Geothermal Development Company (GDC) was Development Company (GDC) to be in charge of established in 2008. geothermal resource assessments and sale of steam to future IPPs and KenGen for electricity generation. Privatize KenGen over time starting with an initial The IPO for 30% of KenGen stock took place on May 17, public offering (IPO) of 30% of its equity. 2006 and attracted more than 270,000 shareholders. Creation of a Rural Electrification Authority to The Rural Electrification Authority (REA) was established in accelerate the pace of rural electrification in the 2007 and a rural electrification master-plan (REMP) was country. finalized in 2009. REA has implemented rural electrification project valued at US$23 million through end 2009. Unbundling of KPLC into two entities, one for The transmission company KETRACO was established in transmission, which will be wholly state-owned and 2008. It will be responsible for new transmission assets. the other for distribution, which will be private The existing transmission assets will remain with KPLC. sector owned. Promoting privately or community owned vertically The most significant measure to promote private or integrated entities either operating renewable energy community supply companies has been the Feed In Tariffs power plants or hybrid systems, to coexist with Policy on geothermal, solar, wind, biomass and small hydro licensed electricity distributors. of April 2010. Allowing power generation companies to access The Energy Act 2006 permits electricity supply licensees to bulk electricity consumers through the power sell to large retail consumers. The regulator ERC is the transmission network. approval authority for licenses. Creating a domestic power pool with a provision for A domestic power pool has not been established. wholesale and retail markets to create competition and thus reduce the cost of electricity. 49 2004 Energy Policy Commitments Status in 2010 Privatization or concessioning of isolated power The Privatization Authority has engaged a transaction stations to reduce operating costs and thus free up adviser. resources for rural electrification expansion. Increase lifeline tariff applicable to domestic The Tariff Schedule of July 2008 that will remain applicable consumers of up to 50 kWh per month to at least for three years established the lifeline energy charge of KSh recover the cost of electricity generation. 2.00 per kWh for domestic consumers for the first 50 kWh consumed per billing period (month). Transfer of the rural electrification assets within the No progress made on transferring rural electrification assets interconnected electricity network to licensed to licensed electricity distributors. electricity distributors. Source: National Energy Policy, Sessional Paper No. 4, 2004. 2. Outcomes of the 2004 Energy Policy. Positive outcomes stemming from the reform program to date include: five independent private power producers; financially viable public companies (KenGen and KPLC) with large private shareholding; an independent regulator with an excellent track record of decision-making including tariff setting and approval of power purchase agreements; large increase in the rate of connecting new customers; and good progress in reducing system losses. Key sector performance data are provided in Table 16 below. Table 16: Electricity Sector Key Performance Data for 2009 Indicator Value No of electricity customers. 1,267,198. Household electricity access. 20%. The number of new connections being 201,194 in 2008/2009 (from 50,000 in 2001/2002 and 145,000 in made annually. 2007/2008). Average number of low voltage 5,065 in 2008/2009 (from 8,560 in 2005/2006). breakdowns per month. Improved customer service. KPLC`s customer service is best practice in the region. It utilizes pre- payment meters, deferred payment options, payment via mobile phones and other innovations for improved customer service. Revenue Collection as % of Billing. 100.4% in 2008/2009 (from 99.1% in 2005/2006). System load factor. 62%. Losses (% of energy purchased from 16.3% in 2009/2010 (reduced from 18.8% in 2003/2004). suppliers). In comparator countries losses are: Ghana 26%; Nigeria 34%; Ethiopia 19%; Tanzania 24% and Uganda 30%. Average growth in energy supplied 5.3%. (2003/2004 to 2008/2009). Cost Recovery. In FY2009 and FY2010 there is a small government subsidy to mitigate the cost of the high -- cost emergency generation that was contracted because of drought that reduced hydropower output. KPLC profit before tax was KSh 5.7 billion (US$76 million) in FY2009. KenGen profit before tax was KSh 5.1 billion (US$68 million) in FY2009. Number of Customers per staff. KPLC 181 compared to 264 for UMEME (Uganda), 167 for Tanesco (Tanzania) and 155 for EEPCO (Ethiopia). Construction costs for transmission and Unit costs compare favorably with other countries (US$100,000 for 132 distribution line unit costs. kV single circuit lines and US$20,000 and US$15,000 per kilometer for 33 kV and 11 kV lines respectively). 50 3. Emerging Electricity Sector Challenges. The Government is committed to completing the policy reform agenda set out in 2004 even as it seeks to tailor it to the new challenges that have emerged since then. These challenges include persistently high international energy prices, uncertainty with respect to timing of regional supply projects from neighboring countries, spill- over effects of the global financial crisis that may dampen investor interest in large scale projects. More particularly the challenges facing the sector include the following: (a) High prices for electricity. High electricity prices, because they erode competitiveness, can be a disincentive for industry in deciding whether to locate in Kenya or expand their existing operations. Furthermore, households in Kenya consuming the modest amount of 200 kWh per month currently pay about 19 US cents compared to an average price of 11.5 US cents per kWh for residential customers in the United States in 200929. (b) Low levels of access constrain achievement of national socioeconomic goals. Approximately 20 percent of households in Kenya are estimated to have electricity access with the rest having to rely on fuel-based lighting, dry cell batteries, and other electricity substitutes that are costly and often unreliable. (c) Mobilizing investment for system expansion. Despite Kenya`s successful track record in attracting and sustaining IPPs (at the beginning of 2010, five IPPs accounting for 343 MW are in operation) the international financial crisis may dampen investor interest in new projects in Kenya. (d) Uncertainty with respect to timing of regional supply projects in neighboring countries. The international financial crisis has contributed to the uncertainty regarding implementation of some of the large generation projects in Ethiopia and elsewhere that can be a source of low cost electricity supply to Kenya. These projects are critical to the establishment of the east Africa power market. The eastern Africa power market would also contribute to greater reliability of electricity supply in Kenya and its neighbors and would reduce reserve capacity requirement for each country. B. Government Electricity Access Scale -- Up Program 2009 -- 2014 4. The Government has translated its vision for sector development into ambitious targets of 40 percent access by 2020 with an intermediate target to electrify one million new customers and to extend electricity service to all priority loads in rural areas in the next five years. 5. The Government has prepared a Prospectus -- the Kenya Electricity Access Investment Program Prospectus: 2009 -- 2014. The Prospectus was presented to development partners on October 22, 2009 at a donor conference. The Prospectus estimates that US$4,902 million of investment will be required in new generation, transmission and distribution assets to achieve the objectives of its Energy Access Scale-Up Program (Table 17). 29 Average residential price for 2009 according to the Unites States Energy Information Administration. 51 Table 17: Electricity Access Investment Program and the Project by Investment Category Investment Implementing Agency Total Cost of Financing Financing provided Category Government provided by by the Project Program Donors outside of 2009-14*) the Project Geothermal Geothermal Development US$753 million US$605 million US$0 Resource Company Development Generation Independent Power Producers US$1,493 million US$219 million US$1,035 million and KenGen Transmission Kenya Electricity Transmission US$1,096 million US$670 million US$73 million Company Distribution Kenya Power and Lighting US$464 million US$236 million Company Rural Rural Electrification Authority US$1,114 million US$673 million US$36 million Electrification (GoK) Total US$4,902 million US$2,167 million US$1,380 million Source: Electricity Access Investment Program Prospectus 2009 -­ 2014, Ministry of Energy, Kenya, October 2009 6. Table 18 presents a summary of the financial projections completed for the Scale-up Program. The main conclusions of the analysis are as follows: (a) Investment costs. The cost of new capital investment in transmission and distribution (including off-grid and solar systems) from 2010 --2014 is estimated at approximately US$2.0 billion. The capital cost of new generation is excluded from the table since the capital and operating costs of power generation are included in power purchase agreements. (b) Operating cash flows. Net operating cash flows (revenue collected less generation costs, operating costs and finance costs) will be sufficient to meet repayment obligations of about US$250 million on loans at current tariff levels if commercial and concessional lending sources are used. Unless concessional loans of about US$1 billion from donors are available for the Scale-up Program during 2010--2014, the residential retail tariff would need to increase by about 10 percent to meet repayment obligations. Assuming current real tariff levels, the sector will directly contribute to the capital costs of new investments and will be able to service future loans from operating cash flows that are estimated at approximately US$262 million between 2010 and 2014. 52 Table 18: Financial Projections for the Electricity Access Investment Program 2010 2011 2012 2013 2014 Total US$m US$m US$m US$m US$m US$m Net operating cash flows: 32.0 31.9 39.9 71.6 87.1 262.5 Investment costs 32.0 31.9 39.9 71.6 87.1 262.5 ­ Off-grid 56.0 45.2 48.2 48.9 46.1 244.5 ­ Grid 405.5 526.1 366.5 206.2 206.2 1,710.5 ­ Revolving fund 50.0 0.0 0.0 0.0 0.0 50.0 ­ Total 511.5 571.3 414.7 255.1 252.3 2,005.0 Government contributions 114.5 128.0 104.9 65.5 61.6 474.5 and donor grants Borrowing and equity 397.0 443.3 309.8 189.6 190.7 1,530.5 contributions required Repayment obligations 15.4 40.2 58.3 66.4 70.4 250.7 Source: Kenya Electrification Investment and Policy Prospectus, October 2009, Castalia. 7. Planning approach for electricity access scale-up. The Government`s scale-up program is based on a least cost planning approach that maximizes the benefits of the program while minimizing the cost. The planning approach (Box 1: Least Cost Planning for Electricity Access Scale-Up) makes use of geospatial analysis to determine the technology option (grid, isolated mini-grid or off-grid including solar PV) for electrifying a given area. The planning approach takes account of population density patterns and the nature of grid rollout that requires strengthening of the transmission network concurrently with extension of the distribution network. The least cost approach favors first connecting areas with high population density that are closest to the existing grid and later connecting those areas that are less densely populated and that are more distant from the grid. Equity considerations compel modification of these strict least cost criteria so that the towns and districts centers in more remote areas also benefit from the scale-up program. Thus, while maintaining least-cost principles, the planning approach also targets electrification within 10 years of all priority loads (i.e. schools, clinics) in rural and district centers. 53 Box 1: Overview of Least Cost Planning for Electricity Access Scale-Up DATA INPUTS PLANNING ANALYSIS Costs of Medium voltage Comparison of cost of technology options - Grid and Off-Grid lines and off-grid facilities. (including hydro, diesel and solar photovoltaic) Fuel costs Demographic data. Geographic information of Selection of Least Cost Electrification Option existing electricity and other infrastructure & Priority Loads Geospatial Rural Solar prioritization for Electrification electrification for grid compatible Program for grid remaining priority areas compatible areas loads Investment Plan for Electrification (Grid and Off-Grid) C. Supply Demand Balance 2004 -- 2015 8. Electricity consumption, including system losses in the interconnected system grew from 5,035 GWh in 2004 to 6,489 GWh in 2009, a total increase of about 29 percent. Recorded coincident peak demand also grew from 884 MW to 1,070 MW, about 10 --15 percent below the unconstrained demand due to the combination of inadequate generating capacity and distribution system constraints. 9. The available electricity for consumption is dictated mostly by the production of the hydropower plants, which account for approximately 50 percent of total installed power Comparison of technology costs--The country hydropower 6,622 is critically dependent on the generating capacity. Production from thewas divided intoplantsplanning cells (sub-locations), and a simple demand forecast is computed for each planning are in final demand in each weather to compare the capital and prevailing hydrological conditions, whichcell. Theturn influenced bycell is usedconditions. In operating in 2004 -- 2005 and in 2007 -- 2009, dry weather each area. particular,costs of appropriately-sized technologies to serve demand in conditions led to about 15 percent Geospatial prioritization for grid compatible areas--To prioritize new grid connections a weight is applied to grid and 22 percent decline in generation from the hydropower plants relative to prior years. During compatible cells depending on demographic and cost factors, including proximity to the existing grid, interhousehold distances, social infrastructure, access to road networks, and below ability of consumers curve to minimize the drought period the reservoirs have been operatedthe initialthe minimum rule in each planning cell to afford of high the useelectricity.cost oil-fired diesel plants. Under this operating regime, it has been impossible to Rural reservoirs program (off-grid areas)--The off-grid systems planned in shortages continue to fill theelectrificationduring years of average hydrology, and the supplythe REMP are incorporated into the prevail. Since the take-or-pay contractual arrangements with the Independent Power Producers scale-up plan. Solar are based on capacity charge, loads--Areas that are from emergency medium off-grid systems (IPPs)electrification for remaining priority energy production not planned for grid connection orspeed diesel will need to been some electrification with the target plants have receivecontracted to copeto meetdemand. of providing supply to all priority loads. Investment plan for national electrification--The cost of the planned investments (grid and off-grid) provide the basis for detailed financial analysis. This analysis considers how the investments can be financed at the lowest possible cost to mitigate tariff impacts of the investment program and ensure that electricity will be affordable to a sufficient proportion of Kenyan households. 54 Source: Kenya Electrification Investment and Policy Prospectus, October 2009, Castalia 10. To correct the situation to achieve lowest cost operating regime, the Government has decided to undertake a detailed reservoir and hydropower plant optimization analysis, which would provide for the optimal utilization of the hydropower plants relative to the thermal power plants. The analysis should consider both short-term and long-term optimization of the generating system to establish the value of water for sustainability of the available hydrology. 11. The projected energy balance (Table 19) from 2009 onwards, even under conservative assumptions about demand growth indicates almost 60 percent increase in demand relative to 2009 by 2015 (see Annex 9 for background to estimate). 12. A number of additions to the generating system to cope with the demand and to provide for adequate reserve margin are at various stages of implementation (Table 20). The capacity additions are based on the long-term least-cost generation expansion study. The uncertainty about the production of the hydropower plants points to risk of being able to cope with the demand. To cope with such a risk, there is a policy to accelerate the expansion of geothermal capacity to relieve the hydropower plants from base load duty to mid-range and peaking duty, and in turn reduce the role of oil-fired thermal generation. 13. There is opportunity to address supply security and address the cost of power supply through a focus on regional power interconnections and possibly joint development of large scale plants for economies of scales in partnership with neighboring countries. Such large scale plants would enable the introduction of modern power generating technologies for higher efficiencies and lower environmental and climate change impacts. 55 Table 19: Supply and Demand Outlook 2004 -- 2015 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Net Sent Out Energy Actuals Forecast (GWh) KenGen Hydropower Stations 3259 2869 3025 3277 3488 2849 2203 2963 3435 3490 3502 3502 Oil-fired Thermal Power Stations 352 491 626 421 408 587 473 894 1177 743 704 783 Geothermal Power Stations 682 920 886 900 922 903 974 974 990 990 2018 3048 KenGen --Total (GWh) 4293 4280 4537 4598 4818 4339 3650 4831 5602 5223 6224 7333 Independent Power Producers Oil-fired Thermal 455 841 978 872 871 914 Geothermal 105 115 117 112 98 276 378 378 378 378 378 378 Wind Power Stations 0 0 0 0 0 0 13 13 53 53 53 193 Coal ARM 159 159 159 159 159 159 159 IPPs -- Total (GWh) 560 956 1103 984 970 1190 1901 1781 2644 2411 2056 2428 Emergency Power Producers (EPP) GWh Oil fired Thermal 0 0 30 561 556 914 1053 517 Imports (GWh) UETCL 171 99 15 13 25 29 29 29 29 29 29 29 TANESCO 0 0 0 1 1 1 1 2 2 2 3 3 Imports -- Total 171 99 15 14 26 30 30 30 30 30 30 30 Total Sent Out + Imports 5024 5336 5686 6157 6370 6474 6825 7316 7929 8701 9600 10576 Exports to Uganda 0.0 15.0 24.0 73.0 46.0 27.0 0.0 0.0 0.0 0.0 0.0 0.0 Net Available to Transmission Network (GWh) 5024 5321 5662 6084 6324 6447 6825 7316 7929 8701 9600 10576 Transmission Losses % 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 Transmission Losses (GWh) 201 213 226 243 253 258 273 293 317 348 384 423 Net Available to Distribution Network (GWh) 4823 5108 5435 5840 6071 6189 6552 7024 7612 8352 9216 10153 Distribution Losses % 0.148 0.141 0.156 0.136 0.126 0.123 0.118 0.113 0.108 0.103 0.103 0.103 Distribution Losses (GWh) 733 744 879 848 795 784 773 794 822 860 949 1046 Net Available for Consumption 4090 4364 4556 4992 5276 5405 5779 6230 6790 7492 8267 9107 Effective Capacity + New Additions (MW) 995 904 996 1014 1254 1310 1537 1707 2110 2364 2464 2514 Allowance for maintenance (MW) 154 171 317 355 370 377 Net Available Reliable Capacity (MW) 995 904 996 1014 1254 1310 1383 1536 1794 2009 2094 2137 System Peak Demand (Recorded) -- MW 884 899 920 987 1044 1072 Est. Unconstrained Demand (MW) 884 908 965 1036 1111 1192 1262 1353 1466 1609 1775 1955 System Reserve Margin (%) 12.6 -0.4 3.2 -2.1 12.9 9.9 9.6 13.6 22.3 24.9 18.0 9.3 System Load factor (factor) 0.65 0.67 0.67 0.67 0.65 0.62 0.62 0.62 0.62 0.62 0.62 0.62 14. Least Cost Power Development Plan. The Government`s Least-Cost Power Development Plan (LCPDP) prioritizes the required investments in generation to meet demand from new connections in the access scale-up program as well as estimated demand from 56 economic growth. The LCPDP was developed with technical assistance from the World Bank using power sector planning tools MAED for load forecasting, Valoragua for hydro-thermal mix optimization and WASP for least cost expansion plan. The LCPDP covers the period 2009 -- 2029. Committed investments with commissioning anticipated through 2016 (i.e. over the proposed project period) are in Table 20 below. Table 20: Status of Committed Power Generation Projects to be Commissioned 2009 -- 2016 Actual or Project Name & Developer Capacity Status in April Anticipated Fuel Type (MW) 2010 Date of Commissioning September 2009 Mumias cogeneration Private sector (Sugar refiner) 26 Operational September 2009 Ngong Wind Public Sector (KenGen) 5.1 Operational October 2009 Kiambere Hydro Public Sector (KenGen) 20 Operational December 2009 Iberafrica Extension Private Sector IPP 52.5 Operational II Thermal (oil) December 2009 Rabai Thermal (oil) Private sector IPP 83.3 Operational December 2009 Rabai Steam Turbine Private sector IPP 5.3 Operational May 2010 Tana Hydro Public Sector (KenGen) 20 May 2010 Olkaria II Unit 3 Public Sector (KenGen) with 35 Operational IDA, KfW and AFD financing December 2010 Kipevu III Thermal Public Sector (to be financed 120 (oil) from KenGen Public Infrastructure Bond) December 2010 Athi River Thermal I Private Sector IPP (with 80 Negotiations in possible IDA Partial Risk progress Guarantee and MIGA) June 2011 Athi River Thermal II Private Sector IPP (with 80 Negotiations in possible IDA Partial Risk progress Guarantee and MIGA) June 2011 Thika Thermal Private Sector IPP (with 80 Contract award in possible IDA Partial Risk progress Guarantee and MIGA) December 2011 Ngong Wind Phase II Public Sector (KenGen) 14 N/A Athi River Thermal Private Sector IPP 19 (coal) October 2011 Sangoro Hydro Public Sector (KenGen) 21 January 2011 Eburru Geothermal Public Sector (KenGen) 2.5 June 2013 Kindaruma upgrade Public Sector (KenGen) 32 Hydro N/A Geothermal Wellhead Public Sector (KenGen) 75 2014 Mombasa Thermal Public Sector (KenGen with 300 Negotiation with (Coal) Joint Venture (JV) partner) JV partner June 2014 Olkaria I extension Public Sector (KenGen) with 140 IDA, KfW, JICA, AFD and EIB June 2014 Olkaria IV Public Sector (KenGen) with 140 IDA, KfW, JICA, AFD and EIB 2013 Olkaria III Private Sector IPP 50 2013 Turkana Wind Private Sector IPP 300 Source: Least Cost Power Development Plan, Government of Kenya, 2009. 57 D. Sector Institutional Background 15. Ministry of Energy. The Ministry of Energy leads the Government`s policy-making in the electricity sector. 16. Ministry of Finance. The Ministry of Finance represents the Government as the majority owner of KPLC and KenGen. 17. Kenya Electricity Generating Company (KenGen). KenGen is responsible for managing, operating, and developing all of Kenya`s public power generating facilities. KenGen accounts for 75 percent of installed capacity in 2009 and sells to KPLC under several power purchase agreements (PPAs) approved by the regulator in 2009. KenGen was listed through an initial public offering of 30 percent of Government-owned equity in March 2006. In 2009 it issued a public bond, the largest infrastructure bond to date in Kenya that attracted 3,207 investors of which 2,500 were retail investors and raised US$330 million. KenGen`s vision is to be the market leader in the provision of reliable, safe, quality and competitively priced electric energy in the Eastern Africa region. 18. Kenya Power and Lighting Company. KPLC is responsible for procuring power, managing, operating, and maintaining the transmission and distribution network, and selling power to retail customers. It is subject to regulation by ERC that sets performance targets including: revenue collection as a percentage of total billing; meter reading coverage; average waiting period for new connection; and system losses. 19. Independent Power Producers. Five independent power producers (IPPs) -- Iberafrica, OrPower4, Tsavo, Mumias and Rabai -- account for 16 percent of installed capacity in late 2009. - Iberafrica -- Thermal power plant 108 MW OrPower4 -- Geothermal power plant 48 MW (increasing to 100 MW by 2014) - Tsavo -- Thermal power plant 74 MW - Mumias Sugar Co. Ltd. -- Cogeneration plant 26 MW - Rabai -- 86.6 MW thermal power plant 20. Geothermal Development Company (GDC). The Government established the Geothermal Development Company (GDC) in 2008 to take primary responsibility for the exploration and development of geothermal resources. GDC will confirm the viability of potential geothermal resources through a program of technical studies and exploratory drilling, and offer geothermal resources to potential power developers through competitive tendering. 21. Kenya Electricity Transmission Company (KETRACO). KETRACO was established in late 2008 to plan, finance, build and manage new transmission assets. Existing transmission assets will remain with KPLC. In the medium-term (5 to 7 years) the Government intends that KETRACO becomes a fully fledged Independent System Operator (ISO) of the high voltage transmission system and of the bulk power supply electricity market. KETRACO would be a provider of transmission services, including load dispatching, operation, management, and development of new high voltage transmission network. 58 22. Rural Electrification Authority. The Rural Electrification Authority (REA) was established under the 2006 Energy Act to implement the Rural Electrification Program. The REA is responsible for planning rural electrification according to guidelines provided by the Ministry of Energy, and manages the Rural Electrification Program Fund for these objectives. REA extends distribution lines from KPLC`s existing network into new areas, and constructs off- grid supply systems in areas that cannot economically be grid connected. 23. The Energy Regulatory Commission. The Electricity Regulatory Commission (ERC) is the regulatory agency for the entire energy sector. The ERC is responsible for economic and technical regulation of the power, renewable energy, and downstream petroleum sub-sectors. The ERC is required to protect the interests of consumer, investor, and other stakeholders. Functions of the ERC include reviewing and setting tariffs and service quality standards, licensing, enforcement, dispute settlement, approving power purchase and network service contracts, and preparing an indicative national energy plan. E. Geothermal Resources in Kenya 24. Kenya has become a world leader in development and utilization of its indigenous, green, and abundant geothermal resources. At Naivasha, north-west of Nairobi, installed geothermal generation capacity is 198 MW in April 2010. This ranks Kenya in the top 10 nations to have developed geothermal resources for power production. There are many additional sites in the Rift Valley (Figure 3) where exploratory drilling will be carried out to determine the resources. The group of international consultants retained by KenGen to advise on its geothermal development program has determined that the Menengai and Longonot geothermal prospects are ready for drilling of exploratory wells, with the aim of confirming commercial resources at each site. It is expected that drilling of Menengai will begin in 2010 and of Longonot in 2011. On the basis of surface exploration and field modeling in about 13 sites, it is reasonable to expect reserves of several hundred MW at each of these fields. Figure 3: Location of Geothermal Resources 59 Annex 2: Major Related Projects Financed by the Bank and/or other Agencies KENYA: Electricity Expansion 1. Related World Bank Projects IDA IP DO Project Credit No. Sector Issue lending Co-financing rating rating (US$m) Energy Sector Power Kenya, EIB, 3958-KE S S 80 Recovery project AFD, NDF Energy Sector Recovery project Power Kenya, EIB, 4572-KE S S 80 Additional AFD Financing 2966-KE Energy Sector Kenya, EIB, Completed in Power S S 125 Reform project KfW June 2004 Private power/ MIGA guarantee renewable N/A N/A 50 for geothermal IPP energy Agricultural Agriculture/ Productivity and 4592-KE S S 82 Kenya Power Agri. Business Education Sector 4242-KE Education MU S 80 SWAP Support project Slum Upgrading Urban Kenya, AFD, Proposed N/A N/A 100 project infrastructure SIDA Urban Municipal Program Proposed N/A N/A 100 Kenya infrastructure Private power IFC Proposed (HFO, wind, N/A N/A N/A IDA, MIGA KPLC) 60 2. Related development partner-financed projects 1. African Development Bank (AfDB), Agence Française de Développement (AFD) and the European Development Bank (EIB) are cofinancing the 400 kV Mombasa-Nairobi Transmission line. 2. AfDB is syndicating financing for the proposed 300 MW Turkana wind power project to be implemented as a Public Private Partnership. 3. Government of Spain plans to finance the 400 kV transmission line from the Turkana wind project. 4. The French Development Agency (AFD) has financed studies and technical assistance and a pilot Revolving Fund scheme to reduce the upfront cost of electricity connections. It plans to finance drilling rigs for the Geothermal Development Company. 5. AFD and Government of Spain are financing rural electrification projects. Spain is also financing solar PV electrification in rural areas. 6. JICA has provided financing for the construction of the 60 MW Sondu Miriu hydro power plant and the ongoing construction of the 21 MW Sangoro hydropower plant. It plans to finance the construction of the 220 kV transmission line from Olkaria to Lessos. KfW is financing the rehabilitation of existing two units and installation of one new unit at Kindaruma hydro power plant (total 32 MW). 7. Government of Finland has financed the preparation of the Rural Electrification Master plan and co-financed electricity distribution investment. 8. UNIDO is financing decentralized generation. 9. Governments of Spain and Belgium are financing wind power projects in Ngong Hills. 10. Government of China is financing geothermal drilling and plans to finance transmission lines. 11. Government of Hungary plans to finance transmission lines. 12. BADEA, OFID and the Saudi Fund for Development are considering financing rural electrification and transmission. 61 Annex 3: Results Framework and Monitoring KENYA: Electricity Expansion Table 21: Results Framework PDOs Outcome Indicators Use of Project Outcome Information (a) Increase the 1. Electricity generated from renewable generation Assess project effectiveness in capacity, efficiency, and capacity constructed under the project, (net improving electricity service quality of electricity GWh/year). quality and reliability. supply. 2. Electricity losses per year in the project area (%) -- CORE Supplemental information: + Total net injected generation (MWh) + Share of technical losses (%) + Share of non-technical losses (%). 3. Average interruptions frequency per year in the project area (Number) -- CORE Supplemental information: Total number of customers served in the project area. 4. People provided with access to electricity in the Assess project effectiveness in (b) Expand access to project area (Number) -- CORE. increasing electricity access electricity in urban, (disaggregated by gender and peri-urban and rural Supplemental information -- breakdown by: grid type of user). areas. connection, off-grid connection, conventional, and off-grid connection renewable. 5. Direct project beneficiaries (number), of which female (%) -- CORE. Intermediate Intermediate Outcome Indicators Use of Intermediate Outcomes Outcome Monitoring Component A: 6. Generation capacity of renewable energy Assess timeliness of Geothermal (geothermal) constructed or rehabilitated under the implementation in the Generation project (MW) -- CORE. construction of new generation capacity. Increase electricity generation capacity from renewable green source (geothermal). Component B: 7. Transmission lines constructed or rehabilitated Assess timeliness of Transmission under the project (km) -- CORE. implementation in the construction of transmission Increase the capacity of Supplemental information -- breakdown by: lines. the electricity transmission lines constructed, transmission lines transmission system to rehabilitated. supply existing and new customers. 62 Component C: 8. Distribution lines constructed or rehabilitated by Assess timeliness of Distribution KPLC under the project (km) ­ CORE. implementation in construction of new distribution lines and Extend and upgrade the Supplemental information: distribution lines substations. electricity distribution constructed, and distribution lines rehabilitated, system. rural and non-rural. Assess timeliness in service delivery to social institutions 9. Substations constructed or rehabilitated by KPLC and agri-enterprises in rural under the project (number). areas. 10. Distribution lines constructed in rural areas by REA under the project (km). 11. Isolated grids constructed or rehabilitated by REA under the project (number). Supplemental information: disaggregation by type of generation. 12. Community (public facilities) electricity connections provided under the project (number) -- CORE Supplemental information -- breakdown by community center, hospital, school and other. 13. Business electricity connections provided under the project (number) -- CORE. Supplemental information: breakdown by enterprises and agri-business. Component D: Sector Institutional Development and Operational Support Improve capacity of 14. Roadmap for implementation of the wholesale Assess effectiveness of sector institutions. electricity market is adopted by MoE. technical assistance for 15. Rural Electrification Master Plan (REMP) annually institutional and policy updated. development. 16. Cost of service study completed one year before 2014 tariff review is launched. 63 Table 22: Arrangements for Results Monitoring Project Outcome Baseline Data Responsibility Indicators (2010) 2011 2012 2013 2014 2015 2016 Frequency Collection for Data Comment Instruments Collection 1. Electricity generation from renewable generation KenGen capacity constructed under KenGen PIT 0 0 0 0 1100 2020 2020 Annual operational the project, net Team Leader report (GWh/year). 2. Electricity losses per 16.3 15.7 15.2 15.0 15.0 14.7 14.5 year in the project area (%) -- CORE. Supplemental information: KPLC + Total net injected audited KPLC PIT generation (MWH) Annual financial Team Leader + Share of technical losses statements (%) + Share of non-technical losses (%). 3. Average interruptions 70,000 67,000 64,000 61,000 57,000 54,000 51,000 frequency per year in the project area (Number) -- KPLC CORE. KPLC PIT Annual operational Supplemental information: Team Leader reports Total number of customers served in the project area. 4. People provided with 0 0 0 150,000 475,000 925,000 1,425,000 1.425 million access to electricity in the people target project area (Number) -- corresponds to CORE. 285,000 KPLC and KPLC and household Supplemental information: Annual REA project REA PIT connections, reports Team Leaders assuming the breakdown by urban grid, average size of rural grid, rural offgrid Kenyan conventional and rural household of 5 offgrid renewable. 64 Project Outcome Baseline Data Responsibility Indicators (2010) 2011 2012 2013 2014 2015 2016 Frequency Collection for Data Comment Instruments Collection 5. Direct project 0 0 150,000 475,000 925,000 1,425,000 Direct beneficiaries (number), of (49.5%) (49.5%) (49.5%) (49.5%) beneficiaries which female (%) -- are people that CORE. KPLC and KPLC and will be Annual REA project REA PIT provided with reports Team Leaders access to electricity in the project area. Intermediate Outcome Indicators Component A: Generation Generation capacity of 0 0 0 0 280 280 280 Annual KenGen KenGen PIT Renewable Energy operational Team Leader constructed or report rehabilitated under the project (MW) -- CORE Supplemental information: breakdown by the generation source. Component B: Transmission Transmission lines 0 0 0 105 334 334 334 Annual KPLC KPLC PIT constructed or rehabilitated Team Leader under the project (km) -- CORE. Supplemental information - - breakdown by: transmission lines constructed, transmission lines rehabilitated. Component C: Distribution upgrading and expansion 65 Project Outcome Baseline Data Responsibility Indicators (2010) 2011 2012 2013 2014 2015 2016 Frequency Collection for Data Comment Instruments Collection Distribution lines KPLC KPLC PIT constructed or rehabilitated 0 0 0 350 1,025 1,700 2,280 Team Leader under the project (km) -- CORE. Of which 0 0 0 0 500 1,000 1,500 KPLC KPLC PIT Urban (KPLC) Annual Team Leader Supplemental information +Urban lines constructed +Urban lines rehabilitated. Rural lines constructed 0 0 0 350 525 700 780 REA REA PIT (REA). Team Leader Substations constructed or rehabilitated by KPLC KPLC PIT 0 0 0 0 10 20 26 Annual KPLC under the project Team Leader (number). Community (public 0 0 0 200 300 400 450 facilities) electricity connections provided under the project (number) -- CORE. REA project REA PIT Supplemental information - Annual reports Team Leader - breakdown by Community center, Hospital, School, Trading Centers and Other; and by conventional and renewable energy source. Business electricity 0 0 0 0 5,000 10,000 15,000 connections provided under the project (number) -- CORE AFRICA. REA project REA PIT Annual reports Team Leader Supplemental information -- breakdown by enterprises and agri- business. 66 Project Outcome Baseline Data Responsibility Indicators (2010) 2011 2012 2013 2014 2015 2016 Frequency Collection for Data Comment Instruments Collection Component D: Sector Institutional Development and Operational Support Roadmap for No No Yes Yes Yes Yes Yes implementation of the MoE Project wholesale electricity Year 3 GOK report Coordinator market is adopted by MoE. Rural Electrification Master Plan (REMP) Annual, MoE Project annually updated. No No No Yes Yes Yes Yes starting REA reports Coordinator Year 3 Cost of service study completed one year before MoE Project 2014 tariff review is No No No Yes Yes Yes Yes Year 3 ERC reports Coordinator launched. 67 Arrangements for Monitoring and Evaluation Overview 1. There are four levels to the Project`s performance monitoring. The first is monitoring of the Project`s outcome and intermediate outcome by tracking progress in the implementation of the project`s four components and the achievement of key outcome indicators. The second level consists of the extent to which the implementing agencies have met financial performance indicators. The third level concerns the environmental and social indicators. The fourth level is third-party monitoring and evaluation of the Project`s progress in improving economic opportunities and raising living standards. Project Implementation Progress and Outcome 2. At the project level, the monitoring arrangements in Table 22 will govern the evaluation of key performance indicators (project outcome and intermediate outcome). The Project Implementation Teams (PITs) of each implementing agency will be responsible for collecting the required data for monitoring the performance of the component that the entity will manage. The allocation of responsibility will be as follows: (a) KenGen, for Component A (geothermal generation); (b) KPLC, for Components B, C1, C3 and C4 (transmission and distribution upgrading); (c) REA, for Component C2 (rural electrification); and (d) MoE, for Component D (technical assistance for sector development). 3. Each PIT will prepare quarterly progress reports summarizing, inter alia, the outcomes of the Project relative to targets. The monitoring may involve indicators additional to those shown in Table 22. For KPLC and KenGen, the officers responsible for performance monitoring (Chief Manager, Planning, Research and Performance Monitoring (KPLC) and Manager for Regulatory Affairs (KenGen) will audit the performance indicators (incorporated in stated quarterly progress reports) for accuracy, before submitting the reports to the Project Coordination Team (PCT). This team, in turn, will be responsible for consolidation of the information from the implementing entities and distribution to the Ministries of Energy and Finance and the development partners. Financial Performance of Sector Entities 4. The financial performance of the sector entities, KenGen and KPLC, will have a significant impact on the achievement of project outcome indicators. For example, less than satisfactory financial performance could hinder the ability of the implementing entity to manage key project activities, which could adversely affect the achievement of targets for electricity access under the Government`s scale-up program. Therefore, the Project`s supervision staff will closely monitor financial performance targets reflected in the legal agreements for the Project and reported in the quarterly progress reports. 68 Monitoring of Environmental and Social impacts 5. Each of the Project`s investment components has an environmental and social monitoring and evaluation plan (ESMP). For the generation and transmission components, RAPs have been developed and these include plans for monitoring and evaluation of the impacts of resettlement. Data collection will be the responsibility of the implementing entities, which have experience in World Bank-financed projects. The implementing entities will compile the data and produce quarterly impact reports. Third-party Monitoring and Impact Evaluation 6. A premise of the Government`s electricity scale-up program and of the Project is that electrification is key to fostering economic opportunity and raising living standards. Electrification is expected to generate small business development, foster economic linkages, and enhance agricultural production along with other income-earning opportunities in both rural and urban areas that will benefit from the program. Studies of electrification programs in Bangladesh, Vietnam and elsewhere have provided empirical evidence that electrification enhances social outcomes through reduced cost and improved quality of lighting and improved service delivery of public facilities such as schools, health clinics and public administration. 7. Knowledge and understanding of specific conditions for maximizing the impacts of electrification can improve program design. For example, in what way do initial conditions at the community and household levels interact with the program to influence the rate of connection take-up and penetration? Are impacts higher or lower in places with higher levels of initial development in terms of market and other institutions? How does the presence or absence of other development programs in areas being electrified influence outcomes? Such information, based on careful, rigorous impact evaluations will help improve program appraisal and design including post-electrification initiatives that can increase the Project`s impact. 8. In contrast to assistance with relatively rapid welfare impacts (such as cash transfer programs), the impact of electrification programs may not be immediately apparent. Furthermore, long-term evaluations are difficult to design and sustain. The third party monitoring and evaluation of design will need to balance the requirement of rigorous methodology with cost considerations. MoE will contract an external consultant to conduct this impact analysis. Monitoring and Evaluation Capacity of Implementing Entities 9. The implementing entities have capacity and specialized staff for monitoring and evaluation. The Project, however, will provide additional assistance for those aspects of monitoring and evaluation that the entities may not be familiar with, e.g. third-party monitoring and evaluation. 69 Annex 4: Detailed Project Description KENYA: Electricity Expansion Overview 1. The Project has four interlocking components essential for not only meeting future electricity demand but also for diversifying Kenya`s electricity supply from climate dependent hydro power to more reliable green geothermal energy, expanding access to electricity, improving supply reliability, and advancing electricity sector reforms. The first component, which is the largest, accounting for 74 percent of total project cost, is the expansion of geothermal power generation capacity at Olkaria. The second component is the construction of three new transmission lines and related infrastructure to connect Garissa in the North Eastern Province to the national grid for the first time and improve the reliability of electricity supply to major agriculture areas in western Kenya. The third component supports investments required to launch electrification programs in urban and rural areas and to increase the reliability of supply. The fourth component consists of institutional development and operational support necessary for future system planning, increased private sector participation in power markets, and renewable energy development to reduce the adverse environmental impact of fossil fuels. The following sections describe the activities of each component, their investment costs and the financing plans, and the allocation of activities by financier. Component A. Geothermal Generation Description of Activities 2. This component will construct 280 MW of geothermal generation capacity, consisting of (a) an extension of the capacity of the existing Olkaria I by 140 MW; (b) a new power station in the Olkaria Domes field, adjacent to the Olkaria I station, with a capacity of 140 MW; and (c) connection of steam wells to the two power stations and the associated facilities for transmitting the power to the national grid. The Project will also finance consulting services for design and supervision, and installation of infrastructure facilities at the construction sites. The drilling of geothermal steam wells through January 2010 secured 50 percent of the steam required for the 280 MW. To obtain the rest of the steam required for the project, drilling will take place during the construction of the power plants over two and a half years30. Cost and Financing 3. The estimated cost of the component is US$1,035 million. The financing plan is: IDA (US$120 million); JICA (US$323 million); AFD (US$210 million); EIB (US$168 million); KfW (US$84 million); and KenGen (US$130 million). 4. The financing involves a combination of joint financing of two main contracts by co- financiers (IDA & KfW and AFD & EIB) whose procurement procedures are flexible enough to permit such an option and parallel co-financing of the other contracts. Each co-financier will have its own loan agreement. IDA, AFD and EIB will lend to the Government, which will re-lend the 30 The cost of drilling the outstanding wells is about US$273 million. Of this KfW will finance US$15 million, the Exim Bank of China US$95 million, and GOK US$163 million. 70 money to KenGen. JICA and KfW will lend directly to KenGen. IDA and the other co-financiers have built in flexibility in their disbursement arrangements to cater for potential variations in the final costs of the contracts. The cost estimates include contingencies. Packaging of Contracts 5. The design of the packaging for the contracts has given considerable attention to efficiency in the use of funds from five development partners. A key element in the design is the use of a single consulting engineer to plan and coordinate the various activities required to complete the construction of the two power plants. Other factors taken into account are: (a) the need to accommodate the multiple international sources of financing while promoting competition among contractors and suppliers as much as possible in order to obtain competitive prices for the various Project components; and (b) lessons learned from the experience with procurement for the ongoing ESRP. The allocation of activities among financiers also has taken account of their preferences. For example, JICA prefers to provide co-financing with KenGen and to finance electromechanical equipment and AFD prefers to finance equipment but not consultancy. Finally, each construction contract will have a maximum of two co-financiers, to minimize KenGen`s administrative work and streamline the approval process. Allocation of Activities by Financier 6. In line with the recommendations of the feasibility study for the Component and taking account of the above contract packaging criteria, the Component has activities organized in seven categories. Three categories have two joint financiers and four have a single financier. A1. Activities Financed by IDA with Joint Co-Financing from KfW (US$147 million)31 Supply and installation of steam gathering and distribution systems for Olkaria I and IV. These installations will include steam separator stations, steam distribution pipelines from the separator stations to the power plants, pipelines for re-injection of hot and cold condensates to re-injection wells and instrumentation systems. A2. Activities Financed by IDA (US$13 million) (a) Construction of access roads and other local infrastructure required to construct and operate the plants. (b) Technical advisory services, including Panel of Geothermal Experts. These experts will provide KenGen with independent review of the Project`s technical implementation. A3. Activities Financed by KfW (US$30 million) Design and supervision services. The subcomponent will finance design and supervision engineering services to facilitate efficient execution of the Component. The consultancy assignment will include: (i) preparation of pre-qualification; (ii) detailed design for steam field development; (iii) preparation of bidding documents including technical specifications 31 Costs estimate exclude contingencies. 71 and construction schedules; (iv) assistance to KenGen in the tendering process; (v) project management; (vi) construction works supervision; and (vii) training of KenGen staff in project management, bid evaluation, contract administration, project cost tracking and reporting, risk management, steam pipeline design, and design review of power plant and high voltage substation and transmission line drawings. A4. Activities Financed by JICA with Co-Financing from KenGen (US$305 million) Power plant development at Olkaria I. This includes the engineering, procurement and construction of all civil, structural, electrical, mechanical, control and instrumentation works including steam turbine generators for the 140 MW expansion of the existing Olkaria I power plant. These additions will increase the plant`s total power generation capacity to 185 MW. There will be one turnkey contract for all the required construction activities. A5. Activities Financed by AFD and EIB Jointly (US$340 million) Construction of a new power plant at Olkaria IV. AFD and EIB will finance the construction and commissioning of a new 140 MW power plant, Olkaria IV. The financing of this new generation capacity will cover all civil, structural, electrical, mechanical, control and instrumentation works for the new plant. There will be one turnkey contract for all the required construction activities. A6. Activities Financed by EIB (US$32 million) Construction of switchyards and transmission lines for connecting both Olkaria I and Olkaria IV to the national grid. EIB will finance the switchyards and transmission lines for connecting both Olkaria I and Olkaria IV to the national grid. The financing will cover the design, supply, and commissioning of: (i) a new 220 kV substation at Olkaria I; (ii) a new 220 KV substation at Olkaria IV; (iii) expansion of the existing Olkaria II substation; (iv) about 20 km of 220 kV double circuit line from Olkaria IV to a new substation at Suswa; (v) about 4 km of 220 kV, double -circuit line from Olkaria I to the existing Olkaria II substation and 25 km of 220 kV line from Olkaria II to the new substation at Suswa; and (vi) modification of the Suswa Substation to accommodate the new double circuit line from Olkaria IV. There will be one turnkey contract for all the required construction activities. A7. Activities Financed by KenGen (US$82 million) Acquisition of land and way leaves, resettlement and environmental management. KenGen will finance the acquisition of land for the construction of the Olkaria IV power plant and the associated transmission facilities (KenGen already has the land for the extension of Olkaria I). The company also will finance the environmental costs associated with the construction activities at both plants and the resettlement of people away from the project area because of air and noise pollution, including acquisition of land for the affected people. In addition, KenGen will finance: (i) local infrastructure for the power plant development, including the supply of construction power and water to the construction sites, and general administration of the Project; and (ii) interest during construction. 72 Component B. Transmission Description of Activities 7. This component will extend Kenya`s transmission network by constructing new 132 kV transmission lines and expanding the substations that step down the voltage from these lines to the distribution system. In addition to building the transmission system`s capacity to meet additional demand, Component B will help reduce losses, improve reliability, and enhance the quality of service. The component will build three new transmission lines: (a) Kindaruma-Mwingi-Garissa; (b) Eldoret-Kitale; and (c) Kisii-Awendo. These lines are among the eight 132 kV transmission lines that the Government has designated as priorities for construction during the period 2010 to 2015 in support of its electricity access expansion Program. They will contribute to the expansion of electrification in the Nyanza, Rift Valley and North Eastern Provinces; replace diesel generation; and improve the reliability of electricity supply to major agriculture areas, which have fast-growing population. Cost and Financing 8. The estimated cost of Component B is US$72.5 million. The financing plan is: IDA (US$64.5 million) and KETRACO (US$8 million). Allocation of Activities by Financier B1. Activities financed by IDA (US$64.5 million) (a) Kindaruma-Mwingi-Garissa line. This line will connect Garissa -- the provincial headquarters of the North Eastern Province -- to the national grid. Garissa currently depends on electricity from an isolated network of diesel-fired power units. Peak demand, currently about 5 MW is projected to more than triple by 2030, reaching about 18 MW. The project will help reduce the cost of generation and increase supply capacity that would otherwise be met by installing bigger diesel generators. The scope of work includes construction of 230 km of a 132 kV transmission line from Kindaruma, via Mwingi, to Garissa, including the following substations: (i) 132/33 kV, 1x7.5 MVA at Mwingi; and (ii) 132/11 kV, 1x15 MVA at Garissa. Without new 132/33 kV substations, several new 33 kV lines would have to be constructed. (b) Eldoret-Kitale line. This subcomponent will finance the construction of approximately 60 km of 132 kV, single-circuit transmission line, and a 132/33 kV, 23 MVA substation at Kitale. The 33 KV network that this subcomponent will strengthen is the 33 kV radial from the Eldoret 132/33 kV substation, which supplies the 33/11 kV substations Moi Barracks, Moi`s Bridge, Cheranguria, Kitale and Kapenguria. Several 33/0.4 kV distribution transformers are also connected to this 33 kV radial, most concentrated between Moi Barracks and Moi`s Bridge. The load in this area was about 15 MW in 2009 and according to the load forecast is expected to increase to about 45 MW by 2030. 73 (c) Kisii-Awendo line. This subcomponent will extend the Kisii 132 kV substation (additional 132 kV line bay) and construct 44 km of 132 kV lines and a 132/33, 1x23 MVA substation at Awendo. (d) Design and supervision services. This subcomponent will finance engineering services to facilitate efficient execution of the transmission component. This engineering company will help KPLC with bidding for the three design, supply, and installation contracts for the above lines. B2. Activities financed by KETRACO (US$8 million) Activities associated with the component's environmental and social impacts. These activities include land acquisition, resettlement, the implementation of the Environmental Monitoring Plans, and coordination with KPLC. Component C. Distribution Description of Activities 9. This component will have four subcomponents that will support the expansion and upgrading of the distribution network and connection of an additional 300,000 customers over the period of 2011 -- 2016. Approximately 90 percent of the new connections are likely to be in urban and peri-urban areas, with the remaining 10 percent in rural areas. About 17 percent of household connections will be in peri-urban slums. The estimated average cost per connection is US$960. Cost and Financing 10. The estimated cost of Component C is US$272 million, of which about 77 percent will be for the strengthening and extension KPLC`s distribution networks (Subcomponent C1). The remaining 23 percent will finance programs for the access of low-income areas (Subcomponents C2, C3 and C4). The budget allocation across components will be subject to evaluation during the Project`s mid-term review. Depending on the results of this review, it may be necessary to modify the allocation of resources among the various subcomponents in order to ensure efficient utilization of IDA funds. 11. The financing plan is: IDA (US$134 million); AFD (US$10 million); KPLC (US$30 million); REA (US$2 million); GPOBA (US$5 million); and users (US$91 million). Subcomponent C1: Strengthening and Extension of the Distribution Networks Description of Activities 12. This subcomponent will support the reinforcement and extension of KPLC`s distribution networks in the greater Nairobi metropolitan area and in the Coast, Mt. Kenya, and Western and Nyanza Provinces. Investments in this subcomponent are expected to result in 250,000 new connections over the period 2011 ­ 2016, improved system reliability and reduced losses. 74 13. Subcomponent C1 will support investments in substation construction and refurbishment and construction of new medium-voltage lines (66 kV and 33 kV) and low voltage (11 kV) lines. The component will upgrade some of the 11 kV lines to 33 kV (to increase power transfer capacity and power quality), replace some of the existing distribution transformers, rated 11/0.415 kV, with transformers rated at 33/0.415 kV and install auto re-closures and load break switches at strategic points along the lines, in order to minimize supply interruptions during normal line operations. The subcomponent`s provision of GIS indoor switchgear and tele-control equipment will support the linkage of substations to the SCADA system for automated system management. The subcomponent will also finance the purchase of pre-payment meters, which will enable consumers to better manage their electricity purchases (e.g. allowing them to limit the quantity of electricity they purchase to what they can afford) and facilitate revenue collection by KPLC. Cost and Financing 14. The estimated cost of this subcomponent is US$210 million. The financing plan is: IDA (US$95 million); KPLC (US$25 million); and users (US$90 million). Allocation of Activities by Financier C1 (a) Activities Financed by IDA (US$95 million) (i) Construction and upgrading of substations and power lines. This subcomponent will finance the construction and refurbishment of about twenty six 33/11 kV and 66/11 kV substations and the construction of about 1,390 km of distribution lines as follows: 320 km of 66 kV lines, 930 km of 33 kV lines, and 140 km of 11 kV lines. In addition, the subcomponent will finance associated poles and other equipment. (ii) Installation of pre-payment meters. IDA will finance 50,000 -- 60,000 pre-payment meters. (iii) Implementation support services. IDA will finance a supervision engineer to help KPLC with the implementation of Component C on an as needed basis. C1 (b) Activities Financed by KPLC (US$25 million) Installation, land acquisition, compensation, environmental monitoring, civil engineering. KPLC will finance: (i) installation of substations and lines; (ii) land acquisition for substations, way leaves, resettlement/compensation, and environmental monitoring; and (iii) the cost of a civil engineer. C1 (c) Activities Financed by Consumers (US$90 million) Service connections. New customers connected to the system will finance the cost of a meter and service line. A number of customers in the project areas are expected to benefit from the Revolving Fund, which the project will re-capitalize to allow the payment of the upfront cost of connection in affordable installments (subcomponent C4). 75 Subcomponent C2: Electrification of Priority Loads in Rural Areas Description of Activities 15. The Government`s Rural Electrification Master Plan (REMP) has identified and documented approximately 9,900 priority loads (i.e. public facilities such as schools, clinics, district headquarters, as well as all key trading centers) not yet electrified. Subcomponent C2 will contribute to the implementation of the REMP by electrifying at least 450 target loads, through grid connection as well as off-grid electrification schemes, which will use renewable energy technologies where possible. The electrification of these priority loads will in turn enable the electrification of an estimated 30,000 nearby, rural households. Not all of these connections will take place during the subcomponent`s implementation period because household connections typically lag electrification of public facilities. Subcomponent C2 also will assist REA in developing and testing off-grid electrification models, such as rural mini-grids powered by renewable energy technologies. 16. To support the alignment of electrification with economic development initiatives, the subcomponent will build linkages with key productive sectors and social services, with the main focus on agriculture. Thus, the subcomponent will electrify an estimated 250 trading centers, critical to the marketing and processing agriculture produce in Kenya. In addition, the subcomponent`s electrification activities emphasize linkages with the Kenya Agriculture Productivity and Agribusiness Project (KAPAP), which has identified the lack of electricity as one of the key constraints to improving agricultural productivity and agribusiness growth. 17. REA has identified 34 rural electrification schemes for the first year of the Project`s implementation. The estimated total cost of these schemes is US$10.5 million (including a contingency). All identified schemes were selected from the REMP, based on the following procedure: (a) 17 schemes that directly benefit priority locations of the KAPAP project; (b) 17 additional smaller schemes designed to improve contract packaging, economies of scale and regional distribution of the investments. The latter are primarily schemes adjacent to the KAPAP schemes with a higher order of economic priority, as identified in the REMP. Table 23 summarizes key data on the initial selection of electrification schemes. Table 23: First Year's Rural Electrification Investments by Province Number of Estimated costs Length of lines to be Number of priority Province schemes (US$ million) constructed (km) loads to be connected Coast 11 4.11 145 76 Eastern 6 2.57 92 44 Nyanza 6 1.49 52 37 Rift Valley 2 1.10 39 19 Western 9 1.23 43 26 Total 34 10.50 371 202 Cost and Financing 18. The cost of this component is US$36 million. Financing plan: IDA (US$34 million) and REA (US$2 million). 76 Allocation of Activities by Financier C2 (a) Activities Financed by IDA (US$34 million) (i) Grid extensions. The subcomponent will finance the construction of medium-voltage (MV) and low voltage (LV) lines, MV/LV transformers, and service lines to public facilities in rural areas. (ii) Design and implementation of off-grid electrification projects, including pilot programs. The subcomponent will support REA in the design and implementation of renewable energy off-grid electrification projects. (iii) Engineering and supervision services. IDA will finance a consulting company to provide REA with implementation support. C2 (b) Activities Financed by REA (US$2 million) Land acquisition, environmental monitoring and compensation payments. REA will finance the cost of land acquisition and way leaves, the implementation of the environmental monitoring plan, and compensation and resettlement. Subcomponent C3: Slum Electrification Description of Activities 19. This subcomponent will finance, through an output-based mechanism, the connection of about 50,000 low-income customers in Kenya`s slums. 20. Practically all residents in slums are classified as poor. About 73 percent of the dwellers in these settlements live on less than US$42 per adult equivalent per month, excluding rent. Household surveys in several settlements show that the residents pay a very high proportion (33% on average) of their income for their energy-related expenditures, due in part to the fact that they often receive electricity from informal service providers at high rates 32. These informal providers charge consumers more than the KPLC tariff for poor quality service without regard for safety. 21. In order to make connections more affordable, encouraging households to switch service from informal service providers to KPLC, the Government and KPLC have introduced a special reduced connection fee for slums amounting to KSh 1,160 (US$15) or about five percent of the connection cost (US$300) in these settlements. This significant reduction in the connection fee has spurred demand for new connections. KPLC has been using its own funds to finance the difference between the cost and the reduced connection fee, but because of limited funds, connection progress in slums has been slow. 22. The US$300 connection costs include MV and LV lines, transformers, drop lines and meters that do not require internal wiring of the premises (ready boards). Pre-payment meters 32 KPLC: Review of Customer Connection Policy, 2006. 77 purchased under Component C1 may also be used in the electrification schemes for the slums. Following best practices from slum electrification, KPLC will use smaller transformers, which minimize the lengths of LV lines, and thus reduce an opportunity for theft. Although this approach increases initial investment costs, the expected savings due to loss reduction in system operation is expected to offset the increase. 23. The subcomponent`s investments will take place over a period of three years. In the first year, the investments will target connections in Kibera (Nairobi), the largest slum in Kenya (population ranging 800,000 -- 1 million). The subsequent investments will include other slums in Kenya. KPLC has implemented two pilot projects in Kibera, which have confirmed the willingness of households to pay for electricity and have provided valuable lessons in electrification that the subcomponent`s design has incorporated. One such lesson is the benefits of using pre-payment meters, which suit better the needs of the clients with irregular income, giving them control over the usage and budgeting for electricity. In addition, the pilots highlighted the need to use technologies that reduce theft opportunities and low-cost technical solutions (e.g. ready boards that do not require internal wiring of houses) that reduce connection costs. Costs and Financing 24. The total cost of the subcomponent is US$16 million. Financing plan: IDA (US$5 million), GPOBA (US$5 million), KPLC (US$5.25 million) and users (US$0.75 million). Table 24 shows the break-down by financing source of the estimated cost of a connection. Table 24: Connection Cost Break-down Contributor Amount (US$) Percent of total Households connection charges US$15 5.0% GPOBA grant US$90 30% IDA credit US$100 32% KPLC US$95 (approximate) 31% Total US$300 100% Allocation of Activities by Financier C3 (a) Activities Financed by IDA (US$5 million) Connecting low-income consumers in slums to electricity supply. IDA will finance, on an output-based mechanism, about US$100 per one connection. C3 (b) Activities Financed by a GPOBA grant (US$5 million) (i) Connecting low-income consumers in slums to electricity supply. The GPOBA grant will finance, on an output-based mechanism, about US$100 per one connection. (ii) Verification services. The GPOBA grant will assist KPLC to engage an independent verification agent to verify the number and quality of the service connections that KPLC will make. 78 C3 (c) Activities Financed by KPLC (US$5.25 million) (i) Connecting low-income consumers in slums to electricity supply. KPLC will finance the difference between the actual cost of connection and the GPOBA, IDA, and customer contributions. (ii) Managing the slum electrification program. KPLC will finance all project management activities, including community outreach. C3 (d) Activities Financed by Electricity Customers (US$0.75 million) Connections. Each customer will pay about US$15 for an electricity connection to their dwelling. 25. Both the GPOBA grant funding and IDA financing will pay for the connections on an output-basis. This means that KPLC will pre-finance all materials and works, and complete the connections. Following the completion of a critical number of connections (e.g. 5,000), an independent Verification Agent will verify the information that KPLC provides on connections. GPOBA and IDA payments will be released only for verified connections. Subcomponent C4: Revolving Fund for Deferred Connection Fee Payments Description of Activities 26. Subcomponent C4 will support the re-capitalization of the Revolving Fund, which will help finance deferred payments of connection fees. The electricity connection rate in Kenya is currently highly skewed towards higher income households. About two-thirds of households with access to electricity are in the top income quintile. The bottom-three income quintiles account for only 10 percent of households with access. One of the reasons for this imbalance is the high connection fee of KSh 35,000 (about US$460), which prospective customers must pay upfront. The Revolving Fund will allow lower-income customers to pay the connection fee over time. 27. KPLC will use the Revolving Fund to pre-finance up to 80 percent of the connection fee for lower-income customers. The customers will have to pay up to 20 percent of the connection fee (about US$92) upfront. They will finance the residual amount (i.e. up to 80 percent of the connection fee), which they will repay to KPLC in about 24 installments subsequent to connection, at an interest rate of 5 percent. The monthly electricity bill will include the installment payment for the pre-financed connection cost and KPLC will have the authority to disconnect customers who do not pay the agreed monthly installment amount. KPLC will transfer repaid funds from the customers back to the Revolving Fund, increasing the funds available for pre-financing additional connections. 28. KPLC already has tested the Revolving Fund successfully and has programmed its billing and collection systems to incorporate the deferred payment option. 79 Cost and Financing 29. AFD intends to provide a loan to re-capitalize the Fund. An approximate amount of US$10 million equivalent has been included in the Project`s financing plan. Component D. Sector Institutional Development and Operational Support Description of Activities 30. Studies, capacity building and training activities in this component are designed to help sustain the policy, institutional and regulatory environment that the Government has created with the support of earlier Bank-financed operations. These activities are necessary for the expected results of the project materialize. Component D has three subcomponents. Cost and Financing 31. The estimated cost of this component is US$11.5 million. It is financed entirely by IDA. 32. Subcomponent D1 -- Institutional Development and Studies (US$7 million). Building on the institutional development component of ESRP, this subcomponent will further strengthen the sector institutional framework and the management of the power companies. The activities are the following: (a) Establishment of a Wholesale Electricity Market (US$0.5 million for Phase 1): The objective of this activity is to advance the wholesale electricity market as stated in the 2004 Energy Policy (Sessional Paper No. 4). A wholesale electricity market would enable the transformation of KETRACO, over a period of five to seven years, into an Independent System Operator (ISO) responsible for the operation, management, and development of the high voltage transmission network. Phase 1 of the activity would prepare the road map for this transformation, building on earlier studies under ESRP and would prepare the regulatory instruments. If the Government decides to implement an open-access regime, the subcomponent may have a second phase supporting the key activities required to make this regime operational. Phase 2 would then encompass the design of the technical architecture (including communications infrastructure, inspection and control) and load dispatch protocols. (b) Facilitating Private Sector Investment in the Electricity Sector (US$0.5 million): The objective of this activity will be to prepare a Private Sector Investment Prospectus, an investor conference in Kenya and road show outside Kenya, in order to attract private sector investment in the sector. The Prospectus would set out, in detail the key information private investors would require for decision-making, including the details of the regulatory regime (including tariff setting mechanism for bulk and retail tariffs, licensing etc.) and guarantee instruments available from multilateral institutions. This activity model will include the preparation of model PPAs for wind, hydro, geothermal, biomass and thermal energy. (c) Cost of Service Study (US$0.5 million): The objective of the rate-design study is to help ERC determine system charges such as wheeling charges and rates for the various categories of consumers, which recover costs and send appropriate price signals to customers about the cost of electric service. The study will determine the costs of supply at the various voltage levels 80 for the various categories of consumers. This study will provide the information necessary for a tariff review in 2014. The tariff review for 2011 will rely on existing system studies carried out under ESRP. (d) Materials and Equipment Supply Chain Study (US$0.2 million): The Electricity Access Investment Program underway has substantially increased the quantity of materials and equipment required for electrification (poles, transformers, meters, etc.). Subcomponent D1 includes a consultancy to support KPLC`s and REA`s procurement programs to identify opportunities for cost reduction in materials and equipment procurement. The activity will examine the critical constraints that increase costs and recommend what measures KPLC and REA could take to address these constraints. In addition, the consultancy will recommend any adjustments (or streamlining) in regulations governing KPLC`s and REA`s procurement that could result in lower costs while maintaining the integrity of procurement processes. (e) Risk Analysis and Risk Management Study for the Electricity Sector (US$0.5 million): This activity will evaluate the risks associated with power infrastructure assets and recommend risk management options. The study would cover safety and physical integrity of power infrastructure including generation plant and hydroelectricity dams. It would include a review of the adequacy of planning transmission lines to take account of natural disasters, such as severe flooding. The study also would look into the advisability of improving independent engineering inspection of infrastructure. (f) Pre-feasibility and Regulatory Studies for Medium Sized Renewable Energy Options (US$0.5 million): This activity will consist of two studies. The first study will investigate the capability of the existing electricity system to absorb independent generation (mainly wind). The study will incorporate existing data to construct energy resource maps and their location in relation to the existing grid and determine how future expansion of the network can facilitate the development of the resources. The second study will assist ERC in designing important regulatory instruments that will facilitate the development of small and medium renewable sources of electricity. (g) Feasibility Studies for New Investment Projects as Required (US$4.3 million): These may include a feasibility study for the next large scale geothermal development and transmission lines. 33. Subcomponent D2 -- Training (US$2.9 million). The subcomponent will provide the sector entities (KenGen, KPLC, KETRACO, GDC, REA, ERC and MoE) with training in the management of environmental and social impacts and in sector operations, including: project management; contract negotiations and administration; works and goods procurement; the selection of consultants; project preparation, analysis and financing; and arbitration and mediation. Subcomponent D2 also will include enhanced capacity-building for the electricity sector planning group within ERC, consisting of experts from the sector entities, which is responsible for system studies including the preparation of the Least-Cost Power Development Plan. This activity will include the transfer of software planning tools such as EMPEP, and MAED and training in their application. The subcomponent also supports twinning arrangements for KETRACO and ERC with international transmission companies and regulators. 81 34. Subcomponent D3 -- Project Implementation Support and Monitoring/Evaluation (US$1.6 million). This subcomponent will strengthen MoE`s project implementation and coordination teams through short- and long-term consultancies. Subcomponent D will also support MoE in the design and implementation of a methodology for evaluating the project`s impact as well as activities to strengthen the project`s demand-side accountability mechanisms, including third-party monitoring. 82 Annex 5: Project Costs KENYA: Electricity Expansion Estimated Cost and Financing Plan Project component/estimated cost Financing (US$ million) Cost User US$ m GoK KenGen KPLC Ketraco REA IDA JICA KfW EIB AFD GPOBA fees Total A. Geothermal Generation 1,035 130 120 323 84 168 210 1,035 Power plants 645 23 305 127 190 645 Steamfield 147 96 52 147 Substations & transmission 32 32 32 RAP & environment 10 10 10 Consultancy 30 30 30 Panel of Experts 1 1 1 Local infrastructure & admin. 1) 30 18 12 30 Interest during construction 54 54 54 Contingency 86 25 11 18 2 9 20 86 B. Transmission 72.5 8.0 64.5 72.5 T-lines and substations 60 60 60 RAP & environment 7 7 7 Consultancy 3 3 3 Contingency 2 1 1 2 C. Distribution 272 30 2 134 10 5 91 272 C1. Strengthening and extension of distribution networks 210 Substations and lines 82 82 82 Installation of SS and lines 20 20 20 Prepayment meters 8 8 8 Connections 90 90 90 RAP & environment (urban) 0.5 0.5 0.5 Consultancy (KPLC) 3 1 2 3 Contingency 6 3 3 6 C2. Electrification of priority loads in rural areas 36 Grid extensions 24 24 24 Off-grid electrification 8 8 8 RAP & environment (rural) 2 2 2 Consultancy (REA) 2 2 2 C3. Slum electrification 16 5 5 5 1 16 C4. Revolving Fund 10 10 10 D. Institutional Development and Operational Support 11.5 11.5 11.5 Inst. development and studies 7.0 7 7 Training 2.9 2.9 2.9 Project impl. support, M&E 1.6 1.6 1.6 TOTAL 1,391 - 130 30 8 2 330 323 84 168 220 5 91 1,391 1) Construction infrastructure (access roads, electricity and water) & infrastructure required to operate the plants (borehole roads, offices) Notes: (a) Costs are exclusive of duties and taxes. (b) US$30 million is from the IDA Pilot Crisis Response Window (CRW). (c) User fees refer to the connection fees KPLC collects from about 250,000 consumers and 50,000 slum residents. (d) An additional $273 million is required to complete drilling of steam wells. Financing is expected from KfW, China Exim Bank and Government of Kenya. 83 Annex 6: Implementation Arrangements KENYA: Electricity Expansion 1. The implementing entities are Ministry of Energy, Kenya Electricity Generating Company Ltd., Kenya Power and Lighting Company Ltd. and the Rural Electrification Authority. Ministry of Energy (MoE) 2. The responsibilities of MoE will include overall project coordination and management of the project`s components for which it is the designated implementing entity. Overall Project Coordination 3. MoE will coordinate the execution of all project components through a Project Coordination Team (PCT), chaired by the Ministry`s Project Coordinator. The team will consist of the team leaders of the Project Implementation Teams (PITs), of the implementing entities participating in the project. It also may include other specialists and stakeholders, as required. MoE will organize quarterly meetings of the PCT and will share the minutes of the meetings with the Permanent Secretary for Energy, the Chief Executives of the implementing entities, and the co- financiers. 4. Through its Project Coordinator, MoE will prepare quarterly progress reports on the project`s implementation with inputs from the implementing entities. The reports will review progress in the Project`s implementation, costs and financing, and assess the agreed key indicators of progress, which Annex 3 -- Results Framework and Monitoring -- presents. It will furnish these to the Permanent Secretaries for Energy and Finance, the Chief Executives of the implementing entities, and the co-financiers. MoE will provide to the public, a summary of these reports, which will appear on the Ministry`s website. 5. MoE will ensure the implementation of all necessary environmental and social management and monitoring activities in accordance with the environmental and social management plans, the Resettlement Action Plans, and the Indigenous Peoples Planning Framework. 6. Finally, MoE, through its Permanent Secretary, will be responsible for the overall coordination with development partners in the energy sector through chairing quarterly donor coordination meetings. Management of Components 7. MoE, through its PIT, will manage Component D -- Sector Institutional Development and Operational Support, except for the training components for KenGen, KPLC and REA (subcomponents D2 (a), D2 (b) and D2 (c)), which they will manage themselves. The PIT will be responsible for all procurement, contract management, financial management of Project funds, preparation of progress reports, updating of project costs, procurement and financing plans. 84 8. The PIT will report to the Permanent Secretary for Energy. In addition to the Project Coordinator, the PIT members include a Procurement Officer, an Accountant, a Renewable Energy Specialist, a Power Engineer and other specialists as required. Kenya Electricity Generating Company Ltd. (KenGen) Overall Project Implementation 9. The implementation of the generation component (Component A) and its training activities under subcomponent D2 (a) will be KenGen`s responsibility. A Project Steering Committee, under the Managing Director, which consists of KenGen`s operational directors, will oversee the Project`s implementation. An independent Panel of Experts (specialists in geothermal development) will review implementation progress twice a year and provide written reports of its findings to the Steering Committee. 10. Table 25 below shows the allocation of implementation responsibility among the key functions. Table 25: Allocation of Implementation Responsibility in KenGen Function Responsibility Managing Director Overall Responsibility - signs loans and contracts and conducts official communication with the Financiers. Project Steering Committee Negotiates financing for the Project and oversees the work of the PIT. Approves the various evaluation results for various components of the Project Tender Committee (contracts of more than KSh 50 million requires a review by Procurement Oversight Committee). Under the oversight of the Regulatory Affairs Director, implements the RAP RAP Implementation Committee including compensation procedures and development of resettlement sites for the Project. Independent Evaluation Panel Monitors implementation of the RAP Environment, Safety, Quality and Under the oversight of the Regulatory Affairs Director, implements the Liaison Unit Environmental and Social Management Plan (ESMP) for the Project. Geothermal Development Manager Manages drilling operations and resource development. Panel Geothermal Experts Provides expert advice to KenGen. Project Implementation Team (PIT) Team Leader Manages day-to-day operations. Legal officer Legal matters. Resident Engineer Coordinates the work of Site Engineers and monitors activities for both contractor and consultants. Site Engineers Coordinate and monitor technical aspects of implementation and monitor all installations, inspections, and commissioning. Accountant Accounting and management of project funds. Specialists Specialist services -- monitoring, procurement, environment, payments, contractual issues etc. Design and Supervision Consultant Prepares designs and tender documents, supervises contractors` work. 85 11. The Project Implementation Team will be responsible for the day-to-day management of Project activities. The PIT consists of a Team Leader, legal officer, a resident engineer, a steam field engineer, an electrical engineer, a mechanical engineer, a civil engineer, an accountant and other specialists as required from time to time. 12. In addition, KenGen has engaged, through competitive international selection, a Design and Supervision Consultant to prepare conceptual designs for the plant and substation, full designs for the steam field component, assist in the bidding for the different contract packages, approve contractors` design drawings, verify contractors` invoices and supervise construction works. 13. The Team Leader and other members of the PIT are experienced, permanent KenGen staff members who have been involved in the implementation of the ESRP and other projects. The core members of the PIT are already in place and KenGen has recruited additional engineers to strengthen the PIT in the management of the project. 14. The PIT will be responsible for all procurement processing, contract management, management of Project funds, preparation and updating of progress reports, project costs, and procurement and financing plans. The PIT will provide the Project Steering Committee and MoE with quarterly progress reports -- two weeks after the end of the quarter -- which will include the status of: Overall project implementation -- actual progress compared to implementation plan agreed during negotiations. Monitoring of project costs, financing plan and disbursement of each financier`s loans. Implementation of the Resettlement Action Plan and environmental management plans. Achievement of the results monitoring indicators for the Generation Component. 15. The co-financiers, including IDA, have reviewed the procurement and implementation plans for the generation component and found them satisfactory. The implementation plan has scheduled construction to begin in mid-2011 after a procurement period of about 12 months. Commissioning of the power plants is programmed for 2015. Except for JICA, the co-financiers have agreed to use either the World Bank`s standard procurement documents (for IDA-financed contracts) or procurement documents modelled after the harmonized Multilateral Development Banks` Master Bidding Documents with suitable adaptations for contracts financed by the other co-financiers. Specific Arrangements for the Main Construction Activities 16. The following sections discuss the specific arrangements for the major construction activities: 17. Steam field development. KenGen`s Design and Supervision Consultants will prepare the detailed design of this development while construction contractors will supply the required equipment and install it according to the design. KfW, IDA, and KenGen have agreed that the procurement would follow the World Bank`s procedures and that no-objections to the various stages of the bidding process will be provided by IDA. The bid invitations will appear in the local 86 press, the UNDP Development Business and Development Gateway Market (dgmarket) and the Germany Trade and Investment Journal, GITAI. 18. Power plants. There will be two separate engineering, procurement and construction contracts (turnkey) for the construction of the power plants. Procurement for the expansion of Olkaria I will follow the guidelines of the financier, JICA, and use the agency`s standard bidding documents. However, AFD and EIB, the co-financiers for the Olkaria IV power station, will follow EIB`s guidelines and use procurement documents modeled after the Harmonized Multilateral Development Bank`s master bidding documents. The prequalification and bidding for the two contracts will take place simultaneously. 19. Substations and transmission lines. There will be one turnkey contract for the construction of the required transmission infrastructure. In accordance with the terms of the KenGen- KETRACO Implementation Agreement, KenGen will be responsible for implementation of the substations and transmission lines, including the acquisition of required way leaves. The company will hand over the assets to KETRACO after the end of the contractor`s liability period for any defects. Consequently, KenGen`s Tender Committee will approve the contract award and KenGen will sign the contract with the competitively selected contractor. KETRACO and KPLC have designated a staff member each to work with KenGen in the implementation of this component to ensure adequate interface between the new investments and the national grid. Management of Environmental and Social Safeguards 20. Under previous Bank-financed operations, KenGen has demonstrated sufficient capacity to manage the potential environmental and social impacts and is thus considered capable of managing those associated with the Project. KenGen`s Environment, Safety, Quality and Liaison Unit will implement the Environmental and Social Management Plan for the power plants. It has qualified staff, located at the project site, in the fields of EIA, air quality, waste management, safety, environmental resource management. Annex 10 discusses the company`s capacity for environmental and social safeguards management in detail. 21. KenGen will set up a separate Resettlement Implementation Committee for the project under the leadership of the Regulatory Affairs Director. This committee will include the District Commissioner for Naivasha, the District Lands and Settlement Officer for Naivasha, Community Elders, a representative for women and vulnerable groups, and KenGen staff. In addition, KenGen will engage an Independent Evaluation Panel to monitor the progress of the RAP`s implementation. Co-Financiers' Coordination 22. KenGen will meet quarterly with the five co-financiers for the Generation Component -- AFD, EIB, KfW, JICA and IDA -- to review implementation schedules, progress with procurement, funds flow etc., and discuss any implementation issues that may arise. The co- financiers will organize joint implementation review missions when practical. 87 Kenya Power and Lighting Company Ltd. (KPLC) Overall Project Implementation 23. KPLC will be responsible for implementing the project`s Transmission Component (Component B) and Distribution Subcomponents C1, C3, and C4 and its training activities under subcomponent D2 (b). The company`s designated PIT, which is also implementing ESRP, is part of KPLC`s permanent organizational structure and reports to the company`s Distribution Manager. The PIT is being strengthened with additional procurement, accounting and engineering experts to meet the demands of this Project, in addition to the continued implementation of ESRP. In addition to an overall Team Leader and a designated project manager for the installation works that KPLC will implement with its own staff and local contractors, the PIT has personnel responsible for: (a) design and engineering; (b) procurement and stores management; (c) accounting; (d) installation services (substations and lines); and (e) substation land and way leaves acquisition. An engineering consultant, financed by the project, will provide support to KPLC for specific activities, including design and procurement, supervision, and other aspects of the project, as required. In addition, the PIT will receive support from other parts of KPLC, for instance the Network Planning and Engineering Design Department and the Engineering Standards and Inspection Department. KPLC has also recruited a civil engineer to enhance the company`s in- house capacity in design preparation, reviews, and civil works supervision. 24. The PIT will be responsible for management of all implementation activities, project funds, and the preparation of progress reports, procurement and financing plans. The PIT will also ensure that the implementation of the project according to the provisions of the environmental and social safeguards instruments and the Indigenous Peoples Planning Framework. Table 26 provides the allocation of responsibilities for specific implementation activities. Table 26: Allocation of Implementation Responsibility in KPLC Activity Responsible Party Key undertakings Overall responsibility Managing Director Project Management PIT Day to day management of Components B and C1, C3 and C4 and coordination. Project scope definition KPLC (PIT, Network Planning and Works identification, design layouts and Engineering Design Department) specifications. Civil and Electrical Engineering Support Consultants Land and way leaves Company Secretary and Property Land identification, evaluation, planning, acquisition Department negotiations and payments. Environmental management SHE Department Environment and social impact assessments, implementation of environmental management plans. Resettlement and Resettlement Unit Implementation of RAPs and compensation compensation programs, screening for Indigenous Peoples. Independent Evaluation Panels Monitors the implementation of the RAPs. Tender documents` PIT Procurement of the various goods, works and preparation services including responding to bidders` queries, Network Planning and Engineering Design pre-bid conferences, bid evaluation and contract Department preparation. 88 Activity Responsible Party Key undertakings Tender evaluation Support Consultants (civil and electrical) Contract awards Tender Committee Approves evaluation reports and contract awards. Stores management Stores and Stocks Control Department Receipt, storage and issue of project equipment and materials. KPLC executed works: Head of Distribution Civil works; Line surveys including way leaves acquisition; - Construction Civil Engineering Contractors Equipment installation, testing and KPLC Construction Unit and Property commissioning; and Department Line construction. Labor and Transport Contractors PIT Works supervision, certification and preparation - Supervision Projects and Construction Department of as build drawings. Engineering Standards and Inspection Department EPC Contracts: Detailed designs, procurement and delivery of EPC contractors equipment to the sites, civil works, equipment - Construction installation, testing, commissioning and handover to KPLC. - Supervision PIT Land acquisition and site handover; Projects and Construction Department Procurement and contract award; and Property Department Contract management including design approvals, Civil and Electrical Implementation Support works supervision, quality assurance, certification Consultants and witnessing of tests. 25. The PIT will provide MoE with quarterly progress reports two weeks after the end of each quarter during the project`s implementation period. These reports will include the status of: Engineer, Procure and Construct contracts (EPCs) for Component B and Subcomponent C1 and its own executed project works for components C1. The reporting will compare actual progress to the implementation plan agreed during negotiations; Electrification activities (Subcomponent C3) for slums and uptake of loans from the Revolving Fund; IDA-financed materials in stores; Project costs and disbursements; Environmental management and resettlement activities, including the implementation of the Indigenous Peoples Planning Framework; and The results monitoring indicators for Component B and Subcomponents C1, C3 and C4. Implementation of the Transmission Component (Component B) 26. KETRACO will be the owner and operator of the transmission lines. However, because KETRACO does not yet have the requisite procurement and financial management capacity for an IDA-financed project, KPLC will manage the Transmission Component on behalf of KETRACO, as an implementing agent. The Mutual Cooperation and Provision of Services Agreement between KPLC and KETRACO will govern the implementation arrangements. According to this Agreement, KPLC will be responsible for all procurement activities, management of credit funds for this component, and supervision of contractors. KPLC`s Tender Committee will approve 89 contract awards for the transmission line contracts. KPLC will sign contracts on KETRACO`s behalf and manage the IDA Credit for the component. The Project will finance a Design and Supervision Consultant to prepare bidding documents and assist in the bidding of the contracts for the transmission lines, approve contractors` design drawings, verify contractor`s invoices and supervise the construction. There will be a RAP Implementation Committee for each Transmission line involving resettlement and an Independent Evaluation Panel to monitor the progress of the RAPs` implementation. Implementation of Subcomponent C1 -- Strengthening and Extension of the Distribution Network 27. Most of the construction of substations will involve turnkey contracts (17) selected through ICB. However, KPLC`s own staff or local contractors will install nine substations (five new and four rehabilitations) and install all distribution lines. The IDA Credit will finance the turnkey contracts and the materials and civil works for the nine substations and distribution lines. KPLC will finance installation for the nine substations and lines. KPLC will store the IDA-financed materials in designated areas to ensure that the materials are not used for routine/other similar works outside the project. The Bank's supervision missions will review the store ledgers to confirm the adequate safeguarding of equipment. Table 27 summarizes the construction responsibility between KPLC and EPC contractors. Table 27: Construction Responsibility for Subcomponent C1 Activity Description Responsible KPLC Turnkey contractor Construction of New (number) 5 17 substations Upgrade/Refurbishment (number) 4 - Construction of lines 66 kV (km) 320 - 33 kV includes upgrading of some existing 11 kV to 33 kV (km) 930 - 11 kV (km) 140 - Implementation of Subcomponent C3 -- Slum Electrification 28. KPLC will procure the materials required for connecting consumers in the settlements using its commercial procedures and its own technical staff for the installation of the connections. The Head of Distribution will supervise the work. The Bank`s procurement assessment has confirmed that KPLC`s procurement procedures are satisfactory for the implementation of this subcomponent using Output Based methods. 29. IDA and GPOBA each will reimburse KPLC for approximately US$100 per connection after a Verification Agent has confirmed the connections. KPLC will finance the balance of the cost of the connection, about US$100. GPOBA and IDA will disburse funds quarterly or when KPLC has achieved a critical number of connections (e.g. 5,000). The Verification Agent, competitively selected by KPLC and financed from the GPOBA grant, will verify the quantity and technical quality of connections based on a representative sample of connections realized during the payment period. 90 30. The consumers will be metered through a pre-payment system. The key advantages of the model are: An improved collection rate for KPLC; Greater flexibility for the consumers (Households in slums often have irregular incomes and it is more convenient for them to buy electricity in smaller quantities, when they have financial resources); Direct interaction of KPLC with tenants, reducing the intermediary role of the landlords; and Income-earning opportunities for slum residents through the sale of the prepaid cards. Implementation of Subcomponent C4 -- Revolving Fund for Deferred Connection Fee Payments 31. KPLC has established a dedicated bank account for the Revolving Fund and will use the resources to pre-finance 70 - 80 percent of the connection fee for lower-income customers. The customers will pay the remaining 20 - 30 percent upfront. The customers will repay the 70 - 80 percent of the connection fee back to the revolving fund in 24 installments during 25 months after the connection, at an interest rate of five percent. 32. Once a customer signs a contract with KPLC, agreeing to the deferred payment scheme, and pays the upfront fee, KPLC will proceed with connecting the customer, and will receive the remaining portion of the connection fee from the Revolving Fund. The customer will be billed monthly by KPLC for (a) electricity consumption; and (b) installment repayment. KPLC will retain the electricity consumption payments while it will transfer the installment repayment back to the revolving fund to be used for pre-financing other connections. Figure 4 illustrates the process for the payment of the connection fee for new customers with low income. Figure 4: Operation of the Revolving Fund REVOLVING FUND US$10 million INFLOW Fund withdrawals to OUTFLOW finance customer Customer repayments to connections replenish the Fund KPLC INFLOW OUTFLOW con 70-80% of the US$460 20-30% cash Connection Cost contribution plus 24 monthly installments CUSTOMER 91 Rural Electrification Authority (REA) Overall Project Implementation 33. REA will be responsible for implementing the Distribution Subcomponent C2 -- Electrification of priority loads in rural areas and its training activities under Component D {subcomponent D2(c)}. 34. REA`s designated PIT will be responsible for all procurement, contract management, financial management of project funds, preparation of progress reports, updating of project costs and procurement and financing plans. The PIT will report to REA`s Chief Executive and includes a Team Leader, a rural electrification engineer, a procurement officer and an accountant. The PIT, integrated into REA`s permanent organizational structure, will coordinate closely with REA`s other departments involved in project implementation. These departments include those responsible for planning and design, procurement, and financial management. For example, REA`s design department will be responsible for site surveys and the design of the grid extensions. In addition, REA may engage or designate from its own staff a logistics expert to improve its material management in order to adequately account for the materials procured with the IDA credit as well as materials financed by other development partners and REA itself. Table 28 provides the allocation of implementation responsibilities in REA. Table 28: Allocation of Implementation Responsibility in REA Activity Responsible Party Key undertakings Overall responsibility CEO. Project Management PIT. Day-to-day management of Component C2. Project scope definition PIT, Network Planning and Engineering Works identification, design layouts, and Design Department specifications. Implementation Support Consultants. Land and way leaves REA Company Secretary (Legal Land identification, evaluation, planning, Acquisition Department), Design Department. negotiations and payments. Environmental KPLC`s SHE Department with assistance Environmental and social impact assessments, management from REA staff. implementation of environmental management plans. Resettlement and KPLC`s Resettlement Unit with assistance Preparation and implementation of RAPs, if compensation from REA staff. required, and compensation programs, screening for Indigenous Peoples. Tender documents` PIT. Procurement of the various goods, works and preparation services including responding to bidder`s queries, Procurement and Supplies Department, pre-bid conferences, bid evaluation and contract Tender evaluation preparation. Implementation Support Consultants. Contract awards Tender Committee. Approves evaluation reports and contract awards. Stores management Procurement and Supplies Department. Receipt, storage and issue of project equipment and materials. 92 Activity Responsible Party Key undertakings REA executed works: Civil works, - Construction REA Operations (Construction) Department Line surveys including way leaves acquisition, Legal Department Equipment installation, testing and commissioning, Labor and Transport Contractors. Line construction. REA PIT Works supervision, certification and preparation of - Supervision Operations (Construction) Department as built drawings. Implementation Support Consultant. EPC Contracts: Detailed designs, procurement and delivery of EPC contractors equipment to the sites, civil works, equipment - Construction installation, testing, commissioning and handover including as built drawings. PIT Land acquisition and site handover, - Supervision Operations (Construction) Department Procurement and contract award, Legal Department Contract management including design approvals, Implementation Support Consultant works supervision, quality assurance, certification and witnessing of tests. Inspection of power lines REA and KPLC Will inspect technical quality before accepting transfer of lines from REA to KPLC. 35. The PIT will coordinate with KPLC according to procedures established in the REA-KPLC Service Level Agreement, entered into by KPLC and REA on April 30,2010, including procedures for environmental and social work. An Implementation Support Consultant, to be competitively contracted and hired on a retainer basis, will support REA with specific activities throughout the project cycle, including the planning and updating the REMP, line designs, site surveys, procurement, supervision of works and material management. 36. The PIT will provide MoE with quarterly progress reports, two weeks after the end of each quarter, which will include the status of: EPCs and REA`s own executed project works -- actual progress compared to implementation plan agreed during negotiations; Project cost and disbursement monitoring; IDA-financed materials in stores; Environmental and resettlement activities and implementation of the Indigenous Peoples Planning Framework; and Results monitoring indicators. 37. The first year`s electrification schemes, estimated to cost about US$10.5 million, will be a combination of a turnkey contract (about US$4 million) and schemes implemented using REA`s current arrangements with local contractors (about US$6 million). The turnkey contract will include the construction of schemes in one concentrated area in the Coast Province. The experience gained from these two implementation approaches will guide the implementation modality for investments in the subsequent years. 38. REA will select the rural investment schemes to be financed by the IDA credit annually from the REMP, taking into account coordination possibilities with REA`s other investment plans. Where possible, REA will coordinate with KAPAP to target agri-business areas, as long as they 93 are compatible with the REMP. Otherwise, the schemes will be selected based on their order of economic priority, as identified in the REMP. IDA will approve the annual investment plans before their implementation. 39. Prior to the implementation of the off-grid activities, REA will prepare an implementation plan and present it to the Bank for a no objection. 40. REA will store the Project-specific materials in designated areas to ensure that the materials are not used for routine/other similar works that will be ongoing. The Bank's supervision missions will review the store ledgers to confirm that equipment has been adequately safeguarded. Cooperation between REA and KPLC 41. According to the REA-KPLC Service Agreement, REA finances the construction of rural electrification lines, which it subsequently transfers to KPLC for operation and maintenance. In order to ensure that KPLC is willing to absorb the lines constructed by REA, REA will coordinate with KPLC throughout the project cycle. In particular, REA will submit its annual investment plans and designs to KPLC for comment. In addition, KPLC will conduct an inspection of the lines, before it accepts the transfer. Management of Environmental and Social Safeguards 42. KPLC`s Safety Health and Environment Department (SHE) and Resettlement Unit (RU) will manage the environmental safeguards and eventual resettlement and compensation associated with the rural electrification developments. This provision has been included in the aforementioned Service Level Agreement between REA and KPLC. The RU will screen areas for rural electrification according to the guidelines in the Resettlement Policy Framework for the Project. If this screening identifies the need for resettlement or compensation, KPLC`s RU will conduct the required consultations, prepare the required RAPs and implement them. REA staff will participate in these activities while in the process of building its own capacity and eventually, when its internal capacity is adequate, will take over primary responsibility for safeguards implementation. 94 Cross-Sectoral Linkages 43. Where possible, the Project will build linkages with productive and social sectors as discussed in Box 2 below. Box 2: Rural Electrification linkages with Agriculture and Social Sectors To maximize impact of the proposed interventions, the project will build linkages with productive sectors and key social services, with the main focus on agriculture, health and education. Agriculture. The REMP includes trading centers among the priority loads, which typically are the local centers for marketing and processing agriculture produce in Kenya. The plan has identified and prioritized for electrification of over 3,300 market centers. Of this total, Subcomponent C2 will cover an estimated 300. In addition, subcomponent C2 will explicitly explore and promote linkages with agricultural productivity through cooperation with the Kenya Agriculture Productivity and Agribusiness Project (KAPAP).33 REA and the Project Implementation Unit of KAPAP have established a task force focused on the linkages between electrification and agriculture, targeting priority sub- projects. The selection of rural electrification projects, where possible, will target locations that reflect KAPAP`s priorities. In off-grid schemes, the use of agricultural residues for electricity production is being explored. The agribusinesses expected to benefit from the electrification under the proposed investments include groundnut processing, commercial cassava processing, dairy processing, fish processing, cold storage, fruit and honey processing and others. Health and Education. The REMP prioritizes the connection of health facilities and secondary schools in rural areas, and establishes a framework for their full electrification over a 10-year period. This framework targets the electrification of over 800 health facilities and 1,800 schools during the next five years. Subcomponent C2 will support this program by electrifying about 100 secondary schools and 50 health facilities. Annual investment plans for electrifying public institutions will reflect consultations with health and education sector authorities to ensure coordination with priorities, allowing the programs of the institutions to take a full advantage of the new electricity connections -- e.g. plans for complementary investments, such as audio-visual appliances or medical equipment. 33 The objective of the KAPAP project is to increase agricultural productivity and incomes of participating smallholder farmers in the project areas by transforming and improving the performance of agricultural technology systems, empowering stakeholders and promoting the development of agribusinesses. The lack of modern energy services has been identified as one of the key constraints to improving agricultural productivity and agribusiness growth. 95 Annex 7: Financial Management and Disbursement Arrangements KENYA: Electricity Expansion A. Financial Management Introduction 1. The World Bank`s FM staff at the Nairobi Country Office conducted a Financial Management Assessment of Kenya Electricity Generation Company Ltd. (KenGen), Kenya Power and Lighting Company Ltd. (KPLC), Ministry of Energy (MoE) and Rural Electrification Agency (REA) -- the entities implementing the Project. KPLC will also be implementing Component B on behalf of Kenya Electricity Transmission Company Ltd. (KETRACO) in line with the provisions of the Mutual Cooperation and Provision of Services Agreement between KPLC and KETRACO. KETRACO is expected to take over the implementation of Component B after building its capacity during project implementation and having put in place satisfactory financial management systems. The World Bank`s FM staff will assess its capacity at mid-term. 2. The objective of the assessment was to determine: (a) whether the four entities have adequate FM arrangements in place to ensure the funds will be used for the purposes intended in an efficient and economical manner and the four entities are capable of correctly and completely recording all transactions and balances related to the Project; (b) the Project`s financial reports will be prepared in an accurate, reliable and timely manner; and (c) the entities` assets will be safely guarded; and (d) the Project will be subjected to auditing arrangements acceptable to the Bank. The FM assessment was carried out in accordance with the Financial Management Practices Manual issued by the Financial Management Sector Board on November 3, 2005. The assessment complied with the Financial Management Manual for World Bank-Financed Investment Operations that became effective on March 1, 2010. 3. The Financial Management assessment concluded that the financial management arrangements meet the Bank`s minimum requirements under OP/BP 10.02. With the implementation of the financial management action plan, the financial management arrangements for the Project will be further strengthened. The residual risk rating for KenGen and KPLC is moderate while for REA and MoE it is substantial. Country Issues 4. The most recent piece of diagnostic work that provides up to date information on the country`s public financial management (PFM) system is the Public Expenditure and Financial Accountability Assessment (PEFA) of 2009. Although the PEFA assessment rated highly the credibility of the Government budget, it identified key risks related to project implementation in the areas of classification of the budget, orderliness and participation of the budget process, effectiveness of internal audit especially in regard to the extent of management response to internal audit findings, timeliness and regularity of accounts reconciliation, quality and timeliness of annual financial statements mainly arising due to the difficulties in using the Integrated Financial 96 Management Information System (IFMIS), scope, nature and follow up of external audit issues and legislative scrutiny of external audit reports and budget law. 5. Other country-level FM risks arise from the country`s overall governance environment and corruption concerns. This is being addressed by strengthening of management oversight through ministerial audit committees, enhancement of social accountability mechanisms and capacity enhancement of integrity assurance agencies particularly Kenya Anti-Corruption Commission (KACC), Kenya National Audit Office (KENAO), and Internal Audit Department (IAD). 6. Through its Public Financial Management Reform Strategy, the Government remains committed to strengthening fiduciary safeguards with a view to achieving economy, efficiency and effectiveness in the use of public funds. With the support of a number of Development Partner- assisted initiatives, including the IDA-funded Institutional Reform and Capacity Building Project (IRCBP), the Government is seeking to rapidly enhance the financial accountability framework, particularly through strengthening legislation related to public financial management. 7. The Government has initiated far-reaching portfolio-level FM reforms with support from the Bank to address identified fiduciary weaknesses in management of donor-funded projects. In the Bank-financed portfolio, project implementation has been delayed by constraints in the flow of resources and limited absorptive capacity. The Government has adopted International Public Sector Accounting Standards (IPSAS) cash basis of accounting for Bank-financed project effective FY2008. The Government issued Treasury Circular No. 3/2009 on development and implementing of Institutional Risk Management Policy Framework, which make it mandatory for all public institutions including line ministries, state corporations and local authorities, to adopt a risk framework. The Framework provides for elaborate social accountability mechanisms including public reporting, and corruption prevention mechanisms. On implementation, the Framework will mitigate the risks associated with management of public resources. 8. The Government has agreed to conduct annual risk-based Fiduciary and Funds Flow Review and in-depth/forensic audit reviews done by Internal Audit Department and the Treasury (Ministry of Finance). The first review was conducted during 2009. Ministry of Finance (MoF) and the relevant implementing agencies are in the process of implementing the findings and recommendations. Table 29 summarizes the inherent and control risks and mitigation measures. Table 29: Financial Management Risk Assessment and Mitigation Description of Risk Risk Mitigation Measures Condition of Residual incorporated in Project Effectiveness Risk/ (Risk) Implementation (Yes/No) rating INHERENT RISKS Country Level This is based on the Country Public Issues are being addressed at the No S (S) Financial Management environment and country level through the country`s it takes into consideration relevant governance action plan, strengthening country governance issues e.g. corruption of the public financial management concerns and current political crisis system (supported by the Bank through arising from the general election in the Institutional Reform and Capacity December 2007. The rating is derived Building Project). from the country ratings for CPIA 97 Description of Risk Risk Mitigation Measures Condition of Residual incorporated in Project Effectiveness Risk/ (Risk) Implementation (Yes/No) rating Question 13 (Quality of Budgetary and Financial Management) and Question 16 (Transparency, Accountability and Corruption in the Public Sector). Entity Level KenGen, MoE and KPLC are Staff of REA will be trained in World No L for all successfully implementing the IDA- Bank Financial Management and entities financed Energy Sector Recovery Project. Disbursement guidelines before project They have fairly good Financial effectiveness. (L for Management systems in place to account KenGen, for the project`s funds. KPLC and KPLC & KenGen are also quoted on the Nairobi MoE Stock Exchange implying that they have good corporate governance arrangements M for REA) regulated by the Capital Markets Authority. REA is a body corporate established under Section 66 of the Energy Act, 2006 (No 12 of 2006). The entity is fairly new and could face challenges in staffing, and complying with World Bank Financial Management and Disbursement guidelines. Project Level The project is complex with four FM risks under each of the FM No M (S) implementing entities, four components arrangements have been identified and and a number of subcomponents. The mitigated for each of the implementing project will be one of the largest in the entities. country involving a large amount of resources and complex contracting/ procurement arrangements. The project has an OBA element under A verification agent will be contracted component C3 on slum electrification that to verify the installation of electricity in requires verification to ensure KPLC has slums before payments for installation installed electricity connections in slums. are made on an output based approach. Overall Inherent Risk Without mitigation: S After mitigation: M 98 Description of Risk Risk Mitigation Measures Condition of Residual incorporated in Project Effectiveness Risk/ (Risk) Implementation (Yes/No) rating CONTROL RISK Budgeting KenGen, KPLC, MoE and REA have MoE budget is prepared using No L for KPLC, adequate budgeting arrangements (see Microsoft Excel and reviewed for KenGen and Budgeting arrangements section below). accuracy and completeness by both REA However, the budget for MoE is prepared MoE and Ministry of Finance before manually using Microsoft Excel as the submission for approval to Parliament. M for MoE Integrated Financial Management Information System (IFMIS) does not (L for KPLC, have a budgeting module. KenGen & REA M for MoE) Accounting KenGen, KPLC, MoE and REA KPLC: A consultant for SAP has been No M for KPLC, The following risks were identified: hired to resolve the interfacing issue of REA and the SAP accounting software. KenGen KPLC and MoE have challenges with their accounting information system. MoE: Although IFMIS issues are S for MoE KPLC upgraded their system and have broadly being addressed by been facing interface challenges between Government under the Public Financial (M for the Financial Module and Revenue Management Reform Program, as a KPLC, REA Collection Module while MoE is using mitigation measure for this project, and KenGen the IFMIS, which was found to produce MoE will prepare the project accounts unreliable accounts by the Controller and manually using Microsoft Excel until S for MoE) Auditor General hence MoE is facing the IFMIS issue is resolved. MoE has challenges in reconciling differences agreed to prepare a fixed asset register between the trial balance and existing during FY2010. project financial statements. MoE does not maintain a Fixed Asset Register to monitor their assets as pointed out by the Controller and Auditor General. 99 Description of Risk Risk Mitigation Measures Condition of Residual incorporated in Project Effectiveness Risk/ (Risk) Implementation (Yes/No) rating Internal control All implementing entities have a strong MoE: Bank to work with MoE audit No S for MoE internal audit function although the audit committee to strengthen its capacity. and REA committee for MoE is weak and needs to There are also efforts being undertaken be strengthened. by the Government under the Public M for Financial Management Reform KenGen and Internal control issues identified in the Program to strengthen audit committees KPLC management letters in regard to KPLC, in all the Government ministries. KenGen, MoE and REA need to be (S for all resolved. In addition, the issues that were MoE, KPLC, KenGen and REA to entities) identified in the qualified audited address internal control issues. KenGen accounts of MoE (see the auditing and KPLC have confirmed that work is arrangements section below) need to be ongoing to address these issues. resolved as they will impact on this However, the Bank will monitor these project. issues using action plans agreed with the implementing entities during the implementation of the ongoing Energy Sector Recovery Project and the implementation of this project. The action plan will state the actions to be undertaken, by whom, and by when they should be accomplished. MoE should address issues that led to the qualification of its accounts. MoE has already sent a letter to this effect to the Controller and Auditor General who is expected to provide a confirmation following verification that the issues have been resolved. Funds Flow Kenya portfolio has had disbursement Measures to be taken to minimize No M (S) challenges in the past as delays have been procurement-related funds flow delays experienced. through capacity building of the Project team. Training and video conference meetings are being held between the Bank and the disbursement section of Treasury -- Ministry of Finance to make them more effective. Direct Payments and use of Special Commitments will be the main disbursement methods to the Project hence ensuring a high disbursement rate. 100 Description of Risk Risk Mitigation Measures Condition of Residual incorporated in Project Effectiveness Risk/ (Risk) Implementation (Yes/No) rating Financial Reporting Financial Reporting arrangements are REA staff will be trained in Bank No L for KPLC, adequate for KPLC, KenGen and MoE. Financial Management guidelines that MoE and REA has submitted an agreed format of include preparation of IFRs before KenGen the Interim Financial Report (IFR) to the project effectiveness. Bank. M for REA The staff of REA needs training in the (L for KPLC, preparation of IFRs. MoE and KenGen S for REA) Auditing External audit arrangements are in place The methodology of KENAO needs to No S(S) (see auditing arrangements) but the audit be strengthened through capacity methodology of the Kenya National Audit building. The Bank will liaise with all Office (KENAO) needs to improve. First, key stakeholders i.e. MoF and auditors need to discuss issues raised in Controller and Auditor General to the management letters with clients address this issue. before finalizing the audits. Secondly, the external auditors sent to the Ministry of Finance to audit the Designated Accounts need to consult with the external auditors sent to the project to avoid a situation where the Designated/Special accounts reflect amounts withdrawn and not claimed that has led to qualification of almost all Bank funded projects in Kenya. Overall Control Risk Without mitigation: S After mitigation: S for REA and MoE, M for KenGen and KPLC Overall Risk Without mitigation: S After mitigation: S for REA and MoE, M for KenGen and KPLC H ­ High S ­ Substantial M ­ Moderate L ­ Low 9. The action plan in Table 30 below indicates the actions to be taken by each of the implementing entities to strengthen its financial management systems and the expected completion period: 101 Table 30: Actions to Strengthen Financial Management Responsible Completion Action Entity Date Internal controls systems: MoE, KPLC, KenGen and REA to address MoE, KPLC, During project internal control issues (including fixed asset register and tagging issues) as KenGen and implementation well as audit qualification issues for MoE. REA Audit Committee: MoE to strengthen their audit committee capacity to become more efficient in following up and addressing issues raised by both internal and external audit reports. Funds Flow: Address the funds flow bottlenecks in order to have adequate MoE, KPLC, Ongoing timely funds for the project. This is to be done through capacity building of KenGen and the project team, improving communications with the Disbursement Center REA and use of other methods of disbursement such as direct payments and special commitments. MoF and IDA Auditing: The methodology of KENAO needs to be strengthened through KENAO Ongoing capacity building to improve on the communications in addressing Management Letter and Audit Qualifications with their clients (projects). The Bank will liaise with all key stakeholders i.e. Treasury and Controller and Auditor General to address this issue. Information Systems: KPLC to resolve the interfacing issue of the SAP KPLC, MoE During project accounting software. A consultant for SAP has been hired in this regard. and MoF implementation IFMIS issues should also be addressed by the Ministry of Finance in order to ensure MoE has an adequate information system. Strengths and Weaknesses of the Financial Management System 10. The Project financial management is strengthened by the following salient features:- Budgeting arrangements are adequate except for MoE that has to prepare its budget using excel as it has no information system to prepare the budget. All implementing entities have adequate Financial Management Manuals documenting the financial management arrangements including internal controls to be used for the project. Staffing arrangements are adequate for all entities. KenGen, KPLC and REA have adequate accounting information systems except that KPLC has to address an issue concerning interfacing between Financial Module and Revenue Collection module to strengthen the system. MoE on the other hand is using IFMIS which is facing challenges hence it will need to mitigate this risk by preparing project accounts using Microsoft Excel. All implementing entities have a strong internal audit function except that the audit committee for MoE is weak and needs to be strengthened through capacity building. Financial Reporting arrangements for KenGen, KPLC and MoE are satisfactory in regard to preparation of Interim Financial Reports. REA`s staff will need training to strengthen their capacity in this area. All implementing entities are using acceptable accounting standards to prepare their final accounts for auditing. 102 External auditing arrangements are adequate but need to be strengthened in the areas of auditing the designated accounts and consultations with clients on audit findings before the audit reports are finalized. The project financial management is weakened by the following salient features: The management letters for all the implementing entities identified internal control system weaknesses that need to be addressed. The issues that led to the qualifications of the audit reports of MoE need to be followed up and addressed. In addition, the fixed asset register for MoE needs to be put in place. MoE audit committee is weak and its capacity needs to be strengthened. Kenya portfolio has had disbursement challenges in the past as delays have been experienced, but efforts are underway between the Bank and Ministry of Finance to address these issues from a portfolio perspective and the project will mainly use special commitments and direct payments to have a high disbursement rate. External audit arrangements are in place (see auditing arrangements) but the audit methodology of the Kenya National Audit Office (KENAO) needs to improve. First, auditors need to discuss issues raised in the management letters with clients before finalizing the audits. Secondly, the external auditors sent to the Ministry of Finance to audit the Designated Accounts need to consult with the external auditors sent to the project to avoid a situation where the Designated/Special accounts reflect amounts withdrawn and not claimed that has led to qualification of almost all Bank funded projects in Kenya. REA`s staff needs capacity building to strengthen their compliance with submission of Interim Financial Reports to the Bank. KPLC and MoE have challenges with their accounting information system. KPLC upgraded their system and have been facing interface challenges between the Financial Module and Revenue Collection Module while MoE is using the IFMIS, which was found to produce unreliable accounts by the Controller and Auditor General. Hence MoE is facing challenges in reconciling differences between the trial balance and existing project financial statements. In addition, the IFMIS does not have a budget module to prepare the budget. Institutional and Implementation Arrangements 11. The project will be implemented by four entities that are legally established with no significant financial management issues except for the risks identified in the risk table above that are being mitigated. KenGen and KPLC are state corporations quoted on the Nairobi Stock Exchange, while MoE is a government Ministry and REA is a body corporate established under Section 66 of the Energy Act, 2006 (No. 12 of 2006). 12. KenGen, KPLC and MoE are implementing the IDA-financed Energy Sector Recovery Project and their performance in regard to meeting the financial covenants has been satisfactory. 103 13. During project execution the four implementing entities will implement and manage: procurement, including purchases of goods, works, and consulting services; project monitoring, reporting and evaluation; contractual relationships with IDA and other co-financiers; and financial management and record keeping, accounts and disbursements. 14. MoE will coordinate the implementation entities and be the operational link to the IDA on behalf of Government of Kenya on matters related to the implementation of the project. 15. The Permanent Secretary (PS), MoE, will be the Accounting Officer for the project, assuming the overall responsibility for accounting for the project funds. The heads of the institutions/Chief Executive Officers of KenGen, KPLC and REA will report to the Accounting Officer on matters concerning the accountability of the project`s funds. Financial Management Arrangements Budgeting Arrangements 16. KenGen: KenGen has qualified staff who undertake budgeting and monitoring. Budgeting procedures are documented under ISO procedure titled Budgeting & Budgetary Control Procedures` which covers the entire process from budget preparation, budget control, monthly variance analysis and management reports and is considered adequate Systems Application and Products (SAP) computerized information system is used for budgeting under the controlling module` and budgeting follows a bottom up approach. After KenGen`s Board approval, the budget is forwarded to the Ministry of Energy and the Ministry of Finance for approval and is consolidated under the Ministry of Energy (MoE) Printed Estimates. 17. KPLC: There are qualified staff who undertake budgeting and monitoring. Financial management procedures in regard to budgeting documented under the Budget and Budgetary Control Manual are in place and are considered adequate. SAP system is used for budgeting and budgeting follows a bottom up approach. After KPLC`s Board approval, the budget is forwarded to the Ministry of Energy and the Ministry of Finance for approval and is consolidated under the Ministry of Energy (MoE) Printed Estimates. 18. MoE: The Ministry`s budgets are prepared and incorporated in the Development Estimates and approved by Parliament. MoE has qualified staff to undertake budget planning and monitoring. Budgeting procedures are well defined in the Government Financial Regulations and Procedures. Budgeting process is done manually using Microsoft Excel as the Integrated Financial Management Information System (IFMIS) does not have a budgeting module. 19. REA: The budgeting process is deemed adequate. Budgeting follows procedures set out in the Rural Electrification Authority Finance Procedures & Instruction Manual. The budget is then submitted to the Ministry of Energy (MoE) for consolidation in the Printed Estimates. Actual expenditure is monitored against planned/budgeted expenditure on a monthly basis and this is done in the SAP system. 104 Accounting Arrangements 20. KenGen: The Company uses the SAP system of accounting. The system is able to capture expenditures and generate reports and this is adequate for accounting and financial reporting purposes. SAP system is being upgraded to the latest version and the upgrade is expected to be completed by end of 2010. The staff are qualified and experienced. The Chief Accountant Project Finance will be in charge of the project`s accountability. The Chief Accountant Project Finance will report to the Corporate Finance Manager who will report to the Finance and Commercial Director. Important to note is that the recruitment of the Chief Accountant Project Finance and the Corporate Finance Manager is in an advanced stage and is expected to be completed by the end of May 2010. The Finance Manager will be standing in to account for any of the project funds until the recruitment is finalized. The Financial Management Manual, i.e. the operating procedure and work instruction manual for the Finance Department is adequate to be utilized for the project. Recording of fixed assets is done in the Fixed Asset Register, which, is in SAP. However, KenGen is in the process of reconciling and recording all its fixed assets with 80 percent done with a target of completing the process by end of May 2010. Safeguarding is done by having well manned stores and tagging of assets. In addition, before a payment for a fixed asset is made, it must have received a fixed asset number. 21. KPLC: The Company uses the SAP system of accounting. The system is able to capture expenditures and generate reports and this is adequate for accounting and financial reporting purposes. The SAP has however been having challenges every time it is upgraded in form of interface differences especially between the Financial module and the revenue collection module. A consultant has been engaged to address this issue. The staff is qualified and experienced and the financial management manual, i.e., Financial Division Accounting Instructions Manual is adequate for the project funds. Recording of fixed assets is done in the Fixed Asset Register, which is in SAP. Safeguarding is done by having well manned stores and tagging of assets. 22. MoE: MoE has a fully-fledged accounting unit operating within the laid down Government Financial Regulations and Procedures and government circulars/guidelines issued from time to time to enhance checks and balances, which are adequate for the project. An independent accounting section for donor-funded projects (External Resources Section) with three competent (qualified and experienced) staff is in place. The only challenge is that the Government`s computerized Integrated Financial Management Information System (IFMIS) was found to produce unreliable accounts by the Controller and Auditor General and as such, MoE is facing challenges of reconciling differences between the trial balance and existing project financial statements. This issue is being addressed by the Government broadly under the Public Financial Management Reform Program but as a mitigation measure, the project accounts produced by MoE will be manually prepared using Microsoft Excel. The audit report for FY2009 for MoE noted that they do not maintain a Fixed Asset Register or Register for Non Current Assets. The MoE has agreed to prepare this register during FY2010. 23. REA: REA has an FM Manual in place called the Finance Procedures and Instruction Manual, which is considered adequate. SAP accounting system is in use and is able to generate most of the required reports including management accounts. The current management accountant will be the project accountant reporting to the Chief Manager, Finance. Recording of fixed assets 105 is done in the Fixed Asset Register, which is in SAP but the process of tagging fixed assets is ongoing and needs to be completed. Internal Control and Internal Auditing Arrangements Internal Auditing 24. KenGen, KPLC, REA and MoE all have a strong internal audit function with audit committees in place to address issues raised by both internal and external audit reports but the audit committee of MoE is weak and needs capacity building. The assessment also noted that KLPC and KenGen have anti-corruption policies. Internal Control Systems 25. MoE, KPLC, KenGen and REA have adequate financial management manuals documenting the internal control systems to be used under the project. Review of Internal Control Systems 26. A review of the external audit reports and the management letters flagged several internal control issues in KenGen, KPLC and MoE, which are being addressed by the respective entities and will be monitored during project implementation by the Bank using agreed upon action plans with the entities. The Management for KenGen is available in project files. However, the Chief Internal Auditor of KenGen confirmed that the issues were being addressed. 27. KPLC: FY2009 Management Letter noted that the accounting system had system interface differences and bank reconciliation differences that needed to be resolved. KPLC management informed the Bank that a consultant has been hired to improve the system interface. 28. MoE: FY2009 audited accounts were qualified and internal control issues were skewed towards ineligibility of expenditure and material unexplained differences but these issues have since been explained by MoE to the Controller and Auditor General of the Kenya National Audit Office. The Bank therefore expects to receive a confirmation letter from the Controller and Auditor General that the issues raised have been resolved. 29. REA: A review of the internal control issues in REA in November 2009 revealed the following issues: (a) fixed asset register needs to be updated; (b) remaining 10 percent of the fixed assets need to be tagged to identify REA as the owner of the asset; (c) proper books of accounts were not being kept in 2008 although this was a minor issue not enough to justify a qualification of the accounts; and (d) though there is segregation of duties as detailed in the FM manual, this has been achieved in some areas by use of temporary staff. In the area of petty cash, this segregation has not been achieved as the staff doing the bank reconciliations is the same one handling petty cash. The management of REA confirmed that they have hired three more staff in their Finance Department, which would address the segregation of duties issue. Management also confirmed that their fixed asset register was up to date with the development of the asset sub-module in the SAP accounting system. 106 B. Funds Flow and Disbursement Arrangements Bank Accounts 30. The implementing entities will maintain the following bank accounts for the purposes of implementing the Project: Designated Accounts: Five Designated Accounts will be opened: one for Component A and training under D2 (a) implemented by KenGen; one for Component B implemented by KPLC on behalf of KETRACO; two for Component C -- one for KPLC {Component C1, C3 and training under D2 (b)} and another for REA {Component C2 and training under D2 (c)}; and one for Component D1, D2 (d) and D3 implemented by MoE. These Designated Accounts will be denominated in US dollars and disbursements from the IDA Credit will be deposited on these accounts. Project Accounts: Five Project Accounts will be opened for each of the five designated accounts mentioned above. These Project accounts will be denominated in local currency (Kenya Shillings -- KSh). Counterpart funds and transfers from the Designated Account (for payment of transactions in local currency) will be deposited on these accounts in accordance with Project objectives. 31. The Designated and Project Accounts will be opened in commercial banks based in Kenya that are acceptable to the Bank. The Bank has recommended that the Designated and Project Accounts be opened within one month after effectiveness and their details communicated to the Bank with the signatories of the accounts. Funds Flow Arrangements 32. Funds flow arrangements for the project (through the bank accounts above) are as follows: Each of the implementing entities will prepare a six-month cash flow forecast based on agreed work plans then submit a withdrawal application request to the Bank (IDA) through the Ministry of Finance. IDA will process the withdrawal application and disburse funds to the Designated Accounts in US dollars. Ministry of Finance will transfer funds from the Designated Accounts into the Project Accounts in local currency. Ministry of Finance can also transfer counterpart funds into the Project Accounts. Project expenditure can be paid from either the Designated Account or Project Account. 33. Delays have been experienced in disbursing funds to projects in Kenya and the Bank (IDA) has been working with Ministry of Finance to address this issue. Other methods of disbursements particularly Direct Payments and Special Commitments will be encouraged to increase the rate of disbursements. 107 Funds Flow Chart 34. The figure below shows the Funds Flow for each of the four implementing entities. WORLD BANK (IDA) DESIGNATED PROJECT ACCOUNT in ACCOUNT in USD in a KShs in a Local Local Commercial Bank Commercial Bank Payments to project activities IDA Disbursement Methods 35. Special Commitments and Direct Payments: Special Commitments using irrevocable letters of credit will be the main disbursement method for the project. Direct payments to suppliers for works, goods and services upon the borrower`s request, may also be used for the project. Hence challenges faced with disbursing through the designated account at country level will be minimized. Details about these two methods of payments are included in the Disbursement Letter. 36. Report-based Disbursements: The project will also receive funds into the designated account using the report based disbursement method. IDA will make the initial disbursement to the project after receiving a withdrawal application with a six months cash flow forecast. This withdrawal application should be prepared within one month after project effectiveness. Thereafter, IDA will disburse into the respective Designated Account based on quarterly IFRs, which would provide actual expenditure for the preceding quarter (3 months) and cash flow projections for the next 2 quarters (6 months). The IFR together with the Withdrawal Application (WA) will be reviewed by the Bank`s Financial Management Specialist (FMS) and approved by the Task Team Leader (TTL) before the request for disbursement is processed by the Bank`s Loan Department. 37. Reimbursements: These can also be made to the Designated Account. These payments will also be reported in quarterly IFRs. 38. The IDA Disbursement Letter will provide details about each of the above disbursement arrangements. C. Financial Reporting Arrangements 39. The implementing entities will produce quarterly unaudited Interim Financial Reports (IFRs) for each of the designated accounts and the related project accounts. KenGen, KPLC and MoE have been producing satisfactory IFRs under the ongoing Energy Sector Recovery Project and should have no difficulty developing the formats for this project. REA has agreed with the 108 Bank on the format and contents of the IFR to be utilized for this project. The IFRs are to be produced on a quarterly basis and submitted to the Bank within 30 days after the end of the calendar quarterly period. 40. The IFRs submitted to the Bank will have a section on Financial Reporting and Disbursement containing the following: Reporting Section includes: Statement of Sources and Uses of Funds; and Statement of Uses of Funds by Project Activity/Component. Disbursement Section includes: Designated Account (DA) Activity Statement; Bank Statements for both the Designated and Project Account; Summary Statement of DA Expenditures for Contracts subject to Prior Review; and Summary Statement of DA Expenditures not subject to Prior Review. 41. The project will also prepare the projects annual accounts/financial statements within 3 months after the end of the accounting year in accordance with accounting standards acceptable to the Bank. The audited financial statements should be submitted to the Bank within 6 months after the end of the accounting year. KPLC, KenGen and REA will prepare their accounts in accordance with International Financial Reporting Standards while MoE will prepare their accounts in accordance with International Public Sector Accounting Standards. 42. The accounts/financial statements will comprise of: (a) A Statement of Sources and Uses of Funds/Cash Receipts and Payments, which recognizes all cash receipts, cash payments and cash balances controlled by the entity; and separately identifies payments by third parties on behalf of the entity. (b) The Accounting Policies Adopted and Explanatory Notes. The explanatory notes should be presented in a systematic manner with items on the Statement of Cash Receipts and Payments being cross referenced to any related information in the notes. Examples of this information include a summary of fixed assets by category of assets, and a summary of IFR Withdrawal Schedule, listing individual withdrawal applications; and (c) A Management Assertion that Bank funds have been expended in accordance with the intended purposes as specified in the relevant World Bank legal agreement. 43. Indicative formats of these statements will be developed in accordance with IDA requirements and agreed with the Country Financial Management Specialist. 44. KenGen, KPLC and REA will use the SAP accounting information system to prepare the financial reports while MoE will use Microsoft Excel. The staff of REA will need to be trained in preparing IFRs. 109 D. Auditing Arrangements 45. The Controller and Auditor General of the Kenya National Audit Office (KENAO) are primarily responsible for the auditing of all government projects. Usually, the audit is subcontracted to a firm of private auditors, with the final report being issued by the Controller and Auditor General, based on the tests carried out by the subcontracted firm. In case the audit is subcontracted to a firm of private auditors e.g. in the case of KenGen and KPLC under the Energy Sector Recovery Project, IDA funding may be used to pay the cost of the audit. The private external auditors have to be acceptable to the IDA. The audits are done in accordance with International Standards on Auditing. 46. For each of the Designated Accounts and related Project Accounts, an audit report must be submitted to IDA within six months after the end of each financial year. The audit reports for the project may be consolidated into the entity accounts provided there are adequate notes disclosing the sources and uses of IDA funds and reconciliation of the Designated Account. 47. KenGen, KPLC and MoE that are currently implementing the Energy Sector Recovery Project do not have any overdue audit reports. Audit reports for FY2009 were also submitted in time to the Bank. 48. External audit arrangements are in place (see auditing arrangements) but the audit methodology of the Kenya National Audit Office (KENAO) needs to improve. First, auditors need to discuss issues raised in the management letters with clients before finalizing the audits. Secondly, the external auditors sent to the Ministry of Finance to audit the Designated Accounts need to consult with the external auditors sent to the project to avoid a situation where the Designated/Special accounts reflect amounts withdrawn and not claimed that has led to qualification of almost all Bank funded projects in Kenya. 49. A review of the most recent audit reports revealed the following: 50. KenGen: The auditors issued a qualified audit opinion on the 2008/2009 institutional financial statements on departure from IAS 21 on treatment of unrealized exchange gains and losses relating to foreign currency denominated borrowings, which would have resulted into a loss before tax to the KenGen. KenGen has followed up this issue by seeking opinions from the Institute of Certified Public Accountants of Kenya and the International Accounting Standards Board and they have been informed that this issue will be resolved with the revision of IAS 39 on Financial Instruments: Recognition and Measurement. 51. KPLC: The external auditor issued an unqualified audit opinion on the 2008/2009 institutional financial statements. 52. MoE: The auditor issued a qualified audit opinion on the 2008/2009 institutional financial statements where the Special Account Statement reflects amounts withdrawn and not yet claimed and there were unexplained expenditure variances between the Development Appropriation Account (DAA) and Project Financial Statements as well as unexplained variances between the Statements of Receipts and Expenditure and the Trial Balance. MoE has provided explanations in regard to these issues to the Controller and Auditor General and upon verification a clearance letter 110 showing that these issues have been addressed is to be issued by the Controller and Auditor General. 53. REA: The Controller and Auditor General issued an unqualified audit opinion on the REA financial statements for the financial year ended June 30, 2008. 54. The arrangements for the external audit of the financial statements of the project should be communicated to IDA through agreed audit terms of reference. The Bank has shared the audit terms of reference with KENAO and this should be adequate for the audit of all the implementing entities of this project. 55. The Bank encourages the disclosure of the project audit reports to the public in the spirit of being transparent. 56. The audit reports that will be required to be submitted by KenGen {Components A and D2(a)}, KPLC {Components B, C1, C3 and D2(b)}, REA {Component C2 and D2(c)} and MoE {Components D1, D2(d) and D3} and the due dates for submission are shown in Table 31. Table 31: Audit Reports and Due Dates Audit Report Due Date KenGen and KPLC: Within six months after the end Entity Financial Statements and Management Letter. These should have adequate disclosures of each fiscal/financial year. of the projects sources and uses of funds and reconciliation of the Designated Account. REA and MoE: Annual audited financial statements and Management Letter for the project (including reconciliation of the Designated Accounts with appropriate notes and disclosures). KETRACO: Annual project specific Accounts and Management Letter (including reconciliation of the designated Accounts with appropriate notes and disclosures). E. Conditionality 57. None. F. Financial Covenants 58. Financial covenants are the standard ones as stated in the Financing Agreement Schedule 2, Section II (B) on Financial Management, Financial Reports and Audits and Section 4.09 of the General Conditions. G. Implementation Support Plan 59. Based on the outcome of the FM risk assessment, the following implementation support plan is proposed. The objective of the implementation support plan is to ensure the project maintains a satisfactory financial management system throughout the project`s life. 111 FM Activity Frequency Desk reviews Interim financial reports review Quarterly Audit report review of the program Annually Review of other relevant information such as interim internal Continuous as they become available control systems reports. On site visits Review of overall operation of the FM system Semi-Annually (Implementation Support Mission) for MoE and REA and annually for KenGen and KPLC Monitoring of actions taken on issues highlighted in audit reports, As needed auditors` management letters, internal audit and other reports Transaction reviews (if needed) As needed Capacity building support FM training sessions Before project start and thereafter as needed. H. Disbursement Table for the IDA Credit Category Category Description Amount of IDA financing Percentage of Expenditures to be allocated Financed by IDA (excluding taxes) (expressed in US$) 1 Works, goods, and consulting services under 114,755,000 100% components A1, A2, and training under D2 (a) 2 Works, goods, and consulting services under 63,464,927 100% component B1 3 Works, goods, and consulting service under 99,014,825 100% components C1 (a), C3 (a), and training under component D2 (b) 4 Works, goods, and consulting services under 34,250,000 100% component C2 (a) and training under component D2 (c) 5 Works, goods, consulting services and training under 10,400,000 100% components D1, D2 (d), and D3 6 Unallocated 8,115,249 TOTAL AMOUNT 330,000,000 Retroactive Financing 60. Up to US$3 million or one percent of the IDA Credit will be available to finance eligible expenditures incurred from January 1, 2010 to Credit signing. 112 Annex 8: Procurement KENYA: Electricity Expansion A. General 1. Procurement for the IDA-financed components of the proposed project will be carried out in accordance with the World Bank`s "Guidelines: Procurement Under IBRD Loans and IDA Credits" dated May 2004 revised October 2006; and "Guidelines: Selection and Employment of Consultants by World Bank Borrowers" dated May 2004 revised October 2006, and the provisions stipulated in the Financing Agreement. The other co-financiers will follow their own procurement rules. The various items under different expenditure categories are described in the Procurement Plan below. For each contract to be financed by the IDA Credit, the different procurement methods or consultant selection methods, the need for pre-qualification, estimated costs, prior review requirements, and period are agreed between the Borrower and the Bank in the Procurement Plan. The Procurement Plan will be updated at least annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. The procurement entities as well as contractors, suppliers, and consultants will observe the highest standard of ethics during procurement and execution of contracts financed under this project. The project will carry out implementation of the IDA-financed components in accordance with the Guidelines on Preventing and Combating Fraud and Corruption in projects financed by IBRD Loans and IDA Grants dated October 15, 2006 (the Anti-Corruption Guidelines). 2. Procurement Environment: The public procurement system in Kenya covers all government entities, which include the central government, local authorities, state corporations, education institutions and other government agencies that purchase goods, works and services using public resources in accordance with the provisions of the public procurement law, the Public Procurement and Disposal Act of 2005 (PPDA). It came into effect in January 2007, replacing the Exchequer and Audit Act (Public Procurement), Regulations, 2001. Section 8 (1) of the Act established a central Public Procurement Oversight Authority (PPOA) in addition to the Public Procurement Department established under the Regulations (2001) in the Ministry of Finance. The PPOA was officially launched in June 2008, but still it is not fully staffed. The Act sets out the rules, procedures and institutional arrangements that the public entities should follow in the management of public procurement. The Act also provides mechanisms for enforcement of the law. The PPOA provides oversight function in monitoring compliance with rules and procedures spelt out in the Act. However, the Act contains provisions that impede transparency and efficiency (for example the Act allows tender evaluation criteria based on a merit point system rather than in monetary terms). 3. A Public Officers Ethics and an Anticorruption Law was enacted in May 2003, but their effect has still to be felt. Corruption in procurement is not yet controlled. The country has a very vibrant civil society and media who are proactive and open in pursuing and reporting cases of impropriety. The Public Procurement Administrative Review Board (PPARB) is doing a good job in dealing with flawed contracts, and subsequently disseminating to the public the decisions made 113 in all the cases adjudicated. Scrutiny by civil society and the media on the one hand, and the actions of the PPARB on the other, have significantly reduced the risk level, by forcing the Government to address issues of impropriety in public procurement and also ensuring that public officials are more accountable while conducting public procurement. Under the Governance Action Plan, the Government has introduced the following procurement reforms, which are at different stages of implementation: Enhancing transparency and information symmetry in bidding process and contracts implementation by requiring all agencies to publish information on all contracts required by law on a functional Government website, which is accessible to the public; Pre-qualification of companies interested in bidding for government contracts and the up- dating of the list on a yearly basis to avoid conflict of interest; Establishment of a mechanism for evaluation, vetting, disqualification and debarring of errant companies from participating in government procurement processes; and Development of a website and implementation of e-procurement. 4. Procurement Implementation Arrangements: Procurement will be done by four entities, namely, (a) Ministry of Energy (MoE); (b) Kenya Electricity Generating Company Ltd. (KenGen); (c) Kenya Power and Lighting Company, Ltd. (KPLC); and (d) Rural Electrification Authority (REA). 5. MoE: Besides procurement responsibilities, MoE will have an overall responsibility for coordination of the project. Specifically, the MoE will be responsible for procurement of activities under Component D ­ Institutional Development and Implementation Support. The existing Project Implementation Team (PIT) will be responsible for all procurement, contract management, financial management of project funds, preparation of progress reports, updating of project costs, and financing plans. 6. KenGen: KenGen will be responsible for procurement of activities related to implementation of the generation component. Day-to-day procurement will be done by its PIT. In addition, the PIT will be responsible for contract management, management of project funds, preparation and updating of progress reports, project costs, and financing plans. 7. KPLC: KPLC will be responsible for implementing the project`s T & D components. The company`s PIT will be responsible for all procurement, contract management, financial management of project funds, preparation of progress reports, updating of project costs, and financing plans. In addition, KPLC will be responsible for Implementation of the Output-Based slum electrification program that will be co-financed by GPOBA and IDA. 8. REA: REA will be responsible for procurement activities related to implementation of the project`s rural electrification activities (subcomponent C2). The agency`s PIT will be responsible for day-to-day procurement function. 9. Use of National Procurement Procedures: All contracts other than those to be procured on the basis of International Competitive Bidding (ICB) and consulting services shall follow the procedures set out in the Public Procurement and Disposal Act of 2005. The Bank has reviewed 114 the Act and found it to be acceptable except that the following provisions would be adopted under this project (a) bidding period for National Competitive Bidding (NCB) shall not be less than 30 days as opposed to 21/14 days provided in the law; (b) government parastatal institutions shall be allowed to participate in procurement only if they are legally and financially autonomous, operate under commercial law, and are independent from the borrower and its purchasing/contracting authority; (c) preference system shall not be allowed; (d) merit point system shall not be used for bid evaluation; (e) price negotiations under NCB shall be allowed only where the bid price is substantially above market or budget levels and only then if negotiations are carried out to try to reach a satisfactory contract through reduction in scope and/or reallocation of risk and responsibility, which can be reflected in a reduction in Contract price; (f) shopping procedures shall be used instead of direct procurement for low value contracts; (g) the two envelope bid opening procedure for procurement of goods shall not be permitted; and (h) the Bank`s standard bidding documents for goods and works should preferably be used or National SBD for NCB contracts can be used if they are modified to meet the Bank`s requirements. 10. A specified number of NCB contracts to be prior reviewed by the Bank will be identified in the procurement plan each year. 11. The provisions of Performance-Based Procurement also called Output-Based Procurement will apply to Component C3 Slum Electrification. 12. Procurement of Works: Works contracts including supply and installation and EPC to be procured under the Project would include geothermal steam gathering and distribution network, construction of substations and transmission lines. Contract packages estimated to cost US$5,000,000 equivalent or above per contract will be procured through International Competitive Bidding (ICB) procedures that provide for use of domestic preference. Contract packages estimated to cost less than US$5,000,000 equivalent per contract would be procured through National Competitive Bidding (NCB) procedures subject to the exceptions described in paragraph above. Small contracts estimated to cost less than US$100,000 for works, equivalent per contract may be procured through Shopping procedures by comparing prices for quotations received from at least three (3) reliable contractors or suppliers. In such cases, request for quotations shall be made in writing and shall indicate the description, scope of the works, the time required for completion of the works and the payment terms. All quotations received shall be opened at the same time. Direct contracting for works may exceptionally be an appropriate method in emergency situation, provided the Bank is satisfied in such cases that no advantage could be obtained from competition and that prices are reasonable. The procurement will be done using the Bank`s Standard Bidding Documents (SDB) and Standard Form of Evaluation for all ICB contracts. For NCB contracts, the Bank`s standard bidding documents for works should preferably be used or National SBD can be used if they are modified to meet the Bank`s requirements. In accordance with para.1.14 (e) of the Procurement Guidelines, each bidding document and contract financed out of the proceeds of the Financing shall provide that: (a) the bidders, suppliers, 115 contractors and subcontractors shall permit the Association, at its request, to inspect their accounts and records relating to the bid submission and performance of the contract, and to have said accounts and records audited by auditors appointed by the Association; and (b) the deliberate and material violation by the bidder, supplier, contractor or subcontractor, of such provision may amount to an obstructive practice as defined in paragraphs 1.14 (a) (v) of the Procurement Guidelines. 13. Procurement of Goods: Goods procured under this project would include: power transformers, substation switchgear, overhead line equipment, etc. Contract packages estimated to cost US$500,000 equivalent per contract will be procured through ICB procedures. Goods contracts estimated to cost less than US$500,000 equivalent per contract would be procured through NCB procedures subject to the exceptions described above of this Annex. Small contracts estimated to cost less than US$100,000 for goods equivalent per contract may be procured through Shopping procedures by comparing prices for quotations received from at least three (3) reliable contractors or suppliers. In such cases, request for quotations shall be made in writing and shall indicate the description, specifications, the time required to deliver the goods, and the payment terms. All quotations received shall be opened at the same time. As a general rule, a qualified supplier who offers goods or materials that meet the specifications at the lowest price shall be recommended for award of the contract. Limited International Bidding for goods may exceptionally be used when there are only a limited number of known suppliers worldwide. Direct contracting goods may exceptionally be an appropriate method in emergency situation, provided the Bank is satisfied in such cases that no advantage could be obtained from competition and that prices are reasonable. The procurement will be done using the Bank`s Standard Bidding Documents (SDB) and Standard Form of Evaluation for all ICB contracts. For NCB contracts, the Bank`s standard bidding documents for goods should preferably be used or National SBD can be used if they are modified to meet the Bank`s requirements. In accordance with para.1.14 (e) of the Procurement Guidelines, each bidding document and contract financed out of the proceeds of the Financing shall provide that: (a) the bidders, suppliers, contractors and subcontractors shall permit the Association, at its request, to inspect their accounts and records relating to the bid submission and performance of the contract, and to have said accounts and records audited by auditors appointed by the Association; and (b) the deliberate and material violation by the bidder, supplier, contractor or subcontractor, of such provision may amount to an obstructive practice as defined in paragraphs 1.14(a)(v) of the Procurement Guidelines. 14. Procurement of Non-Consulting Services: Non-consulting services, which are services that are not of intellectual or advisory in nature will include, but not limited to (a) services of office equipment; and (b) maintenance of project vehicles. The procurement of non-consulting services shall follow the existing SBDs with appropriate modifications. 15. Selection of Consultants: The consultancy services that will be financed by IDA under the Project would include: (a) design and supervision; (b) establishment of a wholesale electricity market: (c) facilitating private sector participation in the electricity sector (d) electricity cost of service study; (f) materials and equipment supply chain study; (g) risk management study for electricity sector; (h) pre-feasibility and feasibility studies. All consulting services will be procured following the procedures set out in the Guidelines for the Selection and Employment of Consultants by World Bank Borrowers. Consulting contracts will, as far as possible, be awarded under Quality and Cost Based Selection (QCBS) procedures. Other methods of selection will be 116 determined for each assignment depending on the type of assignment and the provisions of the Consultants Guidelines and will be indicated in the procurement plan. 16. Quality Based Selection (QBS) would be followed for assignments, which meet the requirements of paragraph 3.2 of the Consultants Guidelines. 17. Assignments for standard and routine nature such as audits and other repetitive services would be selected through Least-Cost Selection (LCS) method in accordance with paragraph 3.6 of the Consultants Guidelines. 18. Consulting services by firms used for assignments estimated to cost less than US$200,000 equivalent per contract and for which the cost of a full-fledged selection process would not be justified may be selected on the basis of Consultant Qualifications (CQS) in accordance with paragraphs 3.7 and 3.8 of the Consultants Guidelines. 19. Fixed Budget Selection (FBS) would be followed for assignments, which meet the requirements of paragraph 3.5 of the Consultants Guidelines. 20. Single-Source Selection (SSS) would be followed for assignments, which meet the requirements of paragraph 3.9 - 3.12 of the Consultants Guidelines, and will be subject to the Bank`s prior review regardless of the amount. Specifically, SSS would be applied only in exceptional cases if it presents a clear advantage over competition when selection through a competitive process is not practicable or appropriate. It would be made on the basis of strong justification and upon the Bank`s concurrence to the grounds supporting such justification: (a) for tasks that represent a natural continuation of previous work carried out by the firm; (b) in emergency cases, such as in response to disasters and for consulting services required during the period of time immediately following the emergency; (c) for very small assignments; or (d) when only one firm is qualified or has experience of exceptional worth for the assignment. 21. Short list of consultants for services estimated to cost less than US$200,000 equivalent per contract may be comprised entirely of national consultants in accordance with the provisions of paragraph 2.7 of the Consultant Guidelines. 22. Individual Consultants (IC) will be selected on the basis of their qualifications by comparison of CVs of at least three candidates from those expressing interest in the assignment or those approached directly by the implementing entity in accordance with the provision of Section V of the Consultants Guidelines. 23. Consultancy services estimated to cost above US$200,000 equivalent per contract for firms, and all single source selection of consultants will be subject to prior review by the Bank. The Bank will prior review evaluation process for selection of individual consultants above US$100,000. All consulting services shall use the Bank`s Standard Request for Proposal (RFP) and Standard Form of Evaluation. 117 B. Assessment of the Implementing Entities' Capacity to Implement Procurement 24. An assessment of the capacity of the implementing entities to implement procurement actions for the project was carried out by the Bank`s Procurement Team in the Nairobi Country Office in October 2009. The assessment reviewed the organizational structures of the four implementing agencies, and the capacity of the project staff responsible for procurement in each of the implementing entities. The assessment concluded that the procurement risk at KenGen, KPLC and MoE is Moderate while the procurement risk at REA is rated High. Because REA will be responsible for the implementation of only 12 per cent of the IDA Credit, the overall project risk for procurement is Substantial. The implementing entities` procurement capacity is discussed in the paragraphs below. 25. MoE: The MoE has a PIT that will be responsible for a procurement function. The PIT consists of a Project coordinator, Procurement Officer, an Accountant, a Renewable Energy Specialist and a Power Engineer. All but the Renewable Energy Specialist are already in place. PIT members have experience in the implementation of the on-going Energy Sector Recovery project. The PIT reports to the Permanent Secretary for Energy. 26. KenGen and KPLC: The Project Implementation Teams in these two implementing entities are all adequately staffed with technical and procurement officers who have acquired adequate experience from the on-going project and have access to appropriate tools and knowledge, including assistance from the World Bank Country office. Contract supervision is adequate. 27. KenGen PIT consists of a Team Leader, a Steam Field Engineer, an Electrical Engineer, a Mechanical Engineer, a Civil Engineer, a Procurement Officer, an Accountant and an Environmental Specialist. KenGen has implemented three EPC contracts financed by the World Bank and donors. Under the on-going ESRP, KenGen is implementing an EPC contract of value US$100 million, i.e., Olkaria II Unit 3 extension with assistance of an external consultant. The same consultant has been selected -- competitively -- using KfW funds to continue assisting KenGen under this project for activities related to all contracts. KenGen will implement three EPC contracts and one supply and installation contract under this Project. KenGen`s Board, through its Procurement Oversight Committee, approves all procurements with a value above KSh 50 million (US$650,000). A Tender Committee approves contract awards and submits them to the Board`s Procurement Oversight Committee for review when the value exceeds KSh 50 million. The Tender Committee consists of executive directors, the Company Secretary and a Procurement Specialist. It invites representatives of the professional bodies to observe deliberations. 28. KPLC`s PIT consists of a Team Leader, a Chief Engineer, Power Engineers, a Procurement Officer, an Accountant and an Environmental Specialist. In addition, the Project will finance the services of a Design and Supervision Engineer for the transmission component and an implementation support consultant for the distribution subcomponent (C1). The PIT is part of KPLC`s permanent organizational structure and reports to the company`s Chief Executive. KPLC with assistance of an external consultant has implemented eleven EPC contracts under the on- going ESRP. Under this Project, KPLC will have an external consultant to assist them in the implementation of the EPC contracts. A Tender Committee reviews and approves contract awards. 118 29. REA: REA like all other central Government ministries, departments and public authorities has a procurement unit (the Procurement Division) and a Tender Committee each of which is entrusted with clear responsibilities that are set forth in the Public Procurement and Disposal Act (2005). The Tender Committee comprises managers of Divisions. The Procurement Division is staffed with seven people comprising a manager, a senior procurement officer, two procurement officers, an assistant procurement assistant and two contract employees. The contract employees are responsible for procurement record keeping and providing support in other procurement duties. All Procurement Division staff members are computer literate, and equipped with computer workstations. However, the Division shares printers and photocopiers with all other REA Divisions, which may compromise the confidentiality of documentation. The professional staff of Division was recruited competitively from the private sector. Their experience or training in World Bank procurement is limited. 30. Based on the procurement staff size and background training in procurement, REA has the capability to implement procurement under the subcomponent Electrification of Priority Loads in Rural Areas (C2). However, due to lack of experience or training of the PD staff in World Bank procurement procedures, procurement risk at REA is rated High. C. Key Issues, Risks, and Corrective Measures 31. The key issues and risks for procurement include: Generic risks in implementing agencies: Delay in the production of procurement plans and updates; Weak coordination between technical experts and procurement units in preparation of bidding documents or RFP resulting in delays in the start of the bidding process and completion of the evaluation of bids and proposals; Delay in appointment of evaluation committees leading to delays in the finalization of the evaluation process and hence award of contracts; and Inadequacies in the national public procurement law and regulations. Risks specific to REA: Lack of experience in the World Bank procurement procedures; and Lack of dedicated office equipment such as printers and photocopiers in the Procurement Division to ensure confidentiality of procurement documentation. 32. The agreed corrective measures are: Train all procurement staff of the implementing agencies in procurement planning, and establish a monitoring system of implementation of procurement plans; Define the roles of all personnel involved in procurement process administration , and strengthen the coordination of inputs by the actors; 119 Appoint evaluation committees during preparation of submissions by invited bidders and consulting firms; Conduct periodical training for all members of Tender Committees in public procurement procedures and specifically in the evaluation procedures of bids and proposals; Organize a procurement induction course for staff of the Procurement Division and members of REA`s Tender Committee prior to the Project effective date; Include in the Financing Agreement the inadequacies of the public procurement law listed in paragraph 9 of this Annex as exceptions to the national procurement procedures; and Equip REA`s Procurement Division with adequate office equipment. D. Procurement Plan 33. The Recipient, at appraisal, developed a procurement plan for the first 18 months of project implementation, which provides the basis for the procurement methods. This plan was agreed between the Borrower and the Bank`s Project Team at negotiations on April 13, 2010 and will be available at the World Bank`s website. It will also be available in the project`s database and in the Bank`s external website. The implementing entities will update the Procurement Plan in agreement with the Bank`s Project Team annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. E. Frequency of Procurement Supervision 34. In addition to the prior review supervision to be carried out from the Bank`s Nairobi and Washington offices, the capacity assessment of the implementing entities has recommended two annual supervision missions to carry out post review of procurement actions. 120 Procurement Plan for the first 18 months KENYA: Electricity Expansion Project information: KENYA: ELECTRICITY EXPANSION PROJECT Project ID No: P103037 Project Implementing Entities (PIEs): Ministry of Energy (MoE), Kenya Power and Lighting Company Limited (KPLC), Kenya Electricity Generating Company Limited (KenGen) and Rural Electrification Authority (REA). Bank's Approval Date of the Procurement Plan: April 13, 2010 Date of General Procurement Notice: April 27, 2010 Period Covered by this Procurement Plan: September 2010 -- February 2012 II. Goods and Works and Non-Consulting Services 1. Prior Review Thresholds: Procurement decisions subject to Prior Review by the Bank as stated in Appendix 1 to the Guidelines for Procurement: Procurement Method Prior Review Threshold Comments 1. ICB and LIB (Goods) >=500,000 All contracts 2. ICB and LIB (Works/Supply & Installation All contracts of Plant & Equipment) >=5,000,000 3. ICB (Non-Consultant Services) >=500,000 All contracts 4. NCB All values 1st contract only 5. Direct Contracting All values All contracts 6. Force Account All values 7. Shopping >=70,000 8. Performance Based Procurement None 121 2. List of Contract Packages to be Procured Following ICB and Direct Contracting: Ref. Contract Financier Cost Procurement P-Q Domestic Review Expected No. (Description) Estimate Method Preference by Bid- (yes/no) Bank Opening (Prior/ Date Post) 1. 66/11 & 33/11 KV Power IDA 5.0 ICB No No Prior November Transformers. 2010 2. Substation Switchgear and IDA 18.0 ICB No No Prior November equipment including steel 2010 structures (several lots). 3. Overhead line equipment IDA 15.0 ICB No No Prior November for upgrade and 2010 reinforcement of the Distribution network (several lots). 4. Substation Civil Works (3 IDA 3.0 NCB No No Prior December lots). 2010 5. Pre-payment meters. IDA 8.0 ICB No No Prior December 2012 6. Geothermal steam IDA & 147.0 ICB Yes No Prior February gathering and distribution KfW 2011 network (Lots A & B). 7. Olkaria I Power Plant. JICA 305.0 ICB Yes No Prior November 2010 8. Olkaria IV Power Plant. AFD & 340.0 ICB Yes No Prior November EIB 2010 9. Olkaria 1 & IV EIB 32.0 ICB Yes No Prior December Interconnection Lines and 2010 Substation. 10. EPC for construction of IDA 40.0 ICB No No Prior January 15, Kindaruma-Mwingi- 2011 Garissa 132 kV transmission line. 11. EPC for construction of IDA 8.5 ICB No No Prior March 15, Kisii-Awendo 132 KV 2011 lines and associated substations. 12. EPC for construction of IDA 12.0 ICB No No Prior March 15, Eldoret-Kitale 132 KV 2011 lines and associated substations. 13. EPC for the Construction IDA 11.2 ICB No No Prior April 2011 of 66/11 & 33/11 KV Substations in Nairobi Region. 14. EPC for the Construction IDA 5.2 ICB No No Prior May 2011 of 33/11 KV substations in the Coast Region. 15. EPC for the Construction IDA 11.4 ICB No No Prior June 2011 of 33/11 KV substations in the Mt. Kenya Region. 16. EPC for the Construction IDA 13.4 ICB No No Prior July 2011 of 33/11 KV substations in the West Region. 17. Supply and installation of IDA 3.9 ICB No No Prior May 2011 Grid Extension Lines (REA). 122 III. Selection of Consultants Prior Review Thresholds: Selection decisions subject to Prior Review by Bank as stated in Appendix 1 to the Guidelines Selection and Employment of Consultants: Selection Method Prior Review Threshold Comments*) 1. Competitive Methods (Firms) >=200,000 All Contracts 2. Single Source (Firms) All Values All Contracts 3. Consultants Individuals >=100,000 All Contracts *) TORs of all contracts shall be cleared with the Bank. 3. Short lists composed entirely of national consultants. Contracts for which shortlists may consist exclusively of local consultants pursuant to the provisions of paragraph 2.7 of the Consultants` Guidelines will be determined in the Procurement Plan based on their nature and availability of firms in the local market. 4. Any other special selection arrangements: N/A 5. List of Consulting Assignments with Short-List of International Firms: Description of Assignment Financier Cost Selection Review Expected Ref. estimate Method by Bank Proposals No. US$ (Prior / Submission million Post) Date 1. Design and Supervision Engineer for IDA 3.5 QCBS Prior July 30, 2010 Transmission component. 2. Design and Implementation support IDA 2.0 QCBS Prior November 2010 Engineer -- Substations -- KPLC. 3. Implementation Support consultant -- REA. IDA 2.0 QCBS Prior November 2010 4. Establishment of a wholesale electricity IDA 0.5 QCBS Prior November 2011 market. 5. Facilitating private sector participation in IDA 0.5 QCBS Prior March 2011 the electricity sector. 6. Electricity cost of service study. IDA 0.5 QCBS Prior June 2011 7. Materials and equipment supply chain IDA 0.2 QCBS Prior January 2011 study. 8. Risk management study for electricity IDA 0.5 QCBS Prior April 2011 sector. 9 Pre-feasibility and feasibility studies IDA 0.5 QCBS Prior February 2011 (several). 123 Annex 9: Economic and Financial Analysis KENYA: Electricity Expansion A. Economic Analyses Overview 1. The economic internal rate of return (EIRR) on the investment in each of the main components of the project -- generation, transmission and distribution, was assessed to establish the economic merit of the Project as a whole. The analysis followed the standard approach of comparison of the quantifiable economic costs and benefits expressed in constant base-year prices of early 2009. Key Assumptions for the Expansion of Electricity System Capacity 2. Economic growth. For the purpose of carrying out economic analysis of the Project, a base case GDP growth rate ranging from 5 percent in 2010 to about 8 percent in 2014 and 2015 has been assumed in projecting future electricity demand. Electricity consumption is assumed to have a GDP elasticity of 1.3 based on historical data. Thus, electricity demand in the interconnected system is projected to grow at about 6.5 percent in 2010 and reach 10.3 percent in 2013 and 2014. 3. Load forecast and capacity balance. Based on assumptions for economic growth, energy demand is projected to grow from 6,825 GWh in 2010 to about 10,576 GWh in 2015. Peak demand would be 1,955 MW in 2015. By 2011, the system will be constrained to meet demand due to inadequate generating capacity because the system reserve margin is estimated to be only 13 percent, well below the required 20 percent reserve margin that would assure security of supply. The addition of about 47 MW (net of retirements) in thermal and hydro plants in 2012, following the commissioning of the 35 MW Olkaria II Unit 3 geothermal plant in 2010, will provide temporary relief for one year. 4. Timing of capacity expansion. Additional generating capacity will be required in 2014, which coincides with the timing of the in-service date of the first units of the Olkaria I expansion and the new Olkaria VI power station under the Project. These plants would ensure that the demand would be met adequately and securely, and ensure system reserve margin of about 18 percent in 2014. However, in addition to generation capacity constructed under the Project additional capacity of about 400 MW (provided by generation plants currently in development (see Table 20 above in Annex 1) would need to be required to be in service in 2015 to enable adequate and secure supply. The electricity demand and supply balance for 2004 -- 2015 is provided in Annex 1. 124 Economic Analysis of the Generation Component Summary Results 5. Table 32 below summarizes the results of the economic analysis of the Generation Component. It has resulted in a Base Case Economic Internal Rate of Return (EIRR) of 23 percent and Net Present Value (NPV) of US$841 million. The use of lower discount rates of 10 percent and 8 percent would yield a higher NPV of 1,237 million and US$1,805 respectively. The analysis also tested sensitivity to key variables that could affect the EIRR: (a) a 20 percent real increase in the capital costs; (b) a 20 percent decline in output of the power stations; and (c) two years` construction delay. The estimated EIRR for each of these cases is above the estimated long-term opportunity cost of capital to Kenya of 12 percent. Even in the extreme case of simultaneous occurrence of these events, the EIRR is 13 percent, confirming the robustness of the economic merit of the generation component. Table 32: Results of EIRR Analysis for Generation Component Case Net Present Value EIRR ( %) (US$ million) Base Case: benefits valued at LRMC of generation (US$0.2064/kWh) 841 23 Sensitivity case 1: 20% real increase in capital costs 662 19 Sensitivity case 2: 20% decline in net energy sent out 481 19 Sensitivity case 3: 2 years` construction delay 575 19 Sensitivity case 4: combined impact of (1) 20% real capital cost increase; (2) 126 13 20% decline in sent out energy; (3) 2 years` construction delays 6. Table 33 below shows the detailed calculations for the base case EIRR on the Generation Component. 125 Table 33: Generation Component: Economic Cost-Benefit Analysis -- Base Case Capital Product- Sent Expend- Fixed ion Hot Cold Drill Variable Total out Total Net Year iture O&M Wells Wells Wells Rigs O&M Cost energy Value Benefit Benefit US$m US$m US$m US$m US$m US$m US$m US$m GWh US$m US$m US$m 2008 2009 0.0 0.0 2010 101.1 100.1 -100.1 2011 241.3 241.3 -241.3 2012 472.9 472.9 -472.9 2013 345.7 345.7 -345.7 2014 46.3 14.64 0.03 60.9 1028 0.21 216 154.9 2015 29.28 0 0 0 0 0.06 29.3 2057 0.21 424.5 395.2 2016 29.28 18.15 9.63 0 4 0.06 61.1 2057 0.21 424.5 363.4 2017 29.28 30.25 6.42 2.628 4 0.06 72.6 2057 0.21 424.5 351.9 2018 29.28 18.15 6.42 2.628 4 0.06 60.5 2057 0.21 424.5 364.0 2019 29.28 6.05 3.21 0 0.06 38.6 2057 0.21 424.5 385.9 2020 29.28 18.15 3.21 0 0.06 50.7 2057 0.21 424.5 373.8 2021 29.28 18.15 0 0 0.06 47.5 2057 0.21 424.5 377.0 2022 29.28 6.05 0 0 0.06 35.4 2057 0.21 424.5 389.1 2023 29.28 6.05 0 0 0.06 35.4 2057 0.21 424.5 389.1 2024 29.28 12.1 3.21 0 0.06 44.7 2057 0.21 424.5 379.9 2025 29.28 6.05 3.21 0 0.06 38.6 2057 0.21 424.5 385.9 2026 29.28 6.05 0 0.06 35.4 2057 0.21 424.5 389.1 2027 29.28 6.05 0 0.06 35.4 2057 0.21 424.5 389.1 2028 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 2029 29.28 6.05 0 0.06 35.4 2057 0.21 424.5 389.1 2030 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 2031 29.28 6.05 0 0.06 35.4 2057 0.21 424.5 389.1 2032 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 2033 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 2034 29.28 6.05 0 0.06 35.4 2057 0.21 424.5 389.1 2035 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 2036 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 2037 29.28 6.05 0 0.06 35.4 2057 0.21 424.5 389.1 2038 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 2039 29.28 0 0.06 29.3 2057 0.21 424.5 395.2 Net Present Value (NPV) at 12% discount rate: US$841 million. Economic Internal Rate of Return (EIRR): 23%. Key Assumptions 7. Least-Cost Expansion Plan. The long-term least-cost power generation expansion plan (LCPDP, December 2008) was prepared by the MoE and ERC in collaboration with the power utilities. The candidate generating plants and technologies considered for the inclusion in the plan were: (a) oil-fired thermal -- medium and high-speed diesels; (b) geothermal; (c) hydro power; (d) wind; (e) co-generation -- combined heat and power; and (f) coal-fired steam. Computer planning 126 models using long-term dynamic optimization methodology were applied to establish the long- term generating expansion program. 8. Analysis of alternative expansion paths. Comparative life-cycle cost analysis, based on the data used in the LCPDP to ensure consistency, shows the relative merits of the various feasible candidates considered for the LCPDP as shown in the table below. Candidate Plant and Technology Life-cycle cost (US$/kWh) Geothermal-Olkaria IV (140 MW) 0.092 Lake Turkana Wind Power (300 MW) 0.105 Coal-fired (3x100 MW) 0.128 Medium-Speed Diesel (6x15 MW) 0.149 Emergency High Speed Diesel 0.212 9. The above comparison confirms the expansion of the existing Olkaria I power station by 140 MW and the construction of the new Olkaria IV power station as the top priority developments. It also confirmed the Lake Turkana Wind Power as the next priority development in the expansion program. 10. Investment cost analysis. The total estimated cost of the generation investments in the Project is US$1.035 billion, including price and physical contingencies (total 20%), interest during construction (IDC) but excluding drilling. The economic analysis considered the base cost expressed in early 2009 prices plus a 10 percent physical contingency allowance, excluding price contingency and IDC but including drilling. The cost components considered for the economic analysis are as follows: Component Estimated economic cost (US$ million) *) Drilling of steam wells 300.9 Steam field development 147.4 Power plants 645.0 Substations and high voltage transmission 31.9 Consultancy for Engineering, Procurement and Supervision of 30.0 Construction Owner`s Cost ( Administration) 41.0 Resettlement and Compensation 10.0 Total US$1.206 billion *) Includes wells to be drilled. 11. Expenditure for construction, used in the economic analysis, were estimated to begin in 2010 and end in 2014, with full commissioning of the two power stations, Olkaria I expansion (140 MW) and Olkaria IV (140 MW), and the associated infrastructure. The first full year operation of the two power stations is assumed for the purposes of the economic analysis to begin in 2015. 12. Annual operating and maintenance (O & M) costs include: (a) fixed operation and maintenance at 3.5 percent of total capital cost excluding drilling, consultancy, owner`s cost, and resettlement; (b) variable O & M costs at US$60,000, based on the actual variable O & M costs of the existing geothermal stations; and (c) expenditure required to replenish steam wells -- both production and hot and cold water reinjection wells -- and related rig mobilization costs, as shown below: 127 Type of well Cost Make-up Production Wells US$6.05 million/well Hot Water Reinjection Wells US$3.21 million/year Cold Water Reinjection Wells US$ 2.628 million/year Drilling Rig Mobilization US$4 million/year 13. The estimated output of the power stations is based on the following assumed operating parameters: Parameter Value Total Installed Nameplate Capacity 280 MW Availability Factor. 90.6% (based on (i) planned and unplanned outage of 6% of 365 days (approx. 22 days); (ii) 60 days for 5-yearly overhaul for long-term average of 12 days per year. Total availability factor of (365-22- 12)/365* 100 = 90.6%. Estimate of Availability Factor Long-Term 253.68 MW [(280*0.906) =253.68 MW]. Average Available capacity of Power Station. Load Factor. 0.925% (feasibility study). Gross Energy Generation. 2155.56 GWh [253.68*0.97 * 8760 = 2155.56 GWh]. Auxiliary electricity consumption at power 4.58% of energy gross generation (estimated). stations. Net sent out energy. 2056.8 GWh [2155.56 GWh *0.9542 = 2056.8 GWh]. 14. Benefits Estimation. The benefits of the Generation Component are the net energy sent out to the transmission system, valued at estimated long-run marginal cost of electricity generation of US$0.2064/kWh (based on the LCPDP). On this basis, the total annual benefits are: 2,056.8 GWh*$0.2064/kWh = US$424.52 million. Economic Analysis of the Transmission Component Summary Results 15. The results of the economic analysis, shown in the table below, indicate a robust EIRR of about 32 percent for the Base Case, declining slightly to 27 percent when estimated benefits are reduced by 20 percent. However, these estimates are substantially above the cost of capital to Kenya, estimated at 12 percent. Table 34 below shows the summary of the EIRR calculation and Table 35 provides the details of calculation. Table 34: Economic Costs for Transmission Component Scenario Net Present Value EIRR (%) (US$ million) Base Case 182.4 32 Sensitivity case 1: 20% reduction in expected benefits 135.9 27 128 Key Assumptions 16. The following parameters were assumed for the purpose of the economic analysis: Economic costs: (a) Total capital cost of transmission lines, substation, (a) US$58.2 million, including physical contingencies but and consulting services; and excluding price contingencies; (b) Annual fixed operation and maintenance cost. (b) 2% of total capital costs. Benefits: (c) Incremental energy savings through improved (c) US$0.84/kWh. reliability from reduced supply outages valued at the cost of un-served energy to the economy; and (d) Valued at LRMC of generation plus incremental (d) Incremental energy made available through transmission cost of US$0.01/ kWh (total improved power transfer capability. US$0.2164/kWh) as a reflection of willingness-to-pay. Economic life: 40 years. Economic operating life of transmission lines and substations. 129 Table 35: Transmission Component -- Economic Cost-Benefit Analysis -- Base Case Costs (US$ million) Economic Benefits (US$ million) Design & Super- Trans- vision Kisii- Eldoret- Kindaruma mission Sub- Consult Fixed Total Awend Kitale -Mwingi- Total Net Year Lines stations -ant O&M Cost o line line Garissa line Benefits Benefits 2011 3.5 1.85 1 6.35 -6.35 2012 17.6 9.25 1.5 28.35 -28.35 2013 10.56 5.55 1 17.11 -17.11 2014 3.5 1.85 1 0.54 6.89 2.5 4.8 6.6 13.9 7.1 2015 1.07 1.07 2.9 5.9 7.3 16.1 15.0 2016 1.07 1.07 3.4 7.1 8.1 18.5 17.4 2917 1.07 1.07 4.0 8.3 8.9 21.2 20.1 2018 1.07 1.07 4.4 9.7 9.9 24.0 23.0 2019 1.07 1.07 4.9 11.3 10.8 27.1 26.0 2020 1.07 1.07 5.2 12.9 11.8 30.0 28.9 2021 1.07 1.07 5.8 14.7 12.9 33.4 32.3 2022 1.07 1.07 6.4 16.6 14.0 37.0 36.0 2023 1.07 1.07 7.0 18.7 15.2 40.9 39.8 2024 1.07 1.07 7.6 20.9 16.5 45.0 43.9 2025 1.07 1.07 8.2 23.4 17.9 49.5 48.4 2026 1.07 1.07 8.8 26.0 19.4 54.2 53.2 2027 1.07 1.07 9.5 28.9 21.0 59.3 58.3 2028 1.07 1.07 10.1 32.1 22.6 64.8 63.7 2029 1.07 1.07 10.7 35.5 24.4 70.7 69.6 2030 1.07 1.07 11.3 39.2 26.4 76.9 75.8 2031 1.07 1.07 11.9 43.3 28.4 83.6 82.6 2032 1.07 1.07 12.5 47.9 30.6 91.1 90.0 2034 1.07 1.07 13.1 52.5 33.0 98.6 97.6 2035 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2036 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2037 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2038 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2039 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2040 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2041 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2042 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2043 1.07 1.07 13.8 52.5 33.0 99.3 98.2 4044 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2045 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2046 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2047 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2048 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2049 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2050 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2051 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2052 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2053 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2054 1.07 1.07 13.8 52.5 33.0 99.3 98.2 2055 1.07 1.07 13.8 52.5 33.0 99.3 98.2 Net Present Value (NPV) at 12% Discount Rate: US$182.43 million. Economic Internal Rate of Return (EIRR): 32%. 130 Economic Analysis of the Distribution Component Summary Results 17. The economic analysis evaluates the joint contribution of the four distribution subcomponents to the overall component`s target of connecting 300,000 connections in urban, peri-urban and rural areas. It was assumed that out of 300,000 new connections, 270,000 will be urban and peri-urban (of which 50,000 are expected to be in slum areas), and 30,000 will be rural customers. Based on the demand surveys, it was also assumed that 10 percent of all connections would be business/institutional customers. The EIRR amounted to 21.1 percent and the Economic Net Present Value (NPV) to US$93.5 million (at 12% discount rate) as shown in Table 36 below. Table 36: Economic Analysis Distribution Component Economic Analysis: Determination of the Cost and Benefit of Connection of new Customers Cost ­ Components Total Benefits Difference: T&D O&M Year Investment Cost of losses Costs Cost Loss Willingness savings Benefits - Cost Energy to pay (substations) Costs (Million (Million (Million (Million (Million (Million US$) US$) US$) US$) US$) (Million US$) US$) 2011 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2012 46.44 0.00 0.00 0.00 46.44 0.00 0.00 -46.44 2013 69.66 6.59 1.16 4.64 82.06 20.48 4.61 -56.97 2014 92.88 16.62 2.93 11.61 124.03 51.60 5.18 -67.25 2015 69.66 30.14 5.32 20.90 126.01 93.59 5.82 -26.60 2016 0.00 40.63 7.17 27.86 75.66 126.18 6.53 57.05 2017 0.00 41.44 7.31 27.86 76.62 128.71 7.34 59.43 2018 0.00 42.27 7.46 27.86 77.59 131.28 8.25 61.94 2019 0.00 43.12 7.61 27.86 78.59 133.91 9.27 64.59 2020 0.00 43.98 7.76 27.86 79.60 136.58 10.42 67.40 2021 0.00 44.86 7.92 27.86 80.64 139.32 11.70 70.38 2022 0.00 45.76 8.07 27.86 81.69 142.10 13.15 73.56 2023 0.00 46.67 8.24 27.86 82.77 144.94 14.77 76.95 2024 0.00 47.60 8.40 27.86 83.87 147.84 16.60 80.58 2025 0.00 48.56 8.57 27.86 84.99 150.80 18.65 84.46 2026 0.00 49.53 8.74 27.86 86.13 153.82 20.96 88.64 Economic Internal Rate of Return (EIRR): 21.1%. Economic Net Present Value (NPV) to US$93.5 million (at 12% discount rate). Key Assumptions 18. Methodology. The economic analysis follows a consumer surplus methodology commonly used in electrification projects. The following explanation of the methodology draws on IEG`s evaluation report of rural electrification.34 The methodology, illustrated by Figure 5: Illustration of Consumer Surplus Method Calculation, uses demand curves to estimate the increase 34 The Welfare Impact of Rural Electrification: a reassessment of the costs and benefits -- an EIG Impact Evaluation, World Bank, Independent Evaluation Group, 2008. 131 in consumer surplus, which results from the increase in the energy consumption at lower price, following electrification. 19. The amount the consumer is willing to pay for a quantity Q is the area under the demand curve from 0 to Q. Hence the consumer is willing to pay A+B+D for consumption Q0 but actually pays B+D (=P0*Q0), leaving a consumer surplus of A. Once electricity becomes available, the consumer surplus is A+B+C, so the increase in consumer surplus, as a result of electrification, is B+C. This consumer surplus has two parts: that arising from the reduction in the price of the Q0 units already being consumed and that associated with the new consumption Q1-Q0. 20. The benefit to the consumer is B+C. The area D+E is what consumer pays for the new consumption of electricity. This area also equals to the cost of production + producer surplus. The area D+E is also often included in the economic benefits, which is acceptable as long as it is also reflected in the cost side of the analysis. In that case D+E is simply a transfer payment from the customer to the utility and therefore a neutral flow for economic analysis. The present economic analysis integrates D+E in both benefit and cost calculations.35 Figure 5: Illustration of Consumer Surplus Method Calculation 21. The value of area C depends on the shape of the demand curve. The simplest assumption is a linear demand curve (a straight line) between the two observed points. But if the demand curve is convex to the origin, as theory suggests, then the linear demand curve overestimates the amount of consumer surplus. It is therefore recommended to use a constant elasticity (log linear) curve. Alternatively, it is possible to assume only a fraction of linear demand curve consumer surplus estimate. The present analysis uses a linear demand curve for simplicity, but considers only 1/3 of the consumer surplus benefits derived from this linear curve. 22. Data. The willingness of non-electrified households to pay for electricity is derived from household surveys. The data is primarily derived from a recent socio-economic study carried out in 2008 for Kenya`s Rural Electrification Masterplan (REMP), based on a survey of 1,776 households. The result of the survey is that about 11 percent of the available household budget 35 The alternative is to deduct the payments (D+E) from consumers but then add them to producers, so when summing across all flows, these payments/receipts cancel out. 132 was paid for energy. On average, non-electrified households of the sample pay 2,033 KSh per month (US$26.75) for energy, of which KSh 1,128 (US$15) are electricity substitutable expenditures for kerosene, diesel, candles and batteries. 23. KPLC in 2006, conducted surveys in peri-urban areas in preparation for the company`s new connection policy. These surveys covered 800 households and small enterprises in these areas, including slums. The KPLC surveys arrive at a very similar willingness to pay for peri- urban customers -- KSh 1,200 (US$15.7) for households in regular peri-urban areas, and KSh 1,164 (US$15.3) in slum areas. WTP of small businesses is somewhat higher -- about KSh 1,300 (US$17). The consumption Q0 of non-electrified households is estimated by REMP at US$27.9 kWh/month. This consumption is derived from the survey`s information on household appliances and their usage. The present economic analysis therefore uses the kWh as a common consumption denominator. It would be more precise to calculate, separately, benefits for different final uses -- light, audio-visual appliances etc. However, this is not considered practical, due to the high diversity of electricity use, particularly by peri-urban households (light, audio-visual appliances, small domestic appliances etc.). 24. The consumption Q1 of electrified households is estimated based on KPLC data for electrified customers. The consumption is estimated based on the current consumption averages for different customer categories, and the expected distribution among these categories. The expected average peri-urban consumption is 143 kWh/month, while an expected rural average consumption is 94 kWh/month. 25. Limitations of the analysis. The calculation covers only benefits derived from the increased consumer surplus of electrified households. There are additional benefits, which the analysis does not capture, including improved education (both through electrification of schools and availability of light for students to read at night), health services (electrification of health clinics), productive uses (electrification of agri-businesses, and market centers). As these benefits are more difficult to quantify and objectively verify, they are not included in the present analysis. The economic internal rate of return (EIRR) is therefore likely to be underestimated. 26. Consumer demand curves. From available data, demand curves were derived for peri- urban and rural customers separately, to reflect different consumption patterns. The curves are included below. Linear curves are assumed, but only 1/3 of consumer surplus (triangle C) is included in benefits to compensate for the more probable convex shape of the demand curve. 133 Figure 6: Demand Curves of Peri-urban and Rural Consumers US$ Demand curve peri-urban consumers US$ Demand curve rural consumers 0.70 0.70 0.60 0.60 0.50 0.50 0.40 0.40 y = -0.0036x + 0.62 y = -0.0078x + 0.7402 0.30 0.30 0.20 0.20 0.10 0.10 0.00 kWh 0.00 kWh 0.00 50.00 100.00 150.00 0.00 20.00 40.00 60.00 80.00 100.00 27. Consumer Benefits were calculated separately for peri-urban and for rural customers, per methodology described above. The calculation results in annual benefits of US$422 for peri-urban and US$318 for rural customers (areas A+B+C+D). Table 37: Consumer Benefits for Distribution Component Benefits Peri-urban (US$) Rural (US$) All (US$) Area B+D (original expenditures) US$/month 14.8 14.8 Area C (consumer surplus) US$/month 7.76 4.5 Area E (new consumption) US$/month 12.6 7.2 Total net benefits US$/month 35.2 26.5 34.3 Total net benefits US$/year 422.0 318.0 411.8 Source: World Bank estimates 28. Benefits of reduced losses. In addition to facilitating the connection of new customers, the proposed investments will also have additional benefits of reducing technical losses. KPLC has calculated the loss reduction benefits derived from the upgrading of the sub-stations, financed by the project. These loss savings benefits were therefore added to the consumer benefits. 29. Costs. Costs include both investment and recurrent costs. Table 38 shows the investment costs. Table 38: Investment Costs for Distribution Component Investment costs US$ million Costs total 256.5 Grid upgrade and extension 113.5 User connection costs, urban and rural customers 90.2 User connection costs, slums 0.8 Slum electrification 16.0 Rural electrification grid extensions and connection of priority loads 36.0 Source KPLC and World Bank estimates 134 30. Recurrent costs include the cost of electricity generation to serve the new connections, transmission losses, and O & M costs. 31. Other key assumptions. The table below includes key data and assumptions used for EIRR calculations. Table 39: Assumptions for Economic Analysis of Distribution Component Parameter Value WTP non-electrified households 1,128 KSh/month kWh consumption equivalent -- non-electrified customers 29 kWh WTP per kWh non-electrified 39 KSh/kWh Average tariff for electrified households (includes social tariff customers) 0.11$/ kWh Peri-urban average consumption for electrified customers 143 kWh Rural average consumption for electrified customers 94 kWh Energy cost of KPLC (projection for FY2010) 0.08 $/kWh Annual increase of energy demand per customer 2% Energy system losses 15% O & M costs 10% Exchange rate (March 17, 2010) 76.6 KSh/US$ Connection fee -- urban and rural customers 457 US$ Connection fee slums 15 US$ Source: World Bank. 32. Sensitivity Analysis. The Project`s appraisal conducted this analysis for the following scenarios: (a) increase in investment costs by 20 percent; (b) overestimation of WTP of non- electrified customers by 20 percent; and (c) overestimation of consumption of electrified households by 20 percent. Table 40 summarizes the results. In all cases, the project yields acceptable EIRRs and positive NPVs (at 12% discount rate). Only in the combined scenario of all three occurrences, the EIRR is reduced to 4.8 percent. As noted above, this EIRR does not include additional electrification benefits, which are difficult to quantify, such as from improved provision of education and health services and improved productivity. Table 40: Sensitivity Analysis for Distribution Component Scenario EIRR (%) 1. 20% increase in investment costs 14.8 2. WTP of non-electrified households reduced by 20% 13.5 3. Consumption of electrified households reduced by 20% 17.6 4. All three scenarios above combined 4.8 135 B. Financial Analyses Summary of Findings 33. Kenya`s electricity sector overall is in good financial condition, evident in the financial statements of KenGen and KPLC. Over the past five years, both companies have generated sustained profits and cash-flows, maintained adequate liquidity and cash reserves as well as manageable levels of debt. This profitability, in large measure, is due to major Bank-supported reforms in the power sector since 2004, especially tariff regulation designed to support efficient utility operations. Both companies, as implementing agencies under the ongoing, Bank-financed ESRP, have complied with the project`s financial covenants. As publicly listed companies, the transparency of their operations has improved, as both KenGen and KPLC are required to produce regular financial reports for their investors. Due to Kenya`s major investment needs in the power sector to meet expected electricity demand, both KenGen and KPLC face the challenge of maintaining profitable operations as they become significantly more leveraged in the future. The two companies have recently taken steps to strengthen their balance sheets to facilitate the financing of their investment programs. 34. The financial forecast for both companies between 2010 and 2014, which coincides with the project`s implementation period, shows that both companies will remain profitable despite taking on increased debt to finance power system expansion. KenGen`s current ratio is projected to decline from 2.7 to 1.3 and then to increase due to the cash-flow from new generation investments. Its debt service ratio (DSCR) would also decrease from current level (2.2) to a minimum of 1.3. KPLC is expected to improve its liquidity due to a capital increase later this calendar year thereby improving its current ratio to a comfortable level of 2.1. In spite of its investment program, KPLC is expected to maintain a DSCR of 1.4 or above throughout the forecast period. Given that both companies are generating cash-flows that are secured by existing tariff regulation, their forecast financial ratios can be considered as healthy. 35. The following sections discuss the detailed findings on the sector context of the investment program, the historical performance of KenGen and KPLC, and results, along with key assumptions, of the projected financial statements for 2010 -- 2014. Sector Context 36. Resilience to External Shocks. The financial viability of the Kenyan power sector stands in contrast with the situation of many other SSA countries. Investments and access to electricity have increased at a significant pace over the last few years overcoming challenges arising from high international oil prices that have had a large impact on thermal generation costs, and from drought conditions that reduced output of low-cost electricity from hydro generation. This resilience compares favorably with what happened during a previous drought that caused a power supply crisis in 1999/2000. This crisis led to financial distress for the sector including four consecutive years of heavy losses for KPLC from 1999 to 2002 leading to its financial rescue by the Government in 2003. 136 37. Sector Regulation. The Energy Act of 2006 created the Energy Regulatory Commission (ERC). ERC was the successor to another previous regulatory body (the Electricity Regulatory Board). The Commission started therefore with a preexisting regulatory experience in the electricity sector. Its authority extends to other energy sub-sectors including oil products. In the electricity sector, ERC is responsible for the licensing of operators, the setting of technical standards, and tariff setting. In this respect, the general principle affirmed by the 2006 Energy Act is that tariff must be just and reasonable so as to enable a licensee to maintain its financial integrity, attract capital and operate efficiently. 38. Financial Structure of the Power Companies. Both KenGen and KPLC have private investors in their capital, and are listed on the Nairobi Stock exchange, with the Government retaining a majority ownership. The Initial Public Offering for KenGen, which took place in 2006, has been considered a success and resulted in 30 percent of the company`s equity in the private holding. KPLC shares are less actively traded. While a majority of KPLC ordinary shares are held by private investors, the Government owns most of the equity in the company, under the form of preferred shares, which it received as a result of its capital injection in KPLC in 2003. Preferred shares are entitled to an annual statutory dividend of 7.85 percent when the company reaches a certain level of profitability (which it did in FY2009). The Government has recently announced its intention to convert most of the preferred shares to ordinary shares. In addition, in order to further maintain KPLC equity levels, new ordinary shares will be issued and offered to investors with the Government renouncing its preferential subscription rights. 39. Corporate Transparency. As publicly listed companies, KenGen and KPLC have to produce regular financial reports for their investors. Both companies publish interim results (every six months) in addition to their annual financial statements. With regard to financial reporting and disclosure, the companies are under the supervision of the Capital Market Authority. KenGen issued a ten year Public Infrastructure Bond in September 2009. The public offering had to receive the prior approval of the Capital Markets Authority. The prospectus released for the public offering, and prepared with the assistance of external advisors (audit and legal firms) contains detailed technical information, income statement and cash-flow projections, projections for tariff revenues, description of power purchase agreements, analysis of assets and asset revaluation, and risk factors. As part of its planned capital restructuring, KPLC will issue extra shares, and will also be required to release a prospectus for investors. Overall, the partial privatization of KenGen and KPLC and their listing on the local stock market have had a positive impact on sector governance and transparency. In addition to the direct impact on the governance and reporting practices of the two companies, the local shareholders ensure scrutiny of decisions made by the authorities (Government, ERC) that impact on the utilities` financial performance. 40. Creation of a Transmission Company. The Government has recently created a transmission company, KETRACO. In the next few years, KETRACO is likely to remain purely an asset holding company, which will own the new transmission assets in Kenya (including the investments supported by the Project). The maintenance and operation of the assets would be assured by KPLC. The longer-term plan for KETRACO is to transform the company into a fully- fledged Transmission System Operator. The indicative timetable for this transition is five to seven years (and therefore beyond the horizon of this financial analysis). 137 41. Regulation of Retail Electricity Tariffs. Current retail tariff regulation (KPLC tariffs) has been in place since July 2008. The detailed mechanisms were drawn up following a (Bank- financed) tariff study. A key feature is the automatic pass-through on a monthly basis, of generation related fuel costs, as well as of adjustments for exchange rate depreciation. In addition, adjustments for inflation take place every six months. The annual tariff revision also takes into account the target for annual distribution losses. This system has the features of a price-cap: tariffs are based on a formula defined ex ante. KPLC has a strong incentive to improve its performance between tariff reviews. Any cost reduction or increase in sales will directly improve KPLC`s operating income. At the same time, the tariff mechanisms adequately protect the company from most of the major risks it cannot control (variation in the cost of generation and exchange rate). This leaves however some significant risk exposure for KPLC. The indexing of local cost inflation is only partial thus exposing KPLC to changes in the inflation rate. More importantly, KPLC is exposed to the demand risk, which would not necessarily be the case with a revenue-cap system. Because of this exposure to the volume of energy sold, the effect on consumer demand of macroeconomic factors such as oil price or economic growth has an impact on KPLC. The company is also exposed to sector-specific risks, in particular to the availability of generation to meet demand. The current situation in which there is significant un-served demand is penalizing KPLC. 42. Assessment and Outlook for Retail Electricity Tariffs. Overall, the current tariff mechanisms appear to have worked well. They have effectively protected KPLC`s financial viability in a context of stress (drought, high oil prices) while creating adequate incentives for the company to reduce its own costs and enhance its commercial performance. It is also in KPLC`s interest to source bulk power supply efficiently (in terms of cost and availability). The periodicity of tariff reviews (every three years) appears optimum given the characteristics of the Kenyan power sector. The five-year periodicity for tariff reviews which is practiced in many developed countries would be excessive for a utility that is undertaking significant investments, expanding its customer base at a rapid rate, and operating in a less predictable environment than mature distribution utilities in industrialized countries. The next tariff revision is scheduled to take effect in July 2011. ERC has indicated that, following this revision, which will focus on tariff level adjustment, it will conduct a cost of service study in order to reexamine tariff structures. The Project will finance this cost of service study. 43. Price Regulation for KenGen. Long-term power purchase agreements (PPAs) with KPLC determine the company`s prices. The PPAs related to existing generation assets were signed and approved by ERC in June 2009. Under the earlier pricing structure, KenGen remuneration was entirely based on the volume of energy generated. Under the new PPAs, KenGen remuneration has three main components: the capital recovery charge (CRC), the fixed operation and maintenance charge (FOMCR), and the variable operation and maintenance charge (VOMCR). KenGen is entitled to receive the first two components in full as long as it meets the contractual target for generating plant availability. Only the VOMCR component is based on the volume of power generated. In addition, for thermal generation plants, fuel costs are automatically passed through. 44. The pricing structure reflects KenGen`s underlying costs. It is similar to the pricing formulas of PPAs with Independent Power Producers (IPP). The structure provides incentives for KenGen to maximize the availability of its generation plants and reduce operating costs. This 138 structure, which remunerates KenGen on a plant by plant basis, is also consistent with the fact that KenGen does not determine dispatch of its generation plants. KPLC is responsible for generation dispatching. The term of each PPA is variable and depends on the generation technology as well as the age of the plants concerned (20 years for hydro plants and recent geothermal plants, 15 years for recent diesel-fired plants, and 5 years for Kipevu gas turbine plant). 45. Under the existing PPAs, KenGen still bears some exposure to hydrological risks, which it cannot control. Below a certain level of rainfall, hydro plants are not able to meet their availability targets. The drought situation has negatively impacted KenGen`s financial performance in FY 2009 and is likely to also have a significant impact in FY2010. KenGen would like to reduce its exposure to the hydrological risk and it plans a study will examine this issue. 46. New Generation Projects. New PPAs, to be negotiated according to the same general principles as existing agreements, will cover new generation plants. The pricing structure for KenGen generation is similar to the structure of power purchase agreements concluded by KPLC with Independent Power Producers (IPPs). One significant difference, however, is the currency denomination. Contracts with IPPs are denominated in foreign currency (US$). In contrast, KenGen`s PPAs are in Kenya shillings with an adjustment for the depreciation of the shilling against foreign currency. The foreign exchange pass-through mechanisms appear adequate to allow KenGen to cover the debt service and O & M costs denominated in foreign currency. However, the indexing mechanisms for inflation in contracts with IPPs are more favorable than the mechanism applied in KenGen`s PPAs. The indexing for local inflation in KenGen`s PPA is only partial (50%). For long-term PPAs, this mechanism could weaken KenGen`s ability to cover its costs in case of accelerated domestic inflation. It would be advisable to examine this issue, at least for future PPAs. 47. Challenges for the Future. The Kenyan power sector will require a significant increase in investments in order to meet expected growth in demand and the two utilities inevitably will become more leveraged. There is a clear need to increase generation capacity. KenGen, while profitable, has a low return on assets largely below the weighted average cost of capital (WACC) for private sector investments in generation. Power purchase agreements for new generation projects will allow KenGen to cover its cost of capital and earn a 15 percent post-tax return on equity in local currency when the company meets its performance targets. Levels of return on assets and equity are currently higher for KPLC than for KenGen. However, with the extension of its customer base, KPLC is experiencing a shift towards less profitable customers (i.e. domestic users, with lower consumption, a less favorable load profile, and situated in areas costlier to serve). The trends that have supported KPLC`s recent financial performance (reduced distribution losses and increased productivity) could be more difficult to sustain under these circumstances. 48. Overall, the cost-of-capital component of electricity tariffs for generation and for network assets will have to increase if the power sector is to remain financially viable. However, a reduction in fuel costs (in tandem with the scale-up of geothermal generation) and efficiency gains to reduce operating expenses could help mitigate the impact of higher investment costs. 49. Strong Development Partner Support for Sector Expansion. The Kenyan authorities have taken steps to address the financial challenges that the sector is facing (i.e. KPLC`s financial restructuring and revised power purchase agreements that allow higher return for KenGen). 139 Nevertheless, it would not be realistic to expect private sector investment to fill the entire financing gap of the sector without very significant increases in electricity tariffs, which would not be socially and politically sustainable. Consequently, there is a strong justification for concessional financing of the scale-up program for electricity access. 50. Under current regulatory mechanisms, the concessional funding of power sector investments will have a direct beneficial impact on electricity tariffs. For KenGen, the actual cost of the financial debt incurred for a project is reflected in its PPA prices. Regarding electricity distribution, the next KPLC tariff revision, scheduled for June 2011, will take into account the cost of debt incurred for new projects. Transmission investments will not be included in KPLC`s asset base, following their transfer to KETRACO, and thus will not have an impact on tariffs. Financial Analysis of KPLC and KenGen 51. Solid Financial Situation of Both Companies. KenGen and KPLC have released audited financial statements for FY2009 (ending in June 30, 2009), which confirm their solid financial situation. The analysis of the financial statements of both companies for the last five years demonstrates that both utilities have been consistently profitable, generating generate significant free-cash flows. The utilities have been able to improve their operational performance and currently are not highly leveraged and clearly able to service their financial debt. Furthermore, both companies are in overall compliance with their financial targets. KPLC's Recent Financial Performance 52. Over a six-year period (FY2004 to FY2009), KPLC has been able to increase its profitability, improve its operational performance, expand its customer base and maintain a healthy financial position as shown in Table 41 below. 140 Table 41: KPLC Income Statement, FY2004 -- FY2009 Income Statement FY 2004 FY 2005 FY 2006 FY 2007 FY 2008 FY 2009 2004- 2009 evolution KSh million Sales (GWh) 4,090 4,379 4,580 5,065 5,322 5,432 33% Operating Revenue Electricity sales excl. fuel 20,303 21,755 22,494 24,436 36,909 41,451 104% Fuel cost recovery 3,020 6,586 11,473 13,508 16,433 28,269 836% Other income 543 672 989 501 966 1,154 Total operating revenue 23,866 29,013 34,955 38,445 41,767 66,363 178% Operating Expenses Power purchase costs 12,665 11,767 11,570 12,102 11,963 18,770 48% Fuel costs 2,874 6,592 11,906 14,010 16,666 28,348 886% Distribution, customer services 4,348 4,808 5,012 4,531 3,974 6,541 50% Energy transmission 956 1,000 1,166 1,398 1,484 1,483 55% Administration 2,166 3,005 3,095 4,022 4,158 5,547 156% Total Expenses 23,010 27,172 32,750 36,063 38,245 60,688 164% Operating Profit 856 1,841 2,206 2,382 3,522 5,675 563% Operating margin 3.6% 6.3% 6.3% 6.2% 8.4% 8.6% Net finance income (costs) 18 138 292 266 (719) (758) Profit Before Tax 874 1,979 2,498 2,649 2,738 4,782 447% - - - - Income tax expense 416 - 709 - 854 930 973 156 Net Profit 458 1,270 1,644 1,718 1,765 4,627 911% Net margin 1.9% 4.4% 4.7% 4.5% 4.2% 7.0% 53. Between 2004 to 2009, KPLC operating revenues have increased by 178 percent due to: An increase in the volume of energy sold of 31percent (representing an annual average growth of 5.5%); and An increase in the nominal average tariff per kWh of 117 percent (47% in real terms). 54. For FY2009, the average tariff per kWh was 12.9 KSh (about 16 US cents). Most of the real tariff increase between FY2004 to FY2009 is attributable to a pass through to customers, of increased bulk power purchase costs, which have been driven higher by fuel costs. Fuel costs represented 60 percent of KPLC bulk supply costs in FY2009 compared to only 18 percent five years earlier. Bulk power supply costs are the major operating expense for KPLC. The company`s distribution service charge (the difference between tariff revenues and power purchase costs) represented only about 25 percent of end-user tariffs in 2009. Due to an effective pass-through mechanism to end-users, the international increase in the cost of fuel has not adversely affected KPLC significantly. Throughout the period, the fuel-cost recovery revenues received from customers have adequately reflected fuel costs. In parallel, KPLC has managed a slight reduction in its distribution costs per kWh (in real terms). As a result, between 2004 and 2009, KPLC`s operating margin (Operating Income/Operating Revenue) rose significantly. This combination of 141 increased revenue with improved profitability explains the 563 percent increase in the operating income. 55. While the tariff-setting mechanisms have been effective in protecting KPLC from variations in bulk supply costs outside its control, they are not the major factor behind KPLC`s increased profitability. As shown in Table 42 below, the average distribution service charge per kWh -- the portion of retail tariff that the distributor retains after power purchase costs -- actually declined in real terms between FY2004 and FY2008. Throughout the period, KPLC has improved its efficiency, as demonstrated by several performance indicators: Distribution losses. After a slight increase between 2004 and 2006, losses declined significantly between 2007 and 2009. The level of distribution losses for 2009 (16.3%) places KPLC among the best performing power distribution utilities in Sub-Saharan Africa. Revenue collection is satisfactory. The average collection time in 2009 was well below the target of 60 days (currently at 47 days); and Labor productivity, as measured by the ratio of customers per employee, or by sales per employee, improved significantly between 2004 and 2009. However, the ratio of customer per employee (181 in 2009) indicates significant scope for further improvement. Table 42: KPLC Technical and Commercial Performance Indicators, FY2004 -- FY2009 KPLC - Technical and Commercial indicators FY2004 FY2005 FY2006 FY2007 FY2008 FY2009 Commercial indicators Sales (GWh) 4,090 4,379 4,580 5,065 5,322 5,432 Average nominal tariff (KSh/kWh) 5.9 6.7 7.7 8.0 8.1 12.9 Average nominal tariff (US cents/kWh) 7.7 8.6 10.2 11.3 12.3 16.1 Average real distribution service charge (KSh/kWh)* 1.9 2.1 1.9 1.7 1.6 2.2 Technical indicators Distribution losses 18.8% 18.1% 19.6% 17.9% 16.6% 16.3% Customers/employees ratio 111 120 129 144 159 181 Sales (KWh) per employee 634 688 717 753 762 739 Number of customers (thousands) 686 735 802 924 1060 1267 * June 2003 price level 56. KPLC has improved its profitability in parallel with a steady improvement in electricity access. The number of customers (including rural electrification) increased by more than 13 percent per year on average between 2004 and 2009. Investments also increased significantly since 2006, leading to an increase in financial leverage, which, nevertheless, remains at a reasonable level. 57. Based on the latest financial statement (for FY2009 ending on June 30, 2009), KPLC is comfortably in compliance with the financial covenants for the ongoing Energy Sector Recovery Project. The Debt Service Coverage Ratio (DSCR) and the Self Financing Ratio are well above 142 the targets. The only exception is the Current Ratio, which at 0.9 is slightly below the 1.0 target. This indicator is the ratio of current assets to current liability and is a measure of the company's ability to pay back its short-term liabilities (debt and payables) with its short-term assets (cash, inventory, receivables). In this particular case, the low value of the ratio does not indicate that the utility is in a situation of financial distress. First, the value of the ratio is paradoxically depressed by KPLC`s good performance at reducing customer receivables. Second, KPLC`s operations generate significant free cash flows, which are protected by the pass-through mechanisms in tariff regulation. In addition, KPLC`s solvency would allow the company to negotiate short-term loans. At the same time, reinforcing KPLC cash position to increase its financial flexibility would be desirable and should take place as a result of the planned financial restructuring. Table 43: KPLC's Financial Performance Indicators, FY2004 -- FY2009 Financial Ratios Target FY2004 FY2005 FY2006 FY2007 FY2008 FY2009 Value in ESRP Debt Service Coverage 1.2 8.6 3.3 6.8 4.1 5.3 Current Ratio 1.0 1.6 1.5 1.1 1.2 0.9 Self Financing Ratio 25% 170% 23% 54% 161% Other financial performance indicators Leverage (debt/debt+equity) 21% 16% 13% 24% 38% 41% ROA 4.2% 8.3% 10.1% 10.5% 12.5% 14.5% ROE (Net profit to Equity) 10.4% 7.2% 8.7% 8.4% 8.0% 19.5% 58. KPLC`s return on assets reached 14.5 percent in 2009 compared to 4.2 percent five years earlier. This level of profitability is high for a public power distribution utility, especially compared to the majority of power utilities in Sub-Saharan Africa, which have seen increases in oil prices erode their profitability during the past decade. However, this level of profitability is not excessive considered in the context of interest rates for private sector borrowing in Kenyan shillings. KPLC Financial Outlook (2010 -- 2014) 59. The Bank has reviewed KPLC`s financial outlook in detail and has found it satisfactory. The key financial indicators show that the company will maintain profitability during the period of the Project. The Government and KPLC have requested that the forecast not appear in the PAD. However, the full financial evaluation of the company, including the forecast, is available in the project files. 143 Table 44: KPLC Performance Indicators, Forecast FY2010 -- FY2014 FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 Actual Forecast Forecast Forecast Forecast Forecast Financial Ratios Debt Service Coverage 5.3 5.2 3.5 2.5 1.6 1.4 Current Ratio 0.9 1.2 2.1 2.3 2.3 2.1 Leverage (debt/debt+equity) 41% 54% 46% 48% 49% 51% Return on Assets (ROA) 14.5% 15.5% 13.4% 11.9% 9.7% 10.1% Other Indicators Losses 16.3% 16.2% 16.0% 15.7% 15.2% 15.2% Annual increase in energy sold 2.1% 5.5% 7.8% 8.9% 10.3% 10.3% Cost of kWh purchased (US cents/kWh) 9.1 11.3 9.8 11.4 10.3 10.3 Revenue per unit sold (US cents/kWh) 16.1 18.6 17.0 18.3 16.7 16.7 Exchange Rate Assumption (KSh/US$ at year end) 75.0 76.8 78.7 80.6 82.5 84.6 60. Main results from the forecast: The main conclusion from the forecast is that KPLC financial viability would be maintained throughout the period. KPLC balance sheet structure would be significantly improved by the capital restructuring. In particular, the current ratio would go from 0.9 to 2.1. The financial leverage would also be reduced. Given the level of investments throughout the period, the value of the indicators would slightly decline after FY2011. At the end of the period, the DSCR would be at a 1.4 (against a covenant of 1.2 in the ongoing project). KPLC return on assets would somewhat decline (to a level slightly below 10% in FY2013), which is to be expected in a phase of acceleration of investments. Also, as part of the tariff review process, the regulator will take into account the lower cost of debt from concessional funds. This will reduce the Weighted Average Cost of Capital (WACC) that enters into the determination of tariff levels. As a result, the lower cost of debt mechanically reduces the return on assets. 61. Risks: The financial indicators at the end of the forecast would remain at comfortable levels. There is therefore a margin of safety in the forecast and KPLC would be able to accommodate a higher level of financial debt or lower profitability without a serious threat to its financial viability and its ability to service its debt36. The accelerated growth of the sector in the medium-term will create more uncertainty for tariff setting and therefore a potential financial risk for KPLC. Under existing price-cap regulation, KPLC is exposed to the demand risk within each tariff period. The commissioning date of new generation plants could have a significant impact on the volume of sales in a given year. Given the level of uncertainties, preparing the tariff review for FY2012--FY2014 will present significant challenges. During the review, some caution regarding the assumptions for the timing of new generation would be advisable (delays are much more likely than a commissioning ahead of schedule). 36 Leverage ratios of 75% -- 80% are common for regulated distribution utilities in developed countries such as Great Britain (and indeed are assumed by regulator when determining the cost of capital allowed in the revenue requirement) but would likely be to elevated in a developing country like Kenya where the sector is less mature (need for significant expansion investments vs. only renewal and maintenance in developed countries). However, given the favorable regulatory arrangements in Kenya, a leverage of around 60% could be acceptable for KPLC. 144 KenGen Recent Financial Performance (FY2004 to FY2009) 62. KenGen margins have been protected by the pass through of fuel costs and have allowed the company to generate significant cash-flow from operations. This combination of limited new investments and of significant cash flow has allowed KenGen to remunerate its shareholders (dividend payout ratio around 40% of net profit on average) while maintaining a low level of financial debt. Table 45: KenGen Income Statement, FY2004 -- FY2009 INCOME STATEMENT FY2004 FY2005 FY2006 FY2007 FY2008 FY2009 KSh million Sales Volume (GWh) 4,300 4,282 4,538 4,599 4,818 4,339 Sales 7,511 7,480 7,987 10,853 11,372 11,518 Fuel cost recoveries 1,244 3,219 6,077 3,411 4,543 7,866 Foreign exchange adjustment - 313 236 192 81 973 Other operating revenue 0 0 0 96 96 161 Total revenue 8,754 11,012 14,300 14,552 16,092 20,518 Non fuel revenue per unit 1.7 1.8 1.8 2.4 2.4 2.9 (Ksh/kWh) Fuel costs 1,244 3,124 5,982 3,411 4,542 7,860 Consumables, overheads 2,975 3,368 3,583 4,218 4,607 4,400 Gross operating Income 4,536 4,520 4,735 6,924 6,943 8,258 % of total sales revenue (non fuel) 60.4% 60.4% 59.3% 63.8% 61.1% 71.7% Depreciation 1,740 2,025 2,000 3,446 3,404 3,847 Net operating income 2,795 2,495 2,735 3,477 3,538 4,411 % of total sales revenue (non fuel) 37.2% 33.4% 34.2% 32.0% 31.1% 38.3% Non operating income 439 385 1,041 751 219 688 Foreign exchange gains (loss) (808) 637 589 1,420 9 176 Earnings Before Tax & Interest 2,426 3,517 4,366 5,648 3,767 5,275 (EBIT) Interest on long-term borrowings 0 898 645 554 688 719 Taxation 805 866 -48 2,274 -2,818 2,485 Exceptional 0 0 0 -375 0 0 Net profit 1,621 1,752 3,769 2,446 5,876 2,071 63. KenGen is comfortably in compliance with the financial covenants under ESRP. The company`s ability to service its debt is not in doubt (DSCR is above 2.0) and it does not face any liquidity problem. The high level of the current ratio reflects a large, positive, net cash balance. The self-financing ratio is also well above the covenant limit, reflecting low levels of investment compared to the cash flow. One negative dimension of KenGen`s financial performance is its low level of operating profitability compared to its asset base. KenGen`s prices are regulated through the approval, by the regulator, of its power purchase agreement with KPLC. New power purchase agreements have taken effect in FY2009 and have allowed KenGen to increase its generation margins (2.9 KSh per kWh against 2.4 KSh per kWh for the two previous years). As a result, the company`s profitability has increased but still remains low, with a return on assets below 5 percent. 145 64. In FY 2007, KenGen conducted a revaluation of its assets, which had the effect of increasing its equity significantly (by KSh 25 billion an increase of 65%). However, the regulatory return on assets (represented by the Capital Recovery Charge in the PPA) is still based on asset values (historical values) prior to the reevaluation. Over time, the reevaluation reserve in KenGen books will tend to decrease (in line with the depreciation of the underlying assets) and new generation projects are entering KenGen books and the regulatory asset base at identical values. The gap between KenGen`s asset book value and its regulatory asset base will therefore tend to decrease and the company`s return on assets will increase as a result. Table 46: KenGen's Financial Indicators, FY2004 -- FY2009 Target Value in FY2004 FY2005 FY2006 FY2007 FY2008 FY2009 ESRP Financial Ratios Debt Service Cover Ratio 1.5 3.1 4.0 3.3 2.2 2.2 Current Ratio 1.5 2.8 2.8 2.0 2.0 2.7 Self Financing Ratio 25% 136% 137% 113% 83% Other financial performance indicators Investments/Gross Operating 72% 42% 43% 77% 114% 57% Income ROA 5.5% 4.9% 5.4% 4.0% 3.9% 4.8% ROCE 4.4% 3.8% 5.3% 3.9% 3.8% 4.7% ROE (Net profit to Equity) 3.4% 3.6% 10.3% 3.8% 8.5% 3.3% Leverage (net debt/net 21% 25% 25% 18% 20% 27% debt+equity) KenGen Financial Outlook (2010 -- 2014) 65. The Bank has reviewed KenGen`s financial outlook in detail and has found it satisfactory. The key financial indicators show that the company will maintain profitability during the period of the project. The Government and KenGen have requested that the forecast not appear in the PAD. However, the full financial evaluation of the company, including the forecast, is available in the project files. Table 47: KenGen Performance Indicators, FY2010 -- FY2014 FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 Actual Forecast Forecast Forecast Forecast Forecast Financial Ratios Debt Service Coverage 2.2 2.3 2.1 1.7 1.4 1.3 Current Ratio 2.7 5.5 2.9 1.5 1.3 1.8 Leverage (debt/debt+equity) 27% 26% 33% 43% 51% 50% Return on Assets (ROA) 4.8% 2.7% 5.4% 5.5% 6.0% 6.6% Other Indicators Sales growth (energy volume) -10.0% -8.2% 36.4% 26.1% 20.6% 9.3% Revenue per kWh generated excluding fuel. (US cents) 3.7 3.8 4.3 3.9 3.9 3.9 End of year KSh/US$ 75.0 76.8 78.7 80.6 82.5 84.6 146 66. Main conclusions from the forecast. KenGen starts from a position where it is underleveraged and has excessive liquidity (from the bond issue) to fund an ambitious investment program. The financial indicators at the end of the period (2013 -- 2014) can be considered normal (see Table 47). The decline in the debt service cover ratio in 2012 and 2013 corresponds to the firsts repayments of the principal on the public infrastructure bond after a 2 year grace period. The projected level of the DSCR at the end of the forecast (1.3) remains adequate given that KenGen owns a diversified portfolio of generation plants generating free cash-flows that are secured by the pricing mechanisms. The implementation of KenGen investment program appears compatible with the preservation of the financial viability of the utility. This program would result in a doubling of KenGen generation over 5 years (the total cost of the program is around US$1.8 billion). 67. Risks. This analysis found that KenGen`s financial outlook above is subject to three main risks as follows: Hydrological risk: KenGen`s results in 2010 will be significantly impacted by lower hydro generation due to the drought. The hydrological risk is currently unfavorable for KenGen. If reduced hydrology does not allow KenGen to reach its contractual plant availability targets, it will see a reduction in the capacity payments. On the other hand, above average hydroelectric output would not provide any financial upside for KenGen (no increase in capacity payments). KenGen has argued that it is not in a position to control the risk, especially since the dispatching of its hydroelectric plant is controlled by KPLC. The regulator (ERC) has indicated that it would reexamine this issue. Given (i) the likelihood of an adjustment of regulatory mechanisms, and (ii) the fact that the share of hydro in KenGen generation portfolio is going to decrease, hydrology is likely to be a reduced risk factor for KenGen in the future. Implementation of investment program: KenGen`s schedule for implementing its investment program appears optimistic. Under the assumptions retained by the company, the program would be almost entirely completed by the end of FY2013 (this explains the increase in the current ratio in FY2014 due to a sharp reduction of investment in the last year of the forecast). The only significant investment that would still have to come online after 2013 would be the coal power plant. In practice, it is likely that the implementation of investments will stretch over a longer period (into 2014 and possibly 2015). This would obviously reduce KenGen revenues but also spread capital expenditure and reduce debt service. Indexing for local inflation in PPA: As explained above in the description of regulatory mechanisms, KenGen is only partially protected against local cost inflation by its PPAs. This does not appear to be a major issue in the short- to medium-term, but could be problematic in the longer-term, especially in case of increased inflation. 147 Annex 10: Environmental and Social Safeguard Policy Issues KENYA: Electricity Expansion I. Environmental Safeguards A. Summary and Conclusions 1. The Project`s positive environmental impact will result primarily from the switch to geothermal power as the source of baseload electricity generation in Kenya. Because geothermal energy is a more secure renewable energy source than hydropower, the current source of baseload power, it will diminish the need for thermal backup capacity (both in the private and public sectors) and thereby reduce air pollution resulting from the use of fossil fuels. However, the proposed project also will have adverse environmental impacts that require mitigation and has received a Category A rating, assigned to projects that are likely to have significant adverse environmental impacts that are sensitive, diverse, or unprecedented. 2. The Project will mitigate a number of diverse, environmental impacts occasioned by construction and operation of project components. All three components are likely to cause relatively minor air and water pollution during the construction phases and, once the works are completed, limited loss of non-critical animal and plant habitats. Also, the generation and transmission components will have a significant social impact due to land acquisition, which will result in loss of some assets necessary for livelihood (such as agricultural land) and relocation of people. Furthermore, the proposed project will have to mitigate some disruption to the indigenous peoples, who have a socio-economic and cultural connection to the project area (see Section II). The implementing entities (KenGen, KPLC and REA) have prepared and documented the necessary mitigation plans for the expected adverse impacts. The responsible implementing agencies (KenGen and KPLC) have demonstrated the capacity to manage environmental mitigation plans in Bank-financed projects. 3. The implementing entities have prepared Environmental and Social Impact Assessment (ESIAs) and Environmental and Social Management Plans (ESMPs) for the generation and transmission components. The preparation of the ESIAs has taken place in accordance with Kenya`s Environmental (Impact Assessment and Audit) Regulations of 2003. The ESIAs were prepared by independent consulting firms and incorporate the safeguard policies and the Environmental Health and Safety (EHS) Guidelines of the World Bank. The draft ESIAs were publically disclosed in Kenya and in the Bank`s InfoShop between October 23, 2009 and January 10, 2010. For the distribution and electrification components, the implementing entities have completed Environmental and Social Management Frameworks (ESMFs), which were disclosed in Kenya and in the Bank`s InfoShop between November 17, 2009 and January 8, 2010. 4. Although the entities that will implement the Project have basic in-house capacity to execute the ESMPs, the proposed project will provide training to strengthen existing capacity. The planned training program covers awareness building of the environmental impacts resulting from 148 the implementation of all three components, familiarization with the World Bank`s safeguard policies, and skills development for implementation, environmental auditing, monitoring and occupational health and safety. 5. The following sections outline, for each of the Project`s components: (a) the key positive and negative environmental impacts; (b) mitigation measures for negative impacts; (c) planned monitoring procedures; (d) the consultative process with key stakeholders; (e) a description of the implementing agencies` capacity for executing the ESMPs, along with associated training programs; and (f) the details of public disclosure of the ESIAs and the ESMFs. B. Environmental Impact Analysis by Component Generation Component Description The construction of generators running on geothermal steam -- totaling 280 MW of power - - 140 MW at the Olkaria I site and 140 MW at the Olkaria IV site, just outside the border of Hell`s Gate National Park in Naivasha. The connection of the new generating units to geothermal wells and the transmission system. Positive Impacts 6. The increase in geothermal generation capacity will expand the use of clean, renewable energy that is more secure than hydropower and thereby will reduce dependence on fossil fuel- based thermal plants when hydropower is not available due to drought. Because the expansion of geothermal generation will reduce the requirement for electricity from existing and new fossil-fuel based plants, the component will enable Kenya to earn carbon credits, under the Clean Development Mechanism (CDM), the post-2012 Carbon Partnership Facility, or other sources of carbon finance. Potential Negative Impacts and Proposed Mitigation Measures Impact Mitigation Measures Potential Monitor the impact on fauna in the Hell`s Gate Park. Limit habitat degradation and degradation or loss (especially during drilling and construction stages) in accordance with measures loss of habitat [due outlined in a Memorandum of Understanding (MoU) signed between KenGen and to the construction Kenya Wildlife Service (KWS) in 2008. For the construction of the units at Olkaria of additional power I, KenGen will liaise with KWS to periodically monitor the effect on wildlife, if any. units at the Olkaria Should KWS indicate a significant impact, KenGen may consider purchasing land to site]. The loss is offset the loss of the wildlife migratory corridor, or may provide some natural expected to be barriers to enable wildlife to freely and safely bypass the construction area. minimal.37 37 The construction of the new generation units at the Olkaria IV site will result in a minimal loss of animal habitat (less than one percent) within the Kedong Ranch Limited area: about 54 hectares of land, out of 79,500 hectares. 149 Impact Mitigation Measures Reduced water Hydrological studies (currently underway) will determine water abstraction rates, availability caused including measures adopted by the Lake Naivasha Riparian Association to by water harmonize water abstraction from all users around the lake. The findings have been abstraction from included in the final ESIA. KenGen, under IDA`s supervision, will continuously Lake Naivasha. monitor water use and water levels and ensure water recycling as feasible. Water pollution Before discharging brine water into any water body, KenGen will analyze the caused by brine water`s quality to ensure that it complies with NEMA`s Environmental Management water discharge and and Coordination (Water Quality) Regulations of 2006. A progress report will sludge disposal. verify this compliance. Where possible, KenGen will install concrete piping for brine transport and re-inject the brine. Sludge, including toxic non-biodegradable substances, will be removed from condensers and cooling towers during major overhaul activities. KenGen will manage the sludge (expected to be small) properly by drying, encasing it in concrete and burying it. KenGen has confirmed planned disposal of the sludge according to NEMA`s Environmental Management and Coordination (Waste Management) Regulations of 2006. KenGen will provide supporting information about the kinds of geological characteristics and management requirements needed. Air pollution Avoid the removal of vegetation until clearance is required. Re-vegetate or stabilize resulting from exposed surfaces as soon as practically possible. Refrain from excavation of the increased dust handling and transport of soils in the event of strong winds. Cover vehicles and during reduce speeds to lessen the likelihood of spills and windblown dust. Monitor air construction. quality standards to ensure that they follow the environmental, health and safety guidelines of NEMA and the World Bank Group. Transmission Component Description The component will construct the following three 132 kV transmission lines: Kindaruma- Mwingi-Garissa; Eldoret-Kitale; and Kisii-Awendo (see Map attached as Annex 16). 38 Positive Impacts 7. The lines will expand electrification and improve the reliability of supply. Access to electricity will benefit economic development through: (a) employment creation (direct and indirect) and increased investments; (b) expansion of businesses and income levels; and (c) increases in agricultural production due to better irrigation resulting from electrified water pumps. The availability of electricity also will reduce air pollution by replacing isolated diesel generation units, thereby reducing fossil fuel emissions. 38 The proposed routes have been identified through an analysis of alternatives taking into account economic and financial analyses, load forecasts, system analyses, as well as environmental and social impacts. 150 Potential Negative Impacts and Proposed Mitigation Measures Impact Mitigation Measures Pollution of water Minimize clearing and disruption to riparian vegetation. Avoid using courses caused by machinery in the vicinity of watercourses. Observe manufacturer machinery siltation of soil during and equipment guidelines, procedures to prevent oil spills. construction activities leading to aquatic habitat damage. Occupational health and Highlight the importance of providing appropriate safety equipment to safety concerns [of workers and adequate medical and sanitary facilities. Provide education, workers and inhabitants of guidance and counseling on HIV/AIDS and other STDs to construction and the project area] including maintenance staff. Distribute condoms to construction and maintenance staff. risk of fire, electrocution Construction contracts will include requirements to observe adequate health from live power lines, and safety procedures. exposure to fumes, noise pollution, transmission of sexually transmitted diseases, etc.. Adverse impacts on Minimize bird collisions by wire-markings that will alert them to the presence avifauna due to presence of power lines. Take appropriate measures in design and construction of the of power lines. transmission lines to minimize the risk of electrocution of raptors and nesting birds. 39 Soil erosion due to the Avoid clearing in riparian areas in order to reduce soil erosion and safeguard construction of towers, riverbank protection. Re-plant degraded areas with local species to which may interfere with complement natural vegetation regeneration to improve ground cover. Site the natural drainage towers away from drainage lines and floodways to minimize interference with systems by modifying natural drainage systems. In placing towers, leave a protection zone of 15 m water flow. 40 when crossing rivers and streams with the span ranging of 10 -- 15 m, and 5 m when crossing any drainage channels. Terrestrial habitat Re-vegetate affected areas with native plant species. Clear trees selectively, alteration41 due to removing tall woody species but leaving saplings for quick regeneration of construction of towers. vegetation along the way leave. Establish an integrated vegetation management approach along the transmission line rights-of-way. Generation of solid Provide guidelines (included in ESMPs) for the appropriate disposal of waste from construction construction waste. activities and in worker camps. 39 Nature Kenya, the Ornithology Department of the Museums of Kenya and KWS could provide guidance on more specific actions to protect birds. 40 In addition to soil erosion, this can contribute to flooding, channel modification, downstream scouring and sedimentation in streams and other drainage channels. Although temporary in nature, these impacts can be ongoing if adequate drainage works are not constructed to prevent erosion. 41 The construction of the transmission line will mainly affect flora with minimal impacts on fauna. The construction will affect no protected wildlife conservation areas and impacts on wildlife will be minor during the construction phase (disturbance through movement of people and machinery and loss of habitat from the establishment of the 30 m ROW along the length of the route). The proposed route of the transmission line passes mainly through a landscape that has already been greatly disturbed by mixed subsistence farming, mechanized farming and mixed grazing. 151 Impact Mitigation Measures Air pollution resulting Use soils excavated for the erection of pylons to refill areas where removed from dust generated by and avoid exposing loose, dry, bare soil to wind or water for long periods. breaking hard ground Ensure that construction workers have face masks and eye protection during during construction, as clearance work that local residents are advised to avoid the area during well as benzene and other clearing of vegetation, and that water spraying of construction area is polyaromatic undertaken regularly. hydrocarbons from the motorized chain saws used for clearing of vegetation. Potential destruction or Implement Chance Find Procedures (to be specified in the construction damage to resources of contracts) in case of an archeological or culturally important discovery during archaeological, construction. According to this procedure, work will cease on the site upon paleontological, historical, discovery of the resource. The local Environmental Officer, after inspecting architectural, religious and securing the site, will contact Museums of Kenya for advice and arrange (including graveyards and for survey or safeguard work as appropriate. burial sites), aesthetic, or other cultural significance. Adverse visual impact Hold extensive public consultations during the planning of power line and on the landscape power line right-of-way locations. Locate high-voltage transmission and [resulting from the distribution lines in less populated areas, wherever possible. presence of transmission lines]. Distribution Component Description Upgrade and infill the distribution networks to connect an additional 300,000 customers over five years.42 Connect designated priority loads -- trading centers, schools, health centers, administrative facilities, other key public/community facilities, and rural households. Electrify slum households. Positive Impacts 8. The upgrading of the distribution systems and connecting priority new customers are linked to the expansion of the transmission system and are necessary to attain the benefits outlined in paragraph 7 above. 42 The proposed upgrading has resulted from an analysis of alternatives taking into account economic and financial analyses, load forecasts, system analyses, as well as environmental and social impacts. 152 Potential Negative Impacts and Proposed Mitigation Measures. Impacts Mitigation Measures Loss of vegetation and related Clearing of vegetation and trees will be strictly controlled. Affected loss of habitat due to clearing of areas will be re-vegetated with indigenous grasses, shrubs, trees, and indigenous vegetation arising flora to limit impact to local flora and fauna. from opening up of access roads and construction activities. Loss of soil cover due to Use soils excavated for the erection of pylons to refill areas where excavations and the use of removed and avoid exposing loose, dry, bare soil to wind or water for quarries and borrow pits. long periods. Water pollution increase as a Minimize clearing and disruption to riparian vegetation. Avoid using result of siltation during machinery near watercourses. Observe manufacturer machinery and construction. equipment guidelines, procedures with regard oil spill prevention. Soil and water pollution due to Ensure that all construction materials are stored and ultimately unsafe disposal of creosote-treated disposed of in an appropriate manner. poles and PCBs. Health damage resulting from Provide workers with face masks and goggles. Ensure water spraying respiratory infections that may of construction area regularly. Ensure that construction workers have arise from dust and cement. facemasks and eye protection during clearance work, and that local residents are advised to avoid the area during clearing of vegetation. Solid waste pollution resulting Ensure that construction sites and worker camps follow appropriate from disposal of solid waste waste management measures. Rehabilitate quarry sites and borrow during construction. pits. Noise pollution [resulting from Provide construction workers with adequate noise -- protection construction activities]. headgear. Increased incidence of sexually Provide education, guidance and counseling on HIV/AIDS and other transmitted diseases (STD). STDs to construction and maintenance staff. Provide condoms to construction and maintenance staff. Construction contracts will include requirements to observe adequate health and safety procedures. Potential destruction or damage Implement Chance Find Procedures to be specified in construction to resources of archaeological, contracts in case of an archeological or culturally important discovery paleontological, historical, during construction. According to this procedure, work will cease on architectural, religious (including the site upon discovery of the resource. The local Environmental graveyards and burial sites), Officer, after inspecting and securing the site, will contact Museums aesthetic, or other cultural of Kenya for advice and arrange for survey or safeguard work as significance. appropriate. II. Social Safeguards A. Summary Findings and Conclusions 9. The Project applies the World Bank`s operational policies on Involuntary Resettlement (OP 4.12) and Indigenous Peoples (OP 4.10) due to expected impacts on land and human settlements. 10. Consistent with World Bank safeguards policies, the implementing entities for each of the Project component have prepared corresponding draft safeguards instruments and publicly disclosed them. 153 (a) Generation -- Environment and Social Impact Analysis (ESIA) for Olkaria I power station; and ESIA and Resettlement Action Plan (RAP) for Olkaria IV power station; (b) Transmission -- ESIAs and RAPs for three transmission lines; (c) Distribution -- Environment and Social Management Framework (ESMF); Resettlement Policy Framework (RPF); and (d) Indigenous Peoples Planning Framework (IPPF). 11. Overall, the Project`s draft RAPs, both for the generation and transmission components, indicate that planned land acquisition, depending on the final routing of the transmission lines, will result in over 10,000, project affected persons (PAPs), who are entitled to compensation (the estimate varies from 10,326 to 10,686, depending on the routes selected for the transmission lines). About 3,319 people will require relocation and livelihood restoration support. 12. The Generation Component. The main social impact of this component will be the loss of land, settlements, and cultural property by 685 Project Affected Persons (PAPs), members of the Maasai Community residing near the planned investments in geothermal generation, due to air and noise pollution. The agreed compensation package consists of land-for-land compensation plus additional compensation covering social services and cultural property. 13. The Transmission Component. Because one of the transmission lines has two routing options, the final design of the component will not be complete until after the start of the Project. The initial screening for social impact indicates PAPs ranging from 9,368 to 9,798, depending on the final decision for routing of the Kindaruma-Mwingi-Garissa transmission line. Most of the impact will be lost land assets for livelihood, which KPLC will compensate, with only about one quarter of the PAPs requiring re-location. 14. For the Distribution Component, which covers investments in distribution infrastructure as well as the electrification of rural schools and health clinics, the details on the need for involuntary land acquisition, the scope of impact and mitigation measures will not become available until the final designs have been prepared. Thus, the implementing entities (KPLC and REA) have prepared Resettlement Policy Frameworks (RPFs) that provide guidance in preparation of a RAP in the event of involuntary land acquisition, leading to resettlement or other compensation. However, based on experience under ESRP, involuntary resettlement resulting from this component is likely to be minor. 15. Indigenous Peoples. Initial screening indicates that vulnerable ethnic groups, classified as indigenous peoples, are either present in, or have collective attachment to, lands in the proposed areas that the implementing entities will acquire for construction of transmission lines. Therefore, an Indigenous Peoples Planning Framework (IPPF) was prepared and disclosed both in Kenya and in the Bank`s InfoShop. The IPPF provides guidelines for the preparation of IPPs, once indigenous communities in the project area have been identified. 16. Corporate Social Responsibility. KenGen and KPLC have established programs to promote corporate social responsibility, which will provide additional benefits for PAPs and other residents of the project area. Their purpose is uplifting the lives of people by providing better education, health, water and electricity supply along with a cleaner environment. Both companies 154 annually set aside one percent of their after-tax profits to finance such activities. Also, the Project`s Environmental and Social Management Plans (ESMPs) outline the institutional responsibilities for implementing and monitoring social mitigation measures during the pre- construction, construction, and operational phases (see Section I - Environmental Safeguards). 17. HIV/AIDS awareness and prevention programs are integral elements of the ESMPs for all project components. Both KenGen and KPLC have corporate policies for reducing the spread of HIV/AIDS. KenGen`s policy focuses on: (a) annual sensitization seminars for all staff; (b) counseling services at the company`s clinic; (c) the supply of materials for control and prevention (posters, pamphlets, condoms); and (d) required prevention programs for all contractors employed by KenGen. KPLC`s comprehensive strategy consists of: (a) sensitization of employees; (b) provision of peer educators for outreach to other employees and their communities; (c) a policy of nondiscrimination based on HIV status; (d) the distribution of booklets on HIV prevention to employees, encouraging them to share the publications with others; (e) the supply of condoms to all employees; and (f) the provision of free antiretroviral treatment for the employees. 18. The following sections discuss the scope and mitigation measures for involuntary resettlement and indigenous peoples, for each of the three project components. B. Involuntary Resettlement Generation Component 19. Impact Analysis. Expansion at the existing Olkaria I power station inside Hell`s Gate National Park, and construction of 140 MW at the planned Olkaria IV power station, located just outside the park, will require acquisition of 3,600 acres of land. This estimated land take reflects the current land use by Olkaria II power station. In addition, modeling studies of air and noise pollution show that in order to minimize noise impacts, all settlements within 35 dB (sound level limit) and settlements in the areas with expected concentrations of hydrogen sulfide greater than the 0.10 parts per million (ppm) may need to be relocated. When these additional areas are covered, the total land take would be about 4,200 acres. The Olkaria II-Suswa transmission line will require acquisition of 0.14 ha of land for the tower footings, as well as 5 m as right of way and 35 m as way leaves along the 20 km long route. The land for the transmission line will be acquired from the present land owner (Kedong Ranch). 20. Scope of Resettlement. The acquisition of the land for constructing the Olkaria IV power station and related infrastructure will necessitate the resettlement of 93 households, comprising 685 persons belonging to the Maasai community. KenGen has prepared a draft RAP for project- affected persons (PAPs). The three objectives of the RAP are to: (a) identify the impacts expected from the resettlement of PAPs; (b) recommend plausible mitigation measures; and (c) establish mechanisms to monitor the implementation and efficacy of proposed mitigation measures. The purpose of the RAP is to ensure that the PAPs should be no worse off after the project than they were before it. 21. Site Visits and Stakeholder Consultations. KenGen conducted site visits for preparation of the RAP between September 14 and October 14, 2009. These visits included a census and social survey of PAPs, land and asset valuation, public meetings, consultative meetings with the 155 PAPs, interviews with key members of the community and site surveys. Discussions on resettlement options and compensation took place over a four-month period -- from September 14, 2009 to December 3, 2009. To convince the community that KenGen has successfully carried out a resettlement exercise before, KenGen sponsored a trip to the Sondu Miriu Hydro Electric Power where a similar resettlement exercise was carried out. During the consultations, the PAPs expressed a willingness to be relocated as long as KenGen provided equivalent land and improved community services. The Maasai community`s main concern was over their land, thus it decided to seek land compensation and resettlement as a single group (communal) rather than as individual households. There were also some cultural concerns regarding the Olduvai Gorge and ancestral graves located within the project area. KenGen also conducted consultations along the Olkaria II- Suswa transmission line and substation between March 25 and 26, 2010. The stakeholders consulted included 13 government officials, 2 KWS staff and 103 persons assumed to be within the project`s zone of influence. The stakeholders` main concern was over proper compensation for any land acquired. 22. Participating village elders of the Maasai community, representing the PAPs, signed the minutes of the meetings carried out in the Moderat Conference Center, Naivasha, on December 3, 2009. In so doing, they agreed to the resettlement compensation except for the parcel of land whose site has yet to be confirmed. The Maasai have consistently stated that they would prefer a site close to the existing settlements. Agreement on the site is pending and will be completed only after the joint approval by the PAPs, KenGen, and the current landowners of the site eventually selected. 23. According to a letter sent by the Olkaria Maasai community to the World Bank, on December 22, 2009, KenGen has agreed in writing to the following: (a) Land -- 1,700 acres of land near the project area. (b) Land for land compensation. (c) Development of infrastructure at the resettlement site: a permanent school, health centre, piped water, housing, churches and community hall. (d) Assistance to the construction of a Maasai cultural centre. (e) Education through children sponsorship program. (f) Employment of the local people who were interviewed is being addressed. (g) Compensation of the grave yards. 24. Meetings held on February 17 and 18, 2010 by members of the co-financiers` appraisal mission with Maasai elders as well as with members of the Olo Nongot and Cultural Center villages confirmed that the PAPs are willing to relocate, on the condition that the formal agreement reached with KenGen on December 3, 2009 is fulfilled, particularly that prior to their agreement to the new site, they obtain title to the land, and they are provided the necessary compensation and relocation assistance. The Maasai elders requested KenGen to update its census of the PAPs because some people were apparently not counted in the initial survey. Through its Director of Regulatory Affairs, KenGen officially confirmed its intention to abide by the agreement. Furthermore, to avoid future misunderstandings, the Maasai elders delegated two members of their communities to be official contacts. 156 25. Agreed Compensation. The Maasai settlements that will require compensation consist of: (a) the Cultural Center; (b) the entire population of the Olo Nongot and Olo Sinyat villages; and (c) a small portion of the Olo Mayana village (small Olo Mayana), located between the main Olo Mayana Village and Cultural Center. Not all of the landowners with assets in the area of the Project are eligible for compensation from KenGen. The resettlement of 35 land and asset owners within the small Olo Mayana village will take place outside the project because an independent court ruling has granted them compensatory land within the Ng'ati Farmers Co-operative, Maiella Farm, adjacent to the project area. This ruling has resulted from a land ownership dispute between the Maasai community and the legally registered landowners, the Ng'ati Farmers Co-operative. The Olo Mayana families, therefore, will not be eligible to receive compensation from KenGen and the resettlement of these families will take place under the jurisdiction of the Naivasha District Lands Board. The 93 households directly affected by the acquisition of land by KenGen will receive compensation in line with OP 4.12. 26. The Maasai settlements cover about 86 acres. Taking account of both the pastures and dwellings that the PAPs are likely to lose, the total agreed amount of land compensation for property owners is 1,500 acres. The RAP also will set aside an additional 200 acres for the development of infrastructure, consisting of educational, health, tourism and religious facilities/amenities. The agreed land compensation for the group of PAPs with more than 12 years of residence is 1,700 acres, with secure land tenure. 27. In addition to compensation of PAPs and the replacement of public infrastructure and other public facilities, payments will be given to the management committees (youth and community management teams) for lost income from the Cultural Center and the tourist activities at Ol Njorowa Gorge, located in Hells Gate National Park. Eligible residents of the Olkaria settlements will receive compensation for the loss of access to the caves on Ol Njorowa Gorge and red and white soil, which has a cultural value. The compensation will consist of the re-establishment of the Cultural Center in another place within the new resettlement site and a lump sum payment of three months of income to the management committees. 28. The Cultural Centre will feature a traditional manyatta and craal, even though the community will live in better quality housing. There will also be compensation for moving the community away from 29 ancestral gravesites, which has provisionally been set at KSh 20,000 per grave. 29. The PAPs also requested direct financial compensation from KenGen`s electricity sales, jobs at the project site and access to the Olduvai Gorge for cultural events. These requests are outside the authority of the project, but KenGen will consider the issues raised by the Maasai community for future planning/development, in particular economic opportunities and access to cultural sites. Transmission Component 30. KPLC has prepared the draft RAPs in consultation with the relevant stakeholders for the three planned transmission lines. The draft RAPs estimate between 9,638 and 9,998 PAPs (depending on the routes chosen), as shown in the tables below. The exact number will be confirmed after completion of the detailed design of the transmission lines. The main impact will 157 likely be the loss of assets, livelihood or access to resources necessary for their livelihood (agricultural land, pastures, etc.). Most PAPs whose assets will be affected have the option of moving/rebuilding them in the same plots of land they hold. So the preferred method of compensation is cash compensation. In order to avoid or minimize the need for physical relocation of PAPs, the draft RAPs have presented alternative designs of parts of the transmission system. About 2,634 PAPs will be physically relocated. Kindaruma-Mwingi-Garissa line Transmission Line/line Number of Number of Total Number of Total number of persons to routing option Structures Households Project Affected be physically affected affected Persons (PAPs) re-located Option A: 205 360 2,160 360 Without re-alignment of line route in Madogo and Bangale Option B: 97 300 1,800 0 With re-alignment of line route in Madogo and Bangale Kisii-Awendo line Transmission Line Number of Number of Total Number of Total number of persons Structures Households Project Affected to be physically affected affected Persons (PAPs) re-located Kisii-Awendo 132 kV 1,700 726 3,630 0 Eldoret-Kitale line Transmission Line Number of Structures Number of Total Number of Total number of persons affected Households Project Affected to be physically affected Persons (PAPs) re-located Eldoret-Kitale 132 kV Houses = 42 300 2,228 294 Commercial Units = 30 15 60 60 Institutions = 7 7 1,920 1,920 TOTAL 78 322 4,208 2,274 31. The RAPs of the transmission lines indicate that different stakeholders (particularly local authorities, community leaders and PAPs) have been thoroughly consulted. Based on feedback received at these consultations, PAPs are willing to cooperate as long as they are properly compensated. In those cases where entire structures are going to be destroyed, the preferred form of compensation is cash but, if the PAPs so prefer, land-for-land compensation will be given. The RAPs have presented alternatives so as to avoid and/or minimize physical relocation of PAPs. In fact, many PAPs will be moving or rebuilding their structures in the same plots of land they already occupy. In some cases the PAPs will be relocated to nearby sites. Where vulnerable ethnic groups are involved, the project will ensure that they are not resettled away from their ancestral territories and that there is no physical relocation without their prior agreement. Distribution Component 32. The localized, social impacts of the various subprojects that will make up these components will be determined by the screening process for environmental and social impacts, which are included in the draft ESMF and RPF. They will utilize the following evaluative tools: 158 The Environmental and Social Screening Form, which will help identify potential adverse environmental and social impacts. The Environmental and Social Checklist, which will outline simple environmental mitigation measures for sub-projects not requiring a separate ESIA report. A summary of the Bank`s safeguard policies to ensure they are taken into account during the sub-project planning stage. 33. If the detailed screening determines that any land acquisition requires involuntary resettlement, KPLC/REA will prepare a RAP, defining the persons affected, the assets involved and the mitigation measures necessary to comply with OP 4.12. 34. Based on preliminary screening, the social impacts of the proposed investments in the distribution system are likely to be relatively minor based on similar infrastructure investments under the ongoing, Bank-financed Energy Sector Recovery Project (ESRP). The main investments in the distribution system under the proposed project will be for about 26 substations and low- voltage lines to support new household connections. The substations will be located primarily in urban and peri-urban areas -- in Nairobi, around Mombasa, in Mt. Kenya and in towns in Western and Nyanza Provinces. The average size of the land required for one substation is about an acre and the planned medium-voltage distribution lines from substations to transformers are relatively short. So far, under ESRP, KPLC has had to prepare only one abbreviated RAP to compensate for the displacement of low-value kiosks along a road. C. Indigenous Peoples 35. The World Bank`s screening has found that the planned routes for the transmission and distribution lines that the proposed project will construct may traverse areas where vulnerable ethnic groups are located. The Kenyan people and the Government of Kenya use several terms for indigenous peoples, including minority or vulnerable ethnic groups. However, for the purposes of the proposed project, the Bank`s screening process, in line with OP 4.10, defines indigenous peoples as those who meet one or more of the following criteria: (a) self identification and identification by others, as distinct, social and cultural groups; (b) collective attachment to ancestral lands and their natural resources; (c) customary cultural, economic, social and political institutions distinct from dominant society; and (d) an indigenous language that may differ from official language of the country. The initial screening has designated the Sengwer, Ogiek, Waata, and Boni peoples as meeting the criteria for indigenous peoples, as defined by OP 4.10. However, this list of indigenous peoples is preliminary. Further screening in the field and consultations with the Government of Kenya may result in the addition of other groups to the list of indigenous peoples as defined by OP 4.10. 36. Given the likelihood that indigenous peoples are present in, or have collective attachment to, project lands, the Government has prepared an Indigenous Peoples Planning Framework (IPPF). The guidelines of the IPPF provide for (a) a social assessment of indigenous communities; (b) free, prior and informed consultations leading to broad community support. In addition, the framework provides for the preparation of an Indigenous Peoples Plan (IPP) to avoid potentially adverse effects of the project on indigenous peoples. If avoidance is not feasible, the IPP will 159 specify measures to minimize, mitigate, or compensate for such effects. Furthermore, the IPP will ensure that the indigenous peoples identified receive social and economic benefits that are culturally appropriate, taking into account gender concerns and the needs of different age groups. III. Stakeholder Consultations Generation Component 37. The preparation of the ESIA for the Olkaria I plant included 11 public consultation meetings with key stakeholders43 in 11 locations during September 2009. Similarly, the preparation of the draft ESIA and RAP reports for the Olkaria IV plant included consultations in ten locations with relevant stakeholders during the month of September 2009. KenGen held follow-up meetings with senior community members, the Provincial Administration, and other stakeholders in October and December 2009. Elements of the proposed projects and the potential positive and negative impacts, as well as mitigation measures, were clearly explained to the relevant stakeholders in both Swahili and English using maps and figures. The communities were given a forum to voice their concerns and most of the issues raised are addressed in the RAP. Implementation of the RAP will be monitored and evaluated by an Independent Evaluation Panel. 38. The majority of questions from stakeholders at the ESIA disclosure meetings focused on resettlement issues and Corporate Social Responsibility programs (health, education, provision of seedlings, etc). However, there were several questions from local residents in the Maasai community, the Public Health Official, and NEMA on the effects of hydrogen sulphide emissions on human and animal health, and plants and soils44. KenGen staff and the environmental consultants (GIBB AFRICA) assured the stakeholders that the fumes would be less after construction, and that the newly constructed plants would emit far fewer emissions than the older ones (due to the discharge of hydrogen sulphide through the cooling tower providing greater plume rise and better dispersion). Stakeholders were advised that they would be given opportunity to comment on whether mitigation measures proved adequate. Section II above provides additional details on mitigation measures agreed with the Olkaria Maasai community. Transmission Component 39. Extensive stakeholder consultations already have taken place with residents along the proposed routes, local administrative officers, and non-governmental organizations (NGOs), community-based organizations (CBOs), and faith-based organizations. For the Kindaruma- Mwingi-Garissa line, consultative public meetings have taken place in each of five project divisions. For the Kisii-Awendo line, there were consultations in three districts during October 2009. For the Eldoret-Kitale line, eight consultative meetings took place during September and October 2009. There were also numerous questions around compensation for land for way leaves and for trees planted along the route. They are addressed in the corresponding RAPs. Implementation of the RAPs will be monitored and evaluated by an Independent Evaluation Panel. 43 District commissioners, district Officers, chiefs, sub-chiefs, village chiefs, and villagers. 44 Some stakeholders felt there were no negative impacts resulting from hydrogen sulphide emissions. Per the ESIA for Olkaria IV (Section 6.5 Public Disclosure of ESIA Findings), Project Affected Persons stated that since they had yet to see negative health impacts arising from noise and hydrogen sulphide, they saw no reason for resettlement. 160 Distribution Component 40. Consultations will take place with affected communities in accessible locations in each district as part of the environmental and social screening process. The results will be communicated in an understandable language to potentially affected persons and beneficiaries. IV. Alternatives (Scenario without the Project) 41. Generation. In the absence of constructing the additional geothermal capacity at Olkaria, KenGen would not be able to meet power demand or would have to construct fossil-fuel plants, which would have a higher economic cost and be more damaging to air quality. 42. Transmission. KPLC would not have the capacity to transmit additional power required for new connections and the benefits of electricity access, reliability and quality of power supply for an additional 330,000 customers under the Project would not materialize. 43. Distribution. Without enhancement of distribution capacity and a program of rural connections to the grid or appropriate off-grid solutions, the Government would not be able to advance its program to bring the benefits of electricity to lower income, peri-urban, and rural consumers. V. Safeguards Monitoring Generation Component 44. In addition to ESMPs, the ESIAs for the construction of the power generation units at Olkaria I and IV contain environmental and social monitoring plans for the construction and operation phases. Transmission Component 45. In addition to ESMPs, all ESIAs contain environmental and social monitoring plans for the construction and operation phases. Distribution Component 46. The Rural Electrification Authority has contracted KPLC`s Environmental Unit to implement and monitor its ESMP with assistance from regional safety officers/engineers. The final ESMP, to be completed once the Project locations are known, will outline the institutional arrangements and cost estimates for environmental and social management during the implementation, operation and decommissioning of the Project. 161 VI. Implementing Entities' Capacity for Safeguards Monitoring Generation Component (KenGen) 47. Under previous Bank operations, KenGen has demonstrated sufficient capacity to manage the potential environmental and social impacts and is expected to be able to manage those associated with the additional generation capacity of the proposed project. KenGen currently owns and operates two geothermal power stations with a total installed capacity of 115 MW at Olkaria. Its Geothermal Resource Development (GRD) Environment Unit at Olkaria has 22 qualified staff in the fields of EIA, air quality, waste management, safety, environmental resource management etc. KenGen has experience in resettlement having relocated people who were displaced (either loss of land/houses, or loss of livelihoods) in the Sondu Miriu Hydro Power project. Furthermore, KenGen has ISO14001and ISO9001 accreditation and its Environmental Inspection Unit regularly monitors the environmental and social aspects of its operations in close cooperation with the KWS, which manages the Hell`s Gate National Park. Transmission Component (KPLC) 48. KPLC has ISO9001 accreditation. The staff of its Safety, Health and Environment (SHE) Department has received environmental training under the ongoing Energy Sector Recovery Project (ERP). In addition to environmental monitoring, KPLC has had experience in resettlement, having relocated about 500 persons who lost their assets due to the acquisition of land for a Thermal Power Project in Mombasa. KPLC`s Resettlement Unit (RA) includes the following specialists: Team Leader, Legal Advisor, Accountant, Building Technician, Environmental and Social Specialist, Socio-Economist, Land Valuer, Electrical Engineer, Way Leaves Officer, and Surveyor. Selected KPLC staff will receive training in environmental management systems and impact assessment, implementation of the environmental and social screening process, hazardous waste management, pollution control and occupational safety and health measures as part of the company`s capacity building. Distribution Component (KPLC) 49. The capacity described above for the transmission component applies to these components as well. VII. Planned Training Program for Environmental Monitoring and Management Generation Component (for KenGen Staff) 50. The planned training program for KenGen staff will consist of Awareness building concerning: (i) the need to incorporate environmental concerns in construction, operation, and maintenance of the facilities; and (ii) environmental regulations and laws pertaining to geothermal power generation, and transmission and distribution; 162 Skills development in: (i) environmental auditing; (ii) environmental monitoring; (iii) incorporation of environmental impact mitigation measures at all stage of project development; and (iv) review of ESIAs and reporting requirements. Familiarization with the World Bank`s safeguard policies. Transmission Component (for KPLC and KETRACO staff) Awareness building on: (i) the need to incorporate environmental concerns in construction, operation, and maintenance of transmission lines; and (ii) environmental, social and land acquisition regulations and laws pertaining to transmission and distribution, and rights of way. Skills development in: (i) environmental auditing; (ii) environmental monitoring; (iii) incorporation of environmental impact mitigation measures at all stage of project development; and (iv) review of ESIAs and reporting requirements. Familiarization with the World Bank`s safeguards policies Distribution Component (for KPLC and REA staff) 51. The ESMF contains the following draft training plan, which has been confirmed during appraisal: Training for REA: Course Participants Estimated Remarks Tuition Cost 1. Environmental Management Systems Four (4) REA PIT 30,800 USD PIT will be involved in and Impact Assessment @ 7700 USD environmental and social screening 2. Hazardous Waste Management and Two (2) REA PIT @ 7700 USD Training relevant as it will Pollution Control 3850 USD improve skills in waste management 3. NEBOSH International Certificate in One (1) REA PIT 7900 USD Training relevant to strengthen the Occupational Safety & Health available skills Total for Tuition 46,400 USD Flight & Accommodation 23,200 USD Grand Total 69,600 USD Training for KPLC: Course Participants Estimated Remarks Tuition Cost 1. Environmental Management Four (4)KPLC regional 30,800 USD Regional staff will be involved in Systems and Impact Assessment & staff environmental and social Implementation of the ESMF @ 7700 USD screening 2. Hazardous Waste Management and Two (2) Environment and 7,700 USD Training relevant as it will Pollution Control social Unit Staff @ 3850 improve skills in waste USD management 3. NEBOSH International Certificate One (1) Central Office 7,900 USD Training relevant to strengthen in Occupational Safety & Health staff the available skills 163 Total for Tuition 46,400 USD Flight & Accommodation 23,200 USD Grand Total 69,600 USD VIII. Public Disclosure of ESIAs and ESMFs Generation Component 52. The draft ESIAs for the Olkaria I and Olkaria IV power plants were disclosed to the public by NEMA on October 23, 2009 through notice in local newspapers. The documents were made available at NEMA headquarters, the Ministry of Environment and Mineral Resources, the Office of the Provincial Director of Environment of the Rift Valley Province, and the District Environment Office of Naivasha. The ESIAs are also available at the offices of KenGen in Nairobi and Olkaria, and a notice indicating their availability has been posted on the KenGen website, and was disclosed through the Bank`s InfoShop on January 25, 2010. Transmission Component 53. The ESIA for the Kindaruma-Mwingi-Garissa line was disclosed to the public on January 11, 2010. The ESIA is also available at the offices of KPLC in Nairobi and on the KPLC website. It was disclosed through the Bank`s InfoShop on January 11, 2010. The ESIA for the Kisii- Awendo line was disclosed to the public on January 14, 2010. The ESIA is also available at the offices of KPLC in Nairobi and on the KPLC website. It was disclosed through the Bank`s InfoShop on January 14, 2010. The ESIA for the Eldoret-Kitale line was disclosed to the public on January 24, 2010. The ESIA is also available at the offices of KPLC in Nairobi and on the KPLC website, and was disclosed through the Bank`s InfoShop on January 24, 2010. Distribution Component 54. The ESMF for the distribution component, which KPLC will manage, was disclosed to the public on November 17, 2009. The ESMF is also available at the offices of KPLC in Nairobi, and it has been posted on the KPLC website and was disclosed through the Bank`s InfoShop on January 8, 2010. The ESMF for rural electrification, which REA will manage, was disclosed to the public on December 23, 2009. The ESMF is also available at the offices of the REA in Nairobi, and a notice indicating its availability has been posted on the REA website, and was disclosed through the Bank`s InfoShop on January 12, 2010. 164 Annex 11: Assessment of Governance Risk in the Kenyan Power Sector KENYA: Electricity Expansion 1. This section reviews some indicators that can be used to assess the level and risk of poor governance and corruption in the Power sector as recommended in the Sourcebook for Deterring Corruption and Improving Governance in the Electricity Sector, issued to staff in April 2009. This assessment relates to the following issues: · Regulatory environment; · Sector performance; · Sector operations; and · Disclosure of information and social accountability. 2. The specific indicators for each item, their status, and risk ratings are shown in Table 48 below. INT has advised the Project team in the preparation of this assessment, which the team will use during Project supervision to track governance and corruption risks and update as new information becomes available. 165 Table 48: Assessment of Electricity Sector Regulatory and Institutional Framework Indicator Status Risk Assessment Regulatory Environment: Medium Institutional The Energy Regulatory Commission (ERC) has the authority to regulate. This mandate framework for was established through an Act of Parliament. Its specific mandate is defined in the Energy regulatory decisions Act, 2006. Its jurisdiction with regard to setting KenGen`s generation prices was challenged by KenGen in mid-2008 in the Energy Tribunal when it made its first tariff ruling. Following an initial ruling by the Tribunal, the matter was resolved amicably and KenGen and KPLC negotiated Power Purchase Agreements, which were subsequently reviewed and approved by ERC. The ERC has adequate technical capacity. ERC`s technical staff are professionally qualified. The Chairman is a former general manager of an electric utility abroad and has the requisite stature to exercise authority. The required qualifications of the Chairman and the General Manager are stated in the Energy Act 2006. The Chairman: (a) must be a holder of an university degree in engineering, energy, economics, law, finance or physical sciences; and (b) must have at least seven years of experience, five of which at a senior managerial level. ERC's performance is monitored through a performance contract with the Government. ERC also participates in the regulatory peer review of African electricity entities led by experts from the Cape Town university. The latest review in 2009 concluded favorably and identified areas for improvement. ERC also carries out annual satisfaction surveys of its clients, the regulated entities. The ERC is operationally independent. First, the ERC finances its activities from a levy in electricity tariffs (85% in 2009), license fees, the petroleum levy and appropriations by Parliament. The Commission`s Chairman is appointed by the President for four years with a possibility of reappointment for another four years. The President may terminate the appointment of the Chairman on the advice of the Commission for specific reasons stated in the Energy Act 2006. Mechanism of Interested parties can appeal regulatory decisions. Any interested party can -- appeal according to paragraph 26 of the Energy Act, 2006 -- appeal the decision of ERC to the Energy Tribunal, which comprises High Court Judges and Technical Specialists. The Tribunal has only been involved in one case, see above. Tariff policy The tariff policy allows for cost recovery. Subsidies are few and targeted. No constituency, except slum dwellers and low- income households, are given tariff subsidies. In FY2009 and FY2010 there is a small government subsidy to mitigate the cost of emergency generation that was brought in because the worst drought in decades has reduced hydropower output. The tariff review policy is public and has been the supported by the Bank. The Tariff Review Policy is available for inspection at ERC`s website and explains the principles of formation of the tariff. The regulator reviews tariffs every three years. The next review is in 2011 and the ERC has requested the regulated entities to submit data on their costs, revenues and investment plans by December 2010. An international consultant financed from an IDA credit has advised ERC on the tariff calculation methods. There is also a feed-in-tariff to promote private small renewable energy generation projects. 166 Licensing Requirements for private sector entry into the sector appear transparent and (for generation, subject to some independent scrutiny. The Draft Energy (Electricity Licensing) importation or Regulations, 2009 set out requirements to be fulfilled by any person desiring a exportation, license or permit authorizing him to carry out any undertaking in the generation, transmission or transmission, distribution or supply of electrical energy in Kenya. The Regulation distribution of is available at ERC`s website. ERC approves each Power Purchase Agreement electrical energy (PPA) between KPLC and generators. Even though the PPAs are not available to and supply of the general public (as is the case in most countries), the media generally reports electrical energy to widely on their contents and the pass-through fuel cost element of each is available consumers) on KPLC`s website and the Kenya Gazette on a monthly basis. Dissemination of ERC decisions, fuel price adjustments and other key decisions are made public. decisions Regulatory instruments, ERC`s decision, and Gazette notices are posted on ERC`s website. ERC advertizes requests for stakeholder feedback on its proposed decisions in local newspapers. Changes in fuel price adjustments in the electricity tariff are published in the Kenya Gazette monthly and are available on KPLC`s website. Changes in inflation and foreign exchange adjustments are published in the Kenya Gazette semi annually. Sector Performance: Low to medium Electricity coverage Electricity coverage is lower than in countries with similar GDP. About 20% of Kenyan households have electricity in their homes. KPLC is making it more affordable to get connected. Following management changes in KPLC, the company has focused more on its commercial operations since 2006 and has increased electricity connections rapidly. Since the relatively high connection charge can deter lower income households from obtaining a connection, KPLC has introduced two initiatives to reduce the burden: it has teamed up with a commercial bank to offer loans for the connection charge and it has recently introduced an installment payment mechanism for lower income customers who would not be able to obtain the commercial loans. Furthermore, in slum areas, KPLC has set a reduced connection fee of US$15 equivalent in place of the standard connection fee of US$460 equivalent. Rural connections have increased after the creation of the Rural Electrification Authority (REA) in 2007. System losses System losses are lower than in comparator countries. About 17% (physical and commercial transmission and distribution losses combined). Losses are lower than in comparator countries such as Ghana 26%, Nigeria 34%, Ethiopia 19%, Madagascar 24%, Benin 17%, Tanzania 24%, Uganda 30%, and Rwanda 22% though higher than in South Africa (10%) and Vietnam (11% in 2006). KPLC has taken steps to address increasing power theft. The recent financial slow-down and the 2008 tariff increase have led to increased pilferage. In response, KPLC has begun replacing credit meters with pre-payment meters, installing feeder and transformer meters to identify high loss areas, installing security seals in meters for large power consumers and it has initiated a program to convert illegal connections in slums into legal connections through specific technical solutions and lowering both the connections fee and the energy charge. It has also intensified media coverage for raids & arrests as deterrent. This investment project will help reduce technical losses. The Bank will finance new substations, rehabilitation of old substations, upgrading of distribution lines, and the automation of the monitoring and control of networks. 167 Collection ratio KPLC's collection ratio is better than in comparator countries. KPLC collects about 99% of all billed energy, compared to 92% in Tanzania, 93% in Uganda, and 98% in Rwanda. KPLC has taken steps to increase collections. KPLC has automated its meter reading, billing, and collection processes. Meter readings are recorded on hand held computers instead of paper. Consumers can pay their bills at supermarket check-outs, branch offices of commercial banks, at post offices and by using their mobile phones. KPLC has also started to roll-out a debit metering technology. This technology will allow customers to pay for their electricity use in advance and in smaller installments in a similar manner they pay for the pre-paid mobile phone service. Financial viability of In FY2009 KPLC`s and KenGen`s profits before taxation were KSh 5.7 billion (US$76 KenGen and KPLC million) and KSh 5.1 billion (US$68 million), respectively. Sector Operations: Medium Number of KPLC's staffing is higher than in comparator countries. KPLC`s number of customers customers per one per staff (181) is higher than in some comparator countries e.g. Uganda`s private distribution staff company, UMEME has 264 customers per staff. Tanzania and Ethiopia rank below Kenya with 167 and 155 customers per staff respectively. However, because of differences in the customer base and the configuration of the distribution networks, caution should be exercised in making country comparisons. The proportion of operating costs spent on salaries is higher for KPLC (10.7%) and Proportion of utility KenGen (24%) than for Uganda`s UMEME (5%) and Ethiopia`s EEPCO (14%). operating costs spent on salaries However, as was the case for the previous indicator, one should be cautious in drawing conclusions of cross-country comparisons. KenGen for instance is operating more than 50 generating units and also has staff for geothermal development, which the comparator companies do not have. Average The average distribution line costs seem competitive. The recent costs in Kenya have transmission and been US$21,000 and US$18,000 per km for 33 and 11 kV lines respectively. On average, distribution line unit these costs have been about US$20,000 and US$15,000 for 33 and 11 kV lines respectively construction costs in comparator countries. Fuel procurement KenGen, KPLC and IPPs purchase petroleum fuels from the licensed Oil Marketing Companies (OMC) in Kenya. Financial KPLC, KenGen and MoE have in place satisfactory FM and budgeting systems and management and arrangements. KPLC and KenGen use SAP for transaction processing and accounting. budgeting For KenGen, all major elements of internal control are in place including segregation of duties and internal audit committee. However, the FY2009 Management Letter noted some weaknesses that the company is now addressing. For KPLC, all major elements of internal control are in place including segregation of duties and internal audit committee. No major internal audit lapses noted but the Management Letter raised some issues in the FY2009 audit. Both companies have an anti-corruption policy. Audit reports KPLC and KenGen use credible private sector auditing firms. Ernst &Young audits both companies` financial statements. The auditors are not allowed to sell consulting services. KPLC and KenGen make their annual audited financial statements and semi-annual management reports available to the public as per the Capital Market Authority`s rules. KPLC and KenGen distribute their annual reports and accounts to their shareholders. All shareholders are allowed to attend the companies` Annual General Meeting for which notice is posted 21 days before the meeting. 168 Procurement All bid invitations are advertized in local newspapers and in KPLC`s KenGen`s and MoE`s websites. Donor financed procurements are advertized also in Dg Market. All bids are opened in public. KenGen`s and KPLC`s respective Tender Committees (TC) are by law responsible for review and approval of bid evaluation reports and contract awards. The companies` Boards, through their Procurement Oversight Committees (POC) endorse the TC approval for contracts over KSh 50 million (US$650,000). The TC`s invite representatives from professional bodies as observers during its deliberations. Mechanism of There is a National Procurement Appeals Board. Losing bidders frequently refer to the appeal Appeals Board to challenge contract awards by KenGen and KPLC. Appeals usually are from losing bidders contesting contract awards. The following five issues will be monitored: Procurement red (a) Bid evaluation periods. flags (b) Number of responses to bid invitations. (c) Contract management, including number of variation orders. (d) Lowest responsive bid significantly above cost estimates. (e) Nature and frequency of complaints. Disclosure and social accountability: Medium Disclosure of There is a general availability of information on the agency web sites. Information of performance data sector performance is available for investors and the public that is able to access the Internet. Both KenGen and KPLC publish their key performance data in their semi-annual management reports and annual reports and hold annual shareholder meetings. The websites of KenGen, KPLC, MoE and ERC provide general information about the entity and its development strategy, their audited financial statements (KenGen and KPLC), technical performance data, energy saving tips, press releases (KenGen and KLC), tendering opportunities, and accept reader feedback. ERC`s website provides guidance on how to apply for license and how to complain about service provision by licensees. Complaint statistics are not published. Recently, KPLC has published in local newspapers its service standards with clear timelines for how long it takes to deliver various services, e.g. connecting to the grid and rectifying a service disruption. Media coverage Media coverage -- TV and press -- on energy sector issues is extensive. It appears unbiased though may contain technical errors and is oftentimes critical of government, KenGen and KPLC. Consumer and staff KPLC carries out annual customer and staff satisfaction surveys through independent satisfaction surveys auditors. KPLC uses the results to develop corporate strategies to improve its customer service. Performance All the implementing entities have annual performance contracts with Government monitoring that set up targets for their performance over the coming year. The Inspectorate of State Corporations, which is part of the Prime Minister`s Office, monitors achievement of the targets quarterly. The performance contracts are not public but the entities are ranked each year based on their achievement of the targets in the contracts. Third-party KenGen and KPLC are quoted in the Nairobi Stock exchange and therefore subject to high oversight levels of surveillance by market regulators in terms of corporate governance and financial reporting. KenGen and KPLC provide data on their financial performance to the Stock Exchange. KenGen and KPLC invite representatives of professional bodies to observe the deliberations of their Tender Committees in large value cases. Both KPLC and KenGen use independent, external consultants to supervise their major capital projects. 169 Transparency of Draft feasibility studies and other technical assistance documents are shared with key private donor engagement and public sector stakeholders in workshops which help ensure that their views are considered in the final recommendations. Data on donor-financed projects is available in the respective Donor`s website but data on the Government websites is limited. The Ministry of Energy has agreed to publish summaries of the Progress Reports of the Electricity Expansion project on its website. Consultations for Public consultations are mandatory part of Environmental Impact Assessments as per environmental and the Kenya Environmental Management and Co-ordination Act 1999. The National social assessments Environmental Management Authority makes available all draft EAs and provides the public 40 days for feedback. The addressing of the feedback by the project proponent is generally included as a condition for approval of the EA. The government has prepared a Strategic Environmental Assessment for the electricity sector, which included consultations with stakeholders. KenGen has established a Resettlement Implementation Committee for the Olkaria IV geothermal project. It includes the district officer for Naivasha, community elders and representatives for women and vulnerable groups. 170 Annex 12: Project Preparation and Supervision KENYA: Electricity Expansion Planned Actual PCN review September 14, 2009 Initial PID to PIC October 7, 2009 Initial ISDS to PIC November 5, 2009 Appraisal March 1, 2010 Negotiations April 12, 2010 Board/RVP approval May 27, 2010 Planned date of effectiveness September 30, 2010 Planned date of mid-term review October 15, 2012 Planned closing date September 30, 2016 Key institutions responsible for preparation of the project: Kenya Electricity Generating Company Ltd. (KenGen) Kenya Electricity Transmission Company (KETRACO) Kenya Power and Lighting Company Ltd. (KPLC) Rural Electrification Authority (REA) Ministry of Energy (MoE) Bank staff and consultants who worked on the project included: Name Title Unit Paivi Koljonen Lead Energy Specialist AFTEG Kyran O`Sullivan Senior Energy Specialist AFTEG Paul Baringanire Power Engineer AFTEG Dana Rysankova Senior Energy Specialist AFTEG Fabrice Bertholet Senior Financial Analyst AFTEG Samuel O`Brien-Kumi Senior Energy Economist (consultant) AFTEG Edeltraut Gilgan-Hunt Environmental Specialist AFTEN Noreen Beg Senior Environmental Specialist AFTEN Jorge Uquillas Rodas Social Scientist (consultant) AFTEN Dahir Warsame Senior Procurement Specialist AFTPC Josphine Ngigi Financial Management Specialist AFTFM Patrick Umah-Tete Senior Financial Management Specialist AFTFM Nightingale Rukuba-Ngaiza Senior Counsel LEGAF Stephen Mukaindo Counsel LEGAF Luis Schwarz Senior Loan Officer CTRFC Vonjy Rakotondramanana Energy Specialist (Engineer) AFTEG Katherine Steel Energy Specialist/YP AFTEG Janine Speakman Operations Analyst AFTEG Shem Olende Consultant (Rural electrification) AFTEG Julius Muchemi Consultant (Indigenous people) AFTEG Lily Wong Chun Sen Program Assistant AFTEG Caroline Kidiavayi Program Assistant AFCE2 Matthew Mitchell Consultant AFTEG 171 Preparation and Implementation Support Cost Bank funds expended to date on project preparation: 1. Bank resources: US$353,000 2. Trust funds: US$50,000 (AFREA) 3. Total: US$403,000 Estimated Approval and Implementation Support costs: 1. Remaining costs to approval: US$100,000 2. Estimated annual Implementation Support cost: US$332,000 The annual implementation support cost is calculated as follows: 83 staff weeks times US$4,000 per week (average cost) = US$332,000. The estimate takes account of opportunities for sharing of travel and staff cost with the ongoing ESRP. The annual costs will be lower towards the end of the project after resettlement and procurement activities have been completed. The tables below show the implementation support plan and staff complement. Implementation Support Plan: Activity Frequency Remarks Project launch workshop Once Full team. Formal Implementation Review (all Twice a year Full team comprising HQ and CO staff experts including environment, for comprehensive implementation social, FM and procurement) with representatives of cofinanciers. Informal Implementation Review Continuous CO staff, staggered between formal missions. Co-ordination meetings with Quarterly Team leader and CO staff. KenGen and co-financiers of generation component Participation in Sector Working Quarterly CO staff. Group FM review Twice annually CO FM team members. Procurement post review Twice annually (as long as CO Procurement team members. procurement risk is substantial) Environmental safeguards review Three times a year during first HQ environmental specialists with two years, then twice a year support from CO specialists and local consultants. Social safeguards review Three times a year during first HQ social specialists with support three years, then twice a year from CO specialists and local consultants. Review of the first impact Once Full team. assessment with possible fine tuning of the project/program, dissemination of the findings, etc. Mid-term review Once Full team and specialists. Review of the subsequent impact As required Full team. assessments Completion/ICR review Once Full team. HQ=Head Quarters; CO=Country Office. 172 The detailed supervision plan for Financial Management is shown is the table below: FM supervision plan: FM Activity Frequency Desk reviews Interim financial reports review Quarterly Audit report review of the program Annually Review of other relevant information such as interim internal Continuous as they become control systems reports. available On site visits Review of overall operation of the FM system Annually (Implementation Support Mission Monitoring of actions taken on issues highlighted in audit reports, As needed auditors` management letters, internal audit and other reports Transaction reviews (if needed) As needed Fiduciary Review by IAD treasury Annually Capacity building support FM training sessions Before Project start and thereafter as needed Staff Complement: Staff skill required Number Staff Key responsibilities of staff weeks per year Sector Leader 1 1 Coordinate with other sectors. Task Team Leader Manage sector dialogue, donor coordination, and overall project implementation support. Operations Analyst 1 1 Ensure corporate requirements are met. Energy sector specialist ­ 1 4 Review sector reform and development issues and policy and institutional project`s TA components. development Energy sector specialist-rural 1 5 Review status of rural electrification component and the electrification Government overall rural electrification program. Power engineer 1 7 Review technical implementation, project costs, technical aspects of bidding documents, attainment of technical targets. Geothermal specialist 1 2 Review status of geothermal component. Financial analyst 1 3 Review financial performance of implementing entities, attainment of financial performance targets. Environmental specialist (HQ) 1 4 Review implementation of environmental management plans. Environmental specialist 1 5 Review implementation of environmental management (local) plans. Social specialist (HQ) 1 4 Review implementation of RAPs and IPPF. Resettlement specialist (local) 1 8 Review implementation of RAPs. Indigenous Peoples specialist 1 4 Review implementation of IPPF and IPPs. (local) Financial Management 1 5 Review financial management arrangements, FMRs and specialist audits; provide capacity building to implementing entities. 173 Staff skill required Number Staff Key responsibilities of staff weeks per year Procurement specialist 1 5 Review procurement plans and procurement documents; carry out procurement ex-post reviews; provide capacity building to implementing entities Procurement consultant 1 As required Review complex procurement issues. Legal councel 1 1 Review compliance with legal agreements. Communications specialist 1 3 Design and implement communication activities. M&E/impact evaluation 1 3 Review and disseminate evaluation results. specialist Other specialists As required Advise on specific issues as they arise. TOTAL 83 174 Annex 13: Documents in the Project File KENYA: Electricity Expansion Feasibility studies: 1. The Olkaria Optimization Study: Feasibility Study Report for New Units of the Optimization Project, West Japan Engineering Consultant, Inc. with subcontracted Services to GeothermEx, Inc. (USA) and Global Senergy Link (Kenya), August 2009. 2. The Olkaria Optimization Study: Diagnostic Report -- Existing Facilities, West Japan Engineering Consultant, Inc. with subcontracted Services to GeothermEx, Inc. (USA) and Global Senergy Link (Kenya), August 2009. 3. Energy Access Scale-up Program: Final Feasibility Report -- Assignment I, SMEC, April 2009. 4. Energy Access Scale-up Program: Feasibility Report -- Assignment II, Norconsult, August 2009. 5. Energy Access Scale-up Program: Feasibility Report -- Assignment III, Norconsult, August 2009. Project design: 1. Sessional Paper No. 4, 2004 (Energy Policy), Government of Kenya 2. Kenya Electricity Access Investment Prospectus 2009 -- 2014, Ministry of Energy, Kenya, October 2009. 3. Kenya Electrification Investment and Policy Prospectus, Castalia Strategic Advisors, October 2009. 4. Least Cost Power Development Plan, Government of Kenya, 2009. 5. Rural Electrification Master plan, MVV DECON, Germany, in cooperation with Re- Engineering Africa Consortium, Kenya, August 2009. 6. Observations Regarding the Planned Optimization of the Greater Olkaria Geothermal Area, Report of the Board of Consultants to KenGen, August 7, 2009. 7. First Medium-Term Plan, 2008 -- 2012, Kenya Vision 2030, Office of the Prime Minister; Government of the Republic of Kenya 2008. 8. Kenya Country Partnership Strategy for 2010 -- 2013, World Bank, Report No. 52521-KE. 9. Financial forecasts for KenGen and KPLC. 10. Review of Customer Connection Policy, KPLC, 2006. 11. Sourcebook for Deterring Corruption and Improving Governance in the Electricity Sector, issued to staff in April 2009. Safeguards: 1. Environmental and Social Impact Assessment for Olkaria I Unit 4 & 5 Geothermal Project in Naivasha District, GIBB, Africa, December 2009. 2. Environmental and Social Impact Assessment for Olkaria IV (Domes) Geothermal Project in Naivasha District, GIBB, Africa, December 2009. 3. Resettlement Action Plan for Olkaria IV (Domes) Geothermal Project in Naivasha District, GIBB Africa, December 2009. 4. Environmental and Social Impact Assessment for the Kindaruma-Mwingi-Garissa 132 kV transmission line, Norken Engineering and Management Consultants, Kenya, January 2010. 175 5. Resettlement Action Plan for the Kindaruma-Mwingi-Garissa 132 kV transmission line, Norken Engineering and Management Consultants, Kenya, November 2009. 6. Environmental and Social Impact Assessment for the Kisii-Awendo 132 kV transmission line, December, 2009. 7. Resettlement Action Plan for the Kisii-Awendo 132 kV transmission line, December 2009. 8. Environmental and Social Impact Assessment for the Eldoret-Kitale 132 kV transmission line, Otieno Odongo & Partners, Kenya, January 2009. 9. Resettlement Action Plan for the Eldoret-Kitale 132 kV transmission line, Otieno Odongo & Partners, Kenya, January 2009. 10. Environmental and Social Management Framework for the Distribution Component, KPLC, January 2010. 11. Resettlement Policy Framework for the Distribution Component, KPLC, November 17, 2009. 12. Environmental and Social Management Framework for the Rural Electrification Component, REA, December 2009. 13. Resettlement Policy Framework for the Rural Electrification Component, REA, December 2009. 14. Draft Screening of Vulnerable Indigenous Peoples in Kenya, World Bank, March 2010. 15. Indigenous Peoples Planning Framework, Ministry of Energy, January 2010. 16. The Sectoral Environmental Impact Assessment Study, SMEC International Pty. Ltd, August 2009. 17. Memorandum of Understanding between Kenya Wildlife Service and Kenya Electricity generating Company Ltd., Geothermal Development in Hell`s Gate and Longonot National Parks, February 8, 2008. Fiduciary: 1. Financial Management Capacity Assessment of Rural Electrification Authority, November 2009. 2. Procurement Capacity Assessment of Rural Electrification Authority, November 2009. 3. FY 2008/2009 Management Letters for KenGen, KPLC, and MoE. References: 1. The Welfare Impact of Rural Electrification: A Reassessment of the Costs and Benefits, An IEG Impact Evaluation 2008, The World Bank, Washington, D.C. http://www.worldbank.org/ieg 2. Welfare Impacts of Rural Electrification Evidence from Vietnam Policy Research Working Paper 5057, Impact Evaluation Series No. 38 Khandker, Barnes, Samad and Huu Minh, The World Bank, Development Research Group September 2009. 3. Kenya Poverty and Inequality Assessment, July 2008, World Bank, report No. 44190-KE. 4. Kenya Economic Update, December 2009, World Bank. 5. IMF Staff Report for the 2009 Article IV Consultation, January 2010, IMF Country Report No. 10/26. 176 Annex 14: Statement of Loans and Credits KENYA: Electricity Expansion Active Projects Difference Between Last PSR Expected and Actual Supervision Rating Original Amount in US$ Millions Disbursements a/ Development Implementation Project ID Project Name Fiscal Year IBRD IDA GRANT Cancel. Undisb. Orig. Frm Rev'd Objectives Progress P083250 KE-Financial & Legal Sec TA (FY05) S MS 2005 18 15.28836 12.72664623 12.03812 - P078058 KE-Arid Lands 2 SIL (FY03) S S 2003 120 31.42648 38.08605797 -1.55981 P111545 KE-Cash Transfer for OVC (FY09) S S 2009 50 50.09862 0.00000033 P078209 KE-Dev Learning Centre LIL S S 2004 2.7 0.877056 0.51868265 P087479 KE-Edu Sec Sup Project (FY07) S MS 2007 80 26.25541 9.81946465 P083131 KE-Energy Sec Recovery Prj (FY05) S S 2005 160 132.2122 41.91592992 -6.38276 P072981 KE-GEF W KE Int Ecosys Mgmt SIL (FY05) S S 2005 4.1 1.096661 0.98999443 P090567 KE-Inst Reform & CB TA (FY06) MS MS 2006 25 20.6915 17.21472338 P095050 KE-NRM SIL (FY07) MS MS 2007 68.5 59.22162 1.20214646 9.284957 P085414 KE-Natl STATCAP Dev S S 2007 20.5 18.20739 12.84893722 P082615 KE-Northern Corridor Trnsprt SIL (FY04) S S 2004 460 354.5987 79.40739547 -4.21241 P081712 KE-Total War Against HIV/AIDS-TOWA (FY07 MU MU 2007 80 63.7568 50.08033333 P074106 KE-W Kenya CDD/Flood Mitigation (FY07) S S 2007 86 75.33557 4.93227684 P096367 KE-Water & Sanitation Srv Impr (FY08) S S 2008 150 129.9452 7.45639029 P109683 Kenya Agric Productivity & Agribusiness # # 2009 82 84.44425 P085007 MSME Competitiveness MS MS 2005 22 16.01134 14.85172223 Overall Result 1424.7 4.1 1079.467 215.8785855 9.168096 177 KENYA: Electricity Expansion STATEMENT OF IFC`s Held and Disbursed Portfolio In Millions of US Dollars Committed Disbursed Outstanding **Quasi Partici **Quasi Partici FY Approval Company Loan Equity Equity *GT/RM pant Loan Equity Equity *GT/RM pant 2006 Abe-kenya 6 0.48 0 0 0 0 0.48 0 0 0 1997 Aef deras ltd. 1 0 0 0 0 1 0 0 0 0 2004 Bp kenya 0 5 0 0 0 0 3.1 0 0 0 0 Cfc stanbic 0 0 10 0 0 0 0 10 0 0 7/8/1982 Diamond trust 10 4.45 15 0 0 10 4.45 15 0 0 2005 I & m bank 0.6 0 0 0 0 0.6 0 0 0 0 0 Ips(k)-allpack 0 0.36 0 0 0 0 0.36 0 0 0 0 Ips(k)-frigoken 0 0.06 0 0 0 0 0.06 0 0 0 0 Ips(k)-prem food 0 0.11 0 0 0 0 0.11 0 0 0 1996/99/09 K-rep bank 0 3.79 0 0 0 0 1.4 0 0 0 2006 Kingdom hotel 20 0 0 0 0 0 0 0 0 0 2005 Kongoni 0.95 0 0 0 0 0.95 0 0 0 0 2005 Magadi soda co. 0 0 0 3.28 0 0 0 0 1.35 0 2007 Rvr 22 0 10 0 0 0 0 10 0 0 2009 Tel 7 0 0 0 0 0 0 0 0 0 1972 Tps ea ltd. 0 0.04 1.76 0 0 0 0.04 1.76 0 0 2000/07 Tsavo power 4.12 0.83 0.39 0.03 6.42 4.12 0.83 0.39 0 6.42 Total Portfolio: 71.67 15.12 37.15 3.31 6.42 16.67 10.83 37.15 1.35 6.42 * Denotes Guarantee and Risk Management Products. ** Quasi Equity includes both loan and equity types. 178 Annex 15: Country at a Glance KENYA: Electricity Expansion 179 Kenya P R IC E S a nd G O V E R N M E N T F IN A N C E 19 8 7 19 9 7 2006 2007 D o m e s t ic pric e s (% change) Co nsumer prices 8.6 1 1 .4 14.5 2.8 Implicit GDP deflato r 5.4 1 1 .6 9.4 13.1 G o v e rnm e nt f ina nc e (% o f GDP , includes current grants) Current revenue 24.9 20.1 20.9 20.9 Current budget balance 1.7 1.6 -1.8 -3.5 Overall surplus/deficit -3.6 -1.8 -2.4 -7.7 TRADE 19 8 7 19 9 7 2006 2007 (US$ millio ns) To tal expo rts (fo b) 907 2,060 3,437 4,048 P etro leum 77 170 104 50 Co ffee 236 296 138 164 M anufactures 134 458 422 337 To tal impo rts (cif) 1,898 3,289 7,365 7,029 Fo o d 130 158 287 224 Fuel and energy 348 519 1,745 1,946 Capital go o ds 433 844 2,252 2,276 Expo rt price index (2000=100) 20 98 140 139 Impo rt price index (2000=100) 20 81 164 127 Terms o f trade (2000=1 00) 101 121 85 109 B A LA N C E o f P A Y M E N T S 19 8 7 19 9 7 2006 2007 (US$ millio ns) Expo rts o f go o ds and services 1,698 2,975 5,963 5,854 Impo rts o f go o ds and services 2,104 3,770 8,200 9,589 Reso urce balance -406 -794 -2,237 -3,735 Net inco me -280 -172 71 104 Net current transfers 72 516 616 579 Current acco unt balance -614 -450 -1,550 -3,051 Financing items (net) 1,049 451 1,776 3,297 Changes in net reserves -435 -1 -226 -246 M emo : Reserves including go ld (US$ millio ns) 294 811 2,654 3,015 Co nversio n rate (DEC, lo cal/US$ ) 16.5 58.7 72.1 67.3 E X T E R N A L D E B T a nd R E S O UR C E F LO WS 19 8 7 19 9 7 2006 2007 (US$ millio ns) To tal debt o utstanding and disbursed 5,783 6,465 6,534 .. IB RD ,1 1 28 213 0 0 IDA 553 2,032 2,764 2,968 To tal debt service 691 657 433 .. IB RD 145 97 0 0 IDA 7 26 82 88 Co mpo sitio n o f net reso urce flo ws Official grants 246 202 651 .. Official credito rs 228 -69 -131 .. P rivate credito rs 153 -121 -69 .. Fo reign direct investment (net inflo ws) 39 20 51 .. P o rtfo lio equity (net inflo ws) 0 27 2 .. Wo rld B ank pro gram Co mmitments 128 94 286 369 Disbursements 1 13 84 41 159 P rincipal repayments 63 85 60 66 Net flo ws 50 -2 -18 93 Interest payments 89 38 22 22 Net transfers -39 -39 -40 71 No te: This table was pro duced fro m the Develo pment Eco no mics LDB database. 9/24/08 180 Annex 16: MAP IBRD 37769 and MAP IBRD 37774 KENYA: Electricity Expansion 181 IBRD 37769 KENYA E L E C T R I C I T Y E X PA N S I O N P R O J E C T FACILITIES TO BE BUILT UNDER THE PROJECT: EXISTING FACILITIES: MAIN TOWNS GEOTHERMAL UNIT OLKARIA GEOTHERMAL FIELD PROVINCE CAPITALS 132 kV TRANSMISSION LINES 66 kV DISTRIBUTION LINES NATIONAL CAPITAL DENSELY POPULATED AREAS INTERNATIONAL BOUNDARIES 33 kV DISTRIBUTION LINES 66 kV SUBSTATIONS NOTE: 11kV distribution lines to be constructed under the project are not shown on the map. 33 kV SUBSTATIONS Existing electricity infrastructure including power plants, substations, transmission and distribution lines are not shown. Lodwar Lodwar This map was produced by the Map Design Unit of The World Bank. The boundaries, colors, denominations and any other El Molo Camp Turkwel information shown on this map do not imply, on the part of The World Bank Lake Group, any judgment on the legal status of Turkana any territory, or any endorsement or acceptance of such boundaries. Marsabit Turkwel Lokichar La kB 2°N am or Su Nasolot Wajir Lo ga Bo ga l Ortum A ND ANDA U G AND A s Milgi Kapenguria 'iro Ng Kitale Kaplamai Habaswein Ewaso Eldoret Elgon View Isiolo Kakamega Mosoriot Nyahururu Moseno Majengo Lessos Bayette Falls Kianjai 0° Nanyuki Meru Kibos a Kabarak Tan Molo Kisumu Ahero Kipsoen Nakuru Grand Falls Kericho Nyeri Garissa Garissa Embu Homa Bay Kisii Matutu Gilgil Mwingi Litein OLKARIA Muranga Mwea Bomet Naivasha Lake Keroka I & IV Magumu Githunguri Awendo a Gatundu Kindaruma ar M Uplands Juja NAIROBI Victoria Ndenderu Rironi L/Kabete Tana Ngong Ngong Kitui Athi River (Syokimau) Hola Matasia Athi River (EPZ) Thua Kiambu Konza Villa Franka 2°S Magadi hi At T A N Z A N I A Tsav o Tsavo Galana Baricho Malindi Kakuyuni Vol Mavueni Kilifi Mariakani Mishomoroni 4°S Kwajomvu 4°S 0 50 100 Kilometers Mombasa KENYA Kwale Diani Lunga Lunga Mwabungu INDIAN 0 50 100 Miles Shimoni Perani OCEAN 36°E 38°E 40°E MAY 2010 IBRD 37774 KE N YA EL EC TR I C I TY E XPA NS I O N PR O J E CT MAIN CITIES AND TOWNS AREAS OF THE RURAL ELECTRIFICATION SCHEMES TO BE FINANCED BY THE PROJECT IN ITS FIRST YEAR PROVINCE CAPITALS OF IMPLEMENTATION* NATIONAL CAPITAL * 34 Rural Electrification Schemes will be implemented in the First Year of Implementation of the Project. CONSTITUENCY BOUNDARIES In subsequent years additional schemes will be implemented. PROVINCE BOUNDARIES INTERNATIONAL BOUNDARIES 34°E 36°E 38°E 40°E 42°E SU D A N Karungu ETHIOPIA Lokichokio 4°N 4°N Lake Ramu Mandera Kakuma Turkana Sololo North Horr Moyale Lodwar Buna El Wak NDA UGANDA Lokichar South Horr Marsabit Tarbaj 2°N Kangatet 2°N Wajir SIGOR SO M L I SOM A LI A Maralal Kitale Kapedo NORTH Archer's EASTERN NAMBALE WESTERN R I F T VA L L E Y Post Garba Mando Tula Gashi MALAVA Eldoret Marigat BUTERE Kakamega IMENTI Isiolo Mbalambala Butere Nyahururu NORTH Falls EASTERN 0° Nanyuki 0° Kisumu Nakuru N YA N Z A Kericho Nyeri RUNYENJES Garissa Gilgil Embu RANGWE NDHIWA CENTRAL Nguni Lake Karungu Narok Thika Bura Victoria Lolgorien Kolbio NAIROBI NAIROBI Kitui Machakos AREA Konza KAITI Magadi KILOME MAKUENI Bodhei 2°S Ikutha 2°S Garsen Lamu Kibwezi Namanga C O A S T Tsavo Malindi WUNDANYI INDIAN Voi N IA TA N ZA NIA VOI Mackinnon OCEAN Park KALOLENI KENYA 4°S Mombasa This map was produced by the Kwale Map Design Unit of The World MSAMBWENI MATUGA Bank. The boundaries, colors, 0 40 80 120 160 200 Kilometers denominations and any other Shimoni information shown on this map do not imply, on the part of The World Bank Group, any judgment 0 40 80 120 Miles on the legal status of any territory, or any endorsement or 34°E 36°E 38°E 40°E acceptance of such boundaries. APRIL 2010