The World Bank · Kenya Electricity Generating Company : Kenya Power & Lighting Company Ltd....

The World Bank

Report No: ICR2915

IMPLEMENTATION COMPLETION AND RESULTS REPORT (IDA-39580 IDA-45720)

ON

CREDITS

IN THE AGGREGATE AMOUNT OF SDR 108.2 MILLION (US$160.0 MILLION EQUIVALENT)

TO THE

REPUBLIC OF KENYA

FOR

THE ENERGY SECTOR RECOVERY PROJECT

March 27, 2014

Energy Practice Sustainable Development

Africa Region

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CURRENCY EQUIVALENTS

(Exchange Rate Effective 12.31.2013)

Currency Unit = Kenya Shilling KSh 81 = US$ 1

US$ 1.4492 = SDR 1

FISCAL YEAR

July 1 – June 30

ABBREVIATIONS AND ACRONYMS

AF Additional Financing AFD French Development Agency (Agence Française de Développement) CBP Community Benefits Plan CDCF Community Development Carbon Fund CPS Country Partnership Strategy CRP Corporate Recovery Program CF Carbon Finance DO Development Objective EIA Environmental Impact Assessment EIB European Investment Bank EIRR Economic Internal Rate of Return EPC Engineering, Procurement and Construction ERB Electricity Regulatory Board ERC Energy Regulatory Commission ERD External Resources Department ERPA Emission Reduction Purchasing Agreement ERSWEC Economic Recovery Strategy for Wealth and Employment Creation ESIA Environment and Social Impact Assessment ESMP Environment and Social Management Plan FM Financial Management FMRs/IFRs Financial Management Reports/ Interim Financial Reports FY Fiscal Year GoK Government of Kenya GWh Gigawatt-hour ICB International Competitive Bidding ICR Implementation Completion and Results IDA International Development Association IP Implementation Progress IPP Independent Power Producer ISR Implementation Status and Results KEBS Kenya Bureau of Standards KEEP Kenya Electricity Expansion Project KenGen Kenya Electrical Generating Company KETRACO Kenya Electricity Transmission Company

KKCFUP Kenya KenGen Carbon Finance Umbrella Project km Kilometer KPLC Kenya Power and Lighting Company KPRL Kenya Petroleum Refineries Limited KSh Kenyan Shilling kV Kilovolt kWh Kilowatt-hour LCPDP Least-Cost Power Development Plan LOC Letter of Credit LPG Liquefied Petroleum Gas M&E Monitoring and Evaluation MoE Ministry of Energy MOEP Ministry of Energy & Petroleum MIS Management Information System MSC Management Services Contract MV Medium Voltage MW Megawatt NDF Nordic Development Fund NEMA National Environment Management Authority NET National Environment Tribunal NOCK National Oil Corporation of Kenya NPV Net Present Value O&M Operations and Maintenance OPRC Operational Procurement Review Committee PAD Project Appraisal Document PDO Project Development Objective PIT Project Implementation Team PPA Power Purchase Agreement PPIAF Public-Private Infrastructure Advisory Facility PRG Partial Risk Guarantee RAP Resettlement Action Plan REA Rural Electrification Authority SCADA/EMS Supervisory Control and Data Acquisition/Energy Management System T&D Transmission and Distribution tCO2e Tons of Carbon Dioxide Equivalent UNFCCC United Nations Framework Convention on Climate Change

Vice President: Makhtar Diop Country Director: Diarietou Gaye

Sector Manager: Lucio Monari Project Team Leader: Mitsunori Motohashi

ICR Team Leader: Mitsunori Motohashi

KENYA ENERGY SECTOR RECOVERY PROJECT

CONTENTS

Data Sheet

A. Basic Information B. Key Dates C. Ratings Summary D. Sector and Theme Codes E. Bank Staff F. Results Framework Analysis G. Ratings of Project Performance in Implementation Status and Results (ISRs) H. Restructuring I. Disbursement Profile

1. Project Context, Development Objectives, and Design .............................................. 1

2. Key Factors Affecting Implementation and Outcomes .............................................. 7

3. Assessment of Outcomes .......................................................................................... 15

4. Assessment of Risk to Development Outcome ....................................................... 211

5. Assessment of Bank and Borrower Performance ................................................... 211

6. Lessons Learned...................................................................................................... 243

7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners........... 25

Annex 1. Project Costs and Financing ........................................................................... 266

Annex 2. Status of Outputs ............................................................................................ 277

Annex 3. Case of the Geothermal Generation EPC Procurement ................................. 311

Annex 4. Economic Analysis ......................................................................................... 344

Annex 5. Bank Lending and Implementation Support/Supervision Processes .............. 377

Annex 6. Beneficiary Survey Results .............................................................................. 39

Annex 7. Stakeholder Workshop Report and Results .................................................... 400

Annex 8. Summary of Borrower's ICR and/or Comments on Draft ICR ...................... 411

Annex 9. Comments of Co-financiers and Other Partners/Stakeholders ....................... 466

Annex 10. List of Supporting Documents ...................................................................... 477

Annex 11. Kenya KenGen Carbon Finance Umbrella Project—Implementation Completion and Results Report ........................................................................................ 49

Annex 12 Reallocations of Credit Proceeds .................................................................. 611

MAP ................................................................................................................................ 622

A. Basic Information

Country: Kenya Project Name: Energy Sector Recovery Project

Project ID: P083131 L/C/TF Number(s): IDA-39580, IDA-45720

ICR Date: 02/25/2014 ICR Type: Core ICR

Lending Instrument: Specific Investment Loan

Borrower: REPUBLIC OF KENYA

Original Total Commitment:

XDR 55.20M Disbursed Amount: XDR 101.27M

Revised Amount: XDR 108.20M Environmental Category: B Implementing Agencies: Kenya Electricity Generating Company Kenya Power & Lighting Company Ltd. Ministry of Energy and Petroleum Co-financiers and Other External Partners: AGENCE FRANCAISE DE DEVELOPPEMENT European Investment Bank Nordic Development Fund B. Key Dates

Process Date Process Original Date Revised/Actual Date(s)

Concept Review: 01/22/2004 Effectiveness: 11/04/2004 11/04/2004

Appraisal: 03/08/2004 Restructuring(s):

10/02/2007 11/26/2008 04/02/2009 05/02/2012 04/15/2013

Approval: 07/13/2004 Mid-term Review: 11/30/2011 11/28/2011 Closing: 03/31/2010 09/30/2013 C. Ratings Summary C.1 Performance Rating by ICR Outcomes: Moderately Satisfactory Risk to Development Outcome: Substantial Bank Performance: Moderately Satisfactory Borrower Performance: Moderately Satisfactory

C.2 Detailed Ratings of Bank and Borrower Performance (by ICR) Bank Ratings Borrower Ratings

Quality at Entry: Satisfactory Government: Moderately Satisfactory

Quality of Supervision: Moderately Satisfactory Implementing Agency/Agencies: Moderately Satisfactory

Overall Bank Performance: Moderately Satisfactory Overall Borrower

Performance: Moderately Satisfactory

C.3 Quality at Entry and Implementation Performance Indicators

Implementation Performance Indicators QAG Assessments

(if any) Rating

Potential problem project at any time (Yes/No):

No Quality at Entry (QEA):

None

Problem project at any time (Yes/No):

No Quality of Supervision (QSA):

None

DO rating before closing/inactive status:

Satisfactory

D. Sector and Theme Codes

Original Actual Sector Code (as % of total Bank financing) Central government administration 3 15 Energy efficiency in heat and power 22 2 Oil and gas 12 1 Thermal power generation 41 16 Transmission and distribution of electricity 22 66

Theme Code (as % of total Bank financing) Corporate governance 14 10 Infrastructure services for private-sector development 14 2 Regulation and competition policy 29 20 State-owned enterprise restructuring and privatization 14 6 Urban services and housing for the poor 29 62 E. Bank Staff

Positions At ICR At Approval Vice President: Makhtar Diop Callisto Madavo Country Director: Diarietou Gaye Makhtar Diop Sector Manager: Lucio Monari Yusupha B. Crookes Project Team Leader: Mitsunori Motohashi Joel J. Maweni

ICR Team Leader: Mitsunori Motohashi ICR Primary Author: Mitsunori Motohashi Joseph W. B. Bredie F. Results Framework Analysis Project Development Objectives (PDOs) (from Project Appraisal Document) The development objectives of the project are to: (1) enhance the policy, institutional, and regulatory environment for private- sector participation and sector development; (2) support efficient expansion of power generation capacity to meet the economy's supply deficits projected to occur by 2006/7; and (3) increase access to electricity in urban and peri-urban areas, while improving the efficiency, reliability, and quality of service to existing customers. Revised PDOs (as approved by original approving authority) The development objectives are to (1) enhance the policy, institutional, and regulatory environment for sector development, including private-sector development; and (2) increase access to electricity in urban and peri-urban areas, while improving the efficiency, reliability, and quality of service to customers. (a) PDO Indicator(s)

Indicator Baseline Value

Original Target Values (from

approval documents)

Formally Revised Target Values

Actual Value Achieved at

Completion or Target Years

Indicator 1 : An adequate national energy policy for efficient development and operation of the sector adopted by the GoK.

Value quantitative or Qualitative)

No energy policy Energy Policy adopted Energy Policy

adopted

Date achieved 1-Jan-2004 31-Dec-2005 12/31/2004 Comments (incl. % achievement)

Fully Achieved. At the Restructuring and Additional Financing of 2009, this indicator reformulated as an intermediate outcome indicator (IOI) for Component A. See IOI 2 below.

Indicator 2 : Energy Law to support implementation of the National Energy Policy is passed and implemented.


Electricity law inadequate to support envisaged regulatory changes

Energy Act implemented

Energy Act is largely implemented

Date achieved 31-Dec-2004 30-Sep-2013 30-Sep-2013 Comments (incl. % achievement)

Substantially Achieved. The Energy Act was passed in 2006. 12 regulations remain to be gazetted at project closing but will be reviewed as part of energy policy and act amendments. This indicator was reworded slightly in 2009.

Indicator 3 : About 276 GWh of additional energy generated per annum (at plant load factor

of about 95%) representing an increase in national power production of about 5%.


0 GWh 276 GWh 0 GWh

Date achieved 31-Dec-2004 30-Jun-2009 30-Jun-2009 Comments (incl. % achievement)

At the Restructuring and Additional Financing of 2009, this indicator was reformulated as an intermediate outcome indicator. See IOI 5 below.

Indicator 4 : About 400,000 new customers to be connected by FY2008/09, representing an increase of about 67% of KPLC’s customers.


0 400,000 240,000


At the Restructuring and Additional Financing of 2009, this indicator was reformulated as IDA core indicator. See PDO indicator (PDOI) 10 below.

Indicator 5 : System losses reduced from about 18.7% in FY2003/04 to about 14.5% by FY2008/09


18.7% 14.5% 16.3%


At the Restructuring and Additional Financing of 2009, this indicator was reformulated as an intermediate outcome indicator. See IOI 3 below.

Indicator 6 : Availability of transmission lines to be improved and power outages reduced to levels considered reasonable for KPLC’s system.


(i) Number of line interruptions per 100 km per month shall not exceed 0.19 for 220kV, 0.50 for 132 kV, and 2.0 for 66 kV; (ii) Availability of 220kV and 132 kV lines shall not be less than 97%.

Availability of transmission lines improved and power outages reduced. (i) Number of average line interruptions was 3.0 by May 2009. (ii) Availability of 200kV and 132kV transmission lines about 99% in FY 2007/08 above the target of 97%.


At the Restructuring and Additional Financing of 2009, this indicator was reformulated as an intermediate outcome indicator. See PDOI 11 below.

Indicator 7 :

Total monthly outages of 11,000 (about 1.54 per 100 customers) to be reduced to no more than 4,000 (0.41 per 100 customers) by the Project Completion Date, September 30, 2009


11,000 4,000 Outages declined to 5,771 monthly incidents

Date achieved 31-Dec-2004 30-Jun-2009 31-Dec-2008 Comments (incl. % achievement)

At the Restructuring and Additional Financing of 2009, this indicator was dropped as the outcome is better measured by the revised PDOI 11.

Indicator 8 : Increase in the number of Independent Power Producers. Value quantitative or Qualitative)

2 8 7


Target substantially achieved (88%). Three additional IPPs will be connected to the national grid by 2014. At the Restructuring and Additional Financing of 2009, this indicator was added.

Indicator 9 : Percentage of disputes and complaints resolved annually by the ERC. Value quantitative or Qualitative)

ERC was not yet established 95% 76%


Target Substantially achieved. In 2012, the rate was 85%. The target falls short in some years, as some complaints are filed toward the end of the reporting period. At the Restructuring and Additional Financing of 2009.

Indicator 10 : Households connected to electricity under the project. Value quantitative or Qualitative)

0 450,000 526,000

Date achieved 31-Dec-2004 30-Sep-2013 30-Sep 2013 Comments (incl. % achievement)

Target exceeded (117%). At the Restructuring and Additional Financing of 2009, this indicator was added.

Indicator 11 : Number of combined monthly distribution line interruptions per 100 km, for 66 kV and 33 kV lines.


4.7 2 2.92


Target achieved in FY2010-12. It fell short in FY2013 due to rapid expansion of connections. At the Restructuring and Additional Financing of 2009, this indicator was added.

(b) Intermediate Outcome Indicator(s)

Indicator Baseline Value

Original Target Values (from

approval documents)

Formally Revised

Target Values

Actual Value Achieved at

Completion or Target Years

Indicator 1 : Sector regulatory agency is established, fully staffed and operation. Value (quantitative or Qualitative)

No sector-wide regulatory agency

ERC is fully operational

ERC is fully operational


Fully Achieved. ERC effectively sets tariffs in 2008 and 2013.

Indicator 2 : National energy policy for efficient development and operation of the sector is adopted and implemented by the GoK

Value (quantitative or Qualitative)

No National Energy Policy

National energy policy in place National energy

policy in place

Date achieved 1-Jan-2004 31-Dec-2005 31-Dec-2004 Comments (incl. % achievement)

Fully Achieved.

Indicator 3 : Annual transmission and distribution losses(% of energy purchased by KPLC) Value (quantitative or Qualitative)

18.7% 14.5% 15.2% 18.6%

Date achieved 31-Dec-2004 30-Jun-2009 30-Sep-2013 30-Sep-2013 Comments (incl. % achievement)

Partially Achieved. Initially trending toward the target, there was an increase in losses to 17.3% in FY12 due in large part to government's aggressive expansion of the national grid into rural areas, which was introduced after the project.

Indicator 4 : Generation Capacity added under the project, additional (MW) Value (quantitative or Qualitative)

0 35 MW 35 MW of capacity added.

Date achieved 31-Mar-2009 30-Sep-2013 31-May-2010 Comments (incl. % achievement)

Fully Achieved. The Olkaria Unit 3 (35MW) became fully operational in May 2010.

Indicator 5 : Electricity generation added under the project, annual net (GWh).

Value (quantitative or Qualitative)

0 276 GWh

296 GWh (FY2011), 280 GWh (FY2012), 255 GWh (FY2013)

Date achieved 31-Mar-2009 30-Sep-2013 30-Sep-2013

Comments (incl. % achievement)

Achieved. Target exceeded in FY11 and FY 12, dip in output in FY 13 was due to maintenance work being carried out. At the Restructuring and Additional Financing of 2009, this indicator was added.

Indicator 6 : Kilometers of distribution lines constructed or rehabilitated under the project. Value (quantitative or Qualitative)

0 1,775 2,114


Target exceeded. At the Restructuring and Additional Financing of 2009, this indicator was added.

Indicator 7 : Number of substations constructed or rehabilitated under the project. Value (quantitative or Qualitative)

0 45 48


Target exceeded (106%). At the Restructuring and Additional Financing of 2009, this indicator was added.

G. Ratings of Project Performance in Implementation Status and Results (ISRs)

No. Date ISR Archived DO Implementation

Progress (IP)

Actual Disbursements (USD millions)

1 12/22/2004 Satisfactory Satisfactory 0.00 2 12/30/2004 Satisfactory Satisfactory 0.00 3 06/22/2005 Satisfactory Satisfactory 1.54 4 12/22/2005 Satisfactory Satisfactory 3.35 5 06/30/2006 Satisfactory Satisfactory 4.15 6 12/23/2006 Satisfactory Satisfactory 5.22 7 06/27/2007 Moderately Satisfactory Moderately Satisfactory 6.52 8 12/20/2007 Satisfactory Satisfactory 11.19 9 06/08/2008 Satisfactory Satisfactory 13.63

10 12/20/2008 Satisfactory Satisfactory 19.45 11 06/16/2009 Satisfactory Satisfactory 27.89 12 11/28/2009 Satisfactory Satisfactory 45.65 13 06/08/2010 Satisfactory Satisfactory 59.90 14 03/29/2011 Satisfactory Satisfactory 79.82 15 10/09/2011 Satisfactory Satisfactory 95.91 16 05/29/2012 Satisfactory Satisfactory 107.96 17 01/25/2013 Satisfactory Moderately Satisfactory 114.27 18 11/11/2013 Moderately Satisfactory Moderately Satisfactory 143.95

H. Restructuring Restructuring

Date(s) Board-

Approved ISR Ratings at Restructuring

Amount Disbursed at

Reason for Restructuring & Key Changes Made

PDO Change DO IP

Restructuring (in USD millions)

11/26/2008 N S S 18.69 Reallocations to improve disbursement.

04/02/2009 N S S 21.91

Expand the impact of the project by increasing new connections, providing additional financing to address price escalations, and adjusting the PDOs and results indicators.

I. Disbursement Profile

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1. Project Context, Development Objectives, and Design

1.1 Context at Appraisal 1. Country Context. In the late 1990s, Kenya experienced a slowdown in growth that led to poverty increasing from 48 percent of the population in 1990 to 56 percent by 2003. Agriculture and manufacturing stagnated, and the quality of energy and infrastructure services declined. Only about 15 percent of the population had access to electricity. Poor economic governance and an uncertain political environment led to a decline in official development assistance and private capital inflows. In March 2004, the new government (which had come into office in 2002), formulated an Economic Recovery Strategy for Wealth and Employment Creation (ERSWEC), which emphasized accelerating economic growth and creating employment, increasing productivity, delivering basic services, and distributing national income equitably. 2. Sector Policy. The Government of Kenya (GoK) recognized that energy services are a critical input to economic activity, contribute to employment and fiscal revenue, and are indispensable to the success of ERSWEC. To realize the energy sector’s potential, the GoK formulated a long-term vision and policy framework to address key sector challenges. The first generation reform, undertaken in the 1990s with support from the World Bank, included unbundling of power generation from transmission and distribution (T&D); adjustment of tariffs; reform of the legal and regulatory environment to open up the power subsector to private investment; introduction of the first Independent Power Producers (IPPs); and liberalization of importation, pricing, and marketing for petroleum products. In further expansion of this support, it was envisaged that a second generation of reforms would be required to continue to address challenges that remained in the sector, including the weak legal and regulatory framework, the monopolistic industry structure and performance of the entities, and low access rates since these issues constrained the efficient and effective operation and development of the sector. 3. Weak Legal and Regulatory Framework. The energy sector was governed principally by the 1997 Electric Power Act and the Petroleum Act, Cap 116. The former governed the generation, transmission, and distribution of electricity and funding for the rural electrification program. The Electricity Regulatory Board (ERB) regulated the sector, but was subject to the provisions of the State Corporations Act exposing it to external interference. ERB’s capacity to set tariffs, review power purchase agreements (PPAs), and monitor and enforce regulation was limited. The licensing of operators and dispute resolutions was vested in the Ministry of Energy (MoE). In the petroleum subsector, several statutes apart from the Petroleum Act, Cap 116, governed petroleum product standards, marketing, and licensing. With the deregulation of petroleum importation, pricing, and marketing, additional operators entered the market, straining the capacity of local jurisdictions to regulate and monitor product standards and compliance with safety and environmental regulations.

4. Structure of Energy Sector. Power generation was dominated by the state-owned Kenya Electricity Generating Company (KenGen), with 88 percent of the country’s generating capacity of 1,124 megawatts (MW); IPPs provided the remaining generation. Three IPPs were generating power as a result of the first generation reforms undertaken in the 1990s. In transmission and distribution, the Kenya Power and Lighting Company (KPLC), a publicly quoted company, was

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the sole licensed bulk power purchaser and distributor that owned and operated the country’s 2,035 kilometers (km) of transmission network. Overstaffed and financially weak, KPLC lost approximately US$30–40 million a year between FY2000 and FY2003. Collection of accounts receivables was taking approximately 70 days on average. As a consequence, investment in productive assets was taking place on a small scale.

5. In the petroleum subsector, the Kenya Petroleum Refinery Limited (KPRL) was 50 percent owned by the GoK, with the remaining shares owned by Shell, BP, and Caltex. KPRL was protected by import tariffs and quantitative measures, which enabled it to supply the domestic liquefied petroleum gas (LPG) market. The National Oil Corporation of Kenya (NOCK), also owned by the GoK, controlled petroleum exploration and oil products supply and distribution. 6. Low Access to Reliable Energy Services. Limited access to electricity (15 percent of the general population and only about 4 percent of the rural population) and poor quality of electricity service was a significant constraint to economic and commercial development as well as to improving the quality of life. Expanding access required significant financial resources, exceeding what was available in the public budget. Furthermore, the cost of rural electrification, where 80 percent of the population resides, was also high. Rural electrification depended on KPLC for distribution and access, and on the Rural Electrification Fund for financing. KPLC was ill-equipped to serve outlying areas, lacking both financial capacity and operating standards. As a result, even in the areas within reach of the national grid, new connections were taking place slowly, with only between 20,000-50,000 incremental customer connections per year. Finally, the quality of electricity supply was inadequate, with system losses close to—or in some years exceeding—20 percent, and frequent occurrence of supply interruptions and outages. 7. Sector Performance. Reflecting these problems, overall energy sector performance was inadequate, with low access to modern energy services; an insufficient level of investment, especially in power generation and distribution; poor quality of electricity supply; and weak institutions to implement and sustain activities. The demand-and-supply balance was also tight, and the utilities had to procure high-cost emergency power when droughts reduced hydropower generation. Based on the medium-case electricity demand growth scenario of about 6 percent per year from FY2003 to FY2008, additional generation capacity was forecast to be needed in FY2007. As it turned out, the demand growth projections at the time of appraisal were accurate, and a shortfall in power actually occurred in FY2006/07, which had to be met by the addition of a 100-MW capacity of emergency power.

8. Development Partnerships in the Sector. The Bank took the leading role among the GoK’s development partners on sector reform dialogue and adopted a coordinated approach in supporting first generation reforms. A large part of development partners’ support, which was starting to decline before the project, focused mostly on power generation and, to a lesser extent, on off-grid energy access. In this context, a second generation of reforms—supporting further unbundling of transmission from distribution and improving governance, infrastructure, and institutions—was undertaken under the Energy Sector Recovery Project (ESRP), accompanied by investments in power generation and distribution to expand access to electricity and to meet the anticipated supply deficit. The 2004 National Energy Policy, i.e. the long-term vision and policy framework that the GoK formulated to reform the sector, was based on a number of preceding

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studies and workshops. These included the Energy Sector Development Strategy, the Power Market Design and Pre-privatization Study, and the National Energy Policy Workshop conducted in February 2004, all of which were supported by the International Development Association (IDA) with funds from the Public-Private Infrastructure Advisory Facility (PPIAF).

1.2 Original Project Development Objectives (PDOs) and Key Indicators 9. The original ESRP’s development objectives were to (1) enhance the policy, institutional, and regulatory environment for private-sector participation and sector development; (2) support efficient expansion of power generation capacity to meet the economy's projected supply deficits by FY2006/07; and (3) increase access to electricity in urban and peri-urban areas, while improving the efficiency, reliability, and quality of service to existing consumers. 10. Progress toward these objectives was to be measured by the following indicators: Policy, Institutional, and Regulatory Environment (i) Adopt an adequate national energy policy, consistent with efficient development and operation

of the sector. (ii) Pass an adequate energy law, including regulatory arrangements designed to effectively

support implementation of the National Energy Policy. Efficient Expansion of Power Generation Capacity (iii) Generate about 276 gigawatt-hours (GWh) of additional energy per year (at plant-load factor

of about 95 percent) representing an increase in national power production of about 5 percent Increase in Access to Reliable and Quality Electricity (iv) Connect about 400,000 new customers by FY2008/09, thus increasing access to electricity

from the current 15 percent by an additional 5 percent of the population by the same date. (v) Reduce system losses from about 18.7 percent in FY2003/04 to about 14.5 percent by

FY2008/09. (vi) Improve the availability of transmission lines and reduce power outages to levels considered

reasonable for KPLC’s system. (vii) Reduce total monthly outages of 11,000 (about 1.54 per 100 customers) to no more than

4,000 (0.41 per 100 customers) by the project completion date of September 30, 2009.

1.3 Revised PDOs (as approved by original approving authority), Key Indicators, and Reasons/Justification 11. In 2009, as part of additional financing and project restructuring, the PDOs were modified to remove one of the original objectives while the other two objectives were maintained. The revised PDOs are to (1) enhance the policy, institutional, and regulatory environment for sector development, including private-sector development; and (2) increase access to electricity in urban and peri-urban areas, while improving the efficiency, reliability, and quality of service to customers. The original objective to support efficient expansion of power generation capacity to meet the economy’s projected supply deficit by FY2006/07 was changed to an intermediate indicator, because that expansion was considered an intermediate outcome indicator for the

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objective on increasing access to electricity (see below). Achievement of the initial generation objective had been delayed, and was now expected in 2010. 12. Progress toward achieving the modified objectives was to be measured by the following outcome indicators: Policy, Institutional, and Regulatory Environment: (i) Energy law supporting the implementation of the National Energy Policy is passed and

implemented. (ii) Increase in the number of IPPs. (iii) The percentage of disputes and complaints resolved annually by the ERC is increased. Increase in Access to Reliable and Quality Electricity: (iv) Access expansion—The number of households connected to electricity under the project is

increased. (v) Quality improvement—The number of combined monthly distribution line interruptions per

100 km for 66-kilovolt (kV) and 33-kV lines is reduced.

1.4 Main Beneficiaries 13. The main beneficiaries included those people who are already connected to the national grid and who would benefit from improved supply of electricity. The distribution component was envisaged to connect 400,000 customers to electricity, a significant portion of whom would be poor and economically marginalized households, farmers, and small informal business owners. This would improve living conditions for the poor and stimulate the informal sector (called ‘Jua Kali’ in Kenya). Other potential beneficiaries included prospective private power investors and operators who would benefit from additional opportunities to participate in the electricity market. MoE and utilities in the energy sector, as well as local and foreign contractors and workers for the generation and distribution works, were also considered to be beneficiaries.

1.5 Original Components 14. The original project had four components: A. Institutional and Capacity-Building Component (US$6.30 million: US$6.25 million International Development Association (IDA); US$0.05 million GoK). Activities include (1) implementing a comprehensive Corporate Recovery Program (CRP) for KPLC through engagement of a management services provider; (2) strengthening the sector regulator’s capacity to review and set power tariffs, prepare secondary legislation, and enforce regulations under the law; (3) equipping the Kenya Bureau of Standards (KEBS) with the skills, training, and equipment necessary for effectively setting and monitoring the standards of petroleum products in the country; (4) upgrading staff skills in MoE and KenGen; and (5) implementing a management and staff development program for KPLC.

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B. Feasibility Studies and Engineering Services Component (US$11.75 million: US$11.06 million IDA; US$0.54 million KenGen; US$0.15 million GoK). Activities include carrying out (1) environmental and social impact assessments (ESIAs) for the generation and distribution components of the ESRP and for the LPG import handling and storage project; (2) consultancy services to update the Kipevu combined-cycle power plant feasibility study; (3) consultancy services for the distribution upgrade component; (4) engineering services for the supervision of the distribution component; (5) a feasibility study and preliminary and detailed designs for the proposed LPG import handling and storage project; (6) a geothermal reservoir optimization study for the Olkaria I and II sites; (7) a study to establish a geothermal development company and preparation of a business plan for the company; (8) consultancy services for preliminary design and supervision of the Olkaria II power plant extension; (9) consultancy services for the detailed design and supervision of the Supervisory Control and Data Acquisition/Emergency Management System (SCADA/EMS); and (10) consultancy services for preparation of future energy projects. C. Generation, Olkaria II Power Plant Extension (US$54.93 million: US$24.01 million IDA; US$24.01 European Investment Bank (EIB); US$6.90 million KenGen). Activities include (1) providing civil works for the extension of the powerhouse to accommodate the third 35-MW steam turbine generating unit, control panel and other ancillary equipment, cooling tower, and switchyard for installing a generator transformer, support bus-bar arrangement, and switchgear equipment; (2) supplying and installing a steam-gathering system from Olkaria I and Olkaria II sites and connecting pipes to the third Olkaria II unit; (3) supplying and installing a 35-MW steam turbine generating unit; (4) supplying and installing a 45-medium-voltage (MV), 11/220-kV step-up generator transformer, complete with switchgear equipment; and (5) supplying and installing other electrical and mechanical equipment, including control room equipment, cables, and other ancillary equipment. D. Distribution Upgrading (US$152.49 million: US$38.64 million IDA; US$51.09 million EIB; US$25.00 million Agence Française de Développement (AFD [French Development Agency]); US$12.00 million Nordic Development Fund (NDF); US$25.77 million KPLC). Activities include (1) upgrading existing and constructing new substations; (2) reinforcing and extending the distribution system; (3) supplying energy meters; (4) upgrading the SCADA/EMS system, including providing a trunked radio system for the Mt. Kenya region.

1.6 Revised Components 15. During both project implementation and the 2009 additional financing (AF) operation, some activities were dropped and new activities were added. A. Institutional and Capacity Building (AF—US$1.1 million IDA). The AF supported training of (1) KPLC, MoE, and Rural Electrification Authority (REA) staff on procurement, contract management, environmental and social impact analysis, the use of geographic information system (GIS)-based electrification modeling and planning for electricity access scale-up preparation; and (2) electrical installation contractors to improve and increase local capacity for installation works. B. Studies and Engineering Services (AF—US$7.2 million IDA). The ESIA for the LPG import handling and storage project was dropped because it was financed by a private company engaged in construction of the facility. The following studies and engineering services were added during project implementation: (1) a study for unbundling KPLC and establishing the KETRACO; (2) a Transmission System Master Plan, including a study for a 132-kV/220-kV ring system for Nairobi; (3) a study to evaluate the technical merits and assess the economic benefits of the 132-

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kV and MV (66-kV, 33-kV, 11-kV) systems needed to cope with the additional customer connections planned in the access scale-up program; (4) preparation of tender documents for the generating plant; (5) a study to assess the short- and medium-term impacts of the electricity access scale-up program on the operations of KPLC (billing, meter reading, collections, etc.); (6) development of monitoring and evaluation methods for implementing the GoK’s electricity access scale-up program; (7) an energy sectoral environmental assessment; (8) provision for wind masts, data loggers, software, and other equipment to assist MoE to carry out feasibility studies on wind power generation; (9) advising on the management/concessioning of electricity systems that are not connected to the national grid; (10) a feasibility study for an LNG regasification plant; (11) biogas consultancy to implement pilot plants in collaboration with flower farms; and (12) a study on the national electricity power system. C. Generation, Olkaria II Power Plant Extension (AF—US$64.2 million: US$26.0 million AFD; US$26.0 million EIB; US$12.2 million KenGen).1 KenGen, AFD, and EIB financed the increased cost for the third unit at the Olkaria II power plant. D. Distribution (AF—US$77.1 million: US$68.9 million IDA; US$8.2 million KPLC). The AF revived items that were trimmed from the original design: (1) reconductoring about 228 km of 11-kV lines in the areas of Malindi (25 km), Nairobi (103 km), and West Kenya (100 km); (2) reconductoring about 270 km of 33-kV lines in West Kenya; (3) installing 11-kV switchgear at various substations and line sectionalizes; (4) financing extensions of the distribution network, transformers, and meters in the Nairobi, Western, Central, and Coast provinces; (5) financing four to six transformer substations in the residential areas of Nairobi that are experiencing high electricity demand growth; (6) installing underground cables in Mombasa; and (7) procuring spare substation transformers, distribution transformers, conductors, insulators, stay rods, and pole accessories.

1.7 Other Significant Changes 16. After project appraisal and approval in 2004, prices for works, goods, and services began increasing, requiring an AF, reallocations, and extensions of the closing date. The largest price increase occurred with the engineering, procurement and construction (EPC) contract for the third unit at Olkaria II. The lead times in procurement processes, worldwide price increases in commodities, and force majeure resulted in substantial price escalations for the EPC contract. The price escalations required the AF discussed below. There were also financing shortfalls in the study component, specifically in the contract for engineering services and the study for optimizing geothermal resources, due to a contract extension following delays in obtaining drilling data and with Olkaria II Unit 3 construction. In the distribution component, prices for aluminum and copper almost doubled between 2004 and 2008, increasing the world prices of electrical goods, such as conductors and transformers. New funding from the AF of US$80 million and reallocations, which were approved by the Bank’s Board in February 2009, addressed these shortfalls. In addition to the AF, four reallocations were undertaken to meet changing circumstances before project closing. The reallocations are summarized in Annex 11.

1 IDA AF was not proposed to meet the increased costs of the third unit at the Olkaria II plant. At the time of the AF in 2009, about US$21 million of the original financing of the costs at appraisal of US$54.93 million (US$24 million IDA; US$24 million EIB; US$6.93 million KenGen) had been disbursed. The AF required was to be provided by EIB, AFD and KenGen.

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2. Key Factors Affecting Implementation and Outcomes

2.1 Project Preparation, Design, and Quality at Entry 17. The ESRP’s design was based on a series of past Bank engagements in the sector, together with a solid understanding and background assessment of the reform measures as well as investment needs. A number of studies, including those supported with funding from the PPIAF, informed the roadmap for reform measures as well as stakeholder engagement. The Task Team Leader, who managed preparation and appraisal, had been involved in the sector since the 1990s, and had identified and supervised the preceding Energy Sector Reform Project, which was approved in 1997. This preceding operation contributed to first generation reforms, including the introduction of private-sector participation in power generation, the establishment of the ERB, and the unbundling of generation from transmission and distribution (T&D). The Bank was involved in the process through policy dialogue and workshops, which led to the formulation of key policies for further sector reform that address: the monopolistic structure of the sector and performance of the main sector entities; the weak legal and regulatory framework; and the country’s low electricity access rate. The ESRP’s design was fully aligned with the GoK’s long-term vision and policy framework which addressed the aforementioned issues in the energy sector. 18. The investment needs and project scope were also evaluated based on a number of studies and reviews undertaken both by reputable consultants and the Bank. Generation expansion was considered in the context of the Least-Cost Power Development Plan (LCPDP), which, after a series of reviews on proposed thermal expansion, placed geothermal power as the least-cost option to meet the anticipated power shortfall at the time. Based on the assessment of least-cost options, the generation component was changed from the initial proposal at the time of the Project Concept Note, which was the conversion of two 30-MW gas turbines at Kipevu to combined-cycle operation, to a 35-MW geothermal power plant installation at Olkaria. The available information on geothermal resources at the time was based on the basic design by the engineering consultant, who worked on the first two units at the Olkaria II site. The distribution component was based on the feasibility studies for distribution reinforcement and upgrade, as well as for the upgrade of the SCADA/EMS system. 19. The ESRP took into account lessons from past operations and knowledge available at the time. Project design also factored in the perception of the sector by private investors. For this reason, the ESRP (1) pursued a gradual, yet comprehensive, policy reform addressing the legal and regulatory environment as well as utilities’ performance; (2) emphasized increased autonomy for the regulator; and (3) supported the establishment of a public, special-purpose, geothermal company to address upfront geothermal resource risks. The government was strongly committed to undertake ambitious and complex reform measures. Hence, the comprehensive package—consisting of institutional and capacity building, studies and engineering services, geothermal power plant extension, and distribution upgrading—was expected to address the main sector challenges.

20. The Project Appraisal Document (PAD) identified improvement in KPLC’s management capacity and maintenance of cost-recovering retail tariffs as high risks. With hindsight, maintaining the performance of KPLC over a longer period could have been given more emphasis, in view of the deterioration in KPLC’s operational performance observed around FY2011, with

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increases in system losses. The delays encountered, particularly in procuring and implementing the generation and distribution components, suggest that the risks of project implementation delays and inefficient handling of procurement and contract administration were, in fact, “high” rather than “medium” risks.

2.2 Implementation 21. As described in Section 3 of this report, the ESRP achieved most of the ambitious objectives that were initially set, and in some instances even exceeded them. Key factors that affected project implementation are summarized below.

22. Complexity of the Reform and Enabling Factors. The GoK, with the Bank’s support, embarked on ambitious sector and institutional reforms under the ESRP. These reforms included complex measures, such as enacting the Energy Act, and establishing and strengthening new institutions. Notwithstanding these complexities and some delays encountered, the reform measures were largely achieved during the project’s life. The ESRP had most of the elements needed to make reform a success: country commitment to implement the reform was strong; broad-based ownership and stakeholders’ buy-ins were undertaken through ad hoc consultations, especially inviting private-sector representatives; strong local champions were present; a clear road map was prepared under the National Energy Policy and the Energy Act; early gains were achieved, including the adoption of the energy policy and the management services contract (MSC) for KPLC; sustaining early success at reform was supported with relevant key studies under the project; and appropriately tailored instruments, such as investment lending and partial risk guarantees (PRGs) were used to follow up. The Bank also had been working closely with local champions for long-term sector reform under the previous reform project, and had a good understanding of the country’s political and economic context.2

23. Price Volatility. Major increases in international prices of input materials between the time of project appraisal in 2004 and the time of contract awards affected financing gaps significantly. Prior to the AF operation in 2009, the pressing issue was the impending cost overrun: major increases in international prices of materials, such as aluminum and copper, as well as high demand for turbines, contributed to rising costs and to the financing gap in both the generation and the distribution components. Moreover, there were not many bidders for the investment components, often resulting in higher costs and cost overruns. For this reason, the additional financing was prepared in discussion with the GoK and the implementing agencies, and in collaboration with other development partners. However, after the global recession of 2008/09, the inflationary pressures on foreign goods eased to some extent, and responses to public procurement became more competitive, which led to overestimation of contract prices, especially for the distribution contracts tendered after 2009. This, in turn, led to cost savings for foreign currency components. Several reallocations took place to help utilize these funds, including burying and reinforcing distribution lines in Mombasa and purchasing additional equipment, such as transformers and conductors.

2 These factors are mentioned in Operations Evaluation Department. 2003 Private Sector Development in the Electric Power Sector: A Joint OED/OEG/OEU Review of the World Bank Group’s Assistance in the 1990s. The World Bank.

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24. Political Transitions. The life of the ESRP coincided with two general elections in 2007 and 2013, and the promulgation of the new constitution in 2010. Post-election turbulence in January 2008, which followed the General Elections of December 2007, affected the project in several ways: (1) reduced productivity of utilities due to staff absenteeism; (2) reduced electricity sales revenue and increased nonpayment of bills; (3) triggered force majeure notices by contractors and subsequent claims for compensation for lost time; (iv) increased the cost of letters of credit (LOCs) because of a higher risk rating for Kenya; (5) prompted renegotiation of contracts that led to increased cost and lengthy processes of negotiation of additional financing from co-financiers, including new security arrangements; (6) led to travel advisories for consultants and contractors for some nationalities that may have caused delays; and (7) heightened risk perception of the country for international investors. In contrast, the period leading up to and following the general elections in March 2013 was relatively peaceful. In the process, key officials of sector entities were changed during the transition. However, sector entities continued their activities and, after delays, a tariff review was undertaken in December 2013, which demonstrated the continuity and robustness of the reform.

25. Procurement Capacity. While MoE and KenGen had previous experience managing Bank projects, KPLC had not played a major part in Bank projects previously. The ESRP incorporated measures to strengthen the project implementation teams (PITs), including recruitment of consultants and engineering consultants, and provision of specialized training activities for key personnel. Despite these measures, the PITs’ capacity to manage procurement and contracts often remained inadequate, which contributed to delays in the management of various key studies, handling of procurement for the generation and distribution components, and the management of the distribution contracts. For example:

• In the case of MoE’s PIT, implementation was hampered by interference of other organizational demands with the PIT’s day-to-day operations; turnover of staff, especially financial management staff; and time-consuming steps for clearance.

• In the case of KenGen, attracting talent to the PIT from other departments was difficult, as reorganization was concurrently taking place. Opening of LOCs slowed down, in part due to the time-consuming nature of interdepartmental interactions and coordination.

• KPLC’s performance, which was a focus of the project, significantly improved as a result of the MSC that was implemented in FY2007–08, with achievement of five out of seven performance indicators. The organization as a whole went through a major turnaround. However, the duration of the MSC was too short to trickle down to levels below middle managers and fully sustain the impact; though it removed a culture of non-performance that was prevailing before the project, it did not fully instill a culture of performance. Moreover, unfamiliarity with Bank procedures and weak coordination with other departments slowed down project implementation.

26. Contract Packaging. Partly reflecting concern about the entities’ capacity to handle complex procurement, the packaging of contracts tended to be consolidated crudely across differing activities (e.g., civil works, steam field development, and electromechanical works for the geothermal EPC contract) or geographical areas (e.g., distribution contracts, each covering dispersed areas). Although the packaging of contracts saved transaction costs for the implementing agencies, as it transferred part of the implementation risks to prospective contractors, it may have either limited the number of responses to a tender (since some

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prospective bidders were not interested in civil works contracts as in case for the generation component) or slowed down implementation (since contractors were logistically challenged as in the case of the distribution contracts). 27. Procurement Clearance. Several large, complex contracts funded under the ESRP, including the generation component and some distribution contracts, required clearance by the Regional Procurement Manager and the Operational Procurement Review Committee (OPRC). A key consideration for the Bank regarding these contracts was to ensure adequate bid competition. As commonly experienced across the Bank3 when the level of clearance is raised, it added to the lengthy process of approvals during prior review. In the case of geothermal generation EPC procurement, the procurement method was changed when only two companies responded to the initial request for prequalification -from international competitive bidding (ICB) with pre-qualification to ICB with post-qualification; KenGen was also advised to contact those companies that did not respond. In a couple of instances, the Bank team hired independent consultants to conduct additional investigations before making any decisions. As mentioned earlier, this lengthy process was compounded further by the inadequate capacity of PITs to handle complex procurement and prepare the corresponding documents. For example, it took four and nine months, respectively, for the prequalification report and the negotiated contract for the generation component to be cleared, following several rounds of iterations with KenGen and within the Bank. The specific case of the geothermal EPC procurement process is discussed in detail in Annex 3. 28. The Bank team responded to changing circumstances and challenges by regularly meeting with senior officials and, when necessary, flexibly adjusting reform milestones while ensuring these activities were on track. When the funding gap was identified, the team restructured the ESRP and provided additional financing in 2009 to accommodate price increases in the generation and distribution components, in collaboration with other development partners. Cost savings were utilized to help ensure PDOs were met through five project restructurings and reallocations across categories. The team facilitated various clinics and provided on-the-spot advice to PITs for fiduciary management. In cases where the auditor’s opinions were qualified or provided a disclaimer of opinion report for MoE, the Bank conducted an in-depth assessment of the issues and agreed on an action plan to strengthen MoE’s capacity. 2.3 Monitoring and Evaluation (M&E) Design, Implementation, and Utilization 29. M&E Design. The M&E system was designed to monitor the performance of the three implementing agencies at two levels: project and corporate. At the project level, KPLC would monitor its Corporate Recovery Program (CRP) and the distribution component; MoE would monitor its capacity building and regulatory subcomponents; and KenGen would monitor its capacity building and the generation subcomponent. At the corporate level, the three agencies would monitor their performance contracts as agreed with the GoK. In addition, eight legal covenants with the GoK were closely linked to the policy reform agenda.

3 Independent Evaluation Group. 2014. The World Bank and Public Procurement—An Independent Evaluation, Volume II: Achieving Development Effectiveness through Procurement in Bank Financial Assistance. The World Bank.

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30. M&E Implementation. The agencies reported quarterly on the seven indicators that measured their performance on policy, institutional, and regulatory reforms; generation capacity; and access to reliable electricity. Their individual progress reports were combined into one quarterly progress report by MoE for submission to the Bank. The progress reports comprised detailed tables on the status of contracts, implementation schedules, and procurement plans. The Bank and the implementing agencies regularly took stock of the compliance status with the covenants on key sector reform measures. During the additional financing and project restructuring, the outcome indicators were streamlined to five indicators capturing results on the policy and the access dimensions. 31. Furthermore, the eight policy covenants were used to monitor project implementation progress: (1) award of management services contract before disbursement; (2) implementation of customer connection policy before disbursement; (3) submission of the proposed Energy Act; (4) establishment of the Energy Regulatory Commission (ERC); (5) preparation and adoption of secondary legislation for the Energy Act; (6) conclusion of PPAs between KPLC and KenGen; (7) adoption of revised retail tariff structures; and (8) establishment of separate T&D units within KPLC. As six out of eight covenants had been met at the time of the additional financing, the remaining two covenants-pertaining to the PPAs and the secondary legislation- were carried over to the additional financing operation. At the time of project closing, all of the covenants were met, except for the one on secondary legislation, because of delays in legal drafting and additional requirements that were later introduced by the Attorney General’s office. However, drafting of all the relevant legislation was completed before project closing, and only the gazetting process is pending. Moreover, the Energy Act has been enforced, and the sector institutions are operational.

32. M&E Utilization. After the 2009 additional financing, revised indicators were used to track project implementation. The reports allowed the GoK and the Bank to oversee KPLC’s CRP and performance contracts, modify the ESRP and provide the additional financing for additional studies and connections, and address the financing gap. There were covenants for KPLC and KenGen to maintain their financial viability, including current ratios, debt-service coverage ratios, self-financing ratios, and number of days in accounts receivables (for KPLC only). Both KPLC and KenGen were in breach of some of the financial ratio covenants in their respective project agreements in FY2012 and FY2013. KenGen obtained approval in December 2013 from its shareholders to increase the company’s authorized share capital. The injection of additional equity is expected to generate revenue for KenGen’s capital expansion program and to restore the self-financing ratio. Following the approval and gazetting of the new retail tariffs (Schedule of Tariffs 2013) by ERC that have been applied from December 1, 2013, KPLC has submitted financial projections for the three-year tariff period and confirmed in writing that the approved retail tariffs will enable it to meet the targets for financial covenants (self-financing, debt service coverage ratio, and current ratio) in the Kenya Electricity Expansion Project (KEEP) project agreement in FY2014, FY2015, and FY2016.

2.4 Safeguards and Fiduciary Compliance 33. Safeguards. The ESRP followed and complied with all the safeguards’ policies and procedures. It was rated B, triggering safeguard policies for environmental assessment (OP/BP/GP 4.01) and involuntary resettlement (OP/BP 4.12). The potential impact was analyzed

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in ESIAs, and mitigation was addressed in the Environmental and Social Management Plan (ESMP) and Resettlement Policy Framework. In addition, KPLC prepared a Resettlement Action Plan (RAP) and environmental impact assessment (EIA) for the distribution component—overhead lines and substations.

• RAP. The mitigation provisions in the RAP have been invoked only for the 66-kV transmission line from Nairobi North Substation to Westland. Commencing in August 2011, KPLC paid compensation to 113 eligible owners of structures/houses along the right of way for this transmission line, in accordance with the RAP. The project-affected people (PAPs) who suffered loss of land, crops, trees, structures, or dwellings were satisfied with the RAP implementation and payments, which was witnessed by the Chief of the Karura location, whose office had verified ownership and maintained the census list of PAPs.

• ESMP. The ESMP mitigation measures for the Olkaria II geothermal plant included injecting cooling water below the water level, mitigating the effect on wildlife by re-routing pipelines to avoid wildlife corridors, and providing water troughs for wildlife. Experts determined that the amount of water drawn from Lake Naivasha for drilling and cooling was inconsequential, compared with that used by the neighboring flower farms. Moreover, most of the water drawn will be recycled after removal of brine, toxics, and non-biodegradable substances, which were encased in concrete and buried.

34. Lavington Substation Case. Apart from the Lavington Substation case briefly described here, in which the Inspection Panel did not recommend an investigation, there were no major safeguards issues encountered during project implementation. On May 10, 2012, the Inspection Panel received a Request for an inspection relating to the ESRP, which was sent by an individual on behalf of the Njumbi Road Residents’ Association. The requesters were concerned about the construction of an electric power substation located in Lavington, Nairobi, which was being financed under the ESRP’s distribution component. The Inspection Panel registered the Request for Inspection on May 24, 2012. On June 25, 2012, the Bank’s management team submitted its Response to the Request for Inspection, along with several recommended measures to mitigate the potential impact of the construction. On July 25, 2012, the panel submitted its Report and Recommendation on the case, which did not recommend an investigation. Parallel to and before the Inspection Panel process, on January 21, 2011, the residents had filed an appeal to the National Environment Tribunal (NET) against the National Environment Management Authority (NEMA) and KPLC for licensing and constructing the substation. After delay, on March 1, 2013, NET issued a ruling that “the EIA licence dated 24th February 2011 issued by NEMA to the 2nd Respondent [KPLC] is cancelled and the approval of the development in question dated 30th December 2010 is revoked” and directed “the 2nd Respondent [KPLC] to relocate its power sub-station to a suitable location and in the process, comply with all applicable laws and regulations.” KPLC filed an appeal against the ruling by NET to the High Court on April 2, 2013. Even though KPLC agreed with the Bank’s recommendations to implement additional, enhanced mitigation measures, they could not be implemented, as the court process was still ongoing at the time of project closing. The Lavington substation was left incomplete. Once the ruling is issued, KPLC will handle the case appropriately and, if needed, utilize its own resources for completion of the substation.

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35. Kenya Olkaria II (Unit Three) Geothermal Expansion—Carbon Finance. The ESRP’s carbon finance (CF) component was designed in 2006 and implemented under the Kenya KenGen Carbon Finance Umbrella Project (KKCFUP). The CF component aimed at reducing carbon emissions by generating additional geothermal energy at the existing Olkaria II geothermal plant (Unit Three), displacing electricity that would otherwise be generated by fossil fuel-based power plants equivalent to about 149,632 tons of carbon dioxide equivalent (tCO2e) a year (as per the Clean Development Mechanism Project Design Document, registered with the United Nations Framework Convention on Climate Change [UNFCCC] in December 2010). An Emission Reduction Purchase Agreement (ERPA) was signed by KenGen and the Community Development Carbon Fund (CDCF) on November 14, 2006, for an estimated total purchase volume of 900,000 tCO2e. The ERPA purchase volume was subsequently adjusted to 478,533 tCO2e, to reflect the actual purchase volume at project commissioning date and the UNFCCC registration date.

36. Part of the carbon revenues received from the CDCF was earmarked under the ERPA to implement a Community Benefits Plan (CBP). The CBP was prepared by KenGen in consultation with poor communities living in the vicinity of the CF project. In June 2011, KenGen disbursed an advance payment of US$225,000 to jump start the implementation of the CBP. As of December 2013, the CBP has provided for the construction of six classrooms at two local primary schools (ongoing), a water supply line (completed), and a livestock water pan (completed), which are expected to benefit 450 pupils, 20,000 local inhabitants, and 40,000 livestock respectively. The KKCFUP’s Implementation Completion and Result (ICR) Report is attached as Annex 11. 37. Financial Management. Compliance with fiduciary controls for financial management (FM) by KenGen and KPLC was satisfactory throughout the ESRP. However, MoE’s FM was only moderately satisfactory for most of 2011 and 2012, with both financial statements given qualified opinions by the auditor. In 2011, this was due in part to rotation of accounting staff in MoE. In response, the Bank’s FM specialist provided FM training for MoE’s accountants in early 2011, which was followed by an in-depth review of MoE’s FM in September 2011. KKCFUP’s ICR also revealed areas of persistent internal control weaknesses. In 2012, an FM action plan was prepared by MoE with inputs from the Bank to address these control issues, and the Bank supported the hiring of FM specialists at MoE in July 2013 before the ESRP’s closing, with a view to improve FM capacity for the KEEP. 38. The processing of disbursements was often delayed. Even though the standard operational procedures assume three working days each for processing withdrawal applications by the implementing agencies (MoE, ERC, KenGen, and KPLC), the process frequently took more than a month. This was due to (1) frequent absence of signatory officers, (2) numerous units involved in the clearance process, and (3) lack of standardization or clarity in information required for clearance. For example, for clearance within MoE, six stages are needed (fund manager, examiner, chief accountant, internal audit, cashier, and the MoE internal External Resources Department [ERD]). In the case of MoE, the accounts controller, ERD disbursement, and World Bank office are all involved in the process. The implementing agencies were subject to numerous information requests from the Ministries of Finance and Energy that were not always standardized.

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39. Procurement. During the ESRP’s implementation, the initial 2004 procurement plan was regularly updated. Although ESRP procurement complied with Bank requirements, it was often delayed. Adherence to procurement plans for the distribution component by KPLC slowed in early 2012. In response, KPLC added engineers and accountants in the implementation unit, which expedited work. Procurement in general and contract management, in particular by KPLC, was moderately satisfactory in 2012 and 2013. The difficult procurement process, involving KenGen, for the geothermal generation EPC contract is described in Annex 3.

2.5 Post-completion Operation/Next Phase 40. The institutional and regulatory reform measures supported under the ESRP, as well as investment in power generation and distribution, continued to be supported by the GoK, utilities, Bank, development partners, and the private sector. The entities established as part of, or in conjunction with, the ESRP (ERC, Kenya Electricity Transmission Company [KETRACO], Geothermal Development Company [GDC], and REA) are carrying out their respective sector mandates. 41. Building on the achievements of the ESRP—including strengthened institutional and regulatory frameworks for private-sector participation in the sector, viable utilities, and expanded annual connection targets—the Bank, in its March 2010 Country Partnership Strategy (CPS), continued supporting mobilization of concessional and private sector financing, expansion of generation preferably of renewables and IPPs, as well as, of transmission and distribution, and the ambitious on- and off-grid connection targets. In May 2010, in line with the CPS, the Bank Board approved the KEEP—co-financed by AFD, EIB, Japan International Cooperation Agency (JICA), and German Development Bank (KfW)—with PDOs of increasing the capacity, efficiency, and quality of electricity supply, and expanding access to electricity in urban, peri-urban and rural areas. Hence, the approach adopted in the ESRP is being replicated and scaled up in the KEEP.

42. The private-sector perception of the Kenyan energy sector improved considerably. In February 2012, the Bank Board approved the Private Sector Power Generation Support Project, which aimed to increase electricity generation through IPPs in Kenya. The project provided PRGs for four IPPs, facilitating private investment in thermal and geothermal power generation. The Eastern Electricity Highway Project, approved in July 2012, supports regional integration and cross-border trade of electricity implemented by KETRACO, which was established based on the study supported under the ESRP. In summary, these projects build on and extend the measures carried out under the ESRP. 43. Several challenges remain that call for post-completion operations:

• First, there is a continued need to clarify the roles and functions of the new entities established, continue to develop technical and institutional capabilities, and support their activities. This includes delineation of roles to remove conflict, regulatory affairs, financial strategies in public-sector entities, system operations of the national grid, development of geothermal resources, and rural electrification.

• Second, the ESRP supported creating an environment conducive for private investment. With an increase in successful financial closures of IPPs, the need for a significant

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volume of investment in the sector, and emphasis on value-for-money of public services through public-private partnerships, there is a need to coordinate investment with the LCPDP, and to refine and establish procedures for soliciting and concluding private-sector transactions.

• Third, the reliability of electricity supply is one of the main infrastructure bottlenecks affecting Kenyan enterprises. The ESRP did not achieve the system losses targets, in part because of the delays in investments in T&D rehabilitation, and the GoK’s aggressive expansion of the electricity network to rural areas, which was not anticipated. Hence, there is a need to ensure funding for expansion of access to electricity in rural areas on a sustainable basis.

3. Assessment of Outcomes

3.1 Relevance of Objectives, Design, and Implementation 44. The ESRP’s development objectives, design, and implementation remain highly relevant to the government’s development priorities, which are reflected in the Bank’s CPS for Kenya. 45. The GoK’s long-term strategy—“Vision 2030”—includes expanding infrastructure access as a key element in achieving a higher level of economic growth and the middle-income country status by 2030. The Medium-Term Plan (MTP) and MTP-2 to implement the 2008–12 and 2013–18 phases of the Vision 2030 strategy, respectively, call for, among others, expanding access to electricity. In an effort to improve equity, the strategy, include access of the rural and urban poor to electricity. The Electricity Access Investment Prospectus 2009–14 supports geothermal generation expansion, expanding the transmission network and substations, and extending distribution to urban and peri-urban areas, including urban slums and rural areas. IDA is supporting the prospectus through the ongoing KEEP, which continues to advance the reforms and investment embarked on under the ESRP (and even earlier with the Energy Sector Reform Project in 1997). The approach taken was effective in advancing the reforms and implementing necessary investment to achieve the goals in the energy sector. 46. Given the current and future GoK and Bank strategies for the sector, the objectives of the ESRP in 2004 to improve policies, regulation, and institutions, as well as expand geothermal generation capacity and access to reliable electricity, were, and continue to be, relevant at project closing and beyond. In addition, the ESRP’s design, building on IDA’s long-term involvement in the sector, its leadership in sector reform, and its capacity to collaborate with development partners and integrate lessons learned, resulted in a project that, despite procurement difficulties and cost escalations, helped establish a viable policy and regulatory environment for expansion of electricity generation, transmission, and distribution; reduced losses and improved quality of electricity; and greatly expanded access. Consequently, the relevance of the project development objectives is rated high.

3.2 Achievement of Project Development Objectives

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Table 1: Summary of PDO Indicators Achievement Status

PDO Indicators Target

Status of Achievement

End-Period Status At Project Restructuring

(Original PDOs)

At Project Completion

(Revised PDOs)

1. National Energy Policy Adopted and implemented Achieved Achieved

The National Energy Policy was adopted in 2004 and has been implemented thereafter. This indicator was reformulated as an intermediate outcome indicator during project restructuring and additional financing in 2009.

2. Energy Act Passed and implemented Achieved Achieved

The Energy Act was passed in 2006 and has been implemented thereafter. 12 secondary legislations remain to be gazette but will be reviewed in the context of Energy Policy and Energy Act amendments being undertaken.

3. Additional geothermal power generation 276 GWh × Not Achieved Achieved

Target exceeded in FY11 (296 GWh) and FY12 (280 GWh). Dip in output in FY13 (255GWh) was due to maintenance carried out. This indicator was reformulated as an intermediate outcome indicator during project restructuring and additional financing in 2009.

4. New customer connections 400,000 Partially Achieved Achieved

Target exceeded. 526,000 customers were connected. This indicator was reformulated as the indicator 10, with increased target, during project restructuring and additional financing in 2009.

5. System losses reduction 14.5% Partially Achieved

Partially Achieved

After initial improvement, the target was not achieved with losses rising to 18.6% due mainly to government’s aggressive expansion of the national grid to rural area. This indicator was reformulated as an intermediate outcome indicator during project restructuring and additional financing in 2009.

6. Availability of transmission lines: (a)interruptions per 100 km per month; availability of 220 kV and 132 kV lines

(a) 0.19 for 220kV, 0.50 for 132 kV, and

2.0 for 66kV; and (b) not less than 97%

Partially Achieved

Substantially Achieved

Availability transmission lines improved and power outages reduced. This indicator was dropped during project restructuring and additional financing in 2009 as the outcome is better measured by the indicator 11.

7. Total monthly outages 4,000 Substantially Achieved

Substantially Achieved

The indicator was reduced from 11,000 in 2004 to 5,771 in 2008. This indicator was dropped during project restructuring and additional financing in 2009 as the outcome is better measured by the indicator 11.

8. Number of IPPs 8 - Substantially Achieved

There are 7 IPPs at the project closing and 3 additional IPPs are expected to be commissioned in FY14.

9. Disputes resolved by ERC 95% - Substantially Achieved

Activities were on track to meet target with the result achieving 85% in FY12. The target fell short in some years as some complaints were filed towards the end of the reporting period.

10. New customer connections 450,000 - Achieved Target exceeded. 526,000 customers were connected. 11. Monthly distribution line interruptions per 100 km 2 - Substantially

Achieved Target was achieved in FY10-12 (1.2-2.0) but fell short in FY13 (2.9) due to rapid expansion of connections.

Summary of Outcome Rating Moderately Unsatisfactory

Moderately Satisfactory

The project’s objectives and design were, and still remain, highly relevant. The project’s efficiency remains substantial. Most of the outcome indicators achieved, or in some cases exceeded, the targets. There were moderate shortcomings in the targets on quality and reliability of electricity supply due mainly to the unforeseen aggressive expansion of the national grid to rural areas. The overall rating is therefore Moderately Satisfactory.

Italic Font: Original PDO indicators, Regular Font: Post-Restructuring PDO Indicators

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47. The modification of the PDOs and indicators and the additional financing carried out in 2009 represented a Level One project restructuring. Therefore, the achievement of the PDOs needs to be assessed both at the time of project restructuring and project closing. The achievement status of the PDO indicators is summarized in Table 1. At Project Restructuring 48. At the 2009 restructuring, approximately four years after project effectiveness, most of the activities for enhancing the policy, institutional, and regulatory environment were either achieved or on track. The institutional and regulatory framework was in place and implemented, new institutions were established, a cost-recovery tariff was introduced in 2008, and KPLC’s performance had improved significantly. However, physical investments in the generation and distribution components were lagging behind. Work at Olkaria II was about 25 percent complete at the time of project restructuring. The number of new connections in the distribution network was 60 percent along: i.e. 240,000 connections versus the initial target of 400,000 by FY2009.

49. With the achievement of only one of the three original PDOs and disbursement of the original IDA credit at 26 percent (only 15 percent, if the additional financing is included)4 in 2009, the achievement of the PDOs at project restructuring is rated moderately unsatisfactory. However, it was for these considerations that the project was restructured. At Project Completion 50. In contrast, by the project closing in November 2013, the investment activities under the generation and distribution components caught up with the policy reforms, and the project had achieved—or had exceeded in some cases—most of the five PDO targets: (1) The Energy Act was enacted in 2006, and drafting of all the relevant legislation was completed before the project closing. Even though the gazetting process was pending at the time of project closing, this did not affect the act’s enforcement significantly, as it was implemented through the sector institutions established. Moreover, the new government that assumed office in 2013 is in the process of amending the act, which makes the secondary legislation less relevant. (2) The number of IPPs increased from three in 2004 to seven at project closing. Even though this falls short of eight as initially targeted, the three IPP plants that were under construction at project closing are expected to be online in 2014. (3) The target on dispute resolution has been largely met, as ERC has managed to resolve all disputes brought before it. The target fell short in some years, as some complaints were filed toward the end of the reporting period.

4 Disbursements of the EIB, AFD, and NDF loans were, respectively 15, 80, and 60 percent. However, it is difficult to attribute the achievement in 2009 to the source of financing, and the IDA disbursement will be used for weighting the ratings.

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(4) The number of households connected to electricity under the project is 526,000, exceeding the original target of 400,000 by 17 percent. (5) The number of monthly interruptions per 100 km for 66-kV and 33-kV lines was reduced from 4.7 to below 2.0 in FY2010–12; improvement in the quality of electricity supply was also observed. Even though the number of interruptions increased to 2.9 a year later in FY2013 and fell short of the target of 2.0, it is expected to improve again with distribution reinforcement measures being undertaken. 51. With the reform measures implemented and the expansion in the generation and distribution network, the sector’s performance has improved significantly. The reform of the electricity sector in Kenya has progressed much farther than reform programs in most other Sub-Saharan African countries. The elimination of the government’s monopoly on the power industry has progressed with KenGen and KPLC listed in the Nairobi Stock Exchange and operating on a quasi-commercial basis. Private investment has become vibrant in the sector. As a result, the number of operational IPPs has increased steadily. With 19 IPPs licensed, including the seven IPPs already operational at the time of project completion, the trend of increased private-sector participation is expected to continue. Kenya has the most advanced geothermal subsector in Africa. In 2013, installed geothermal power generation capacity was 215 MW which places the country’s subsector as ninth largest in the world. The Olkaria II Unit 3 has been operating satisfactorily close to the rated output since its commissioning in May 2010. KPLC, which was constantly realizing losses before the project, is now making profits to sustain its investment and operations. The company has connected 200,000–300,000 households per year since 2010, compared with the slow pace of 20,000–50,000 connections per year that prevailed before the project.

52. The ESRP’s main shortcoming was in meeting the necessary quality and reliability of the electricity network, and the sustainability of KPLC’s improved performance. The reduction in system losses that was on track until 2010 deteriorated, due to the government’s aggressive expansion of the national grid into rural areas, which was introduced after the project, as well as to delays with transmission network reinforcement implemented outside the project. Moreover, sustaining KPLC’s improved performance will still require further improvement in its corporate governance. These issues are being addressed in subsequent operations. Overall, with substantial achievement of the PDOs, a disbursement of more than 93 percent, and with only moderate shortcomings, the achievement of the PDOs at project closing is rated moderately satisfactory.

3.3 Efficiency 53. Based on the same methodologies used with updated assumptions, reevaluation of the cost-benefit analyses undertaken at the time of both appraisal and additional financing reveals that the project’s efficiency remains substantial and is justified economically. 54. For the geothermal generation component, the reevaluated economic internal rate of return (EIRR) at the time of project completion is 22 percent, with a net present value (NPV) of US$53.8 million (Table 1), despite the project delays and cost increases. The EIRR is largely attributable to the level of electricity tariffs that increased more than what was assumed in the

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previous two analyses. The estimated life-cycle cost of the plant remains at US$0.077 per kilowatt-hour, which suggests its comparative cost advantage over other generation options is sound.

Table 2: NPV and EIRR for Generation: PAD (2004), Additional Financing (2009) and ICR (2013)

55. For the distribution component, the reevaluated EIRR at the time of project closing is 32 percent, with an NPV of US$120.8 million (Table 2). This result suggests that the economic rationale for the distribution upgrading remains sound, even when applying conservatively estimated willingness to pay by consumers.

Table 3: NPV and EIRR for Distribution: PAD (2004), Additional Financing (2009) and ICR (2013)

3.4 Justification of Overall Outcome Rating Rating: Moderately Satisfactory 56. The project’s objectives, design, and implementation are still highly relevant in the current sector issues and government priorities. Most of the indicators achieved or exceeded the targets, though the network reliability target was not fully met. Through the project, the electricity sector has become one of the best performing sectors in Sub-Saharan Africa. In addition to catalyzing other development partners’ financing, investors’ perception has improved substantially as a result of the project, which has led to increased private investment in the sector. As mentioned above, the targets on the quality and reliability of electricity supply fell short due to some unforeseen expansion into rural areas and delayed reinforcement of the transmission network, both outside the project. However, these are considered as moderate shortcomings in the context of the project’s achievement of its objectives, its efficiency, and its impacts that go well beyond the project. Therefore, the overall outcome rating is rated moderately satisfactory, based on the calculations in Table 3.

Table 4: Outcome Rating against Original and Revised PDOs

Rating Factors Against Original PDOs

Against Revised PDOs

Overall Comments

1. Rating Moderately Unsatisfactory

Moderately Satisfactory

Some improvement

2. Rating value 3 4 3. Rating value weight 15% 85% 100%

2004 2009 2013

NPV in US$ million (@12%) 25.9 20.4 53.8

EIRR (%) 19 14 22

2004 2009 2013

NPV in US$ million (@12%) 246.0 31.4 120.8

EIRR (%) 30 27 32

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4. Weighted value 0.45 3.40 3.85 5. Final rating - - Moderately

Satisfactory

3.5 Overarching Themes, Other Outcomes, and Impacts (a) Poverty Impacts, Gender Aspects, and Social Development 57. While there are no beneficiary surveys to substantiate poverty or social impact, incidental evidence suggests that the urban and rural poor consider electricity access as an improvement in the quality of life by facilitating students’ study at night, providing security through street lighting, and permitting small businesses to stay open longer to serve clients. KPLC’s customer satisfaction survey, which has been conducted periodically since FY2009, suggests that there has been a steady improvement in the overall satisfaction index:5 64 percent in FY2009, 65 percent in FY2010, 70 percent in FY2011, and FY2012, and 72 percent in FY2013. However, connection charges and electricity tariffs are still very high for the poor, and subsidies and cross-subsidies are not targeted well to those in need. Businesses benefit from access to electricity, but also note the frequent outages and costs.

(b) Institutional Change/Strengthening 58. As noted in the GoK’s Vision 2030 and the Bank’s CPS, the ESRP has helped create a viable policy and regulatory environment and an unbundled sector with viable electricity generation, transmission, and distribution companies. It has also supported the establishment of a public company dedicated to development of upstream geothermal resources. Provision of specialized training helped improve the companies’ technical and institutional capabilities. The partial privatization of KenGen and KPLC and their listing on the Nairobi Stock Exchange have enhanced their disclosure of corporate information for market scrutiny, which has increased their ability to raise capital.

(c) Other Unintended Outcomes and Impacts (Positive or Negative) 59. The rigorous process involved during the NET and the Inspection Panel case regarding construction of the Lavington substation strengthened KPLC’s awareness and preparedness for conducting environmental and social safeguard measures thoroughly. Heightened standards are applied to activities implemented by KPLC, even when the Bank is not directly involved. Some of the measures are as follows:

• Any notice for requests for zoning changes, or potential purchases of land for residential areas, is communicated in writing to all PAPs, those in the vicinity of the proposed substation, with particular emphasis on PAPs in residential areas.

5 The overall satisfaction index is constructed by converting 10-point scale responses to a number of questions that capture customers’ satisfaction with KPLC into a percentage scale, and taking the average.

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• Transparent and interactive consultations are held with all PAPs. Adequate notice is provided for these consultations, and they are documented in the final Environmental Management Plans.

• KPLC intensifies efforts to ensure that noise regulations (Kenya's are stricter than those suggested by the Bank Group Performance Standards) and fire safety protection measures (fire walls, siting of generators) are monitored and enforced during construction and operation.

• KPLC intensifies efforts to ensure that landscaping around potential substation sites minimizes their aesthetic impact.

3.6 Summary of Findings of Beneficiary Survey and/or Stakeholder Workshops 60. Not applicable.

4. Assessment of Risk to Development Outcome Rating: Significant 61. The major risks to the development outcomes concern the sustainability of the reform measures undertaken, including (1) weak sector governance that does not yet allow the utilities to be managed and operated on sound commercial principles; (2) irregular and insufficient adjustment of tariffs, due to lack of acceptance by consumers and political interventions, which could jeopardize the financial viability of the utilities; (3) incoherent sector and system planning and inadequate coordination of prospective investment with the LCPDP to meet the country’s energy and technology requirements; (4) increases in the cost of connections and failure to put in place a sustainable mechanism for funding new connections through subsidized funding; (5) inadequate investment in the distribution system to meet increased access to electricity; and (6) inadequate capacity of the government and utilities.

5. Assessment of Bank and Borrower Performance 5.1 Bank Performance (a) Bank Performance in Ensuring Quality at Entry Rating: Satisfactory 62. The Bank team that identified and appraised the ESRP had the required expertise as well as knowledge of the energy sector in Kenya to ensure quality at entry. It also benefited from the preceding energy sector operation. While no independent quality at entry assessment was undertaken by the Quality Assurance Group to confirm this assessment, the project was in line with the GoK and IDA strategies for the sector, took into account lessons learned, and made it possible to mobilize co-financing from three development partners—AFD, EIB, and NDF. The team ensured that the GoK allocated funds not only for the expansion of generation and distribution, but also for policy, regulatory, and institutional development activities without which the expansion objectives would not have been possible. The long-term engagement with the clients; persistence with making the reform happen; provision of necessary inputs, including analytical work and convening of consensus-building workshops; and in-depth knowledge of the

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political economy surrounding the reform helped the team navigate the initial phases of reform. With hindsight, packaging of the geothermal EPC contract may have excluded some prospective bidders, limiting competition, and later leading to delays in implementation. However, it would have been difficult to foresee this at the time of the project design, especially given that the contract was designed based on the previous project’s experience and on recommendations by the consultant employed by KenGen. Overall, Bank performance in ensuring quality at entry is rated satisfactory.

(b) Quality of Supervision Rating: Moderately Satisfactory 63. The task team’s attentive project supervision was instrumental in keeping the project’s implementation on track. The team held implementation support missions regularly, kept track of project implementation, and proactively addressed issues identified, which contributed to the substantial achievement of PDOs. When a funding gap was identified, the Bank engaged with clients and development partners, and provided the additional financing needed to enhance project activities. The team was persistent and patient in following the reform processes and was flexible in adjusting milestones as needed. Additional inputs and support were provided based on regular discussion and requests from the government, including the study to establish KETRACO, a biogas consultancy, and a number of feasibility studies. Extension of the project closing date as part of project restructuring and frequent reallocations of credit proceeds also reflected the Bank’s flexibility in responding to changing circumstances. 64. At the same time, implementation was hampered by slow procurement and disbursement, most notably in the generation and distribution components. While some of the issues were outside the control of the task team—such as the worldwide inflation of input materials and turbines increasing the price of geothermal turbines, and the time-consuming process involving OPRC—the failure to find a pragmatic solution for the procurement process for the EPC contract, which led to a three-year delay, was a Bank institutional shortcoming that adversely affected the implementation of a key project component. The GoK’s ICR mentions the difficulties in sorting out procurement issues efficiently and agreeing on the appropriate procurement procedures to follow in the case of multiple financiers for the same contract. Nevertheless, the plant achieved the target after its commissioning, and the component was still economical at project closing. With these moderate shortcomings, Bank supervision is rated moderately satisfactory.

(c) Justification of Rating for Overall Bank Performance Rating: Moderately Satisfactory 65. The Bank’s long-term engagement throughout the reform process and its persistence were instrumental in achieving the ambitious reform goals. The team flexibly responded to the need for additional financing and change of scope. While the generation component achieved its objective, delays in the procurement of the EPC contract have adversely affected subsequent client relations. Even though the delays were due to a number of factors, some outside the control of the Bank, they were compounded by the Bank’s failure to find a pragmatic and timely solution to address the issue. For this reason, more weight in the rating is given to this aspect during project implementation; hence, overall Bank performance is rated moderately satisfactory.

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5.2 Borrower Performance (a) Government Performance Rating: Moderately Satisfactory 66. The governments that came into power in 2002 and 2007 were both strongly committed to the policy of providing reliable electricity to the people and businesses to improve their quality of life and to lower the cost of doing business. It is remarkable that the bold decisions in implementing the ambitious sector reform were made and sustained throughout the process. By approximately 2011, the consistent effort by the government to improve the sector’s governance and viable utilities had enhanced the sector’s performance. Occasionally, there were difficulties in getting timely approval and processing by the National Treasury and MoE for counterpart funds and disbursement, as well as in obtaining approval from local governments for right of way and access to construction sites. For these moderate shortcomings, the overall government performance is rated moderately satisfactory.

(b) Implementing Agency’s or Agencies’ Performance Rating: Moderately Satisfactory 67. MoE’s performance was moderately satisfactory. MoE promoted and coordinated the ambitious reform measures implemented as part of the project. For a period of project implementation, MoE’s financial statements received qualified opinions from the auditor, reflecting chronic weaknesses in fiduciary management. 68. KenGen’s performance was satisfactory, especially once the construction started where management of the contract led to commissioning of the generation plant in time. However, before the construction, the low quality of the procurement documents prepared, the considerable time it took during iterations of the documents, and the delay in opening the LOCs (triggered by unavailability of funds from other development partners) in part contributed to the delay. 69. KPLC’s performance was moderately unsatisfactory. The initial outcome targets for system reliability were not fully achieved, the impact of the MSC was not fully sustained, and management of distribution contracts and contractors encountered challenges. However, the company performed well in terms of exceeding the original target of 400,000 additional connections.

(c) Justification of Rating for Overall Borrower Performance Rating: Moderately Satisfactory 70. The GoK and the implementing agencies had a strong commitment to expand electricity supply and improve its quality in the country from the low levels at the time of appraisal. The government’s support for the policy and regulatory improvements and for unbundling the sector’s public companies was effective. While there were some moderate shortcomings noted above, the borrowers adhered to their performance contracts and implemented the policy, regulatory and

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institutional, and generation and distribution components satisfactorily. Therefore, the overall borrower performance is rated moderately satisfactory.

6. Lessons Learned 71. Sector Reform. Sustaining sector reforms requires continuous government commitment through different administrations as well as strong stakeholder engagement. As summarized in Section 2.2 above, the ESRP benefited from the strong country commitment, broad-based ownership and stakeholders’ buy-ins, the presence of strong reform champions, a clear road map embodied in the 2004 National Energy Policy, a combination of quick-wins, various inputs in the form of studies and workshops, and follow-up investment closely tailored to support reform. The project was designed in an environment of limited funding availability from development partners but with a coordinated policy dialogue between partners. Together, these factors enabled the complex reform process to be successfully implemented in a relatively short period. The choice of lending instrument i.e. a specific investment loan, was also effective as the investment helped attain specific sector development goals, while facilitating on-the-job capacity building through learning by doing. Given that sector reform is a long-term endeavor with many factors outside the Bank’s control, the following additional aspects need to be taken into consideration to ensure its sustainability: (1) persistence, patience, and flexibility in adjusting the course; (2) a long-term approach to succession management in the sector (development of a cadre of next-generation leaders and managers); (3) improvement of corporate governance of the utilities to ensure that the reform initiated is institutionalized; (4) standardization of business processes to ensure institutional memory and to free up time for strategic decision making; and (5) strong engagement of stakeholders—especially consumers and trade unions. 72. Geothermal EPC Procurement Process. KenGen and the Bank had fundamentally different views about the costs, benefits, and risks associated with the procurement method to be followed. In future, it would be useful to consider the following aspects: (1) agree among project stakeholders early on to hire independent consultant(s), with experience in geothermal business and technology, and assess up front the costs, benefits, and risks of the procurement method, including direct contracting; (2) carefully design the package of EPC contracts so that a particular way of packaging does not hamper competition, and give consideration also to concerns raised by prospective bidders, separating out where possible contracts for the geothermal steam field, power plant, and transmission lines; (3) enhance coordination among co-financiers if joint co-financing is unavoidable, especially on funding coverage of contract costs as well as conditions precedent for financing, since opening LOCs entails significant risks and costs for implementing agencies; and (4) encourage informed risk taking in procurement decision making, taking into consideration timing factors. In this connection, a Performance Audit Report in the 1990s 6 recommends that “[f]or geothermal projects the Bank needs to be more flexible in its procurement processes,” mainly in the context of geothermal drilling operations. Based on experience with this project, this applies to geothermal power generation as well.

6 Operations Evaluation Department. 1997. “Performance Audit Report Kenya Olkaria Geothermal Engineering Project (Loan S-012-KE), Olkaria Geothermal Power Project (Loan 1799-KE), Olkaria Geothermal Power Expansion Project (Loan 2237-KE), Geothermal Exploration Project (Credit 1486-KE), Geothermal Development and Energy Preinvestment Project (Credit 1973-KE).” The World Bank.

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73. Implementation Capacity. Several lessons can be learned from the capacity building experience with the implementing agencies: (1) continuous engagement with the implementing agencies makes a difference in project implementation. MoE’s and KenGen’s prior experience and continued engagement with Bank operations helped ease the launching of the project activities during the early stages. By comparison, it took longer for KPLC, which had no substantive prior engagement, to set up the PIT and develop the required technical and project management capabilities. (2) In addition to fostering the technical and management capabilities of key officials, training programs turned out to be important tools for the PITs to strengthen collaboration across organizations. In this sense, continuous capacity building throughout project implementation was important for improving project performance. (3) KPLC’s MSC was a timely and effective intervention that helped to turn around the company’s performance. With hindsight, (a) the duration of the contract could have been longer, (b) the number of experts from outside (three people) was too small for a large utility, and (c) performance targets could have included non-technical aspects, such as operational processes and corporate culture, so as to instill a culture of performance at lower levels and make the reform more sustainable. (4) Turnover of fiduciary management staff at MoE, whose job rotation is managed by the National Treasury, had a detrimental impact on the quality of financial reporting. A lesson is that the National Treasury needs also to be engaged further to ensure continuity in fiduciary management officers.

74. Other operational lessons include the importance of (1) government intervention whenever issues arise with local governments (permits, urban planning) or with its own procedures (tax exemption clearances, delays with numerous clearance for release of funds); (2) allowing time for land and right-of-way acquisition; (3) retaining a substantial portion of the contractual amounts for installation to address the often weak capacity of local subcontractors; and (4) keeping a good record of interactions with stakeholders (including consultations on environmental and social safeguards and contractual issues with contractors).

7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners (a) Borrower/Implementing Agencies 75. The comments of the GoK and the implementing agencies focus on the difficulties encountered with Bank procurement procedures (discussed above). The government’s report (Annex 7) also focuses on achievements, challenges, and lessons learned. The discussion on achievements is detailed and suggests a level of satisfaction among government agencies with the results of the ESRP.

(b) Co-financiers 76. EIB provided comments on the early draft ICR that covered two aspects of project implementation: (1) the conclusion of financing agreement between KenGen and co-financiers, and (2) the procurement challenges of the geothermal EPC contract. The comments are incorporated in this report and are summarized in Annex 9.

(c) Other Partners and Stakeholders 77. Not applicable.

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Annex 1. Project Costs and Financing

(a) Project Cost by Component (in USD million equivalent)

Components Appraisal Estimate (USD millions)

Actual/Latest Estimate (USD

millions)

Percentage of Appraisal

Total Baseline Cost 375.1.00 359.24 95.77

Contingencies 2.80

0.00

0.00

Total Project Costs 377.90 0.00 Front-end fee Project Preparation Facility (PPF) 0.00 0.00 0.00

Front-end fee International Bank for Reconstruction and Development

0.00 0.00 0.00

Total Financing Required 377.90 359.24

(b) Financing

Source of Funds Type of Co-financing

Appraisal Estimate

(USD millions)

Actual/Latest Estimate

(USD millions)

Percentage of Appraisal

Borrower 53.90 48.84 90.61 European Investment Bank Parallel 101.00 105.47 104.43 French Development Agency Parallel 51.00 50.20 98.43 International Development Association 160.00 156.46 97.78

Nordic Development Fund Parallel 12.00 12.00 100.00

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Annex 2. Status of Outputs Component A: Institutional and Capacity Building. Original Scope The planned outputs were (1) implementing a comprehensive CRP for KPLC through engagement of a management services provider; (2) strengthening the energy sector regulator’s capacity to review and set power tariffs, prepare secondary legislation, and enforce regulations under the law; (3) equipping the KEBS with the skills, training, and equipment necessary for effectively setting and monitoring the standards of petroleum products in the country; (4) upgrading staff skills in MoE and KenGen; and (5) implementing a management and staff development program for KPLC. Outputs (1) The MSC that KPLC entered into as part of the CRP was in place from June 1, 2006, until June 30, 2008. It enabled KPLC to greatly increase electricity connections, reduce power system losses, diminish outages, and lower receivables. (2) The Energy Act was enacted in 2006, under which ERC and REA were established in 2007. The organizational structure, staffing, financing, strategic plan, and human resource policy manual for ERC were prepared and implemented. An MIS was installed, which supports ERC’s operation and management. As a result of the cost-of-service study, the new and cost-reflective tariff was introduced in 2008. Moreover, as part of the project, the regulations, codes, procedures, guidelines, licenses, and permits were developed to be enforced by ERC, including (a) proposals on draft regulations; (b) pro-forma licenses, license application forms, and permits; (c) model PPAs for various electricity-generating technologies; (d) and legal and technical audits and proposals for reviewing the grid code. (3) The Petroleum Standards Monitoring Unit of KEBS was equipped with laboratory equipment to enforce its surveillance and testing of petroleum products. (4) and (5) More than 1,200 staff members from KPLC, KenGen, MoE, ERC, KEBS, REA, and the Energy Tribunal have been trained in planning, modeling, environmental and social impact, GIS, procurement, and contract management. Staff members from KenGen, KPLC and MoE were trained in computer modeling for power system planning in support of updating the LCPDP. On a small scale, electrical installation contractors were trained in contract management and environmental and social impact and mitigation. Component B: Feasibility Studies and Engineering Services. Original Scope The planned outputs were (1) ESIAs for the generation and distribution components of the project, and for the LPG import handling and storage project; (2) consultancy services to update the Kipevu combined-cycle plant feasibility; (3) consultancy services for the distribution upgrade component; (4) engineering services for the supervision of the distribution component; (5) a feasibility study, and preliminary and detailed designs for the proposed LPG import handling and

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storage project; (6) a geothermal reservoir optimization study for the Olkaria I and II sites; (7) a study to establish a geothermal development company and preparation of a business plan for the company; (8) consultancy services for preliminary design and supervision of the Olkaria II power plant extension; (9) consultancy services for the detailed design and supervision of the SCADA/EMS; and (10) consultancy services for preparation of future energy projects. Outputs (1) The environmental and social impact assessments for the generation and distribution components and for the LPG project were completed in 2009. (2) The study for the Kipevu plant was completed in 2005. (3) The distribution upgrade study was completed in 2005. (4) Consultants were contracted to provide engineering services for the distribution component. (5) The LPG feasibility study was completed in December 2009. As a result of the study, the African Gas and Oil Company constructed the LPG import handling and storage facility in Mombasa with a capacity of 20,000 metric tons (MT). (6) The ESIA for the LPG import handling and storage facility was dropped because it was financed by the private company engaged in its construction. (7) The final report of the geothermal reservoir optimization study was submitted in 2009, which led to the development of an additional 280 MW at the Olkaria I and IV fields. The phase 1 report of the study, submitted in 2005, also contributed to the development of 35 MW of capacity for the Olkaria II Unit 3, supported under the project. (8) The study to establish a geothermal development company was completed in 2007, and the Geothermal Development Company was incorporated in December 2008. The company is developing geothermal resources outside Olkaria. (9) Engineering services for the design and supervision of the Olkaria II power plant extension were completed, with the project commissioning in 2010. (10) Engineering services for supervision of the SCADA/EMS contract were completed in 2010. (11) Feasibility studies were completed for the following activities: (a) twelve 13-kV transmission lines (of which three lines are supported under KEEP), (b) a 220-kV transmission ring around Nairobi, (c) a 300-MW coal-fired power plant in Mombasa, and (d) an LNG regasification plant. (These activities became part of additional financing.) In addition to the original scope, the following additional activities were undertaken: (12) A study on unbundling of KPLC was completed, which led to the establishment of KETRACO in 2009.

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(13) A transmission master plan was undertaken that identified medium-term (2012–17) and long-term (2018–30) reinforcements needed to accommodate the existing network development in Kenya. (14) Development of an M&E method, which was added at the time of additional financing, was dropped from the project activity because it was taken up in KEEP. (15) A sectoral environmental assessment was completed in 2009, which was integral to the investment prospectus prepared for the sector. (16) A total of 95 wind masts and data loggers were installed to validate and update the wind atlas and data collection. (17) The study on isolated diesel stations was transferred to the Privatization Commission (dropped from the project activity). (18) The feasibility study for an LNG regasification plant was completed. (19) A biogas consultant was hired to design and supervise the implementation of pilot biogas plants installed for flower farms. (20) Consultants were hired to help plan and coordinate energy sector planning activities. Component C: Generation, Olkaria II Power Plant Extension. Original Scope The planned outputs were (1) civil works for the extension of the powerhouse to accommodate the third 35-MW steam turbine generating unit, control panel and other ancillary equipment, cooling tower, and switchyard for installing a generator transformer, support bus-bar arrangement, and switchgear equipment; (2) a steam-gathering system from Olkaria I and Olkaria II sites and connecting pipes to the third Olkaria II unit; (3) supply and installation of a 35-MW steam turbine generating unit; (4) supply and installation of a 45-MV 11/220-kV step-up generator transformer, complete with switchgear equipment; and (5) supply and installation of other electrical and mechanical equipment, including control room equipment, cables, and other ancillary equipment. Outputs (1)–(5) Completed in 2010. The 35-MW geothermal plant came online in May 2010 and has generated 296 GWh (FY2011), 280 GWh (FY2012), and 255 GWh (FY2013) of clean energy annually. Component D: Distribution Upgrading. Original Scope The planned outputs were (1) upgrade existing and construct new substations; (2) reinforce and extend the distribution system; (3) supply energy meters; and (4) upgrade the SCADA/EMS system, including providing a trunked radio system for the Mt. Kenya region.

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Outputs (1) Constructed or rehabilitated 48 substations. (2) Constructed or rehabilitated 2,114 km of distribution lines, and installed 1,360 km of fiber optic cable for controlling the T&D system. Connected 526,000 new households, benefitting 2.63 million citizens. (3) Purchased and installed 230,000 energy meters.. (4) Installed a modern SCADA/EMS and trunked radio system. In addition to the original scope, two additional activities were undertaken: (5) Implemented the first undergrounding work of 33-kV lines in Mombasa, connecting Kipevu, Makande, Mbaraki, and Tononoka. (6) Purchased spare parts and equipment (transformers, conductors, insulators, stay rods and concrete pole accessories).

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Annex 3. Case of the Geothermal Generation EPC Procurement 1. A difficult procurement process that led to a considerable delay in awarding the turnkey contract for the extension of the Olkaria II geothermal power plant demonstrates how a series of decisions led to delays and, in this particular instance, increased cost, and produced a suboptimal result. The case is presented in a chronological order, highlighting key factors affecting the process. 2. ICB versus Direct Contracting. In 2004, KenGen, with a brief analysis of the consultants hired by KenGen, proposed direct procurement to save time and ensure that the third unit at the Olkaria II site would be from the same manufacturer as the first two installed units. A preliminary cost estimate at the time was US$46.0 million for civil works, power plant installation, electrical works for the switchyard, and civil and mechanical works at the steam field. However, with a view to ensuring competition, the agreed method of procurement at the outset was an ICB with prior prequalification. At the time, it was unknown if other prospective bidders could deliver at a lower cost but, either way, a key consideration was that inviting them would ensure competition and enhance efficiency. It was thought that there are other potential suppliers who could supply and install the third unit. Moreover, the project was prepared in the context of the 2004 Country Assistance Strategy for Kenya that prioritized improving governance as a pillar of the strategy.

3. Contract Packaging. KenGen also proposed a single turnkey EPC contract, including civil works, steam-gathering system, steam turbine, generator transformer, switchgear, and cables and control room panels, to avoid having to manage a large number of contractors, as had been the case with the two earlier installed units. This was based on the past project experience in which KenGen encountered difficulties managing numerous separate contracts, causing delays. The Bank therefore concurred with the proposal.

4. Market Structure. When the tender process started, there were only two responses to the initial request for prequalification in August 2005. One of the companies subsequently did not respond to the invitation to bid, explaining that it would not bid if the contract were packaged as one EPC contract, as it would give the existing contractor an advantage. The limited response was due to the market structure of geothermal turbine manufacturing, with only a limited number of suppliers worldwide, as well as the packaging of the EPC contract mentioned earlier.

5. Changed Method. While the team proposed to prequalify the two firms, OPRC instructed the team to change the procurement method so as to undertake an ICB with post-qualification and also to invite non-prequalified companies. In the meantime, efforts were made to research the geothermal industry, and solicit opinions from an independent consultant. The consultant recommended that the team reach out to other potential bidders. 6. Quality of Documents. The preparation of the bidding documents was delayed by a few months, due to iterations over the quality of the documents submitted, resolution of a difference in the fraud and corruption language to be applied to the documents between co-financiers, and the delayed completion of the Steam Availability Report supported under the ESRP (Olkaria Geothermal Resources Optimization Study), which was to confirm the geothermal resource availability. When the bidding documents were distributed in July 2006, despite several rounds of

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extension of the deadline for submission, only one bid was received, which was the same company that installed the first two units.

7. Price Escalation and Additional Financing. In the meantime, the international price of turbines had soared. KenGen eventually signed the contract with the bidder (a consortium of Mitsubishi Heavy Industries and Mitsubishi Corporation) in August 2007 at US$87.5 million, a price considerably higher than the US$53.5 million expected at project appraisal in 2004. As a result, KenGen applied for additional financing from AFD, which approved a loan of Euro 20 million in December 2007. Following KenGen’s payment of the 10 percent advance payment to the contractor in September 2007, the contractor started mobilization to the site in December 2007 and began manufacturing equipment.

8. Post-election Turbulence and Delayed Letters of Credit. However, due to the civil commotion following the disputed December 2007 general elections, the contractor issued a notice of force majeure in January 2008 and demobilized. In addition, in February 2008, the contractor issued a notice of intent to terminate, due to KenGen’s failure to issue the required LOCs, which was delayed in part because KenGen did not meet the conditions precedent for the effectiveness of the EIB and AFD financing, including financial security arrangements. Even if the financing had come in time, however, KenGen would still have had the difficulties in opening the large value LOC because other co-financiers did not provide the Special Commitment arrangement that the World Bank did. This arrangement allowed project implementing agencies to open an internationally acceptable LOCs through their local banks without having to provide high value collateral that would otherwise be required by their banks. KenGen subsequently placed the LOCs in February 2008, and the contractor remobilized in March 2008.

9. Negotiated Settlement. As a consequence of the force majeure and the delay in placing the LOCs, the contractor submitted change proposals seeking to revise the contract price, time for completion of works, and amendment of certain conditions of the contract. KenGen then requested IDA not to object to the renegotiated contract in May 2008. OPRC instructed the task team to hire an independent consultant to review the contract in September 2008. The case was finally resolved in February 2009, with the negotiated amounts be treated as the ceiling amounts and the contractor required to document its actual expenditures for relevant items before final payments were released. The amended contract amount was US$119.1 million, more than double the original cost estimate.

10. Conclusion. KenGen and the Bank had fundamentally different views about the costs, benefits, and risks associated with the procurement method to be followed. In future, it would be useful to consider the following aspects: (1) agree among project stakeholders early on to hire independent consultant(s), with experience in geothermal business and technology, and assess up front the costs, benefits, and risks of the procurement method, including direct contracting; (2) carefully design the package of EPC contracts so that a particular way of packaging does not hamper competition, and give consideration also to concerns raised by prospective bidders, separating out where possible contracts for the geothermal steam field, power plant, and transmission lines; (3) enhance coordination among co-financiers if joint co-financing is unavoidable, especially on funding coverage of contract costs as well as conditions precedent for financing, since opening LOCs entails significant risks and costs for implementing agencies; and (4) encourage informed risk taking in procurement decision making, taking into consideration

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timing factors. In this connection, a Performance Audit Report in the 1990s7 recommends that “[f]or geothermal projects the Bank needs to be more flexible in its procurement processes,” mainly in the context of geothermal drilling operations. Based on experience with this project, this applies to geothermal power generation as well.

7 Operations Evaluation Department. 1997. “Performance Audit Report Kenya Olkaria Geothermal Engineering Project (Loan S-012-KE), Olkaria Geothermal Power Project (Loan 1799-KE), Olkaria Geothermal Power Expansion Project (Loan 2237-KE), Geothermal Exploration Project (Credit 1486-KE), Geothermal Development and Energy Preinvestment Project (Credit 1973-KE).” The World Bank.

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Annex 4. Economic Analysis Generation Component 1. Results. The original estimated EIRR in 2004 for the generation component was 19 percent, and the NPV at a 12 percent discount rate was US$25.9 million. The reevaluated EIRR at the time of additional financing in 2009 was 14 percent and with an NPV of US$20.4 million. Based on the same methodology described below, the reevaluated EIRR at the time of project completion is 22 percent with an NPV of US$53.8 million. Table A4-1: NPV and EIRR for Generation: 2004(PAD), 2009 (Additional Financing) and

2013 (ICR)

2. The revised estimates with updated assumptions produce results higher than those in the 2004 PAD and the 2009 additional financing. This is largely attributed to the level of electricity tariffs that increased more than what was assumed in the previous two analyses (most of the other assumptions are similar to the ones adopted in the 2009 analysis). The incremental benefits arising from the tariff increase more than offset the adverse effects of more than doubling the originally estimated project costs. This confirms the analysis in 2009 that the economic viability of the project is particularly sensitive to the retail electricity tariff. 3. The estimated life-cycle cost of the plant remains at US$0.077/kWh, which suggests its comparative cost advantage over other generation options is solid. The assumptions used in the 2009 analysis are still valid: capital cost of US$119.1 million, net available capacity of 33 MW, 85 percent load factor, annual fixed operations and maintenance (O&M) cost of US$1.19 million, steam replenishment cost of US$2 million every five years, and variable cost for consumables of US$0.0055/kWh.

Economic Reevaluation Methodology 4. The analysis is carried out over a 15-year horizon with the following assumptions.

Costs: • Capital costs: The capital costs of the components are based on the actual cost totaling

US$119.1 million, which reflects the more than doubling of the costs from the time of appraisal.

• O&M costs: In the absence of the O&M cost data exclusively for the power plant, the O&M cost is estimated at 2.5 percent of the total capital costs (the same assumption as in 2004 and 2009).

• Steam replenishment: A steam replenishment cost, estimated at $2 million every five years, is applied in accordance with the 2009 assumptions.

• Incremental investment in T&D: Incremental investment in T&D is assumed at US$25 million, and an associated annual O&M cost of about US$1.25 million, to enable the

2004 2009 2013

NPV in US$ million (@12%) 25.9 20.4 53.8

EIRR (%) 19 14 22

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delivery of the incremental power to final consumers. These assumptions are in line with the 2009 analysis.

Benefits: • Sales to final consumers: Incremental sales to final consumers were used to calculate the

benefits. The volume is derived from actual sales starting in 2009, when the unit became operational, and with gross generation of 276 GWh projected into the future, adjusted for T&D losses reported by KPLC and projected into the future at 17.9 percent, which reflects the average of recent T&D losses in the system.

• Average electricity tariffs: The average electricity tariffs were used as a proxy for the willingness to pay in accordance with the original PAD assumptions. These were derived from annual retail tariffs reported in KSh/kWh, converted to US$/kWh at relevant average yearly exchange rates and projected into the future at an average retail tariff of 0.17 US$/kWh, which exceeds the initial PAD assumption of 0.14 US$/kWh.

Distribution Component 5. Results. For the distribution component, the original estimated EIRR was 30 percent and the estimated NPV at a 12 percent discount rate was US$246 million. The reevaluated EIRR at the time of additional financing is 27.4 percent with an NPV of US$31.4 million. Based on a similar methodology as the one applied to electricity access expansion described below, the reevaluated EIRR at the time of project closing is 32 percent, with an NPV of US$120.8 million.

Table A4-2: NPV and EIRR for Distribution: 2004(PAD), 2009 (Additional Financing) and

2013 (ICR)

6. The result suggests that the economic rationale for the distribution upgrading remains solid, even when applying conservatively estimated willingness to pay by consumers.

Economic Reevaluation Methodology 7. This ex-post reevaluation applies a method used for evaluating the electricity access at the time of additional financing to the distribution component as a whole, because substation-level data were not available. The analysis is carried out over a 15-year horizon with the following assumptions.

Costs: • Capital costs: The capital costs of the components are based on the actual cost of IDA-

funded distribution contracts totaling US$105.7 million.

2004 2009 2013

NPV in US$ million (@12%) 246.0 31.4 120.8

EIRR (%) 30 27 32

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• O&M costs: In the absence of the O&M cost data exclusively for the distribution lines, the O&M cost is estimated at 10 percent of the total capital costs (the same assumption as in 2009).

• Cost of energy: The cost of incremental energy supply is derived as follows: the average consumption level of grid-connected consumers multiplied by the number of incremental customers due to the project (i.e., incremental demand), multiplied by average cost of grid-connected electricity supply (including capacity payments).

• T&D Losses: T&D losses are derived from the actual system losses.

Benefits: • Consumers’ willingness to pay: The analysis maintained the same willingness-to-pay

assumption adopted in the 2009 analysis, which was US 22 cents/kWh, as the incremental demand started at about the same time. This assumption is based on a survey of peri-urban households that took place in preparation of KPLC’s customer connection policy in 2006.

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Annex 5. Bank Lending and Implementation Support/Supervision Processes (a) Task Team Members

Names Title Unit Responsibility/ Specialty

Lending Amarquaye Armar Program Manager SEGES Mourad Belguedj Consultant SEGOM Anne Khatimba Program Assistant AFCE2 Helena Mamle Kofi Consultant AFTG1 Joel J. Maweni Operations Adviser EASSD Samuel A. O'Brien-Kumi Consultant AFTG1 Robert A. Robelus Consultant AFTA1 Josphat O. Sasia Lead Transport Specialist AFTTR Yolaine Joseph Senior Operations Officer CFPTO Janine A. Speakman Operations Analyst AFTG1 Assefa Telahun Consultant AFTG1

Moses Sabuni Wasike Senior Financial Management Specialist OPSOR

Supervision/ICR

Henry Amena Amuguni Senior Financial Management Specialist AFTME

Paul Baringanire Senior Energy Specialist AFTG1 Noreen Beg Senior Environmental Specialist LCSEN Paivi Koljonen Lead Energy Specialist AFTG1 Gibwa Kajubi Senior Social Development Specialist AFTCS Mitsunori Motohashi Senior Energy Specialist AFTG1 Efrem Fitwi Senior Procurement Specialist AFTPE Fabrice Karl Bertholet Senior Financial Analyst AFTG2 Jyoti Bisbey Operations Analyst TWIFS Raihan Elahi Senior Energy Specialist AFTG1 Edeltraut Gilgan-Hunt Consultant AFTTR Umang Goswami Consultant CICIN Richard John Kaguamba Consultant CPFCF Anne Khatimba Program Assistant AFCE2 Josphine Kabura Ngigi Financial Management Specialist AFTME Samuel O’Brien-Kumi Consultant AFTG1 Kyran O’Sullivan Senior Energy Specialist AFTG1 Vonjy Miarintsoa Rakotondramanana Energy Specialist AFTG1

Abdolreza B. Rezaian Senior Energy Specialist AFTG1 Nightingale Rukuba-Ngaiza Senior Counsel LEGAM Dana Rysankova Senior Operations Officer OPSRE Rosemary Otieno Program Assistant AFCE2 Lucy Kang’arua Program Assistant AFCE2 Bernadette Milunga Program Assistant AFTG1 Josphat O. Sasia Lead Transport Specialist AFTTR Janine A. Speakman Operations Analyst AFTG1

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Assefa Telahun Consultant AFTG1 Jorge E. Uquillas Rodas Consultant OPSOR Kameel Virjee Consultant TWIAF Dahir Elmi Warsame Senior Procurement Specialist AFTPE

Moses Sabuni Wasike Senior Financial Management Specialist OPSOR

Sandra M. Kuwaza Senior Finance Assistant CTRLA Samuel Kihoro Macharia Finance Analyst CTRLA Regine Mpoyi Program Assistant GEFEX George Ferreira Da Silva Finance Analyst CTRLA Rahmoune Essalhi Procurement Assistant AFTG1 Caroline Nelima Wambugu Team Assistant AFCE2

(b) Staff Time and Cost

Stage of project cycle Staff time and cost (Bank budget only)

No. of staff weeks US$ thousands (including travel and consultant costs)

Lending FY2004 44.94 322.46 FY2005 3.34 23.23

Total 48.28 345.69 Supervision/ICR FY2005 23.08 140.89 FY2006 28.91 204.80 FY2007 23.56 199.83 FY2008 51.95 316.47 FY2009 31.19 128.00 FY2010 32.59 154.88 FY2011 32.05 144.63 FY2012 44.18 125.08 FY2013 23.04 94.31 FY2014 3.34 39.46

Total 293.89 1,548.35

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Annex 6. Beneficiary Survey Results Not applicable.

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Annex 7. Stakeholder Workshop Report and Results In preparation of the Borrower’s Completion Report, the MoEP organized workshops on November 26-28, 2014. The workshops were attended by the PIUs of the MoEP, ERC, KenGen, and KPLC. A summary of the Report is in Annex 8 (The full 47-page report is available in project files).

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Annex 8. Summary of Borrower's ICR and/or Comments on Draft ICR

MINISTRY OF ENERGY & PETROLEUM (MOEP)

Energy Sector Recovery Project (ESRP) Financed by IDA, EIB, AFD, and NDF

REPORT ON THE EXECUTION OF THE PROJECT8

DECEMBER 2013 1.0 Executive Summary 1.1 Using the background section from the PAD, the GoK Implementation Completion Report (ICR) describes the declining economy and services in the 1990s and the increase in poverty. For the sector, the report discusses the low level of connections, the monopolistic structure of the sector, the weak policy and regulatory environment, and the GoK’s strategy to improve the performance of the sector as part of the ERSWEC of March 2004. 1. 2 The PDOs of improving the policy, regulatory, and institutional environment, expanding generation capacity, expanding electricity distribution, and improving the quality of services provided are given, along with the indicators for measuring achievement of the PDOs. The 2009 restructuring—dropping the generation PDO and streamlining the indicator—is described next. 1.3 Project Achievements. The detailed list of achievements at closing for the PDOs in the policy area includes new tariff structure; KenGen initial public offering; promulgation of regulatory instruments; more than 1,200 staff benefitting from various capacity-building programs at KPLC, KenGen, MoE, ERC, KEBS, REA, and the Energy Tribunal; a geothermal reservoir optimization study establishing the feasibility of implementing 280 MW of power generation in Olkaria; a geothermal business plan study forming the basis of splitting KenGen to form the Geothermal Development Company in 2009; and preparation and implementation of an Organizational Structure, Staffing, Financing, Strategic Plan and Human Resource Policy Manual for ERC. The list of achievements also incorporated ERC development, implementation, and enforcement of regulations, codes, procedures, guidelines, licenses, and permits, including proposals on draft regulations for implementation of the Energy Act; pro-forma licenses, license application forms, and permits; model PPAs for various electricity-generating technologies; legal and technical audits and proposals for review of the grid code; development of regulations for downstream petroleum, electricity tariffs, and regulatory accounts; ERC implementation of MIS; and a study of the Kenyan electricity supply system that identified medium-term (2012–17) and long-term (2018–30) reinforcements required as part of the LCPDP for enhancing the KEBS Petroleum Standards Monitoring Unit’s capacity for monitoring and testing petroleum products. The following feasibility studies were completed: the KPLC unbundling study, enabling the establishment of KETRACO in 2009; the LNG regasification plant study, which is the basis for the ongoing tendering to select a concessionaire to construct an LNG regasification plant in Mombasa; the biogas consultancy report; sector-wide environmental impact assessments; and

8 The full 47-page report is available in the project files.

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studies for developing MoE’s capacities in power engineering, petroleum, renewable energy, and biogas. 1.4 The achievements of the increasing access PDO are: • Installed 95 wind masts and data loggers have been. Obtained, analyzed, and used data to

validate and improve the wind atlas. • Constructed/rehabilitated 48 substations and 2,114 km of distribution lines. • Connected an additional 526,000 households to the national electricity grid, benefiting

2,630,000 Kenyan citizens. • Completed a modern control and data acquisition system,, energy management system, and

radio communication system that has improved the efficiency and quality of electricity supply.

• Installed 1,360 km of fiberoptic cable in the T&D system. • Completed a 35-MW unit at Olkaria II, in May 2010, generating an average of 287 GWh

annually. • Completed the following feasibility studies; the Kipevu Combined Cycle power plant study,

which led to identification of the Olkaria II third unit as the best option; an LPG import handling and storage facility study, which led to the African Gas and Oil Company constructing an import handling and storage facility with a capacity of 20,000 MT in Mombasa; a study for a 300-MW coal-fired power plant in Mombasa, whose findings KenGen used to advertise for a public-private partnership for implementing the project (which could not proceed after the site recommended by the consultant was found to be unsuitable because of its close proximity to the Moi International Airport in Mombasa); studies for twelve 132-kV transmission lines of which three lines—the 230-km Kindaruma-Mwingi-Garissa, the 60-km Eldoret-Kitale, and the 44-km Kisii-Awendo—are being constructed under the Kenya Electricity Expansion Project; and the study for a 220-kV transmission ring around Nairobi, which is under construction.

1.5 Project Challenges and Implementation Problems. The executive summary lists the following issues: • A three-year delay in the generation component, and a capital increase of about US$18

million, because of the Bank’s requirement for a feasibility study to be undertaken before procurement could proceed. The resulting prolonged procurement led to further cost escalation of more than US$7 million.

• Delays by KenGen in meeting the preconditions for disbursement by AFD and EIB resulted in funding delays for the generation component, and a depletion of KenGen’s cash reserves. Consequently, the contract price had to be renegotiated and was increased by US$10 million.

• Delays in obtaining tax and duty exemptions from the National Treasury. • Delays with connecting new equipment to the grid. • The negotiation for a lease of land for the Olkaria II project with the Kenya Wildlife Service

took more than a year to reach an agreement. The land was part of the security for EIB and AfD, which led to delays in obtaining the securities for the loans. KenGen failed to open an LOC within the specified contract period for the Olkaria II project due to unavailability of funds. This in turn led to a re-negotiation of the contract agreement. In addition, the Bank delayed its No Objection ruling for the renegotiated agreement between KenGen and the contractor. In 2008, due to the global financial crisis, the distribution component attracted

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bids that were significantly below engineering estimates, leading to major challenges by the winning bidders. Moreover, challenges associated with land acquisition, rights of way, and permits from local authorities led to delays in site handover and commencement of works.

• Limited availability of experienced subcontractors to implement the local works led to delays in implementation and, in some cases, court cases.

• Heightened vandalism of electrical infrastructure, including theft of contractors’ materials from stores, affected completion of projects.

• Delays in obtaining tax and duty exemptions led to delays in clearing imported equipment at the port of entry.

• Bureaucratic approval processes in the line ministries caused delays in processing disbursements.

1.6 Lessons Learned. Direct borrowing from development partners by KenGen was complicated, resulting in delays in reaching financial closure and negatively affecting the overall project schedule. The GoK should mediate in land issues between government agencies to minimize delays in reaching agreement. Agencies should not proceed with signing contracts unless full funding is secured. When seeking donor funds, it is important that bankable documents (feasibility study reports) have been prepared. It was a challenge combining distribution lines and substations in one contract, as the two require different sets of expertise. Bidders tend to put most of the costs into materials and reduce installation costs significantly (front loading). For distribution projects located in geographically widespread locations, it is necessary to package the contracts into manageable lots, and restrict the number of lots a bidder can participate in. 2.0 Implementation and Procurement Issues, Challenges, and Lessons Learned 2.1 Implementation Issues. PITs were established within the organizational units that are normally responsible for implementing similar projects. On commencement of the project, the PITs had sufficient staff and/or consultants with experience and skills in project management. In addition, a management oversight committee was established comprising executive directors from KPLC, KenGen, and MoE. An experienced consulting engineering firm was competitively procured for the design, review, and supervision of construction works. The agencies for the subcomponent for strengthening regulatory capacity—ERB (which later became ERC) and KEB—each appointed focal point persons assisted by two or three other designated staff in liaising with MoE. 2.2 Challenges and Lessons Learned. The creation of the Geothermal Development Company led to the migration of key staff from KenGen, creating work overload within the PIT. Also, the oversight committees of the implementing agencies did not provide the required supervision. The turnover of staff in the accounting and procurement departments of MoE (now the Ministry of Energy and Petroleum [MOEP]) was very high. The accountants and procurement staff were all seconded from the National Treasury to MOEP, and whenever staff changes were made, MOEP got new accountants and procurement staff who had no experience in preparing Financial Management Reports/Interim Financial Reports (FMRs/IFRs) and procurement guidelines. The PIT had to arrange training for these new staff members, but often would lose them again because of interministerial staff transfers. As a result, the quality of procurement documentation, preparation of FMRs/IFRs, and project accounts preparation in MOEP suffered. The hiring of consultants for MOEP’s PIT improved overall project management coordination, and reporting; informed decision making; and enhanced capacity in petroleum standards, renewable energy, rural energy, and power development.

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2.3 Procurement. During project appraisal, a procurement plan for the first 18 months of implementation was developed spelling out the procurement methods that had to be used. This plan was discussed in detail and refined as appropriate during negotiations and approved by the World Bank. The Plan was updated by the GoK on an annual basis. The agreed thresholds for procurement methods and prior review were included in the plan, among other methods, that for works, supplies and installations (the Olkaria II unit) greater than US$500,000, ICB with prior review was required. 2.4 Procurement Issues. The schedule for the procurement of the generation component was affected due to a requirement by IDA that KenGen prove the adequacy of available steam for the additional unit. The project’s initial budget escalated due to cost increases of several contracts that occurred as a result of the unforeseen rise in international prices for construction materials at the time of contract award, and other factors significantly impacted the procurement schedule. In addition, delays in approval of contracts by IDA, and subsequent changes to contract conditions led to prolonged delays in implementation. Among the lessons from this experience is the quality and relevance of initial assumptions during the planning stage will determine to a large extent how well the project will be managed. Also, inadequate funding of the project adversely affects the quality of its management. For instance, KPLC experienced delays in acquiring land for new substations because of lengthy internal procurement logistics. This resulted in some contracts commencing before land was made available to the contractors, causing delays and creating additional costs. KPLC learned the need to tender for projects only after land had been obtained and all necessary legal requirements had been met. However, at times, KPLC did, not factor in the right-of-way acquisition processes in the project schedules. Hence, any delays in right-of-way acquisition led to delays in completing projects. KPLC had also decided to prepare separate contracts for lines and substations, so that the contracts could run concurrently to avoid a scenario where substations are completed before the lines are completed. Another complication was that initially the distribution project component did not require NEMA licensing; however, because of a 2006 change in environmental licensing requirements NEMA had to issue licenses for individual sites, which caused delays. KPLC also experienced delays in acquisition of local authority clearances for its project sites, leading to delays in the handover of project sites to contractors. KPLC has now adopted a consultative approach and close working relationship with the various local governments to enable fast-tracking of the clearance documents. 2.5 Additional Lessons. The Bank’s refusal to allow KenGen to sole source an existing contractor who was at the Olkaria II site led to prolonged delays in securing a contractor. In the end, that same contractor was the only bidder. In addition, the Bank’s insistence on the confirmation of adequate steam resulted in a procurement delay of two years with the EPC contract for the Olkaria II Unit 3. However, where an existing contractor is in place carrying out similar work, there is no guarantee of a low-price bid from either the existing contractor or new bidders for an increased scope of work. During fundraising for future energy projects, the implementing agencies should carry out a cost-benefit-analysis of the available financing options and select those that are most favorable for the smooth implementation of projects. Delays developed in obtaining internal approvals from tender committees and boards of the implementing agencies. The quality gaps in procurement documents submitted to IDA for review and approval contributed to the delays in obtaining No Objection rulings. However, in some

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instances, the Bank took longer than the agreed time to provide No Objection rulings without any apparent reason. Delay in obtaining tax and duty exemptions led to demurrage costs, time extensions, and attendant costs. The lesson learned here was that future loan agreements from development partners should include financing of taxes and duties. In an effort to win the tenders, some bidders underquoted and then wasted time looking for cheap sources of materials and subcontractors, or presented designs that compromised on specification. Hence, significant time was wasted going back and forth during design approval. The lesson learned here was that a credible engineer’s estimate should be used to provide realistic bid prices besides carrying out due diligence on the bidder before contract signature.

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Annex 9. Comments of Co-financiers and Other Partners/Stakeholders 1. EIB provided comments on the early draft ICR. Their comments covered two aspects of project implementation: (1) the conclusion of financing agreement between KenGen and co-financiers; and (2) the procurement challenges of the geothermal EPC contract. 2. In relation to the delays in finalizing financing agreement between KenGen and co-financiers, the EIB’s comments clarified that “the procurement process took much longer than expected, and required special consideration on the background of the World Bank’s standard rules. The contract price had to be re-negotiated and the work site was closed down during the civil unrest, which increased the cost further and led to a lengthy process of negotiation of additional financing from EIB and AFD, including new security arrangements. Also, the financial covenants had to be re-negotiated in order to enable EIB and AFD to disburse loans. In the meantime, in order to continue the project works, Kengen had to raise its own funds and Government funds (which were used to back up letters of credit).” These points were taken into consideration in finalizing this ICR. 3. On the issue of geothermal EPC procurement, the EIB’s comments fully support the description of issues in the early draft, which is substantially retained in this final report.

4. Other co-financiers did not have comments on the draft ICR.

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Annex 10. List of Supporting Documents

1. Performance Audit Report, Kenya. Olkaria Geothermal Engineering Project (Loan S-012-KE); Olkaria Geothermal Power project (Loan 1799-KE); Olkaria Geothermal Power Expansion Project (Loan 2237-KE); Geothermal Exploration project (Credit 1486-KE); Geothermal Development and Energy Preinvestment Project (Credit 1973-KE), June 27, 1997. Operations Evaluation Department. The World Bank. Report No. 16842.

2. Implementation Completion Report (IDA-29660 PPFI-P7711 PPFI-P7712) on a Credit in the Amount of US$125 million to the Republic of Kenya for an Energy Sector Reform Project, June 8, 2005. The World Bank. Report No. 32101.

3. Development Credit Agreement (Energy Sector Recovery Project) between Republic of Kenya and International Development Association, Dated August 4, 2004. Credit Number 3958.

4. Project Appraisal Document on a Proposed Credit in the amount of SDR55.20 Million (US$80 million equivalent) to the Republic of Kenya for an Energy Sector Recovery Project, June 10, 2004. Energy Team, Infrastructure Group, Africa Regional Office, The World Bank. Report No. 28314-KE.

5. Project Paper on a Proposed Credit in the Amount of SDR53 Million (US$80 Million Equivalent) to the Republic of Kenya for an Additional Financing Credit for the Energy Sector Recovery Project, March 9, 2009, Energy Team, Sustainable Development, Africa Region. The World Bank. Report No. 47262-KE.

6. Ministry of Energy & Petroleum, Energy Sector Recovery Project, Financed by IDA, EIB, AFD & NDF, Report on the Execution of the Project, December 2013.

7. Kenya Power. Brief on World Bank Funded KPLC 66/11KV Lavington Sub-Station Project Arising from National Environmental Tribunal at Nairobi Appeal No. NET/67/2011 Njumbi Road Residents Association & Lavington Residents Association vs. National Environment Management Authority and KPLC and Nairobi High Court Civil Appeal No. 178 of 2013 KPLC vs. Njumbi Road Resident Association. As at Thursday 28th November 2013.

8. KenGen Kenya Electricity Generation Company Ltd. GIBB Africa. Olkaria I Units 4 & 5 Geothermal Project in Naivasha District. Environmental and Social Impact Assessment (ESIA) Report, April 2010.

9. The International Development Association, The International Finance Corporation, The Multilateral Investment Guarantee Agency, Country Partnership Strategy for the Republic of Kenya for the Period FY2010–13, March 23, 2010. Eastern Africa Cluster 2, Africa Region, International Finance Corporation. The World Bank .Report No. 52521-KE.

10. Restructuring Paper on a Proposed Restructuring of Energy Sector Recovery Project Credit July 13, 2004 to the Republic of Kenya, May 2, 2012. The World Bank. Report No. 68471 v1.

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11. Restructuring Paper on a Proposed Restructuring of Energy Sector Recovery Project Credit July 13, 2004, to the Republic of Kenya, April 15, 2013. The World Bank. Report No. 76884-KE.

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Annex 11. Kenya KenGen Carbon Finance Umbrella Project—Implementation Completion and Results Report

Document of The World Bank

IMPLEMENTATION COMPLETION AND RESULTS REPORT

ON A

PURCHASE OF EMISSION REDUCTIONS

TO

KENYA ELECTRICITY GENERATING COMPANY

FOR THE

KENYA KENGEN CARBON FINANCE UMBRELLA PROJECT

March 27, 2014

50

IMPLEMENTATION COMPLETION AND RESULTS REPORT

CONTENTS

ABBREVIATIONS AND ACRONYMS 1. DATA SHEET…………………………………………………………………….. ….…52 2. ACHIEVEMENT OF IMPLEMENTATION OBJECTIVES AND OUTCOMES……..54 3. BANK AND PROJECT ENTITY PERFORMANCE……………………………….…..56 4. BENEFITS, TARGET POPULATION, AND RATE OF SUCCESS…………………..56 5. COMMENTS FROM PROJECT ENTITY AND OTHER PARTNERS………………..57 6. COMPLIANCE WITH SAFEGUARDS………………………………………………...57 7. LESSONS LEARNED…………………………………………………………………..57 8. JUSTIFICATION FOR MOVING TO THE SECOND PHASE (CARBON FINANCE

MONITORING) AND SAFEGUARDS COMPLIANCE………………………………59

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Abbreviations and Acronyms

CBP Community Benefit Plan CCGCF Climate Change Group—Carbon Finance Unit CDCF Community Development Carbon Fund CDM Clean Development Mechanism CER Certified Emission Reduction CF Carbon Finance DOE Designated Operational Entity ER Emission Reduction ERPA Emission Reduction Purchase Agreement ESIA Environmental and Social Impact Assessment ESRP Energy Sector Recovery Project GHG Greenhouse Gas ICR Implementation Completion and Results KenGen Kenya Electricity Generating Company Ltd. KKCFUP Kenya KenGen Carbon Finance Umbrella Project KWS Kenya Wildlife Society MW Megawatt PDD Project Design Document PDO project Development Objective UNFCCC United Nations Framework Convention on Climate Change VER Verified Emission Reduction

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IMPLEMENTATION COMPLETION REPORT (ICR) Kenya KenGen Carbon Finance Umbrella Project

1. DATA SHEET A. Basic Information Country: Kenya Project Name: Kenya KenGen Carbon Finance

Umbrella Project Project ID: P103458 (Parent project is P083131) ICR Date: March 19, 2014 Emission Reduction Purchase Agreement (ERPA) Volume in Certified Emission Reductions (CERs) and Verified Emission Reductions (VERs)

Community Development Carbon Fund (CDCF)

CERs 257,671 VERs 220,861

TOTAL 478,532 Bank/International Finance Corporation Lending or Grant (in loan/grant currency): SDR108.2 million Environmental Category: B Project Entity: Kenya Electricity Generating Company

Ltd. Co-financiers and Other External Partners: n.a. ICR Prepared by: Patricia Marcos Huidobro, Noreen Beg,

Joseph Bredie Approved by CD: Diarietou Gaye Approved by SM: Lucio Monari B. Key Dates ERPA signing & effectiveness date November 14, 2006

ERPA amendment dates First Amendment: September 10, 2009 Second Amendment: September 7, 2010 Third Amendment: April 16, 2013

ERPA termination date December 31, 2014 C. Ratings Summary Progress toward Achievement of PDO Moderately Satisfactory Overall Implementation Progress Moderately Satisfactory Overall Safeguards Rating Satisfactory D. Sector and Theme Codes Sector Codes (in %) Renewable Energy 100% Theme Codes (in %) Climate Change 100%

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E. Bank Staff

Position At ICR At ERPA Signing Sector Manager Lucio Monari Subramaniam V. Iyer Task Team Leader Mitsunori Motohashi Paivi Koljonen Deal Manager Patricia Marcos Huidobro Noreen Beg F. ERPA payments and emission reductions (ERs) delivery to date # Payment Payment Type Monitoring Period CERs Delivered Value Date Currency

1 ER Payment 4/12/2010 – 31/12/2011

149,154 11/01/2013 US$

G. Supervision of Carbon Finance Operations Guidelines According to the Bank Guidelines (Office Memorandum, December 1, 2011) oversight (supervision and monitoring) of Carbon Finance operations is conducted in two phases: (1) the implementation phase, from effectiveness of the ERPA to project completion; and (2) the monitoring phase, from project completion to termination of the ERPA. Between these phases, oversight responsibility is transferred from the region to the Climate Change Group–Carbon Finance Unit (CCGCF). Since the Kenya KenGen Carbon Finance Umbrella Project is fully operational and capable of generating emission reductions, the present ICR summarizes the project’s achievements, issues encountered, and lessons learned, in order to transfer it to CCGCF for the monitoring phase.

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2. ACHIEVEMENT OF IMPLEMENTATION OBJECTIVES AND OUTCOMES 2.1 Basic project description and summary of any significant changes since Emission Reduction Purchase Agreement (ERPA) signature 2.1.1 The Kenya KenGen Carbon Finance Umbrella Project (KKCFUP) reduces greenhouse gas (GHG) emissions by displacing fossil-fuel based electricity generation to the grid following the installation of a third 35-megawatt (MW) clean geothermal generating unit at the existing Olkaria II power plant. 2.1.2 The Kenya Electricity Generating Company (KenGen) owns and operates two geothermal power stations, Olkaria I and Olkaria II. The original Olkaria II power plant had two units with a combined capacity of 64 MW. However, there was an estimated steam surplus of 53 MW, which was sufficient for the implementation of a third unit of 35 MW at Olkaria II. 2.1.3 The KKCFUP was designed in 2006 to support the development of an estimated 600,000 certified emission reductions (CERs) and 300,000 verified emission reductions (VERs). An Emission Reduction Purchase Agreement (ERPA) for CERs and VERs from Olkaria II (Unit 3) was signed on November 14, 2006, with the Community Development Carbon Fund (CDCF). The ERPA was amended to, among others, adjust the CER/VER volume according to the amended registration date of the project of December 4, 2010. The CER volume was reduced to 257,671 CERs in the third amendment, and the VER volume was reduced to 220,861 VERs. 2.1.4 As part of the ERPA between KenGen and the CDCF, the project supports the implementation of Community Benefit Plan (CBP), by earmarking a portion of the emission reduction (ER) payments for community projects that enhance access to basic infrastructure and services to poor local communities living in the vicinity of the carbon finance (CF) project site. The CBP was developed by KenGen in close consultation with the local Maasai, Luo, and Kikuyu tribes. The CBP components include the construction of a livestock water pan, six classrooms, and local road repairs, as well as a water pipeline extension to the community health center and employment of local youth. An advance payment of US$225,000 was disbursed to KenGen in June 2011 to help start the CBP implementation. As of January 2014, most of the components have been completed, except for the construction of the six class rooms, which is ongoing. The CBP is estimated to benefit 450 pupils, 20,000 local inhabitants, and 40,000 livestock. As more CERs are certified by the United Nations Framework Convention on Climate Change (UNFCCC) and VERs are verified by an independent auditor, more resources will be used for the implementation of the CBP. 2.2 Project implementation and commissioning

2.2.1 Original Project Development Objective (PDO): The original PDO of the KKCFUP was to reduce GHG emissions by displacing fossil fuel-based electricity generation in Kenya with clean geothermal power generation at the existing Olkaria II (Unit 3) power plant. The construction and operation of the clean geothermal power generation unit at Olkaria II are supported by financing from the International Development Association under the Kenya Energy Sector Recovery Project (ESRP), from the European Investment Bank, and from the Agence Française de Développement. The third unit of the Olkaria II geothermal plant, with an installed capacity of 35 MW, started delivering electricity to the grid on September 1, 2010, and thus displacing electricity from existing fossil fuel-based plants in Kenya.

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2.2.2 The Olkaria II Unit 3 was registered as a Clean Development Mechanism (CDM) project on December 4, 2010. So far, 152,198 CERs have been issued (149,154 CERs delivered to the CDCF), corresponding to the first verification, which covers the period from December 4, 2010, to December 31, 2011. The first payment under the CDCF ERPA for the purchase of CERs was completed in November 2013. As of March 2014, approximately two-thirds of contract ERs remain to be delivered under the CDCF ERPA. 2.2.3 In accordance with the ERPA, KenGen committed to spend part of the CER/VER revenue toward the implementation of a CBP. The CDCF participants visited Olkaria in 2006 when members from the surrounding communities presented priority projects for funding under the CBP. However, as a result of the delays in the project commissioning and CDM registration, the CBP was revised by the Olkaria Corporate Social Responsibility Committee during a meeting on September 6, 2010, as follows. Benefit Beneficiaries Location Expected

completion date 1. Excavation of Olosingate water pan for watering livestock

40,000 livestock

Enoosupukia Location, Mau Division, Narok District

90% complete, final completion March 2014

2. Construction and equipping of 3 classrooms at Ngambani Nursery School

250 pupils/year

Maiella Location, Naivasha Division, Nakuru District

85% complete, final completion March 2014

3. Construction and equipping of 3 classrooms at Oloirwua Primary School

200 pupils/year

Enoosupukia Location, Mau Division, Narok District

March 2014

4. Construction of a waterline from Tank Mpya to Maiella

20,000 people Maiella Location, Naivasha Division, Nakuru District

March 2014

Last priority for future reference 5. Upgrading of 10 km of the Suswa-Narasha Hell’s Gate road to Murraming

10,000 people Inter District, Narok/Nakuru

–

2.2.4 During the implementation phase of the CBP, KenGen has put in place Steering and Management Committees, with members from the Olkaria Geothermal Project as well as staff from the KenGen Head Office. 2.2.5 In accordance with the ERPA, the CDCF made an advance payment of US$250,000 to KenGen to be used for the early implementation of the CBP, in advance of the delivery of ERs. KenGen has reimbursed this advance payment to the CDCF. 2.3 Monitoring, reporting, verification, and issuance of emission reductions

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2.3.1 The monitoring of Olkaria II projects has been carried out by KenGen in accordance with the Monitoring Plan as described in the Project Design Document (PDD).9 KenGen has prepared all monitoring reports. 3. BANK AND PROJECT ENTITY PERFORMANCE 3.1 Assessment and rating of overall Bank performance 3.1.1 Overall, the Bank’s performance has been satisfactory. The Bank’s involvement was critical in the CDM registration and verification stages. Since the beginning of the project, the Bank has collaborated closely with KenGen and has built the capacity needed to overcome many of the obstacles the project encountered, such as the concerns raised by the designated operational entity (DOE) during the verification stage on the project’s boundary. 3.2 Assessment and rating of overall project entity performance 3.2.1 The performance of KenGen is rated satisfactory. KenGen has complied with all of the obligations and requirements expected, such as assisting with the development of the PDD and maintaining good relations with local stakeholders (i.e., municipalities, communities, and nongovernmental organizations). KenGen monitors the performance of the equipment to ensure compliance with the PDD and implements the Environmental Management and Monitoring Plans. KenGen is implementing the CBP in a timely manner and is complying with the safeguards of the ESRP (the parent project).

4. BENEFITS, TARGET POPULATION, AND RATE OF SUCCESS 4.1 The KKCFUP was the third CDM project registered in Kenya, and the first project to issue CERs. ERs have been calculated using information verified by a DOE, an “independent auditor accredited by the CDM Executive Board to verify whether implemented projects have achieved planned greenhouse gas emission reductions,” as well as the CERs issued by the CDM Executive Board. Estimated electricity generated has also been extracted from these reliable sources. Benefit Actions of the Kenya KenGen Carbon Finance Umbrella Project:

Benefit Actions Indicators Baseline value Estimated amount* Results*

Emission reductions

Tons of carbon dioxide equivalent

0 161,520 149,154

Electricity generated exported to the grid

Gigawatt-hours/year 0 276 264

*As of December 31, 2011.

9 For the PDD- and UNFCCC-related documents, please refer to: http://cdm.unfccc.int/Projects/DB/DNV-CUK1276170328.71/view.

http://cdm.unfccc.int/Projects/DB/DNV-CUK1276170328.71/view

http://cdm.unfccc.int/Projects/DB/DNV-CUK1276170328.71/view

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4.2 As of January 2014, the project’s CBP is estimated to benefit 450 pupils, 20,000 local inhabitants, and 40,000 livestock. As more CERs are certified by the UNFCCC and VERs are verified by an independent auditor, more resources will be used for the implementation of the CBP activities.

5. COMMENTS FROM PROJECT ENTITY AND OTHER PARTNERS 5.1 KenGen contributed to the preparation of this Implementation Completion and Results (ICR) report, providing the Bank ICR team with information and data, and facilitating site visits. KenGen also provided the lessons learned section, and the information to describe KKCFUP’s commissioning and implementation experiences. KenGen participated in regular Bank supervision and safeguard missions. 6. COMPLIANCE WITH SAFEGUARDS 6.1 The KKCFUP is in compliance with the environmental and resettlement safeguards of the ESRP, specifically the mitigating measures for the Olkaria II generating unit. The ESRP was rated B and triggered the Safeguard Policy for Environmental Assessment (OP 4.01) and Natural Habitats (OP 4.04). The opinion of the independent consultancy firm (accredited by the Kenyan National Environmental Management Authority) who reviewed the environmental and social implications of Olkaria II in April 2004, was that the environmental and social impacts from the expansion are likely to be moderate to negligible. They would be manageable, given KenGen’s demonstrated capacity for environmental management. As noted, the expansion of the geothermal generation unit uses a renewable and environmentally clean fuel. The ESRP’s environmental staff conducted a mission in 2010 and examined the potential impacts of Olkaria II on wildlife, water availability and quality, and soil and water pollution. The mission consulted with the environmental and social impact assessment (ESIA) consultant, the Deputy District Commissioner, the Kenya Wildlife Society (KWS), and the nearby Maasai community. KWS and the Maasai elders confirmed that Olkaria II has had no effect on wildlife. In fact, the troughs provided by KenGen for wildlife have lessened stress for animals that previously had reduced access to Lake Naivasha. The ESIA consultant found that the use of water from Lake Naivasha for the Olkaria plant, which is being recirculated and only refilled once a year during maintenance, is inconsequential (compared with the nearby flower farms). KenGen analyzes the brine and sludge levels of discharge water and has agreed to reinject the brine underground in reinjection well pads. Sludge that may contain toxic non-biodegradable substances will be encased in concrete and buried. Finally, KenGen will ensure that transmission lines do not loop back into the nearby Hells Gate Park, and instead will go straight to Suswa, minimizing the risk of electrocution of raptors and nesting birds. 7. LESSONS LEARNED 7.1 Communication with local communities and stakeholder is key in CF projects. To ensure successful delivery of the CBP, KenGen:

• Conducts regular meetings with key stakeholders, including the Climate Change Coordination Committee, the local communities, and the Ministry of Environment, Water and Natural Resources.

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• Conducted early consultation, which is key to community ownership and sustainability. In the Olkaria CBP, the community identified and prioritized 4 of the 26 proposed projects. Early on, KenGen conducted meetings with the district officers of Narok and Naivasha. The involvement of the officers was important, because they control channels of communication and information dissemination during public consultation, and can reconcile differences as they are deemed to be impartial. It also helps to involve relevant ministries in technical support activities to ensure that these activities are sustained. KenGen has involved the communities in the selection of committee members who will implement the activities, including the representatives from ministries, such as education and water. Moreover, gender consideration was key during the selection of the committee members. KenGen’s Corporate Social Responsibility Officer, Beatrice Kipingo, who has been based at Olkaria for more than seven years, took care to ensure that females from the community were invited to meetings. Meetings attended by CF and Bank staff can confirm that these female community members made their views known, and their concern for education is reflected in the selection of classroom construction in the CBP.

• Carried out capacity building for committee members to help them understand how to manage the implementation of projects. In addition, using local labor increases the project’s benefits. In the case of the Olkaria CBP, the workers were paid. This was necessary because of the high poverty levels of the communities.

• Did not raise expectations of local communities. Given the lag between project commissioning and ER generation (both triggers for Community Benefit fund release) local communities may become suspicious that the project sponsor (KenGen) is retaining funds. It is also important to manage timing of consultations until the amount of ERs to be generated is known with some degree of certainty, as the amount of Community Benefit funding is dependent upon the amount of ERs generated.

7.2 Independent nature of CDM project cycle and Bank capability to deal with it. Access to project development financing and CDM project registration is key to maximizing the benefits from CDM projects. In this case, a Project Idea Note was submitted to the Bank in July 2006, and the project was registered in December 2010. However, several changes occurred in CDM procedures and regulations, and the PDD had to be updated to reflect the new changes. The registration delay was mostly caused by the validation process, and led to reviews of the ERPA and subsequent reduction in the expected revenue generation from the contract CERs and corresponding VERs. Measurable and certified ERs require a rigorous verification process. 7.3 Direct sustainable development benefits of Olkaria II geothermal project. The development of geothermal energy not only leads to low carbon growth, but also improves access to electricity, reduces overdependency on hydropower electricity, and provides energy security. The dependence on hydropower in Kenya represents a risk due to recurrent droughts and deforestation of the catchment areas. Frequent droughts are causing power rationing and require expensive emergency diesel-powered generation. Growing geothermal energy reduces the dependence on hydropower and emergency power generation. The community fund increased the acceptability of the geothermal expansion project. Distributing indirect benefits among the communities around the plants ensured fairness and avoided controversy. In the case of Olkaria, benefits were distributed between Maiella and Suswa. Suswa is a largely Maasai area, whereby Maiella has a mixed population of Kikuyu and Maasai.

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7.5 Replication effect. The geothermal expansion project was the third CDM project to be registered and the first to issue CERs in Kenya. The project participants are currently sharing the lessons learned from this project with other Kenyan projects that are at different verification stages. 7.6 Partnerships are a key instrument to boost the effects of community plans. KenGen partnered with World Vision International in the Maiela water supply project, which brought synergy.

8. JUSTIFICATION FOR MOVING TO THE SECOND PHASE (CARBON

FINANCE MONITORING) AND SAFEGUARDS COMPLIANCE 8.1 Compliance with safeguards and implementation challenges in the first phase—supervision phase 8.1.1 The project was rated B due to environmental and social safeguards that were triggered during implementation. During implementation, suitable measures were taken to mitigate these safeguard issues. 8.2 Project entity’s capacity to carry out key functions related to safeguard requirements 8.2.1 KenGen’s capacity to address safeguards is satisfactory. 8.3 Potential issues in post-completion operation, including project entity’s capacity and ability of the project to deliver the contracted ERs 8.3.1 No issues are likely to arise in the post-completion of the project. ERs are on schedule for delivery, as estimated. 8.4 Justification for moving to the second phase—carbon finance monitoring phase 8.4.1 All safeguard requirements are fulfilled, and the Environmental Management Plan is fully complied with. No outstanding material issues exist, and no potential issue is anticipated during the remaining term of the ERPA. 8.4.2 For the remaining monitoring activity, KenGen has the capacity to operate the project and to carry out key functions related to safeguard requirements. The monitoring system is proven to be suitable, and the risk was assessed as minimal at the time of the ICR. 8.5. Recommendations and guidance for project monitoring in the second phase—carbon

finance monitoring phase

Subject/ Parameter

Monitoring requirement and associated evidence

Frequency of reporting required

Safeguard policy triggered in Phase 1

Env

iron

men

t

Air pollution and water use, natural habitat protection

Ask KenGen for data on hydrogen sulfide emissions; level of water extraction from Lake Naivasha for project operation; Kenya Wildlife Service reports on loss of fauna or avifauna, or loss of natural habitat (nesting or breeding ground) that can be

Twice yearly OP 4.01; OP 4.04

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attributed to the operation of the plant (if any).

Soci

al

Community satisfaction with operation of water pan, pipeline, and classrooms

Update the numbers of people benefiting from access to water pipeline and water pan; jobs created (e.g., from guarding water pan); any community grievances.

Twice yearly monitoring report

None (but part of CBP)

Evictions of Maasai communities in the Lake Navaisha area

Follow up with the regional team (communications specialist and social specialist) in Kenya on the status of the evictions.

Once every 3 months

None, since the evictions are related neither to KenGen nor to the Olkaria II project. However, the team deems it necessary to follow up on this issue, since the evictions took place near the project area.

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Annex 12 Reallocations of Credit Proceeds

Date of Reallocation

Reallocation Details Remarks

October 2, 2007

Reallocation of SDR 233,000 from unallocated (category 5) to consulting services for Part 4A of the project (category 3-B).

November 25, 2008

• Reallocation of SDR 763,754 (1.4 percent of the credit) from Category 5 (unallocated) to Categories 3B, 3C, and 4A (consultancy services and training) in Schedule 1 of the DCA.

• Reallocation (1.4 percent of the credit) to cover the higher-than-budgeted (at appraisal in 2004) costs of some consultancies and training courses.

May 2, 2012 Savings in Category 1-B (works, supply, and installation for the distribution component, SDR 7.5 million); savings in Category 3-D (consulting services for KPLC, SDR0.8 million); savings in Category 3-E (consulting services for KenGen, SDR0.7 million); reallocation of SDR7 million proceeds from Category 1-B to 2-B; deficit in Category 3-A (SDR0.5 million to be replenished from contingency); savings in consulting services (Category 3-D) of SDR0.5 million reallocated for training KPLC staffs (Category 4-E); savings of SDR0.8 million from (Categories 1-A and 3-E) reallocated to Category 4-D; SDR0.3 million will be reallocated from Category 3-F to Category 1-C; Category 3-F will be replenished by SDR0.01 from the unallocated contingency.

Reallocations to accommodate high priority additional activities.

April 15, 2013

Savings to be reallocated to Category 1-B (goods for the distribution component) to allow KPLC to purchase the equipment necessary to strengthen the distribution system. Of the expected cost savings totaling US$10.7 million, which are generated in Categories 1-B (works, supply, and installation for the distribution component, US$6 million), 2-B (goods for the distribution component, US$3.8 million), 3-A (management services contract, US$0.2 million), and 4-E (training for KPLC, US$0.7 million), US$6.9 million will be reallocated from Categories 1-B, 3-A, and 4-E to Category 2-B.

To utilize cost savings before the Closing Date of September 30, 2013

CENTRAL

E A S T E R N

R I F T V A L L E Y

C O A S T

N O R T HE A S T E R N

N Y A N Z A

WESTERN

NAIROBI AREA

OLKARIA II

NAIROBI

KisumuNakuru Garissa

Mombasa

Nyeri

Kakamega

Lodwar

Kitale

Eldoret

NyahururuFalls

Kericho

KonzaMachakos

Vol

Tsavo

Kwale

Malindi

Lamu

Kitui

Embu

Nanyuki

Gilgil

Wajir

Marsabit

Isiolo

Homa Bay

Moseno

Kisii

Meru

Grand Falls

KiambereKindaruma

KamburuMasinga

Athi

Ngong

Kiambu

Naivasha

Molo

Litein

El Molo Camp

Habaswein

Hola

Mariakani

Lodwar

Kitale

Eldoret

NyahururuFalls

Kericho

KonzaMachakos

Vol

Tsavo

Kwale

Malindi

Lamu

Kitui

Embu

Nanyuki

Gilgil

Wajir

Marsabit

Isiolo

Homa Bay

Moseno

Kisii

Meru

Grand Falls

KiambereKindaruma

KamburuMasinga

Athi

Ngong

Kiambu

Naivasha

Molo

Litein

El Molo Camp

Habaswein

Hola

Mariakani

KisumuNakuru Garissa

Mombasa

Nyeri

Kakamega

NAIROBI

OLKARIA II

CENTRAL

E A S T E R N

R I F T V A L L E Y

C O A S T

N O R T HE A S T E R N

N Y A N Z A

WESTERN

NAIROBI AREA

E T H I O P I A

SOMAL IA

TANZAN IA

UGANDA

SOUTHSUDAN

Ng’iro M

ilgis

Suam

Turk

wel

Tana

Mara

Galana

Athi

Ewaso

Thua

Tsavo

Loga Bogal

Lak Dera

Lak Bor

INDIANOCEAN

Lake

Victor ia

LakeTurkana

34°E 36°E 38°E 40°E 42°E

36°E 38°E 40°E

2°S

0°

2°N

4°S

4°N

4°S

2°S

0°

2°N

4°N

KENYA

0 40 80 160120

0 40 80 120 Miles

200 Kilometers

IBRD 40866

APRIL 2014

MAIN TOWNSPROVINCE CAPITALSNATIONAL CAPITALPROVINCE BOUNDARIESINTERNATIONAL BOUNDARIES

KENYAENERGY SECTOR RECOVERY PROJECT

FACILITIES PROPOSED UNDER THE PROJECT: GEOTHERMAL UNITMAJOR DISTRIBUTION LOCATIONSFACILITIES PROPOSED FOR FUTURE PROJECTS: DIESEL POWER STATIONS 400 kV TRANSMISSION LINESPOSSIBLE SITES OF HYDRO POWER STATIONSDENSELY POPULATED AREAS

220 kV TRANSMISSION LINES




GEOTHERMAL UNIT

OLKARIA GEOTHERMAL FIELD

HYDRO POWER STATIONS

DIESEL POWER STATIONS

STEAM POWER STATION

EXISTING FACILITIES:

This map was produced by the Map Design Unit of The World Bank. The boundaries, colors, denominations and any other information shown on this map do not imply, on the part of The World Bank Group, any judgment on the legal status of any territory, or any endorsement or acceptance of such boundaries.

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