Document of The World Bank

Public Disclosure Authorized Report No. ICR115771

IMPLEMENTATION COMPLETION AND RESULTS REPORT (IDA GUARANTEE NO. B0130)

ON AN

Public Disclosure Authorized INTERNATIONAL DEVELOPMENT ASSOCIATION PARTIAL RISK GUARANTEE

IN THE AMOUNT OF UP TO US$115 MILLION

TO THE

REPUBLIC OF UGANDA

FOR A

PRIVATE POWER GENERATION (BUJAGALI) PROJECT Public Disclosure Authorized September 21, 2018

Energy and Extractives Global Practice Country Department AFCE2 Africa Region

Public Disclosure Authorized CURRENCY EQUIVALENTS (Exchange Rate Effective September 1, 2018)

Currency Unit = Uganda Shilling (U Sh) US$1.00 = U Sh 3,771

FISCAL YEAR July 1 - June 30 (Government of Uganda) January 1 - December 31 (Bujagali Energy Limited)

ABBREVIATIONS AND ACRONYMS

AfDB African Development Bank APRAP Assessment of Past Resettlement and Action Plan BEL Bujagali Energy Limited BEMC Bujagali Environment Monitoring Committee BP Bank Policy CDAP Community Development Action Plan CFR Central Forest Reserve DEG Deutsche Investitions und Entwicklungsgesellschaft (German Investment Corporation) DFI Development Finance Institution DSCR Debt Service Coverage Ratio EIB European Investment Bank EPC Equipment, Procurement, and Construction EIRR Economic Internal Rate of Return ERT III Energy for Rural Transformation Phase III Project ESIA Environmental and Social Impact Assessment GoU Government of Uganda GWh Gigawatt Hour HPP Hydropower Project IA Indemnity Agreement ICR Implementation Completion and Results Report IDA International Development Association IFC International Finance Corporation IPN Inspection Panel IPP Independent Power Producer ISR Implementation Status and Results Report JICA Japan International Cooperation Agency KFS Kalagala Falls Site KfW Kreditanstalt fur Wiederaufbau kW Kilowatt kWh Kilowatt Hour LCOE Levelized Cost of Electricity LTCOR Long Term Conservation Options Report MAP Management Action Plan MW Megawatt ii

M&E Monitoring and Evaluation MIGA Multilateral Investment Guarantee Agency NEA National Environmental Act NEMA National Environmental Management Agency NPV Net Present Value O&M Operation and Maintenance OP Operational Policy PAD Project Appraisal Document PDO Project Development Objective PEAP Poverty Eradication Action Plan PoE Panel of Experts PPA Power Purchase Agreement PPP Public-Private Partnership PRG Partial Risk Guarantee Proparco Promotion et Participation pour la Coopération Economique REFIT Renewable Energy Feed in Tariff SEA Social and Environmental Assessment SMP Sustainable Management Plan SSEA Strategic/Sectoral Social and Environmental Assessment UEDCL Uganda Electricity Distribution Company Limited UETCL Uganda Electricity Transmission Company Limited Umeme Umeme Company Limited (Electricity Distribution Company in Uganda) UJAS Uganda Joint Assistance Strategy WACC Weighted Average Cost of Capital WMDP Water Management and Development Project WTP Willingness to Pay

Vice President: Hafez M. H. Ghanem Senior Global Practice Director: Riccardo Puliti Global Practice Director: Lucio Monari Country Director: Carlos Felipe Jaramillo Practice Managers: Sudeshna Ghosh Banerjee, Sebnem Erol Madan Project Team Leader: Mitsunori Motohashi ICR Team Leader: Raihan Elahi ICR Primary Author: Enrique Crousillat, Kenta Usui

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UGANDA Private Power Generation (Bujagali) Project (P089569) 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 ISRs H. Restructuring (if any) 1. Project Context, Development Objectives, and Design ...... 1 2. Key Factors Affecting Implementation and Outcomes ...... 5 3. Assessment of Outcomes ...... 21 4. Assessment of Risk to Development Outcome ...... 24 5. Assessment of the Guarantee in support of the Project ...... 26 6. Assessment of Bank and Borrower Performance ...... 27 7. Lessons Learned ...... 29 8. Comments on Issues Raised by Borrower/Implementing Agencies/Partners ...... 32 Annex 1. Project Costs and Financing ...... 33 Annex 2. Outputs by Component ...... 34 Annex 3. Economic and Financial Analysis ...... 36 Annex 4. Bank Lending and Implementation Support/Supervision Processes ...... 40 Annex 5. Beneficiary Survey Results ...... 43 Annex 6. Stakeholder Workshop Report and Results ...... 44 Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR ...... 45 Annex 8. Comments of Cofinanciers and Other Partners/Stakeholders ...... 46 Annex 9. List of Supporting Documents ...... 47 Map ...... 49

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DATA SHEET

A. Basic Information

UG - Private Power Country: Republic of Uganda Project Name: Generation (Bujagali) Project Project ID: P089659 L/C/TF Number(s): n.a. ICR Date: September 20, 2018 Guarantee Number B0130 Lending Instrument: IDA Guarantee ICR Type: Core ICR Beneficiary of Bujagali Energy Limited Guarantee: Guarantee Type PRG Original Guarantee US$115 million Amount (US$ m): Guarantor: IDA

Ministry of Energy and Responsible Agency: Mineral Development Revised Guarantee n.a. Amount: Outstanding Guarantee US$ 65.998 million Environmental A – Full Assessment Amount: Category: Implementing Agency: BEL Project Sponsors - Industrial Promotion Services (Kenya) Ltd., Sithe Global, and the Government US$199.76 million of Uganda European Investment Bank (EIB) US$136.00 million International Finance Corporation (IFC) US$128.37 million Co-financiers and Other Commercial Banks (IDA guaranteed lenders) US$115.00 million External Partners: African Development Bank (AfDB) US$111.00 million Netherlands Development Finance Company US$82.10 million (FMO) Proparco US$59.18 million German Investment Corporation (DEG) US$59.02 million French Development Agency (AFD) US$12.80 million

B. Key Dates Revised / Actual Process Date Process Original Date Date(s) Concept Review: 10/18/2006 Restructuring(s): n.a.

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Appraisal: 03/07/2007 Mid-term Review: 12/15/2009 n.a. Guarantee 04/26/2007 Project Closing: 06/30/2012 08/01/2012 Approval: Operation Committee 03/05/2007 Guarantee Expiry 11/30/2023 11/30/2023 Approval: Guarantee 06/22/2007 Effectiveness:

C. Ratings Summary C.1 Performance Rating by ICR Outcomes: Moderately Satisfactory Risk to Development Outcome: Moderate 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: Moderately Satisfactory Government: Moderately Satisfactory Implementing Quality of Supervision: Moderately Satisfactory Moderately Satisfactory Agency/Agencies: Overall Bank Overall Borrower Moderately Satisfactory Moderately Satisfactory Performance: Performance:

C.3 Quality at Entry and Implementation Performance Indicators Implementation QAG Assessments (if Indicators Rating Performance any) Potential Problem Project at Quality at Entry No None any time (Yes/No): (QEA): Problem Project at any time Quality of Supervision No None (Yes/No): (QSA): DO rating before n.a. Closing/Inactive status:

D. Sector and Theme Codes Original Actual Sector Code (as % of total Bank financing) Power 100% 100%

Theme Code (as % of total Bank financing) Infrastructure services for private sector development 100% 100%

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E. Bank Staff Positions At ICR At Approval Vice President: Hafez M. H. Ghanem Hartwig Schafer (Acting) Country Director: Carlos Felipe Jaramillo Judy O’Connor Country Manager Antony Thompson Grace Yabrudy Sudeshna Ghosh Banerjee, Sebnem Practice Manager: S. Vijay Iyer Erol-Madan Project Team Leader: Mitsunori Motohashi Malcolm Cosgrove-Davies ICR Team Leader: Raihan Elahi n.a. ICR Primary Author(s): Enrique Crousillat, Kenta Usui n.a.

F. Results Framework Analysis

Project Development Objectives (from Project Appraisal Document)

The project’s main objective is to provide least-cost power generation capacity that will eliminate power shortages at the time of its commissioning. The proposed project would represent an increase of 250 MW of least cost installed power generation capacity to the national grid.

Revised Project Development Objectives (as approved by original approving authority)

None

(a) PDO Indicators

Baseline Original Target Values (from Actual Value Achieved at Indicator Value approval documents) Completion or Target Years Electricity generated (GWh) from the 1,165 1,352.7 n.a. proposed 250 MW (first year of operation) (16 percent above the target) Bujagali HPP

Levelized cost of 7.69 for high hydrology–11.37 for electricity (U.S. 5.7 for high hydrology–9.7 for n.a. low hydrology cents/kWh) from the low (base) hydrology 9.47 for ICR “base case” hydropower plant

Unmet electricity Load shedding eliminated upon the demand n.a. 0 commissioning of Bujagali (GWh/month) Hydropower Project (HPP)

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(b) Intermediate Outcome Indicators

Original Target Actual Value Achieved at Indicator Baseline Value Values (from approval Completion or Target Years documents)

All borrowers Financial closure and Achievement of and lenders first disbursement Achieved on December 21, 2007 financial closure indicated intent achieved in 2007 The plant started operation on Construction to be August 1, 2012, but was handed Plan construction n.a. completed in 44 months over on October 8, 2012, that is, a progress from financial closure delay of 13.6 months from financial closure.

G. Ratings of Project Performance in ISRs

No. Date ISR Archived DO IP 1 6/26/2007 Satisfactory Satisfactory 2 12/18/2007 Satisfactory Satisfactory 3 6/27/2008 Satisfactory Satisfactory 4 3/26/2009 Satisfactory Satisfactory 5 4/3/2010 Satisfactory Satisfactory 6 8/9/2010 Satisfactory Satisfactory 7 7/30/2014 Satisfactory Satisfactory 8 4/27/2016 Satisfactory Moderately Satisfactory

H. Restructuring (if any)

None

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1. Project Context, Development Objectives, and Design 1.1 Context at Appraisal Country and Sector Context 1. At the time of the preparation of the Private Power Generation (Bujagali) Project in 2007, Uganda had experienced a robust macroeconomic performance, with growth averaging 6.4 percent between 1990 and 2005. However, despite a parallel progress in reducing the national poverty level from 56 percent in 1992 to 31 percent in 2006, the population in the rural areas remained vulnerable, with rural poverty accounting for 90 percent at the national level. Although Uganda had made substantial progress toward achieving the Millennium Development Goals, there remained significant gaps in socio-economic outcomes. 2. Uganda’s demographic was characterized by a very high population growth (3.5 percent in 2005), very high fertility, the world’s highest dependency ratio, and a low life expectancy (49 years at birth). Infrastructure was perceived to be a vital element to boost economic growth necessary to lift the people in the country out of poverty. 3. The power sector of Uganda was suffering from a major power shortage. Uganda’s power generation was dependent on the 380 MW Nalubaale and Kiira dam complex. Due to a severe drought in the region in 2004 output from the Nalubaale and Kiira dropped to 120 MW. The crisis was aggravated by rapid increase of demand, as well as high level of technical and non-technical losses (estimated at 44 percent in 2005). Consequently, electricity supply was characterized by extensive load-shedding, and many large businesses had to rely on high-cost captive backup diesel generating units. Manufacturing, high-value agriculture, and processing industries were the most affected by the electricity supply shortfall. The cost of unserved energy was estimated at US$38.9¢/kWh. 4. To address this urgent situation, the Government of Uganda (GoU) contracted three 50MW thermal generation plants running on costly Automotive Diesel Oils, as well as 10MW power import from Kenya on a non-firm basis. The cost of electricity purchase from the thermal generation plants was approximately US¢20-25/kWh. The incremental energy cost from these emergency thermal plants was subsidized by the Government rather than being recovered through tariff increases to consumers. This resulted in macroeconomic consequences including a higher- than-expected inflation and a widening of the trade deficit due to high oil prices and increases in diesel fuel import for power generation. The situation was not sustainable and further delays in augmenting the country’s power generating capacity through less expensive technologies threatened to undermine the economy. 5. The power crisis was aggravated by the failure of the first attempt to build the Bujagali Hydropower Project (HPP) through private investment (supported by the World Bank Group and other lenders) that collapsed in late 2003, thus exacerbating the urgency to commission emergency/high-cost power generation facilities. 6. The power sector strategy of the GoU was to (a) promote legal, regulatory, and structural sector reform, including leveraging private sector investment; (b) provide adequate, reliable, and least-cost power generation; and (c) scale up rural access, which was as low as 8 percent, to underpin broad-based development. Considerable progress was made in the implementation of a comprehensive power sector reform with the support of the donor community, including the World Bank Group. Such progress included the promulgation of a new Electricity Act in 1999,

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establishing an independent Electricity Regulatory Authority in 2000 and unbundling the state- owned Uganda Electricity Board into separate entities responsible for generation, transmission, and distribution in 2001. 7. Uganda’s 2004 Poverty Eradication Action Plan (PEAP) states the country’s ambitions of eradicating mass poverty and of becoming a middle-income country in the next twenty years. The PEAP presents specific policies and measures to achieve its objectives, grouped under five pillars: (a) economic management; (b) enhancing competitiveness, production and incomes; (c) security, conflict resolution, and disaster management; (d) governance; and (e) human resources development. Energy sector development was included in the pillar (b) and focused on private sector-led investment in generation and increased rural electricity access. Rationale for World Bank Assistance 8. The World Bank participation in the project was justified by the following reasons: (a) electricity was a critical element of the GoU’s PEAP; (b) the combined financial resources of the World Bank Group and other international development finance institutions (DFIs) were essential to mobilize the substantial private funds and commercial lending for the project; and (c) to make private sector investment in Uganda power generation happen and remain effectively engaged in the overall power sector reform initiative. 9. The Bujagali HPP was a landmark engagement with many firsts to its name. For the World Bank Group, the project represented a first hydropower project in Africa after a relatively long period of absence in the sector. Therefore, it represented a test on its capability in helping mobilize the required financing and contributing toward the application of best practices on hydropower development. For Sub-Saharan Africa, it was among the initial group of hydro independent power producer (IPP) project. 10. The Bank has been a reliable development partner in Uganda’s journey to reform its power sector and deliver electricity services to its citizens. The Power Sector Development Operation (US$300 million, approved in 2007) combined Policy Support Program and Specific Investment Loan to contract 50MW thermal plant in Mutundwe, improve energy efficiency and partially cover the cost of emergency power supply. The Energy for Rural Transformation Project Phase I (US$62 million, approved in 2001) increased access to electricity by expanding the distribution network and strengthening the regulatory agency. The Privatization and Utility Sector Reform Project (US$48.5 million, approved in 2000) was developed to improve quality, coverage and economic efficiency of commercial and utility services. Higher Level Objectives to which the Project Contributes 11. A key objective of the 2005-2009 Uganda Joint Assistance Strategy (UJAS) was to reduce poverty through rapid economic growth. Reliable and affordable power is critical to attract investment and promote growth. In this regard, the project constituted a major contribution in support of the GoU’s power sector strategy that aimed to improve service delivery and reliability of supply through private sector participation and to expand access to clean and reliable electricity for households, industries, and social infrastructure. Achieving these goals would contribute toward poverty reduction through income and employment generation, thereby improving the quality of life in Uganda. Also, in offering energy of lower cost, the project would free budgetary resources that the GoU could direct to health, education, and other activities benefiting the poor.

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Extended Monitoring Period Prior to the ICR 12. The Uganda Private Power Generation (Bujagali) Project closed in August 1, 2012, following the commercial operation of the Bujagali HPP. The power plant was however handed over to Bujagali Energy Limited (BEL) on October 8, 2012. This ICR has been completed in August 2018 to address (i) the implementation of Management Action Plan (MAP) developed in response to the 2007 Inspection Panel Investigation Report, and (ii) the GoU request to BEL to refinance its outstanding debt to reduce electricity cost of Bujagali Power Plant. The seventh and final progress report of the MAP implementation, dated February 2018, noted that the MAP has been fully implemented, following issuance of the two outstanding land titles that were indicated as pending in the sixth progress report (February 2017). On July 24, 2018 the Bank issued the Refinancing Time Notice to the GoU confirming that refinancing became effective of July 20, 2018. Given the completion of the MAP implementation and the refinancing of the Bujagali Power Plant, the ICR has been prepared to fully take stock and evaluate the project. Following a standard ICR practice of Guarantee operations, where the ICR is prepared within a year of project closure, the ratings of the project are based on events that took place during the standard ICR period. However, to benefit from the long monitoring period of 6 years after the project close, the ICR is enriched with post-closure events, which did not affect the project ratings. These issues are reflected in section 2.5 (post completion/next phase), section 7 (lessons learned), and other non- rating sections. 1.2 Original Project Development Objectives (PDO) and Key Indicators (as approved) 13. The project’s main objective was to provide least-cost power generation that will eliminate power shortages. The project’s outcome indicators were: • Electricity generated (GWh) from the proposed 250 MW Bujagali HPP; • Levelized cost of electricity (U.S. cents/kWh) from the hydropower plant; and • Unmet electricity demand (GWh/month). 14. In addition, two intermediate milestones/outputs were set to monitor the project’s progress during implementation. Table 1. PDOs and Key Indicators PDO Project Outcome Indicators Target To provide least-cost power Electricity generated (GWh) from 1,165 generation capacity that will the proposed 250 MW Bujagali HPP (first year of operation) eliminate power shortages Levelized cost of electricity (U.S. 5.7 for high hydrology–9.7 for low cents/kWh) from the hydropower (base) hydrology plant Unmet electricity demand 0 (GWh/month) Intermediate Milestones/Outcomes Power plant is Achievement of financial closure Financial closure and first disbursement commissioned on time and achieved by 2007 budget Plant construction progress Construction to be completed in 44 months from financial closure 1.3 Revised PDO (as approved by original approving authority) and Key Indicators, and reasons/justification 15. No changes were made to the PDO or to the related key performance indicators.

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1.4 Main Beneficiaries 16. The project was a public-private partnership (PPP) between the private project sponsors (Industrial Promotion Services [Kenya] Ltd. and Sithe Global), the GoU (including Uganda Electricity Transmission Company Limited [UETCL]), multilateral and bilateral development agencies (detailed below), and commercial lenders. The commercial lenders, Absa Capital (South Africa) and Standard Chartered Bank (United Kingdom), were the beneficiaries of IDA’s Partial Risk Guarantee (PRG). 17. In a broader sense, the project was aimed to benefit all electricity consumers—residential, commercial, and industrial—connected to Uganda’s power grid, as well as the Government, through the project’s contribution in eliminating power shortages and providing electricity service at lower cost and of better quality. 1.5 Original Components (as approved) 18. The approved project included one component: an IDA PRG for the privately owned 250 MW run-of-the-river hydropower plant located at the Bujagali Falls, Victoria Nile River, approximately 8km downstream of the existing Nalubaale/ Kiira hydropower complex. The design of the hydropower plant includes a reservoir with adequate capacity to run the plant for about 10 hours at peak output without any water inflow. Its main structures are an intake powerhouse complex and a rock-filled dam with a height of about 30 meters, together with a spillway and associated works. The project was structured as an IPP to be developed by an already selected sponsor (through its private project company Bujagali Energy Limited [BEL]) and to sell electricity to UETCL under a 30-year Power Purchase Agreement (PPA). The project’s financing plan was completed by loans from the European Investment Bank (EIB), the African Development Bank (AfDB), and a set of European DFIs1 for a total of US$382 million. Annex 1 presents a summary of the project’s financing plan as foreseen during appraisal and the actual values at completion. 19. The IDA PRG of up to US$115 million was designed to support the abovementioned commercial lenders participating in the financing of the project. The PRG covers commercial lenders against debt service default arising from the government’s failure to meet its payments obligations with respect to making a compensation or other payment upon termination of the Implementation Agreement or the PPA (or at any other time under) by reason of any of the following categories of events: (a) political force majeure, (b) changes in law and events making the project contractual agreements unenforceable or void, (c) Government-imposed restrictions on the ability of BEL to be paid or to receive foreign currency or transfer funds abroad, and (d) failure of the Government to fulfill its payment obligations relating to UETCL’s purchase of power and termination payments due by UETCL. The PRG expires in November 2023, at the end of commercial debt repayment period. 20. The IDA PRG was complemented by two World Bank Group financial instruments included in the project’s financing plan, these were (a) two International Finance Corporation (IFC) loans, A and C, of up to US$100 million and US$30 million, respectively, and (b) a

1 French Development Agency, Promotion et Participation pour la Coopération Economique (Proparco), the Netherlands Development Finance Company, Kreditanstalt fur Wiederaufbau (KfW), and German Investment Corporation (Deutsche Investitions und Entwicklungsgesellschaft, DEG).

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Multilateral Investment Guarantee Agency (MIGA) political risk insurance covering the risk of breach of contract for up to US$120.3 million on the equity2 and US$9.5 million on the interest rate swap entered by the lenders3. Thus, the total World Bank Group exposure to the Bujagali HPP was of up to US$374.8 million. To ensure evacuation of power from Bujagali HPP to connect to the national grid, a set of transmission lines were constructed by UETCL as a separate project, funded by the AfDB and the Japan International Cooperation Agency (JICA). 1.6 Revised Components 21. There were no changes in the original project components or in the supporting World Bank Group’s financial instruments. The total project financing requirement increased in the order of US$105 million compared to the appraisal estimate.4 This additional cost was covered by increases in debt from European DFIs and equity from the project sponsors; however, the World Bank Group’s contribution to the financing of the project remained unchanged. The MIGA coverage for breach of contract did increase from US$115 million to US$120.3 million. 1.7 Other Significant Changes 22. There were no significant changes in project design or in the implementation arrangements during the execution of the project. 2. Key Factors Affecting Implementation and Outcomes 2.1 Project Preparation, Design, and Quality at Entry Fit with UJAS and Government Priorities 23. The project design was well aligned with the UJAS and the objectives and priorities of the GoU to promote private sector investment and provide adequate, reliable, and least-cost power generation. The timely and efficient commissioning of the Bujagali HPP was a way to almost double the installed capacity; increase the availability of power supply; and lower the cost of electricity by moving away from emergency thermal power. In doing so, it would contribute toward the achievement of PEAP Pillar 2, which has the specific objective to “strengthen infrastructure in support of increased production of goods and services.” The project’s financing arrangements, which comprised many official lenders, were also aligned to the UJAS’s strategy of promoting strong collaboration and harmonization among development partners and the Government. Soundness of the Background Analysis 24. The background analysis benefitted from the preparatory work made during the first attempt to develop the Bujagali HPP that included an IDA PRG approved by the Board in late 2001. The project sponsor later withdrew from the project, leading to a termination of the agreements by the GoU in September 2003. Subsequently, the GoU initiated a bidding process in adherence with Government’s procurement guidelines to seek a new project sponsor to develop the Bujagali HPP.

2 Equity guarantee issued to World Power Holdings Luxembourg S.à.r.l. (WPH), an affiliate of Sithe Global (USA) 3 Debt swap guarantee issued to Absa Bank Limited of South Africa and Standard Chartered Bank of the United Kingdom. 4 Including the EPC contract, project development costs and financing (details in annex 1).

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25. The background analysis benefitted from the experience of an Inspection Panel (IPN) review (2002–2003). The 2002 Investigation Report of the IPN concluded that the project design did not comply with several safeguard policies, namely, there was no sectoral environmental assessment, there were no appropriate measures to protect the Kalagala Falls Site (KFS), the community development action plan (CDAP) was insufficient and the economic studies had not followed a transparent process. Further, the IPN identified weaknesses in the cumulative effects analysis, compensation plans, as well as a few technical issues (gaps in risk and sensitivity analyses) associated with the project’s economic assessment. 26. This project contemplated developing a hydropower plant of very similar technical characteristics (that is, the same site, same generating capacity of 250 MW, and same basic layout) and had involved an advanced level of engineering design. The scope of the environmental and social impact assessment that was carried out for the project benefitted from the 2002 IPN Investigation Report. Accordingly, project preparation focused on improving the previous design, considering some important changes in the sector/business environment and drawing from the lessons learned during the first effort. 27. Specifically, the PAD mentions the following lessons learned from the previous attempt to develop the Bujagali HPP: • Having a strong project sponsor and a robust financing plan. • Adopting a transparent and competitive process for the selection of the project sponsor and equipment, procurement, and construction (EPC) contractor to ensure sound governance practices. • Ensuring measures are taken to support the efficient operation of the power distribution sector. • Reflecting the findings of the IPN’s Report and the Management’s Response and Action Plan to address the safeguards non-compliance and weaknesses outlined above. 28. Other, more generic, lessons incorporated into project design were as follows: (a) initiating and implementing a comprehensive power sector reform in advance of major new investments can provide advantages; (b) the financial viability of the power sector can be enhanced by commercializing operations and through private participation in the ownership and management of distribution facilities; (c) World Bank Group support can help catalyze long-term private sector financing for capital intensive projects by mitigating some political risks; (d) investment decision should be based on their technical, economic, financial, social, and environmental merits; and (e) an equitable allocation of project risks is important to ensure the long-term sustainability of a project. Project Design 29. The PDO was an appropriate response to the country’s needs and, as mentioned, it was fully compatible with the emergency situation of the power sector and the GoU’s development priority of crowding-in private investment to generate economic growth and reduce poverty. 30. The collapse of the first attempt to develop the Bujagali HPP in 2001-2003 placed a high degree of pressure on the Government and donors alike, as there was an urgent need to commission additional generating capacity. An obvious option was to resurrect the Bujagali HPP while fixing

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the problems that had caused its failure. It was identified that (i) the sponsor’s withdrawal from the project while was caused by the continuous deterioration of the sponsor’s own financial situation, this event was preceded by a set of investigations concerning allegations of corruption in the United States, Norway, the United Kingdom, and Uganda; and (ii) caution to address the IPN process within the World Bank Group considerably delayed the project preparation. 31. Consequently, two corrective measures that characterized the design of the project were (a) improving governance standards through the adoption of transparent and competitive processes for the selection of the project sponsor and the EPC contractor and (b) a more thorough effort in addressing social and environmental matters, including in-depth analyses and the formulation of effective compensation and mitigation measures. Key features in this regard were as follows: • The GoU followed a transparent and competitive process in adherence with its procurement guidelines, and selected BEL as a new project sponsor to develop the Bujagali HPP. The process included a prequalification stage that selected three qualified sponsors and, subsequently, assessed their proposals based on two attributes: project cost (including a proposed return on equity) and the financing plan. By April 2005 the GoU made public the sponsor’s selection and invited BEL to negotiate. Subsequently, the PPA and an Implementation Agreement were signed in December 2005 between BEL, UETCL and the GoU respectively. Throughout this process, the GoU was assisted by expert advisers: Hunton & Williams LLP (legal) and Scott Wilson Piesold (engineering). • During project preparation, the sponsor BEL in July 2005 initiated the process to select the EPC contractor following a competitive bidding process as per EIB’s procurement rules. While the Bank did not require a competitive selection process for EPC, the Bank reviewed the process and established that it was in accordance to the Bank guidelines.5 • The EPC contractor was selected on a competitive basis. Only two offers were received on October 26, 2006, and the lowest EPC bid price was 48 percent higher compared to the costs obtained six years earlier in 2001. The higher bid price was due to the market at the time characterized by high prices for raw material worldwide, a tight market for qualified contractors and regional political turmoil.6 A review of bid prices was conducted by BEL’s owners engineer, and the EPC price and contractual conditions were reviewed by the lender’s independent engineer; they concluded that prices were reasonable given the market conditions. By the time of Board approval, EPC contract negotiations were still under way, including the definition of some risk allocation issues. Hence, the final EPC price had yet to be agreed.

5 Bank procedures in supporting private investments establish that if a sponsor has been selected through a competitive process, the subsequent selection of contractors is not subject to Bank procurement guidelines. In this case, the Bank’s somewhat redundant review of the EPC selection process (i.e. a double scrutiny) coincided with EIB’s procurement requirements. As discussed in sections 2.2 (Implementation), 2.4 (Safeguard and Fiduciary Compliance) and 3.3 (Efficiency), the strict adherence to lenders’ procedures such as public reading of the bids prices proved to be costly. 6 Unfortunately, the bidding and negotiations for the EPC contract coincided with a moment of great market uncertainty in the power industry, that is, the post Enron era.

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• The project design specifically improved on two aspects. First, social and environmental – a comprehensive Strategic/Sectoral Social and Environmental Assessment (SSEA) and Cumulative Impact Assessment was undertaken, ensuring adequate stakeholder consultations.7 Second, economic analysis and examination of alternative investments - additional studies8 concluded that, considering a wide range of options (including small and medium hydropower, other large hydropower projects, thermal generation options, geothermal and other renewable sources), the Bujagali HPP was the least-cost generation expansion option to meet Uganda’s power generation requirements. • Adhering to OP 4.04, it was agreed to protect the KFS in compensation for the loss of the Bujagali Falls, considering that it was an area ecologically similar to the area lost and, hence, an appropriate offset choice9. Accordingly, IFC/IDA and the Government reached an agreement during project preparation10 for the protection of such area. The Government’s commitment in this regard was formally confirmed in the Indemnity Agreement (IA) signed between the GoU and IDA in July 2007. It is important to note that the IA was the sole legal instrument for protecting the KFS, i.e., such protection was not grounded in the national laws and was limited to the duration of the IA. The IA in effect postponed resolving the question of the protection of the KFS beyond the IA to a later date, upon receiving the IDA’s notice of a termination (or prospective termination) of the IDA Guarantee Agreement. 32. The contractual structure of the project was consistent with the industry practice for limited recourse finance transactions. Also, the two-step procurement process—selecting first the sponsor and then the EPC contractor—was consistent with the industry’s practice and suitable to the emergency situation faced by the power system. Figure 1 provides an overview of the main project agreements and the links between the shareholders, which include the BEL, official and commercial lenders, the Government, the off-taker UETCL, and contractors (EPC and operation and maintenance [O&M]). Upon Board approval, IDA proceeded to sign an Indemnity Agreement (IA) with the GoU, a Guarantee Agreement with commercial lenders, and a Project Agreement with the sponsor (BEL). These agreements established the obligations of the parties involved. Among other things, the IA established the GoU’s obligation to repay IDA in the case that the PRG is called, as well as the GoU’s commitment to protect the KFS. 33. The interconnection infrastructure was designed and built as a separate project (with AfDB and JICA financing) and following an international competitive procurement process. To ensure a suitable coordination with the power plant implementation, the procurement and construction process of the transmission lines was managed by BEL on behalf of UETCL.

7 Environmental studies included an assessment of the upstream and downstream impact of Bujagali HPP operation patterns. Studies concluded, inter alia, that the project will result in minor changes to the balance between populations of certain fish species upstream of the dam, and no noticeable change downstream of the dam. No specific mitigation measures were proposed to address impacts on fish resources. However, a monitoring program was implemented to confirm these predictions, and take remedial action if required. 8 Power Planning Associates Ltd. 2007. Bujagali I – Economic and Financial Evaluation Study. 9 Identification of KFS did not include a rigorous baseline assessment of natural habitat, environment and spiritual values. 10 The PAD reports that the agreement ‘Proposed Bujagali Hydropower Project: World Bank Group’s Requirement of an Offset at Kalagala Falls’ was reached on April 25, 2001.

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Table 2. Timeline of Bujagali HPP

2000 GoU’s initiation of planning Bujagali dam / Selected the project developer

Bujagali I (P078024) approved by the Board / Inspection Panel received request for investigation 2001 (first IPN investigation)

2002 First IPN Investigation report issued Bujagali I suspended as the developer withdrew / Bujagali Energy Ltd. (BEL) created by Sithe 2003 Global Power and Investment Promotion Services (IPS) 2005 30-year PPA signed between UETCL and BEL

Bujagali II (P089659) approved by the Board / Guarantee agreement signed / Inspection Panel 2007 received Request for Investigation (second IPN investigation) / EPC contractor selected/ Bujagali Construction started

Second IPN Investigation report issued / Management Action Plan (MAP) in response to IPN 2008 recommendations issued

2012 Bujagali II construction completed, project closed Adequacy of the Government’s Commitment 34. The GoU was strongly committed to the project during preparation and design. The failure of the first attempt to build the Bujagali HPP only heightened the urgency and commitment of the GoU to build new generation capacity to meet the needs of its growing economy. The GoU firmly supported all aspects of the preparation phase including (a) construction and cost overrun risks, (b) adopting an open and transparent process for the selection of a new project sponsor; (c) ensuring the continuity of the resettlement process upon the collapse of the first attempt to build the plant; (d) facilitating the consultation process among stakeholders; (e) provisioning a US$75 million bridge loan to BEL during the final phase of negotiations of the EPC contract, with the aim of locking in the EPC contract price and starting construction before financial closure; (f) ensuring that the Interconnection Project—to be implemented in parallel to the Bujagali HPP—was procured following an international competitive process and ensured a suitable coordination arrangement to avoid any potential delays and/or technical inconsistencies; and (g) maintaining an environment of legal and regulatory stability and supporting the continued commercialization of power sector operations. However, as noted above, Government’s commitment to a permanent protection of the KFS was to be discussed later, toward the end of the IA. Clearly, this arrangement carried the risk to adequate protection of the KFS beyond the duration of the IA.

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Figure 1. Bujagali HPP Contractual Agreements

Source: World Bank. 2007. Project Appraisal Document for the Private Generation (Bujagali) Project in the Republic of Uganda.

Risks 35. Hydropower projects are by nature risky ventures with hydrological uncertainty and the challenge of building a unique set of structures on ground conditions that, regardless of the level of ex ante investigations, are never fully known. For Bujagali HPP, the risks were heightened by the logistical challenges of transporting large equipment in a land-locked country with infrastructure constraints. The risk perception of the Bujagali HPP by private sector was further heightened by the failure of the first attempt to build Bujagali HPP, lack of Uganda’s experience in private-run power generation, and the major electricity supply crisis which the power sector was facing. Consequently, the GoU agreed to take a significant risk in the Bujagali HPP to facilitate rapid execution of the project. 36. The PAD made a comprehensive assessment of critical risks that could affect the project’s performance (table 3). These risks encompassed technical (hydrology, delays, and cost overruns), market (demand growth), economic (macro stability), financing, and policy issues. It is considered that the thorough preparatory work undertaken for the project, including project-specific issues as well as the GoU commitment to support the power sector reform, complemented by the guarantees and other financial instruments provided by the World Bank Group, constituted an adequate set of measures to manage and mitigate these risks.

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Table 3. Risks Summary Risk Identified at Design Mitigation Measure (PAD) Outcome/Comment Inability to mobilize World Bank Group due diligence Risk did not materialize. Project financing financing and multilateral and bilateral achieved according to the plan. institutions financing plan, complemented by sponsors’ bid bond to confirm their financing commitment Demand growth for • Demand forecasts based on a Risk did not materialize. The project’s capacity electricity lower than realistic range of outcomes was quickly absorbed by the power system, as expected (technical, commercial, it replaced existing thermal generation. economic). • Export surplus energy in case of low demand growth. A stable macroeconomic The project’s contribution in The crude oil price increased around 25 percent external environment is removing power shortages (and 2011-2013 as compared to 2006. The maintained. replace high-cost thermal commissioning of Bujagali HPP in 2012 generation) will help Uganda in reduced the fuel cost of the sector and handling any changes in the subsequently helped Uganda’s macroeconomic external environment. performance. Government commitment Government demonstrated Risk did not materialize. The Government’s to power sector is not commitment to a comprehensive commitment to reform continues unchanged. maintained. power sector reform, including its support to the commercial viability of the sector. Umeme Company Limited • Umeme’s agreement to invest The risk materialized. IDA-funded (Electricity Distribution up to US$65 million during the Privatization and Utility Sector Reform Project Company in Uganda), the first five years of concession, backstopped a Letter of Credit Facility private distribution supported by IDA and MIGA11 established by Uganda Electricity Distribution concessionaire terminates coverage for regulatory, Company Limited (UEDCL) in favor of its concession. nonpayment, and breach of Umeme. The Facility protected Umeme from contract risks; the impact of power shortage and non-payment • Concession modified to protect by UEDCL. Umeme from impact of power shortages Hydrology risk associated • World Bank Group due A long-term issue; the risk has not with water flows on the diligence. materialized. Nile River and water • Project confirmed as the least- levels at Lake Victoria cost expansion even under the low hydrology scenario. • Project does not imply an incremental draw from Lake Victoria. Hydropower plant and • Sponsors’ incentives to Hydropower plant experienced delays caused Interconnection Project minimize delays mostly by unexpected ground conditions (see encounter delays and cost • Fixed price EPC contract section 2.2: Implementation). overruns; system not • BEL in charge of operated in line with interconnection procurement international standards. and construction management

11 MIGA coverage only for breach of contract with a term of 20 years for the equity and 11 years for the debt interest rate swap.

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Risk Identified at Design Mitigation Measure (PAD) Outcome/Comment • Emergency plan to evacuate energy in case of interconnection delay Impact of the project on Power development oriented The Guarantee, backstopped by IDA, has not the Government’s toward PPPs, limiting the been called to date, and therefore the GoU’s contingent liabilities Government’s liabilities to its liabilities to Bujagali HPP project is minimal. provision of guarantees (related to the GoU and public-sector performance) Increase in project costs • EPC contract to be a fixed This risk materialized, as the EPC contract price turnkey contract experienced an increase in cost of US$59.5 • Changes in prices to be million above the contract price, in consistency allowed only under very with the risk allocation established in the specific circumstances contracts (section 2.2: Implementation - Cost • PPA structure to provide increases and delays). incentive to BEL to minimize EPC cost increases 37. The contractual structure and risk allocation of the Bujagali HPP transaction was designed along the industry standards of limited recourse financing; that is, risks should be allocated to the party best able to mitigate them and an equitable allocation of project risks between the various parties is an essential condition for long-term sustainability. Hence, in principle, BEL was expected to bear the technical, commercial, and financing risks of the project, while the GoU’s obligations, and inherent risks, were established in the Implementation Agreement, including the terms of the guarantee to back UETCL’s payment obligations under the PPA. In practice, however, the GoU faced a tradeoff between a suitable allocation of risks and the urgency to build the Bujagali HPP the earliest possible. Moreover, the GoU’s ability to negotiate with potential EPC bidders was significantly constrained by the markets conditions, characterized by the rapid increase in the price of raw materials driven by high worldwide demand, and a tight market for qualified EPC contractors. Facing the urgency to address the power shortage, the GoU allowed BEL to proceed with the EPC bidding before a full geotechnical assessment was completed. Hence an important component of the project’s technical risks was borne by the Government which materialized as additional costs and further delays. Also, the price of the turnkey EPC contract included a pass-through provision for a set of conditions previously established, and hence, the risk of cost increase was shared between BEL and the GoU.12 In addition, the PPA (whereby the sponsor is to be paid upon proof capacity availability and not energy) established that hydrological risks were borne by the off-taker. Consequently, the actual allocation of risks was not that of a typical project financing for an IPP, but rather that of a PPA arrangement where the public sector played a significant role and shared considerable risks, including construction delays and EPC contract pricing risks.

12 The PPA established a pass-through for cost increases with a cap. The capacity payment is aimed at securing an agreed return on equity for the sponsor, based on a base EPC cost. If actual costs under the EPC contract are higher or lower than the base EPC cost, the capacity payment is adjusted upward or downward to offset 70 percent (only) of the cost difference between the actual costs under the EPC contract and the base EPC cost, provided that the capacity payment does not change by more than 10 percent as a result of such adjustment.

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Table 4. Risk Allocation of Bujagali HPP

Phase Risks/Obligations Sponsors Lenders GoU World Bank Group Risks Mitigation Package Pre-construction Project Design ■ ■ Debt and Equity Financing ■ ■ ■ Construction Cost Overruns ■ ■ ■ Construction delays ■ ■ ■ Implementation of Environmental ■ ■ ■ Management Plans and Resettlement Policy Frameworks Operation Operation and maintenance ■ ■ Output quality specifications ■ ■ Hydrology ■ Payments under the IA and PPA ■ ■ Concession term Currency devaluation ■ Currency convertibility/transferability ■ ■ ■ ■ Political Force Majeure ■ ■ Changes in Law ■ ■ Natural Force Majeure ■ ■ ■ Source: Project Appraisal Document 2.2 Implementation

38. The Bujagali HPP started commercial operation on August 1, 2012. The power plant was however, handed over to BEL in full compliance with contractual agreements and international technical standards on October 8, 2012, after 13.6 months beyond the original delivery date in August 2011. Project implementation experienced significant cost overrun and implementation delays, but it has operated satisfactorily since completion. Most important, the commissioning of the Bujagali HPP has contributed substantially to the installed generation capacity and energy to the national grid; reducing power shortages; and improving service reliability. 39. Main factors that contributed toward a satisfactory performance were (a) the suitability of the contractual arrangements consistent with the industry practice for limited recourse finance transactions; (b) the managerial and technical capacity of the entities involved, including competent sponsors and the EPC contractor; (c) the effective and independent support of technical experts throughout the implementation process, through the owners' and lenders’ engineers, as well as the Dam Safety Panel of Experts; (d) the Government’s commitment to the project that went beyond its formal obligations of providing a bridge loan to lock in the EPC contract price and start construction without delays and establishing and operating a Multi-stakeholder Bujagali Environmental Monitoring Committee; and (e) a well-coordinated supervision of lenders characterized by biannual joint lender missions. 40. The project’s good implementation performance was reflected in the Implementation Status and Results Reports (ISRs), which rated the project ‘Satisfactory’ for its development objectives and overall implementation progress throughout the implementation period. However, the last ISR carried out more than three years after project commissioning (April 2016) downgraded the project’s implementation progress performance to ‘Moderately Satisfactory’ because of safeguards issues.

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41. The salient implementation difficulties were the following: 42. EPC contractor negotiations. Two bidders competed for the EPC contract following EIB procurement procedures. The winning EPC bidder offered a price of US$467.2 million,13 while the other bid was approximately 43 percent higher. Given the public opening of financial bids, the bid prices became public information. Negotiations lasted around six months, ending in May 2007, that is, a few weeks after Board approval in April 2007. Consequently, the PAD did not include the final EPC contract price since this was unknown. The negotiated EPC price was US$557 million, (about 20 percent higher) and by the end of the project, with approved cost overruns, the actual EPC cost was US$616 million (about 32 percent higher from the bid price). Important aspects of the EPC bidding and negotiations were as follows: • Although comparing hydropower unit costs has inherent limitations (since all projects are different and prices may change considerably with market conditions), the offered EPC bid price in 2007 (US$467 million for 250 MW plant ~ US$1,869 per kW) was 48 percent higher than the EPC price of 2001 for the Bujagali project. Hence, the lenders’ engineer, was engaged in a thorough review of the project costs and conditions of the winning proposal. The lenders’ engineer concluded that, given the prevailing market conditions for hydropower, the 2007 EPC price was reasonable, though somewhat on the high side. • When EPC bids are presented, there is typically a set of commercial terms that are yet to be defined (such as payment schedules, liquidated damages), and lenders’ terms get confirmed subject to credit approvals. These factors of uncertainty are either resolved, or their risks are allocated among the parties, during negotiations. In the Bujagali HPP’s case, EPC contractor proposed to shift the risks to the sponsor. Neither BEL nor the lenders were prepared to take these additional risks; therefore, the EPC contractor negotiated a price increase to mitigate those risks. In reality, the GoU mitigated the risk through higher price of power. • Negotiations were particularly difficult for the sponsor since the market at the time were characterized by high prices for raw material worldwide and regional political turmoil. The high price difference between the only two bidders was a significant advantage for the winning bidder during price negotiations. 43. Cost increases and delays. The construction of the power plant encountered a few difficulties that are typical of hydropower projects. The main problems were adverse ground (geological) conditions under a gated spillway structure, construction problems on the right embankment and a cofferdam, and delays in the delivery and commissioning of some equipment caused by several factors, including a ship hijacking incident and some electromechanical defects. Overcoming the ground conditions problem implied a costly solution that required replacing a bed of low-quality rock by concrete and steel. 44. Agreements established that the construction of the power plant had to be completed in 44 months from financial closure (December 31, 2007). However, the plant was commissioned in August 1, 2012, and handed over on October 8, 2012, 13.6 months behind schedule. Delays were

13 Including direct and indirect costs, contingencies, risk allocation, and price escalation factors. Project Review and Assessment Report for IFC. July 2007.

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caused mostly by unexpected construction (mostly due to ground conditions) and equipment supply difficulties, as well as some repairs required in the electromechanical equipment at the handover stage. According to the EPC contractual conditions,14 a substantial part of the cost increase and delays were borne by the owner and passed on to the off-taker UETCL, through the PPA. 45. The GoU extended a bridge loan of US$75 million to BEL upon delays in the negotiation of the EPC contract, and the subsequent cost of a prolonged power crisis, in a clear demonstration of commitment to the project. This loan allowed BEL to lock in the EPC contract price before the expiration of the bid validity, as well as starting construction before financial closure. The loan was to be repaid from an equity injection at the time of the full notice to proceed. 46. IPN. Following the first IPN case in 2002-3, the IPN received a second request in March 2007 from the National Association of Professional Environmentalists and other local organizations for Inspection for the project. A similar request was also submitted to the Compliance Review and Mediation Unit of the AfDB. The request addressed a broad range of issues on environmental, hydrological, social, cultural, economic, and financial matters. It contended that a failure of the World Bank to follow its own operational policies and procedures in the design (appraisal) of the project would result in harm to the people living in the area and to the environment. An Investigation Report issued by the IPN in August 200815 concluded that World Bank management was not in full compliance with five operational policies.16 The report of the IPN and the management’s response were discussed by the Board on December 2008. It was agreed that management was to report to the Board on the progress of the Management Action Plan (MAP) aimed at addressing all noncompliance issues, in particular those associated with institutional capacity, social and cultural aspects, and environmental mitigation measures of the project. 47. In the MAP, the World Bank committed to the following actions: i) follow up on National Environment Management Agencies’ (NEMA) establishment of a Project Monitoring Committee, and on strengthening of capacities of BEL’s environment and social unit; ii) follow up with BEL’s programs, with timetable and targeted activities, to address the needs of vulnerable groups; iii) follow up with the GoU to update the Cultural Property Management Plan, and its incorporation by BEL into the EPC contractor’s Code of Practice; and iv) work with BEL to review the Environment and Social Independent Panel of Experts (PoE) reports for disclosure. The MAP stressed that in addition to the new actions listed above, ongoing supervision encompassed a set of complementary key actions including strengthening the GoU’s institutional capacity, remedial steps for updating and completion of baseline socio-economic information, monitoring afforestation activities, completion of Kalagala Offset SMP, and the GoU’s commitment to disclose the Lake Victoria hydrological information. 48. Since then, the implementation of the MAP has been monitored continuously through the (a) Quarterly Monitoring and Evaluation Reports prepared by BEL; (b) Reports of the Joint

14 The EPC contract established that ground conditions risks were mostly borne by the owner. 15 World Bank Inspection Panel. Investigation Report. Uganda: Private Power Generation (Bujagali) Project. Report No. 44977-UG. August 2008. 16 OP/BP 4.01 - Environmental Assessment and World Bank policy on Disclosure, OP/BP 4.04 - Natural Habitats, OP/BP 4.11 - Physical Cultural Resources, OP/BP 4.12 - Involuntary Resettlement, and OP/BP 10.04 - Economic Evaluation of Investment Operations.

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Lenders’ Supervision Missions (semiannual missions undertaken until commissioning of the plant in August 2012 and annual missions thereafter);17 (c) Annual Review by the Independent Panel of Experts; and (d) the National Multi-stakeholder Bujagali Environment Monitoring Committee (BEMC) Reports. Seven comprehensive progress reports have been submitted to the Board, presenting a gradual process in solving each of the issues raised by the IPN. 49. The seventh and final report submitted in February 2018 confirms that all actions had been completed including the issuance of two outstanding land titles for resettled households, which were indicated as pending in the sixth progress report (February 2017). Given the completion of all outstanding actions of the MAP, this implementation completion report is prepared. 50. The IPN process has been useful in improving the design and implementation of the project. The management always responded in a thorough and timely manner, thus contributing toward the resolution of the problems raised by the IPN. Finally, in contrast to the first IPN of 2002–3, the process did not bring any significant delays to the project. According to Government officials, the World Bank’s response in addressing the requirements of the IPN, while continuing the normal execution of the project, revealed that an important lesson had been learned. 51. Outstanding issues. Despite an overall satisfactory performance, a few issues associated with environmental and social matters remained outstanding for a long period after project completion. The delays in resolving these issues was the main reason for downgrading the project’s implementation performance in the last ISR, prepared in April 2016, about 44 months after the Project closing, as well as completing this ICR in August 2018. Downgrades included a Marginally Satisfactory rating for overall implementation progress and Marginally Unsatisfactory rating for overall safeguards compliance. The status of actions in last ISR identified the following issues, all pending actions in the MAP of the IPN case: • Implementation of SMP for the KFS by the Ministry of Water and Environment was satisfactory. • Electrification of households in the Naminya Resettlement Area which affected nine villages as part of the CDAP was complete after suffering considerable delays. • Issuance of three land titles for households in the Naminya Resettlement Area was still outstanding.18 52. On September 6, 2016, and September 20, 2016, the IPN registered a third and fourth request for inspection concerning this project, along with two other Bank financed projects: (i) Water Management and Development Project (WMDP); and Energy for Rural Transformation Phase III (ERT III) Project. The requesters alleged that the construction of the Isimba HPP (funded by the GoU and China’s Exim Bank) will flood part of the KFS, an area set aside to protect its natural habitat, environmental, and spiritual values by the 2007 IA between the GoU and the World Bank. Refer to para 68 for more information on this issue.

17 All lenders, including the World Bank, continued launching supervision missions for four years after the plant was commissioned. This joint effort to monitor the implementation of the MAP was also reflected in two ISRs filed in July 2014 and April 2016, after the project closed on August 1, 2012. 18 The seventh Progress Report of the MAP noted that all three land titles have been issued.

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2.3 Monitoring and Evaluation (M&E) Design, Implementation, and Utilization 53. M&E design. The key outcome indicators to be monitored for IDA’s guarantee operation are presented in section 1.2 and Annex 2. The set of indicators chosen was limited to three targets that are simple and easy to quantify, as well as an objective measure of the project’s technical outputs and its impact on Uganda’s power system. In this respect they are considered to be adequate for a private power project that has very specific objectives. The set of outcome indicators was complemented by two intermediate milestones/indicators aimed at monitoring the project’s progress during project implementation. The Results Framework also made reference to additional intermediate milestones/outcomes, such as plant construction costs and commission test results, but no targets were established. 54. Though the number of indicators for outcomes was limited, the set was consistent with the nature of a large private infrastructure project that has many other monitoring mechanisms (for example, the EPC contractor’s and sponsor’s standard engineering supervision methods; BEL’s quarterly construction reports and social and environment quarterly monitoring reports; and the independent lenders’ engineer reviews, POEs, and others). 55. M&E implementation. Data on the outcome indicators and intermediate milestones were collected in full through the monitoring mechanisms mentioned earlier. Two important initiatives proved to be effective in monitoring the progress of the project in all its dimensions: • Joint lenders’ supervision mission. The numerous lenders involved in the project required a special effort of coordination to monitor the project’s progress while minimizing the distracting impact of an excessive number of missions. Joint lenders’ supervision missions, which were held on average every six months, were particularly useful in optimizing supervision resources, improving communications between all parties, and, to the extent possible, harmonizing criteria. Alternating the missions’ lead was an important feature in guaranteeing a balanced participation of lenders. • Bujagali Environment Monitoring Committee (BEMC). Chaired by an academic, this committee was established by the GoU to monitor safeguard issues in a comprehensive manner. The BEMC had a broad representation, including members of Government institutions responsible for all aspects of the project (power, water, environment, trade, regulation) as well as representatives from local governments, nongovernmental organizations, and the private sector. The committee met on a quarterly basis, engaged in site visits and provided recommendations, and became an important counterpart in dealing with lenders. 56. M&E utilization. While project indicators were limited in number and scope (mainly oriented to measure the achievement of development objectives during project operation), the additional mechanisms mentioned earlier provided a broad frame for monitoring different aspects of the project’s progress and take corrective actions on the plant’s construction and its impact. 2.4 Safeguard and Fiduciary Compliance Safeguards 57. The project triggered seven safeguards: Environmental Assessment (OP/BP 4.01), Natural Habitats (OP/BP 4.04), Physical Cultural Resources (OP/BP 4.11), Involuntary Resettlement

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(OP/BP 4.12), Forests (OP/BP 4.36), Safety of Dams (OP/BP 4.37), and Projects on International Waterways (OP/BP 7.50). 58. Overall, safeguards performance was regarded as positive during the construction of the project. Safeguards compliance was rated Satisfactory throughout the implementation period. However, the last ISR of April 2016 (44 months after the plant’s commercial commissioning and project closure) downgraded overall safeguard compliance to Moderately Unsatisfactory. Specific downgrades were Moderately Satisfactory for Environmental Assessment, Natural Habitats, and Forestry and Moderately Unsatisfactory for Involuntary Resettlement. Ratings were downgraded because of some unresolved issues, namely delays in issuing land titles, and in the electrification of the households that had been resettled by the project. 59. The Bujagali HPP is a Category A project in accordance with the World Bank’s OP/BP 4.01. Therefore, BEL conducted a full Social and Environment Assessment (SEA) for the power plant and for the associated interconnection project (on behalf of UETCL)19 as part of the project’s preparatory work. This effort was complemented by several assessments and action plans, including an Assessment of Past Resettlement and Action Plan (APRAP),20 a CDAP, and Public Consultation and Disclosure Plans. The documentation was designed to fulfill regulatory and procedural requirements of the World Bank Group, AfDB, EIB, DEG, and GoU. It is worth noting that to avoid any disruption in the ongoing resettlement process, the GoU proceeded to recruit the safeguards team of the former sponsor upon their withdrawal in 2003. 60. A comprehensive set of studies included (a) an ‘Economic and Financial Evaluation Study’ (commissioned by IFC) that assessed different hydrological scenarios and alternative power generation options; (b) a SSEA of Power Development Options in the Nile Region, which included consultation with other riparian stakeholders; and (c) an update of the cumulative impacts assessment. Other measures included the establishment of a dam safety panel to provide advice on the adequacy of the civil works design and construction procedures. 61. Given its visibility as a complex hydropower plant supported by the World Bank and other DFIs, the project was designed and implemented under tight scrutiny of international and local civil society. An investigation by the IPN commenced in 2007, a few months after construction started. Despite the extensive preparatory work, the IPN identified noncompliance issues in four social and environmental safeguards, as well as in OP/BP 10.04. Consequently, World Bank management, sponsors, and the GoU responded to the IPN requirements in a timely and responsible manner. As indicated in section 2.2, the preparation, monitoring, and reporting of the MAP were useful in addressing in a gradual and satisfactory manner most of the issues raised. 62. Nevertheless, the project was never free of challenges. Evidence of safeguard problems appears repeatedly in the joint lenders’ Aide Memoire and in the World Bank’s ISRs. Issues that suffered delays and/or required special attention were the impact of construction blasting on nearby households, addressing the spiritual values of the Bujagali Falls, delays in the rural electrification component of the CDAP, and the land titling of resettled households, and the protection of the KFS.

19 Because the Interconnection Project is not part of the IDA supported power generation project, BEL took care of the preparation of the two separate SEA reports. 20 Since a Resettlement Action Plan had been formulated and partially implemented during the first attempt to build the Bujagali HPP. In fact, most people living in the area near the power plant site had been resettled already. The APRAP was therefore designed to ensure the continuity of the process as well as to correct its shortcomings.

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63. In 2010 the EPC almost doubled its workforce to recover for technical delays. Following 2 fatalities and incidents in Q1 of 2010, Lenders required BEL and the EPC to commission Operational Health and Safety audits. Implementation of audit findings led to marked improvements and there were no further fatalities under the project. 64. Kalagala Falls Site. The IA signed between IDA and the GoU in July 2007 incorporated a clause to protect the Kalagala Falls as an appropriate offset choice for the area lost in the Bujagali Falls. Accordingly, the GoU made the formal commitment to set aside the KFS exclusively to protect its natural habitat, environmental, and spiritual values. Further, the GoU also committed that it would not develop any power generation that could adversely affect Uganda’s ability to maintain the above stated protection of the KFS without prior agreement with IDA. The GoU also committed to conserve through as sustainable management program and budget, the present ecosystem of Mabira Central Forest Reserve (CFR), Kalagala CFR, and Nile Bank CFR on the Banks of the Kalagala Falls. 65. The GoU has prepared an addendum to the Environmental and Social Impact Assessment (ESIA) of the Isimba hydropower project and identified potential impacts of the Isimba hydropower dam on the Kalagala Falls, including the corresponding mitigation measures. Following public consultations and hearings, the ESIA Addendum was approved by the NEMA on November 30, 201721. The GoU also prepared a separate Long-Term Conservation Options Report (LTCOR) to identify options for strengthening legal protection of the KFS and associated financing and institutional arrangements for the long-term sustainability of the KFS, beyond the expiry of the IA in 2023. 66. Based on the recommendation of the ESIA Addendum and LTCOR, the IA was amended on January 24, 2018 to include a new definition and demarcation of the KFS. The new, extended KFS encompasses the stretch of Nile River approximately 15 kilometers long that begins upstream at 2.5 kilometers below the Bujagali Dam wall and ends downstream at the envisaged tail end of the Isimba Dam reservoir (Maximum Pool Level of 1,055 meters above sea level). It includes the entire Nile River aquatic area and river islands within these limits; all land within 100 meters of both the left and right river banks from the annual maximum high-water line; and the entire area of the Namavundu, Kalagala Falls and Nile Bank Central Forest Reserves, except any of the portions inundated by the reservoir of the Isimba Dam. 67. The Government has committed to conserve the extended KFS by giving it a strong legal foundation under Ugandan law that will go beyond the expiry of the Indemnity Agreement in 2023. This legal protection will be provided under the National Environmental Act (NEA), which has been submitted to Parliament for adoption. In the interim, legal protection is to be provided through a statutory instrument that is being prepared under the Forestry and Tree Planting Act. Ministry of Water and Environment issued, in December 2017, a public notice of intent to declare the extended KFS a CFR, initiating the 90-day public consultation process as mandated by Forestry and Tree Planting Act; the public comment period ended on March 8, 2018. The statutory instrument was publicized for public comments in November 2017 and the period for public comments ended in

21 The report is available at http://nema.go.ug/sites/all/themes/nema/docs/UG-ISIMBA-ESIA%20Addendum- TRACKED%20WB.%20June%2022%202017.pdf.

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March 2018. Further, the GoU has already shared with the Bank legal, institutional, and financing plans for the long-term sustainability of the extended KFS. 68. As mentioned (in section 2.2), in relation to the KFS the IPN registered in September 2016 two requests for inspection of the following IDA-financed projects: (i) Private Power Generation (Bujagali) Project; (ii) Water Management and Development Project (WMDP), which is financing some components of the SMP for the KFS; and (iii) Energy for Rural Transformation Phase III Project (ERT III), which financed preparation of the ESIA Addendum and LTCOR. In April 2017, the IDA Board ruled that the Bujagali Project was not eligible for inspection, as the project was closed in 2012. The Board approved the IPN’s proposal to defer, for up to twelve months, the recommendation on whether or not to investigate the ERT III and WMDP. Following the completion of the ESIA addendum in late 2017 and signing of IA addendum in January 2018, the IPN recommended an investigation of both WMDP and ERT III. The Board is expected to discuss the IPN recommendation in late 2018. Fiduciary and Procurement 69. IDA’s PRG supports the loans of commercial lenders. As such, there were no direct fiduciary issues, as the operation did not involve procurement or procurement-based disbursements under the project. Should the PRG be called, IDA would disburse to the beneficiary (the commercial lenders) and the GoU would then be obligated to repay IDA in accordance with the terms of the IA. 70. The World Bank reviewed the selection process for the sponsor and the procurement process for the EPC contractor and established that the said processes were consistent with its principles. This assessment was supported by the review by the lenders’ engineer of the EPC contractor’s proposal, including a technical assessment of the proposed price for the power plant. It is worth noting that contrary to the industry’s practice—and in alignment with the EIB’s procedures—the EPC’s bid prices were made public at their opening. In a process characterized by limited competition and a large difference in bidding prices, this practice proved to be counterproductive as it resulted in higher costs to the country. Though it is not possible to define in a quantitative manner the impact of this shortcoming, the EPC bid price increased from US$467 million to US$557 million during negotiations. 71. The overall financial management of the project was undertaken by BEL in accordance with commercial practices acceptable to the lenders. 2.5 Post Completion Operation/Next Phase 72. The Bujagali HPP has been operating since 2012 under commercial and technical conditions established by a 30-year PPA signed between BEL and UETCL (December 2005). Upon the commissioning of the plant, BEL engaged an experienced energy utility, Gas Natural Fenosa, to manage the plant’s O&M. 73. During the initial years of commercial operation, the hydropower plant has built a good track record as a reliable source of electricity that is surpassing the technical performance agreed in the PPA, while continuing to monitor the project’s environmental and social impact. Reportedly, the availability of the plant’s contracted capacity of 250 MW is around 98.6 percent, that is, above the targets established by the PPA (95 percent for the first year and 96 percent thereafter). Also, the plant’s annual production is 1,350 GWh, 16 percent higher than the estimates considered at appraisal for the base case, and it is expected to increase as the power market grows. On the off-

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taker’s side, UETCL has built a good track record as a punctual payer. Furthermore, the state- owned distribution company, UEDCL has gone beyond expectations in scaling up household connections, thus expanding its market base considerably, increasing its collections, and benefiting a much larger population. 74. The long-term sustainability of the project will rely on (a) the financial health of the power sector and its ability to generate sufficient revenues to cover the capacity payments for the project and (b) the GoU’s continued commitment to support a commercially oriented power sector, including an economically efficient and equitable tariff policy. The evolving positive performance of the state-owned power sector companies in recent years, as well as the continued engagement of the World Bank through its energy portfolio and policy dialogue, set favorable conditions for ensuring the long-term sustainability of the project. 75. While the levelized cost of electricity from the Bujagali HPP is about USȼ9.47/kWh for base case hydrology, Bujagali HPP actual tariff is constrained by the term of the financing available. As Bujagali HPP's economic life is significantly higher than the tenor of financing availed for the project, the GoU in 2017, requested BEL to refinance its outstanding debt with the aim to reduce electricity costs in Uganda, a high priority for the country. The GoU has committed to fully pass on the refinancing cost savings to consumers, in support of their goals to reduce electricity costs, expand access to electricity, and spur economic growth. 76. BEL appointed IFC and AfDB as the Mandated Lead Arrangers of the refinancing in 2017. The refinancing package will extend the tenor of outstanding DFI loans provided by DFIs in 2007 from the remaining 5 years to 15 years. Within the IDA guaranteed loan facility, two commercial banks (Charter Bank and BNP Pariba) will be fully repaid as part of the refinancing while the other two (Absa and Netbank) will remain in place with their original loans22. IFC’s Board of Directors approved IFC refinancing package on March 8, 2018. 3. Assessment of Outcomes 3.1 Relevance of Objectives, Design, and Implementation Rating: High 77. The project’s objectives and design are consistent with a key past and present objective of the Government, which is to provide reliable and affordable power to attract private investment and reduce poverty through rapid economic growth. 78. The last decade’s power supply crisis was a serious obstacle to economic growth.23 The situation was not sustainable and further delays in augmenting power generating capacity threatened to undermine the economy. In this regard, revising the design and implementing a hydropower project that already had a highly advanced level of preparation was an obvious choice to solve the crisis. Such a design has proved to be fully relevant nowadays, as the Bujagali HPP

22 The decision of the IDA guaranteed commercial lenders to exit or remain as Bujagali HPP lenders with the refinancing was a business decision. 23 With a peak demand in the order of 380 MW, and growing at an annual rate above 30 MW, the country’s power system was suffering from a large capacity deficit in the range of 100–120 MW. Consequently, extensive load- shedding blackouts were causing a high cost to consumers (through unserved energy and/or high-cost backup generating units) and the GoU had to resort to emergency thermal generation using highly expensive imported fuel: two 50 MW thermal generation plants running on diesel oil were commissioned in 2005 and 2006.

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has helped eliminate severe power shortages and constitutes an efficient and key component of the country’s current power supply system. 79. The combined financial resources of the World Bank Group and other DFIs were essential in mobilizing the private funds and commercial lending for the project. IDA’s PRG that covers commercial lenders from an eventual debt service default arising from specific country risk factors is, according to the sponsor, particularly useful in reducing country risks and has thus allowed a very competitive financing and helped reduce costs, as well as provide the sponsor an important degree of comfort. The PRG has also proved to be a valuable instrument in a context where country risks are perceived to be higher by commercial lenders and investors. The coverage of the PRG (and hence its relevance) extends till November 2023, at the completion of the debt service period. 80. In sum, the project’s objectives and design reflect a proper diagnosis of the country’s urgent needs, as well as past and present development priorities, and hence, they remain highly relevant. 3.2 Achievement of Project Development Objectives Rating: Moderate. 81. The Bujagali HPP in its first year of operation generated about 1353 GWh of electricity, which is about 16 percent higher than the target electricity generation. The plant maintained 99 percent availability in first year and 96 percent thereafter against the PPA obligation of 95 percent. The plant doubled the reliable capacity of the national power system, eliminated load shedding completely and allowed fuel savings in alternative thermal generation in the order of US$8 million per month. 24 While the project complied with the financial closure target, there were some limitations in meeting the project’s development objective. The plant construction experienced cost overruns of about 32 percent from the bid price and a construction delay of 13.6 months caused mostly by unforeseen ground conditions. Due to the delayed commissioning, the government had to bear the high cost of alternate generation. The cost overrun also increased the tariff of the power plant from what was targeted during appraisal. Detail project outcomes are provided in Table 5. Table 5. Project Outcomes Project Outcome PDO Target Actual Indicators To provide least-cost power Electricity generated 1,165 1,352.7 generation capacity that will (GWh) from the (first year of operation) (16 percent above the eliminate power shortages proposed 250 MW target) Bujagali HPP Levelized cost of 5.7 for high hydrology– 7.69 for high hydrology– electricity (U.S. 9.7 for low (base) 11.37 for low hydrology cents/kWh) from the hydrology 9.47 for ICR “base case”) hydropower plant Unmet electricity 0 Load shedding eliminated demand (GWh/month) upon the commissioning of Bujagali Hydropower Project (HPP) Intermediate Outcome Indicators/Milestones

24 Savings from the two 50 MW thermal generation plants, conservatively considering a capacity factor of 60 percent and a fuel price of US$800 per ton (US$106 per bbl of diesel in Uganda).

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Project Outcome PDO Target Actual Indicators Power plant is commissioned Achievement of Financial closure and Achieved on December on time and budget financial closure first disbursement 21, 2007 achieved by 2007 Plant construction Construction to be The plant was handed over progress completed in 44 months on October 8, 2012, that from financial closure is, a delay of 13.6 months. 82. The project’s final EPC unit cost, considering approved cost overruns was about US$616 million ~ US$2,466 per kW, a figure relatively high compared to the international experience for hydropower plants with no major technical complexities at the time of bidding. The economic evaluation of the project, considering the actual cost information and construction delay still demonstrates acceptable result, but lower than what was anticipated at appraisal. 83. The Bujagali HPP is a well-built and maintained power plant – the robust design and construction resulted in the reliability of its technical performance. The satisfactory level of plant availability during the last 6 years is a testament of its performance. The guarantee coverage risk ratings are a gauge of such sustainability. This perception is consistent with the business environment within which the project has operated during the last four years; that is, a scenario of political, legal, and regulatory stability, with no obstacles for foreign exchange convertibility and transferability. The only risk factors considered to be moderate are associated with the GoU’s (or Government agency) payment and input supply obligations, areas that are supported indirectly by the project through the provision of a lower-cost bulk energy and the subsequent savings in high- cost fuel consumption that was borne by the GoU. 3.3 Efficiency Rating: Moderate. 84. This Project was a second attempt to build a 250 MW hydropower plant in Bujagali. The first attempt to construct a similar power plant was initiated in 2000 and it was approved by the Bank Board in 2001. As the sponsor withdrew from the project in 2003, the initiative failed and put the GoU under pressure to meet the growing electricity demand and credibly develop a power plant in near future following IPP model. 85. The GoU followed a transparent and competitive process in adherence with its procurement guidelines, and selected BEL in April 2005, as a new project sponsor to develop the Bujagali HPP. BEL initiated the EPC selection process in July 2005 following a competitive bidding process. The market at that time was characterized by high prices for raw material worldwide along with limited availability of qualified contractors due to regional political turmoil. Against this backdrop, BEL selected the EPC contractor following a competitive process. BEL received only two offers in October 26, 2006, and the lowest EPC bid price (US$467 million) was 48 percent higher compared to the costs obtained six years earlier in 2001. The winning bidder further negotiated the award price at US$ 557 million and later with cost overruns the total EPC cost was about US$ 616 million – a total increase of US$ 149 million or about 32 percent. 86. An ex post economic evaluation of the project, using actual data on investment and O&M costs and on the power plant’s energy production for the first three years of operation, yielded the following results (details in Annex 3): an economic internal rate of return (EIRR) of 16.7 percent and a net present value (NPV) of US$211 million. These economic indicators are somewhat lower than the appraisal estimates (which gave an EIRR of 22 percent and an NPV of US$421.7 million)

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but still reveal a solid economic performance and confirm that, in spite of the project’s cost increases and delays, the Bujagali HPP was actually a central component of the system’s least-cost expansion and, hence, an efficient option to address the country’s power crisis and power expansion needs. 87. Adopting the industry practice for limited recourse financing transactions, the project was supported by independent engineers. However, the project was suffered from suboptimal bidding process, resulting in cost overruns and construction delays. 3.4 Justification of Overall Outcome Rating Rating: Moderately Satisfactory. 88. The project successfully constructed a 250 MW hydropower plant with cost overruns and construction delay. The Bujagali HPP after commissioning eliminated all load shedding in Uganda and helped the government save about US$ 8 million in fuel cost of expensive thermal power plants. However, the construction delay that commissioned the power plant after about a year of target date had also been expensive for the GoU. Accordingly, a Moderately Satisfactory rating is assigned to the overall project outcome. 3.5 Overarching Themes, Other Outcomes and Impacts 89. Institutional strengthening. The project was one of the largest private ventures in the power sector in Sub-Saharan Africa. All parties recognize that the experience in dealing with the complexities of limited recourse finance for the complete project cycle in a large infrastructure project, and with the availing of external technical and legal expertise, has contributed considerably in strengthening the capacity of many public institutions. An important learning experience is reported in the application of social and environmental safeguards, as well as in the management of contracts and in civil works and electromechanical technical issues. This capacity is being used in the development of new projects. 90. The Uganda power sector is characterized with a credible and independent regulatory authority. The sector has been able to attract private investment in small scale power plants using renewable energy resources, mostly hydro and solar. The sector has also attracted private investment in electricity distribution. However, in recent times, the sector is moving ahead with development of large scale hydropower plants funded the Government of Uganda and with support from China’s Exim Bank. 3.6 Summary of Findings of Beneficiary Survey and/or Stakeholder Workshops 91. No beneficiary survey was undertaken. 4. Assessment of Risk to Development Outcome Rating: Moderate. 92. As noted in section 2.5, the project has been operating commercially since October 2012. The power plant has performed above the expected technical standards during this period. Such performance is consistent with the project’s sound engineering design and a construction process characterized by high technical and safety standards. In fact, it could be argued that the design and construction of some structures were conservative (that is, high safety factors). While it is likely that this conservative approach contributed toward higher investment cost, it offers a facility of

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high operating reliability. Hence, it is considered that the risks associated with the operation of the power plant and the energy and capacity contribution to Uganda’s power system are negligible. 93. However, the long-term risk to the project development outcome relies not only in the plant remaining in satisfactory operating performance, but in remaining in the list of least cost plant to be dispatched. Some of the IPPs commissioned under the Renewable Energy Feed in Tariff (REFIT) policy of the GoU have tariff below that of Bujagali HPP. However, give the small size of those power plants, that had not impacted the dispatch level of the Bujagali HPP. However, as the GoU is constructing two large hydropower plants (Isimba 183 MW and Karuma 600 MW) with the GoU’s financing and with support from China’s Exim Bank, there is a probability, that electricity for these plants would be cheaper to UETCL compared to Bujagali HPP. Accordingly, the GoU has recently requested BEL to refinance it outstanding debt, to reduce the debt service requirement of the Bujagali tariff. The Bujagali Refinancing has become effective from July 20, 2018 and this will reduce the tariff of Bujagali from 2018-2023 by about USc5.5/kWh. This reduction in tariff benefits from an additional tax holiday granted by the GoU to the Bujagali HPP sponsor. Hence the risk to development outcome is considered as Moderate.

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5. Assessment of the Guarantee in support of the Project 5.1 Impact of the guarantee in mobilizing private sector financing 94. The PRG was provided to protect commercial lenders from the risk of debt repayment failure from BEL arising from the government’s failure to meet certain payments obligations under the Implementation Agreement or PPA (see paragraph 19). The commercial lenders provided finance of US$115.4 million, constituting 16.4 percent of the debt finance, for the Project. Given Uganda’s limited track record to attract private sector financing. The provision of the PRG was instrumental in catalyzing long term commercial debt in Uganda and reducing the risk for commercial debt to an extent that commercial debt could match DFIs maturities. Moreover, without the PRG coverage, the commercial lending needed to close the financing gap of the project would have not materialized. Furthermore, it is considered that the involvement of the World Bank in the Project strengthened all parties’ commitment to abide by international standards and, hence, proved to be instrumental in providing commercial banks an indispensable degree of comfort. 5.2 Role and value of the guarantee in addressing critical risks and improving the overall sustainability of the transaction 95. As mentioned (section 1.5), the PRG covered guaranteed lenders from the risks arising from the government’s failure to meet its payments obligations with respect to making a compensation or other payment upon termination of the Implementation Agreement or the PPA (or at any other time under) by reason of any of: (a) political force majeure, (b) changes in law and events making the project contractual agreements unenforceable or void, (c) Government-imposed restrictions on the ability of BEL to be paid or to receive foreign currency or transfer funds abroad, and (d) failure of the Government to fulfill its payment obligations relating to UETCL purchase of power and termination payments due by UETCL. Among these risks, the risks of political force majeure and changes in law were covered only by the PRG for commercial lenders; therefore, the PRG made a valuable contribution to the Project by addressing risks that were not covered by other parties and created a level of confidence to all parties involved. 96. In a broader perspective, the energy delivered by Bujagali HPP helped to practically eliminate the load-shedding prevailing in the power system and, hence, contributed substantially in improving the technical and financial performance of the power sector, as well as the sustainability of the transaction itself. 5.3 Key issues or events that may arise in the future that could lead to a potential call on the guarantee 97. There are no significant risk factors that could lead to a call of the guarantee. This perception is consistent with the ISR ratings of the Bank’s team that consider the overall guarantee risk to be negligible. 98. The Bujagali HPP is in commercial operation since October 2012 and the guarantee expires in November 2023. Since its commissioning, the plant has performed above the expected technical standards and has operated within a business environment characterized by political, legal and regulatory stability, with no obstacles for foreign exchange convertibility and transferability. The only event that could generate a situation of guarantee being called is the Government’s failure to fulfill its payment obligations. Such a risk is mitigated by the stability of the business environment and by the Project’s positive impact on the power sector’s financial performance. In addition, the

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refinancing of the Bujagali HPP approved by the Board on March 8, 2018 and which became effective since July 20, 2018 will cause an average reduction of Bujagali HPP tariff of 2018-2023 by about USc5.5/kWh. This reduction in tariff benefits from an additional tax holiday granted by the GoU to the Bujagali HPP sponsor. This will further benefit the financial performance of the Uganda Power sector, as this reduction in Bujagali HPP tariff will have an average reduction in Uganda Power Sector end user tariff by about USc2.3/kWh. 6. Assessment of Bank and Borrower Performance 6.1 Bank Performance (a) Bank Performance in Ensuring Quality at Entry Rating: Moderately Satisfactory. 99. The World Bank’s performance during project design/preparation was Moderately Satisfactory. The project’s development objective proposed by the World Bank was an appropriate response to country’s needs and was fully compatible with the emergency situation of the power sector and the GoU’s development priorities. Upon the collapse of the first attempt to build the Bujagali HPP, the World Bank, in close and effective collaboration with IFC, other lenders and the GoU, did a proper due diligence and put together a new project that addressed the shortcomings of the previous design and incorporated the lessons of the first IPN process (2002-2003). This effort correctly included (a) improving governance standards through the introduction of competitive bidding and (b) a more thorough assessment and preparation of social and environmental matters. 100. At appraisal, the World Bank made an extensive and realistic assessment of critical risks that could affect the project’s performance. Furthermore, the World Bank helped structure a comprehensive financing plan with adequate coverage to provide comfort to commercial lenders. The key outcome indicators to be monitored were considered meaningful, simple, quantifiable, and adequate for a private project operation that also had its own monitoring mechanisms. 101. Large hydropower development is a complex and challenging venture that requires addressing potential problems in multiple dimensions: social, environmental, technical, economic, and financial. As such, it is common to encounter problems of design that often affect project implementation. In this regard, the Bujagali HPP was no exception. The project experienced cost increases and completed construction with delays. However, the project still met its development objectives. 102. Shortcomings in the design of the project (mostly on social and environmental matters) triggered an IPN process that concluded that the World Bank was not in full compliance with five operational policies. Two new allegations were submitted to the IPN in September 2016 challenging the impending impacts on the KFS by the Isimba HPP under construction by the GoU. However, this project was not eligible for investigation as it closed in 2012. (b) Quality of Supervision Rating: Moderately Satisfactory. 103. World Bank supervision activities included monitoring the project’s implementation in all dimensions, continued reporting, assessment of the guarantee obligations, and coordinating activities with Government agencies and many lenders. The World Bank conducted well-staffed periodic missions that were integrated into the joint lenders’ supervision missions. The missions’

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Aide Memoire and ISRs reflect a thorough supervision effort in following the project’s construction progress, as well as its compliance with World Bank social and environmental safeguards. A smooth coordination with other lenders helped harmonize criteria and minimize the cost to the GoU and sponsor. 104. Upon the issuance of the IPN Investigation Report (2008), World Bank management and staff worked diligently on preparing a MAP that directly addressed all noncompliance issues raised by the IPN. The implementation of the MAP was monitored by several external entities and reported to the Board on a timely fashion. This open and thorough process helped solve, though with some delays, all the issues raised by IPN. 105. Overall, the World Bank was a trusted and supportive partner that took a clear position on the many challenging issues that had to be addressed. The constant presence in the field with biannual multi-lender missions plus the support of local staff, as well as the attention given to the project by World Bank management, secured high-quality supervision. However, the monitoring of land title issue could have been stronger, as the issue remained outstanding for at least three years after the project commissioning. Hence, the World Bank’s performance is considered Moderately Satisfactory. (c) Justification of Rating for Overall Bank Performance Rating: Moderately Satisfactory. 106. Considering preparation and supervision ratings, an overall rating of Moderately Satisfactory is assigned. 6.2 Borrower Performance (a) Government Performance Rating: Moderately Satisfactory. 107. The GoU was strongly committed to the project through all its phases. This commitment was reflected in various manners, including the following: (a) providing a US$75 million bridge loan to BEL during the negotiations of the EPC contract, with the aim of locking in the EPC contract price and launching construction before financial closure; (b) establishing and ensuring the functioning of the BEMC with representation of all agencies involved in the project, to monitor safeguard issues in a comprehensive manner, report, and provide recommendations; (c) ensuring the continuity of the resettlement process upon the collapse of the first attempt to build the Bujagali HPP; (d) supporting the UETCL as a credible off-taker with timely payments to BEL; and (d) maintaining an environment of legal and regulatory stability and supporting the continued commercialization of power sector operations. 108. A key public sector player in the project has been the state-owned transmission company UETCL. UETCL is the designated off-taker of the Bujagali HPP’s electricity production under a 30-year PPA, as well as the owner of the transmission infrastructure required to deliver the project’s energy to the national grid. During the first years of project operation, UETCL has built a reputation of a good payer. Other public institutions playing an important role in the project are the Ministry of Energy and Mineral Development, the main government counterpart for BEL and official lenders, and the NEMA, the agency responsible for licensing and supervision of environmental matters.

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109. While the GoU was clearly supportive of the project, some of its agencies suffered from limited resources and hence had difficulty in complying with the project’s requirements on time. The GoU’s performance revealed the following shortcomings: (a) delays in the implementation of the CDAP, in the rural electrification program; (b) considerable delays in providing land titles to households resettled by the project; and (c) authorizing the construction of the Isimba HPP without adequately determining the magnitude of impact and identifying appropriate mitigation measures for the KFS. Consequently, the Government’s performance is rated Moderately Satisfactory. (b) Implementing Agency Performance Rating: Moderately Satisfactory. 110. The sponsor’s power company BEL is the implementing entity of the project. Before the project, BEL did not have much experience in hydropower. Hence, BEL engaged the services of a well-known engineering firm to act as the owner’s engineer. Upon its selection through a competitive process, BEL proceeded to select an international EPC contractor for the project on a turnkey basis. Similarly, it has appointed an experienced power company to manage the plant’s O&M activities. In agreement with the GoU and on behalf of the off-taker UETCL, BEL took care in an efficient manner the procurement and construction processes for the interconnection project required to deliver the Bujagali HPP’s energy to the power grid. 111. BEL has ensured that the plant’s technical performance adheres to international standards, surpassing the targets established by the PPA and IDA’s key monitoring indicators. BEL’s reporting on the project’s construction and operation, costs, and social and environmental issues was highly useful for the GoU and lenders alike. Overall, BEL proved to be a responsive, transparent, and very proactive implementing entity and was particularly helpful in addressing the demands of the tight scrutiny the project was subject to. 112. The shortcomings of BEL included suboptimal preparatory activities including conducting a bidding process which allowed about 20 percent increase in the bid price during post-award negotiations. Furthermore, there were cost overruns during construction ending to about 32% increase in the EPC cost compared to bid opening price. The construction of the project was also delayed by about 13.6 months from the agreed delivery schedule. 7. Lessons Learned 113. Coordinated World Bank Group (WBG) approach can deliver results in a complex project: The WBG’s return to hydropower in Africa through the Bujagali HPP confirmed its potential to contribute successfully in the development of complex infrastructure projects. The harmonized participation of several WBG member institutions—IDA, IFC, and MIGA—was highly effective in all phases of the project cycle and contributed significantly toward the project’s success. The complementarity of the WBG institutions’ financial instruments was pivotal in mobilizing the considerable level of private funds required for the project development. Also, the WBG was able to optimize synergies among its institutions through a well-coordinated use of each institution’s resources and know-how during the due diligence process, country dialogue, and supervision. In balance, these factors contributed toward a successful project outcome despite the multiple challenges (financial, technical, social, and environmental) inherent in HPPs. 114. Government commitment is crucial to successfully implement complex infrastructure projects: A consistent Government commitment is essential to ensure successful implementation of a large private infrastructure project. Large projects, such as hydropower projects, are

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particularly complex and often require the support of the Government to address challenges that the public sector is in a better position to tackle, such as a project’s licensing process, consultation with affected people, and some aspects of the compensation plan (for example, land titling). In fact, the participation of the Government in a large infrastructure project is vital to creating an enabling environment for private sector to participate and thrive in. 115. There is a tradeoff between upfront risk allocation and rapid execution of the project. To start construction quickly, the GoU bid out the EPC contract before the geotechnical analysis was completed. The geotechnical risk, which resulted in a significant cost increase during the construction was a tradeoff. As waiting for the completion of the geotechnical study could have been even more costly, as it would have significantly delayed the commissioning of Bujagali HPP and use of emergency power supply would have continued. The GoU and BEL made a sensible decision to take the geotechnical risk in the context of an emergency. Such tradeoff between the upfront risk allocation and rapid execution of the project deserve a careful consideration and judgement. Valuable lessons could be derived by analyzing why the post-award negotiations increased the EPC bid price by about 20 percent. Understanding whether it was due to the procurement process followed or sub-optimal preparation of the bidding document, can provide valuable lessons for future projects. The economic analysis of the project confirmed that even after accepting the cost overruns, the project had an actual EIRR of about 16.7 percent. 116. An effective power sector reform can reduce off-taker risk: The Bujagali HPP’s experience confirms the view that undertaking a comprehensive power sector reform before a major private investment helps in reducing project risks and provide comfort to potential sponsors and lenders alike. In the case of Uganda, private concession for electricity distribution to UMEME significantly improved the bill collection rate, strengthened financial viability of the sector and reduced off-taker risks. 117. Flexible procurement approach is needed in the context of limited competition. Due to the high-risk perception in the electricity sector in Uganda, the Bujagali attracted only two EPC bidders, resulting in limited competition between the bidders. Under such condition, following DFI’s practice of making public the financial bids gave an inadequate negotiating advantage to the winning bidder that resulted in an excessive EPC price increase that was ultimately borne by the Government and consumers. A flexible procurement approach is needed when the project is high- risk by private sector and the competition is limited, including the avoidance of public reading of bid prices. 118. Coordination among financiers help lenders and clients alike. The presence of many lenders poses a significant coordination challenge and the risk of having to deal with different procedures. For example, BEL and the GoU had to cope with equivalents of Inspection Panel from multiple lenders (e.g. Independent Review Mechanism by AfDB), which has taken significant resources. Addressing such a challenge requires a flexible approach from all parties. The joint lenders’ mission approach practiced in the Bujagali HPP proved to be an effective way to harmonize criteria and minimize the distraction (of resources) to the sponsor and government agencies. The joint lenders’ mission was led by a different lender each time, which ensured the involvement of all parties in a balanced manner. 119. Off-set arrangements require careful identification and implementation. During the project preparation, the KFS was identified as the offset site in compensation for the loss of the Bujagali Falls, considering that it was an area ecologically similar to the area lost. This decision

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was made without rigorous identification of a baseline on the natural habitat, environmental, and spiritual values. A clear demarcation of the off-set area was also missing. It is also likely that the identification process did not consider the GoU’s hydropower development plans and other stakeholders’ interests in the KFS, such as the tourism and white-water rafting industries. Careful assessment of these interests during project preparation would have identified potential risks to the long-term sustainability of the off-set and consistent mitigation measures would have been designed and put in place. It is also worth noting that the SMP of the KFS was too broad, covering areas outside the KFS, to be actionable. It would have been useful if the SMP was developed specifically for the KFS. Also, an offset arrangement requires monitoring beyond a project’s implementation period, hence a legal recognition of the KFS within the Ugandan statutory framework could have been useful, right from the beginning, to strengthen the SMP and effective monitoring and enforcement of the KFS in the long-term. Therefore, when offsets are involved, it is critical to have a comprehensive picture of development plans and assessments on the feasibility of concurrent development. This is important for the government primarily but also for the Bank to ensure developments happen as per agreed plans. 120. Responding to the IPN’s findings can improve the project’s performance without causing major delay in implementation. The Bujagali HPP, like other large infrastructure project, was implemented under the tight scrutiny of local and international civil society, including an eventual IPN investigation during the project implementation period. While this process helps to increase the accountability of projects, it is important to avoid an adverse impact on the construction process, unless this is indispensable. The Bujagali HPP’s experience in dealing with the IPN process was exemplary in this regard. The findings of the IPN were used to improve the project’s safeguards compliance, without causing any significant delays in project works. 121. The project design should have been further strengthened based on first IPN findings. The project design had shortcomings on social and environment aspect, which triggered an IPN investigation. This investigation concluded that WB had not fully complied with five operational policies (see para 46 and para 102). This was after the first Bujagali project which found the project was lacking certain aspects of safeguard design and implementation. A robust review of safeguard design and implementation against the backdrop of the findings from the first IPN investigation could have improved the project design and resulted in mitigation measures to prevent a recurrence of similar issues, as identified by the first IPN investigation. Based on the IPN findings, a “checklist” of issues to be addressed could have been created to guide the design of the second Bujagali project and its implementation. This project could have strengthened land acquisition management and safeguards issues in general. 122. Government’s commitment and engagement rapidly increased its capacity. As the Bujagali was the first hydropower IPP in Uganda, it served as an important learning opportunity for the GoU. The GoU benefited from external legal and technical experts that were involved in the design and construction of the Bujagali HPP. Environmental and social safeguard practice of Bujagali became an important benchmark. It was reported that the new hydropower plants currently under construction in Uganda are using the practice of Bujagali as a key reference.

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8. Comments on Issues Raised by Borrower/Implementing Agencies/Partners (a) Borrower/Implementing Agencies Main findings and conclusions of the sponsor’s completion report are presented in Annex 7. (b) Co-financiers No comments received. (c) Other Partners and Stakeholders No comments received.

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Annex 1. Project Costs and Financing

(a) Project Cost by Component (US$, thousands) Components Appraisal Actual Percentage of Estimate Appraisal Equipment Procurement and Construction - EPC (civil 520,064 616,452 +19 works, electromechanical equipment, and spares) Government Contributed Assets 20,000 20,000 0 Project Development Costs 26,838 30,322 +13 IDCa and Financing Fees 94,087 111,695 +19 Contingencies and DSRAb 82,082 46,003c –44 Initial Working Capital and Other Costs 55,509 67,027d +21 Total Project Costs 798,580 891,500 +12 Note: a. Interest during construction; b. Debt Service Reserve Account; c. Debt service reserve only; d. 19,112 for working capital and 47,915 for pass-through cost (‘other costs’). (b) Financing (US$, thousands) Source of Funds Appraisal Actual Percentage of Estimate Appraisal Equity Project sponsors 151,570 179,761 +19 Government 20,000 20,000 0 Total equity 171,570 199,761 +16 Debt IFC 130,000 128,366 -1 EIB 130,000 136,000 +5 Commercial banks (Guaranteed Lenders) 115,000 115,000 0 AfDB 110,000 111,000 +1 European DFIs 142,010 213,103 +50 Total debt 627,010 703,469 +12 Total debt and equity 798,580 903,230 a +13 Note: a. The discrepancy between the actual cost of the project and the financing cost is explained by the fact that, in accordance to contractual agreements, two expenditure categories were disallowed and thus not considered as part of the project’s final cost for the purposes of the PPA. Disallowed expenditures included US$0.8 million for the EPC cost and US$10.8 million that exceeded the permitted development costs.

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Annex 2. Outputs by Component 1. Table 2.1 presents the project’s outputs, which evidence a satisfactory performance when compared to its outcome indicators’ targets. The section below elaborates on the reassessment of a key indicator: the levelized cost of electricity. Table 2.1. Project’s Outputs PDO Project Outcome Target Actual Indicators To provide least-cost Electricity 1,165 1,352.7 power generation generated (GWh) (first year of (16 percent above the performance capacity that will from the proposed operation) target) eliminate power 250 MW Bujagali shortages HPP Levelized cost of 5.7 for high 7.69 for high hydrology–11.37 for low electricity (U.S. hydrology–9.7 for hydrology cents/kWh) from low (base) 9.47 for ICR “base case” the hydropower hydrology plant Unmet electricity 0 Load shedding eliminated upon the demand commissioning of Bujagali Hydropower (GWh/month) Project (HPP) Intermediate Outcome Indicators/Milestones Power plant is Achievement of Financial closure Achieved on December 21, 2007 commissioned on time financial closure and first and budget disbursement achieved by 2007 Plant construction Construction to be The plant was handed over on October 8, progress completed in 44 2012, that is, a delay of 13.6 months months from financial closure 2. Estimation of the LCOE. The project’s LCOE was reassessed on the basis of actual data on the project’s costs and electricity generation for 2013–2015 and used the same methodology of the PAD. The computation covers 2013–2042. • Capacity charge payment. The figure of UETCL’s capacity payment is taken from BEL’s financial model of May 2016, which uses actual figures up to 2015 and projected figures from 2016 onward. Payments vary year to year according to the schedule of debt repayment to lenders and dividend payment to project sponsors and the GoU. • Electricity generation. Actual generation figures are used for 2013 to 2015. From 2016 to 2042, a capacity factor of 68 percent, or annual generation of 1,489.2 GWh, was assumed. This figure is based on consultation with BEL about the estimated capacity factor of the Bujagali HPP. • Cost of capital. The Weighted Average Cost of Capital (WACC, used for discounting) is based on the amount and estimated cost of debt and equity. Based on the estimated data at project completion and assumptions outlined above, the LCOE is estimated to be USȼ9.47 per kWh (2006 U.S. dollar) for the 30-year PPA period. A sensitivity analysis for high and low hydrology was undertaken using the same hydrological scenarios of the PAD. The result is shown in table 2.2.

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Table 2.2. Project’s LCOE

Base Case High Hydrology Low Hydrology LCOE (2006 U.S. cents/kWh) 9.47 7.69 11.37 3. In conclusion, on PDO performance indicators, the project: • performed above the performance target for electricity generated (GWh) (which may have been due to better-than-expected hydrology); • under-achieved the targets for the Levelized Cost of Electricity when compared against the PDO range of USȼ5.7 (high hydrology – 9.7 for low (base) hydrology; and • achieved the performance target for unmet load demand. 4. With respect to the intermediate indicators, the project: • achieved financial closure within 2007 (on December 21, 2007), as expected; and • experienced 13.6 months of delay in construction completion.

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Annex 3. Economic and Financial Analysis 1. An economic analysis of the Bujagali HPP was conducted to assess the efficiency of the project’s outcome. To ensure consistency with the appraisal’s analysis, the methodology employed in the PAD and the consultant’s report25 has been replicated as nearly possible. (a) Economic Analysis at Appraisal 2. During the preparation stage, a comprehensive economic and financial analysis was undertaken by a consulting firm. The economic analysis included a least-cost analysis that assessed multiple expansion plans for Uganda’s power system with variations in demand forecast, hydrology, fuel prices, and investment costs of Bujagali HPP. A summary of the original assumptions and approaches is presented in table 3.1. 3. Costs. These included direct costs associated with the Bujagali HPP and the expansion costs of transmission and distribution infrastructure necessary to deliver the electricity generated to end users. The project’s capital investment costs were estimated based on the latest negotiation with the EPC contractor at the time of appraisal, including also the interconnection of the plant to the grid, environmental and social management costs, development costs and physical contingencies, but excluding financing costs. Although the Bujagali Interconnection Project was dealt as a separate project, it was included in the economic analysis to capture the entire cost incurred to the power system. O&M costs of generation, transmission, and distribution infrastructures were also included. The details are provided in table 3.1. Table 3.1. Cost Estimates of the Bujagali HPP at Appraisal

Item Cost at Appraisal Remarks (US$, thousand) System Expansion Cost Generation 520,616 Including interconnection, environmental, and social management costs Transmission 56,301 Assumed US$206.2 per kW based on long-term average cost; incremental cost analysis on Umeme’s transmission expansion plan Distribution 175,747 O&M Cost Generation 3,000 per year US$1 per kW per month Transmission 563 per year 1 percent of cumulative investment cost Distribution 3,515 per year 2 percent of cumulative investment cost 4. Benefits. The project benefits consist of three components stemming from (a) incremental demand of electricity users, (b) displaced thermal generation costs, and (c) reduced cost of unserved energy demand. The incremental demand is the additional electricity provided to users by the project, and its benefit was calculated based on the demand forecast and the willingness to pay (WTP) of various customer segments. The WTP was derived from projected electricity tariffs, international oil price, and the cost of lighting fuels. The benefit of displaced thermal generation was computed based on the cost of thermal (diesel and heavy fuel oil) generation displaced by the Bujagali HPP. The cost of unserved energy is incurred when there is a supply deficit. This cost was marginal in the base case scenario (US$36,000 from 2019 onwards). Total project benefits ranged between US$160 million and US$200 million per year, or US$0.16–0.18 per kWh. These

25 Power Planning Associated Ltd. Bujagali II—Economic and Financial Evaluation Study, final report. February 2007. Study commissioned by the IFC.

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figures exclude the benefit arising from greenhouse gas reduction. Some of the key assumptions, such as the demand forecast figures and the quantity and per unit cost of displaced thermal energy, were not explicitly provided in the PAD or in the consultant firm’s report. 5. Economic efficiency. The economic analysis at appraisal concluded that the EIRR of the Bujagali HPP under the most likely scenario (base case for demand, oil prices and investment cost; low hydrology) was 22.0 percent. This figure varied from 12.4 percent to 25.8 percent, depending on the scenarios considered. The NPV for the base case was US$421.7 million. (b) Changes in Costs and Benefits since Appraisal 6. Costs. Actual project costs increased by 44.68 percent compared to the appraisal estimates—about 46.3 percent increase for the power plant and 26.6 percent for the Bujagali Interconnection Project. The breakdown is provided in table 3.2. Table 3.2. Change in Project Costs (US$ thousands) aa

Appraisal Actual Change (percentage) Bujagali Hydropower Project 474,892 694,689 +46 EPC contract 441,355 616,452 +40 Environmental and social management 8,258 13,430 +63 Development costs 25,279 30,322 +20 Other pass-through costs 34,485 n.a. Bujagali Interconnection Project 45,724 57,888 +27% Interconnection 27,990 43,951 +57% Environmental and social management 17,734 13,937 -21% Project total cost 520,616 752,577 45% Note: aa. The project cost estimate used for Economic and Financial Analysis differs with that provided in Annex 1 Project Cost and Financing. a. Other pass-through costs include legal and technical fees, license fees, IDA guarantee fee, and so on, among others. Source: PPA (2007) Bujagali II-Economic and Financial Evaluation Study, UETCL (2016) Bujagali Interconnection Project Completion Report. Ernst and Young (2013) Bujagali Energy Limited Final Costs Report.

7. The EPC contract of the Bujagali HPP is the largest driver of cost increase. The estimated EPC cost in 2007 was around US$441 million. When the PAD went to the Board in April 2007, the EPC cost had increased to US$520 million. This last figure was not used in the PAD’s estimation of the EIRR and NPV, presumably because the adjustment came after the economic study’s completion. At completion of the power plant, the final EPC cost was US$616 million. This increase in an amount of US$94 million is attributed to multiple expenses incurred during construction: ground condition work (US$31 million), modifications required due to inaccuracy of previous studies provided to the EPC contractor (US$25 million), and others. It is worth noting that, according to the negotiated agreements, geotechnical risks were borne by the GoU. Hence, the EPC contractor claimed significant additional expenditures for ground conditions and other works which were not part of the original study and design. 8. Benefits. The original plan of the project was to start electricity generation in 2011. However, construction was delayed, and the plant was commissioned in August 2012. This delay resulted in postponed project benefits. However, project benefits were still positive due to the following factors: • More generation. The assumption at the appraisal for the low-hydro scenario,

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considered as the base case, was that the plant would generate 1,165GWh per year. Actual hydrological conditions have so far been more favorable as the power plant is currently generating more than 1,350 GWh per year. This has allowed electricity consumption to grow without facing generation constrains. • Higher oil price. The original economic analysis assumed crude oil price of US$68 per bbl in 2007, gradually dropping to US$32 per bbl in 2015 for the base case scenario. Actual oil prices were higher and kept increasing to peak at US$91 per bbl in 2013 and dropped to US$47 per bbl in 2015. The higher oil price increased the benefit of diesel fuel and heavy-fuel oil savings from thermal displacement. Similarly, this increased the benefit for commercial and industrial electricity users, who saved diesel fuel for their self-generation, as well as newly connected customers who saved traditional lighting fuels such as kerosene. • Higher retail electricity tariff. The original analysis made a retail tariff assumption of US$20.3 per kWh, which declined and stabilized at US$17.2 per kWh with the commissioning of the Bujagali HPP in 2011. In reality, retail tariffs in Uganda increased, rather than decreased, by approximately 30 percent in 2012 (year of Bujagali HPP commissioning). The demonstrated WTP of existing consumers for a higher tariff indicates a higher economic value of the electricity. Hence, the unit benefit of incremental electricity consumption is higher than originally estimated.26 • Increase in new connections. The original analysis assumed an annual increase of 25,000 residential customers from 2011 to 2020. In reality, the number of customer connections increased more rapidly than anticipated: an average of 100,000 residential customers per year since the project’s commissioning. More connections to electricity grid translate into greater benefits of replacing traditional lighting fuels and candles with electricity. (c) Actual Economic Performance 9. Based on the actual parameters described above, the EIRR and NPV of the Bujagali HPP are estimated as shown in table 3.3. Table 3.3. Project’s Economic Indicators Appraisal Actual EIRR (percentage) 22.0 16.7 NPV (2006 US$, million) 421.7 211 10. It should be noted that the following methodological adjustments have been made: • The benefit arising from electricity export was not included in the recalculation. This benefit was marginal in the appraisal analysis and Uganda is currently not exporting electricity. • The cost arising from unserved energy was not included either because this cost was marginal at appraisal.

26 The tariff charged by BEL to UETCL is set high in the first 11 years to repay the project debt, and it declines after the debt has been fully repaid. The original economic analysis did not take into account this pattern and assumed immediate tariff decrease after Bujagali HPP’s commission.

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• The distribution expansion costs were kept as in the appraisal (US$176 million over seven years), assuming that the cost of distribution infrastructure did not significantly change with the number of new connections. 11. The EIRR and NPV of the project are lower than the appraisal estimates, but they still demonstrate a robust economic performance and confirm that the project was an important component of the power generation least-cost expansion. The cost of the project increased significantly, primarily due to higher EPC costs, but project benefits also increased owing to greater electricity generation, higher oil price, higher electricity tariff and a rapid growth of new customer connections. (d) Project Financial Performance 12. The project’s financial performance has been reassessed using actual values. Financial projections confirm that the project remains financially sound, with a minimum Debt Service Coverage Ratio (DSCR) of 1.5 over the terms of the loans. The project’s financial rate of return was re-estimated at 9.3 percent, below the appraisal estimate of 11.2 percent and slightly above the WACC. The decline in the financial indicators is attributed to the considerable increase in the cost of the EPC contract and the delay in the plant’s commercial operation. However, results remain positive because a great part of the cost increases were not borne by the sponsor BEL but passed through to the off-taker, UETCL. Table 3.4. Project’s Debt Service Recovery Ratio (US$ thousands) 2013 2014 2015 2016 2017 2018 Operating income 152,982 135,944 146,034 153,221 157,377 198,250 Debt service 100,742 70,327 87,088 88,503 85,283 86,343 DSCR 1.5 1.9 1.7 1.7 1.8 2.3

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Annex 4. Bank Lending and Implementation Support/Supervision Processes (a) Task Team members Lending World Bank Names Title Unit Responsibility/Specialty Malcolm Cosgrove-Davies Team Leader and Sr. Energy Specialist AFTEG Task Team Leader Suman Babbar Senior Advisor FEU Karen Rasmussen Lead Financial Analyst AFTEG Robert Schlotterer Financial Analyst AFTEG Gulam Dhalla Consultant (Finance) AFTEG Mark Segal Consultant (Economics) AFTEG Helena Kofi Procurement Analyst AFTEG Janine Speakman Operations Analyst AFTEG Raymond Bourdeaux Sr. Infrastructure Specialist FEU Richard Olowo Senior Procurement Specialist ACTPC Patrick Piker Umah-Tete Sr. Financial Management Specialist AFTFM Paul Baringanire Consultant AFTEG Regional Environmental and safeguard Warren Waters AFTQK advisor Robert Robelus Consultant AFTU2 Maria C. J. Cruz Senior Social Development Specialist SDV SDV Agnes Kaye Program Assistant AFMUG Tigest Tirfe Program Assistant AFTEG

IFC Names Title Unit Responsibility Francisco Tourreilles Director CINDR Thierry Tanoh Director CAFDR Rachel Kyte Director CESDR Darius Lilaoonwala Senior Manager CININ Jean Philippe Prosper Senior Manager CAFE1 Patricia Miller Manager CESIG Adil Marghub Principal Investment Officer CININ Saleem Karimjee Principal Investment Officer CAFS 1 Belen Castuera Investment Officer CININ Dan Kasirye Investment Officer CAFE 1 Romani Curtis Investment Analyst CININ Carlos Algandona Principal Power Engineer CININ John C. Kittridge Principal Environmental Specialist CESIG Nicholas E. Flanders Senior Environmental Specialist CESIG Moez Cherif Economist CINDR

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John R. Coogan Manager CLEIP Yeages Cowan Counsel CLEDC Martha Yebra-Bryant Senior Insurance Officer CESIS Jill D. Partington Insurance Analyst CESIS Ann Pasco Communications Officer CEXCM Lucie Cecile Giraud Communications Officer CESKI Sandra Estrada Team Assistant CININ

MIGA Names Title Unit Responsibility Philippe Valahu Acting Director MIGOP Zhengrong Lu Sr. Underwriter MIGOP Thomas Vis Sr. Risk Management Officer MIGEP Srilal Perera Chief Counsel MIGLC Michael Silverman Lead Counsel MIGLC Robert McDonough Sr. Environmental Specialist MIGEP Deniz Baharoglu Sr. Social Sector Specialist MIGEP Angela Gentile Sr. Communications Officer MIGEO Judith Pearce Lead Operations Officer MIGEO Lorie Henson Program Assistant MIGOP

Supervision

Malcolm Cosgrove-Davies Lead Energy Specialist GEEDR Task Team Leader Karen T. Rasmussen Lead Financial Analyst n.a. Suman Babbar Consultant GWASP Janine A. Speakman Operations Analyst GEEDR Maria Concepcion J. Cruz Lead Social Development Special n.a Kristine M. Ivarsdotter Senior Social Development Spec n.a. Robert A. Robelus Consultant GEN05 Raymond Bourdeaux Program Leader ECCU4 Robert Schlotterer Lead Infrastructure Finance Specialist GEEFS Paul Baringanire Senior Energy Specialist GEE05 Mary C.K. Bitekerezo Senior Social Development Spec GSU07 Martin Fodor Senior Environmental Specialist GEN2B Somin Mukherji Senior Financial Analyst n.a. Task Team Leader Howard Bariira Centenary Senior Procurement Specialist OPSPF Paul Kato Kamuchwezi Financial Management Specialist GGO31 Herbert Oule Environmental Specialist GEN01 Constance Nekessa-Ouma Social Development Specialist GSU07 Mbuso Gwafila Senior Energy Specialist GEE01 Mitsunori Motohashi Senior Energy Specialist GEE03 Task Team Leader

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Vladislav Vucetic Lead Energy Specialist GEE01

ICR Raihan Elahi Lead Energy Specialist GEE01 Task Team Leader Enrique Crousillat Consultant, Lead ICR Author n.a. Kenta Usui Energy Specialist GEE01 Chita Obinwa Senior Program Assistant GEE01

(b) Staff Time and Cost

Staff Time and Cost (Bank Budget Only) Stage of Project Cycle US$, Thousands (including travel and No. of Staff Weeks consultant costs) Lending FY2005 25.7 202,418.8 FY2006 32.1 293,692.3 FY2007 51.7 407,677.2 FY2008 22.2 124,255.0 Total 131.62 1,028,043.24 Supervision/ICR FY2008 35.2 178,368.5 FY2009 48.6 291,904.7 FY2010 19.28 103,345.1 FY2011 17.14 79,898.4 FY2012 16.33 78,792.0 FY2013 14.41 106,282.3 FY2014 9.82 49,499.1 FY2015 19.76 112,264.0 FY2016 15.18 93,865.0 Total 195.64 1,094,218.9

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Annex 5. Beneficiary Survey Results

Not applicable.

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Annex 6. Stakeholder Workshop Report and Results

Not applicable. Project stakeholders comprise a very broad group, from private sponsors, lenders and consumers, to local affected people. There were consultation workshops for local stakeholders at the early stages of the project, focusing mainly on social and environmental issues, but, given the nature of the stakeholders’ universe, there was no workshop at the completion of the project.

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Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR

1. In August 2014, the sponsor, BEL, issued a Project Completion Report comprising the following main components: a technical description of the project, a review of the project’s time schedule and compliance with contractual conditions, project final costs, implementation of the Social and Environmental Action Plan, plant production data, an assessment of significant risks, and outstanding legal conditions concerning the project. 2. Main findings and conclusions of the report are summarized here: • Ground conditions required two significant construction changes: (a) an extension of the embankment grout curtain on both abutments of the dam that added a cost of US$7.17 million to the onshore EPC contract and (b) a new reinforced concrete channel that extended 135 m beyond the original gated spillway structure. This work implied an onshore cost of US$20.5 million and 10 months’ time extension and an offshore cost of US$500,000. • Changes in ground conditions, including time extensions totaling 12.5 months, variances in the work from the tender, and some additional changes, led to an EPC cost increase of US$61.4 million, that is, around 10 percent of the agreed price. • At construction peak, over 3,000 people worked on the hydropower plant, both for the contractor and BEL. • The report considered that there were no major issues with impact on the environment. • Overall, the APRAP and CDAP were implemented as planned and largely achieved the intended objective of restoring and improving livelihoods of project-affected people. • BEL fully complied with NEMA’s project social and environmental approval conditions. Compliance was validated, among others, by annual environment audits and routine monitoring by the BEMC. • By August 2014, the power plant’s operation was satisfactory, after overcoming a set of first-year issues and reaching a cumulative availability of over 98.8 percent. • The report did not identify any significant risk factors that could affect the project’s operation. • The report makes reference to two outstanding legal actions concerning claims on damages and compensation sought by affected people.

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Annex 8. Comments of Co-financiers and Other Partners/Stakeholders

No comments received.

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Annex 9. List of Supporting Documents • African Development Bank. Independent Review Panel, Compliance Review Report on the Bujagali Hydropower and Interconnection Projects. 2008. • Bujagali Energy Limited. Annual Environmental Performance Report. March 2016. • Bujagali Energy Limited. Project Completion Report. August 2014. • Bujagali Energy Limited. Final Costs Report. November 2013. • Bujagali Energy Limited. Quarterly Construction Reports. • Bujagali Energy Limited Social and Environmental Monitoring Reports. • Bujagali Energy Limited. Operations Report in terms of Clause 20.5.5 of the Common Terms Agreement January 2015 to December 2015. • Burnside International Limited. Bujagali Hydropower Project – Social and Environmental Assessment. December 2006. • Colenco Power Engineering Ltd. Bujagali Hydropower Development - Uganda. Project Review and Assessment Report for the International Finance Corporation (IFC). July 2007. • Electricity Regulatory Authority. Annual Report, 2012–2013. • Electricity Regulatory Authority, Statistics. • Ernst and Young. Bujagali Energy Limited Final Costs Report. 2013. • Guarantee Agreement. December 21, 2007. • Harvard Business School. International Rivers Network and the Bujagali Dam Project (a). 9- 2-4-083. April 2005. • Implementation Agreement relating to the Bujagali Hydroelectric Project - Uganda. December 2005. • Indemnity Agreement. July 18, 2007. • Joint Lenders Bujagali Hydropower Project Aide Memoire of Supervision Missions 1 through 11. 2008–2015. • Power Planning Associated Ltd. Bujagali II - Economic and Financial Evaluation Study. February 2007. • Power Purchase Agreement relating to the Bujagali Hydroelectric Project - Uganda. December 2005. • Project Agreement. December 21, 2007. • Mac Cosgrove-Davies Lessons from Bujagali on Risk Management. 2013 • Uganda Electricity Transmission Company Limited. Bujagali Interconnection Project. Project Completion report. March 2016. Uganda Electricity Transmission Company Ltd. Annual Report 2013.

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• World Bank Inspection Panel. Investigation Report. Uganda: Private Power Generation (Bujagali) Project. Report No. 44977-UG. August 2008. • World Bank Inspection Panel. Investigation Report. Uganda: Third Power Project, Fourth Power Project and Bujagali Hydropower Project. Report No. 23998. May 2002. • World Bank Aide Memoire for the Project’s Supervision Missions, 205, 2007, and 2015. • World Bank. IEG Review of the (Cancelled) Bujagali Hydropower Project. Report No. ICRR 12388. February 2006. • World Bank Management Report and Recommendation in Response to the Inspection Panel Investigation Report. Uganda: Third Power Project, Fourth Power Project, and Bujagali Hydropower Project. Report No. 24272. July 2002. • World Bank Management Report and Recommendation in Response to the Inspection Panel Investigation Report. Uganda-Private Power Generation (Bujagali) Project. Report No. IDA/R2008-02296. November 2008. • World Bank Project Appraisal Document (PAD) for the Private Generation (Bujagali) Project in the Republic of Uganda. Report No. 3821-UG. April 2007. • World Bank Project Implementation Status Reports (ISRs) 1 through 8. 2007–2016. • World Bank Estimation of the Levelized Cost of Electricity. ICR team draft, September 2016. • World Bank. Ex-post Economic Analysis of the Bujagali Project. ICR team draft, October 2016. • World Bank: Seventh Progress Report on the Implementation of Management's Action Plan in Response to the Inspection Panel Investigation Report, Uganda Private Power Generation (Bujagali) Project, February 2018.

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Map

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