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1 Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized Document of The World Bank FOR OFFICIAL USE ONLY PROJECT PAPER ON A PROPOSED ADDITIONAL FINANCING GRANT IN THE AMOUNT OF SDR MILLION (US$283 MILLION EQUIVALENT) TO THE DEMOCRATIC REPUBLIC OF CONGO FOR THE REGIONAL AND DOMESTIC POWER MARKETS DEVELOPMENT PROJECT (SOUTHERN AFRICA POWER MARKET PROJECT: APL-1B) Energy Group Sustainable Development Department Africa Region Country Departments AFCC2 and AFCRI JUNE 1, 2011 Report No: ZR This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

2 CURRENCY EQUIVALENTS (Exchange Rate Effective April 30, 2011) Currency Unit = Congolese Franc Fc 963 = US$ 1 US$ = SDR 1 FISCAL YEAR January 1 December 31 AfDB ADF APL BCECO CAPP CATE CFAA CQS COPIREP DRC EIB EIRR EMRRP ESRP ESIA ESMF ESMP ESMU FIRR FM FMR GoG GoDRC GWh HIPC HV HVDC ABBREVIATIONS AND ACRONYMS African Development Bank African Development Fund Adaptable Program Loan Bureau Central de Coordination (Central Coordination Office) Central African Power Pool comprising DRC, Republic of Congo, Angola, Chad, Cameroon, Sao Tome and Principe, Gabon, Equatorial Guinea, and Central African Republic Cellule d Appui Technique à l Energie, the unit within the MoE responsible for providing guidance on sectoral strategies and project coordination Country Financial Accountability Assessment Selection based on Consultant Qualifications Comité de Pilotage de la Réforme des Entreprises Publiques, the Steering Committee for Public Enterprise reform Democratic Republic of Congo European Investment Bank Economic Internal Rate of Return The Emergency Multisector Reconstruction and Rehabilitation Project, approved by the Association s Board Environmental, Social and Resettlement Plan: the seven documents, dated December 2006, relating to environmental, social and resettlements aspects of the Project, namely: (i) the ESIA, (ii) ESMP, (iii) the ESMF, (iv) the RPF, (v) the MCHF, (vi) the ESIA Executive Summary (French), and (vii) the ESIA Executive Summary (English), as supplemented by (viii) the PMP. Etude d Impact Environnemental et Social (the Environmental and Social Impact Assessment), dated December 2006, prepared for the Project Cadre de Gestion Environnementale et Sociale (the Environmental and Social Management Framework), dated December 2006, prepared for the Project. Plan de Gestion Environnementale et Sociale (Environmental and Social Management Plan), dated December 2006, prepared for the Project. SNEL s Environmental and Social Management Unit Financial Internal Rate of Return Financial Management Financial Management Reports Government of Germany Government of DRC Gigawatt hours (of energy) Highly Indebted Poor Country High Voltage High voltage, direct current transmission line ii

3 ICB IDA International Competitive Bidding International Development Association IFC International Finance Corporation Inga 1 and 2 The two existing power plants located at the Inga site Inga 3 The proposed new hydroelectric plant at the Inga site IEM Inga Entomological Mission IRR Internal Rate of Return KfW LV Kreditanstalt für Wiederaufbau (German Development Bank) Low Voltage MCHF Cadre de Gestion du Patrimoine Culturel (the Management of Cultural Heritage Framework), dated December 2006, prepared for the Project. MIGA Multilateral Investment Guarantee Agency MoE Ministry of Energy of DRC MV Medium Voltage MW Megawatt NEPAD New Partnership for Africa s Development NPV Net Present Value O&M Owner s Engineer Operations and Maintenance The consulting firm providing engineering services to support tender execution and contract supervision under the Project PCB Polychlorinated Biphenyl PCU Project Coordination Unit PFM Agent The procurement and financial management agent (BCECO) employed by MoE under the Project PIU Project Implementation Unit (CDP under French acronym), located within SNEL PMP Plan de Gestion des Nuisances et Pesticides (Pest Management Plan), dated March 2007, related to the control of black flies in the Inga area QCBS QBS Quality and Cost Based Selection Quality Based Selection RAP RPF Resettlement Action Plan Cadre de Reinstallation Involontaire (Resettlement Policy Framework), dated December 2006, prepared for the Project SADC Southern African Development Community SAPMP SAPP SBD SNEL SOE SOEs SSS TA WDR WHO WTP The Southern African Power Market Program, approved by the Association s Board Southern African Power Pool, comprised of the following Operating and Non-Operating members: DRC, Botswana, South Africa, Namibia, Mozambique, Malawi, Lesotho, Swaziland, Angola, Zambia, Zimbabwe and Tanzania Standard Bidding Documents Société Nationale d Electricité, DRC s national power utility Statement of Expenditures State-Owned Enterprises Single Source Selection Technical Assistance World Development Report World Health Organization Willingness to pay Vice President: Obiageli K. Ezekwesili Country Directors: Yusupha B. Crookes and Marie-Françoise Marie-Nelly Sector Director Jamal Saghir Sector Manager: Subramaniam V. Iyer Task Team Leader: Philippe J-P. Durand iii

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5 DEMOCRATIC REPUBLIC OF CONGO Regional and Domestic Power Markets Development Project CONTENTS ADDITIONAL FINANCING DATA SHEET... vi I. Introduction... 1 II. Background and Rationale for Additional Financing... 3 A. Country Background... 3 B. DRC Electricity Sector Recovery and Development Strategy... 5 C. Project Background, Objectives and Scope D. Project Implementation, Status and Issues E. Rationale for Additional Financing III. Proposed Changes IV. Appraisal Summary A. Project Updated Economic and Financial Analysis Project B. Financial Analysis of SNEL C. Financial Management (FM), Reporting, Audit and Disbursement Arrangements D. Procurement E. Communication Strategy F. Safeguards G. Overall Risk Rating H. Conditions for additional financing Annex 1: Description of the Southern African Power Market Program Annex 2: The Southern African Power Market Project (SAPMP - APL1): Linkage with the PMEDE, Status of Implementation and Lessons of Procurement and Implementation Annex 3: Revised Results Framework and Monitoring Annex 4: Revised Project Description Annex 5: Revised Estimate of Project Costs Annex 6: Economic and Financial Analysis Annex 7: Financial Analysis of SNEL Annex 8: Enhancing SNEL s corporate governance and performance Annex 9: Implementation Support Plan Annex 10: Financial Management and Disbursement arrangements Annex 11: Procurement arrangements Annex 12: Safeguard Policy Issues iv

6 Annex 13: Operational Risk Assessment Framework (ORAF) Annex 14: Energy Efficiency and Load Management Program for DRC Annex 15: Communication Plan Annex 16: Project s Governance Framework Annex 17: Project Preparation and Appraisal Team Members MAPS IBRD & IBRD Table 1: SNEL Domestic Tariffs and Collection Rates by Customer Category... 7 Table 2: Implementation Challenges and Measures Table 3: Measures to Address Cost Overruns Table 4: Detailed Comparison of Initial Versus Revised Project Costs Table 5: PMEDE - Summary of Revised Costs and Financing Plan Table 6: Demand-Supply Balance in Energy (GWh) Baseline Scenario Table 7: Demand-Supply Balance in Capacity (MW) Baseline Scenario Table 8: Demand-Supply Balance in Energy (GWh) Low-Demand Scenario Table 9: Demand-Supply Balance in Capacity (MW) Low-Demand Scenario Table 10: Demand-Supply Balance in Energy (GWh) High-Demand Scenario Table 11: Demand-Supply Balance in Capacity (MW) High-Demand Scenario Table 12: Summary of Project Costs Used in the Economic Analysis Table 13: Willingness to Pay Table 14: Project Cost-Benefit Analysis Table 15: Economic Sensitivity Analysis Table 16: Project cash flow Table 17: Financial Sensitivity Analysis Table 18: SNEL Domestic Tariffs and Collection by Customer Category Table 19: SNEL Summary Cash flow statement and performance indicators Table 20: SNEL Summary Cash flow forecast Table 21: Implementation Risks, Strategies and Proposed Actions Table 22: Timeline Implementation Support Missions Table 23: Implementation Support Team Table 24: Updated Project Procurement Plan Table 25: Commitment and disbursement projections for IDA grant and the whole Project Table 26: Summary of Original Process of Environmental Assessment for the PMEDE Sub- Components Table 27: Civil Works Contracts and Safeguards Requirements March 2011 June PMEDE and PMEDE Additional Financing Table 28: Communication Plan Outline Table 29: Project Governance Framework Outline v

7 DEMOCRATIC REPUBLIC OF CONGO Regional and Domestic Power Markets Development Project ADDITIONAL FINANCING DATA SHEET Date: June 1, 2011 Country Director: Yusupha Crookes and Marie Françoise Marie Nelly Director: Jamal Saghir Sector Manager: Subramaniam V. Iyer Team Leader: Philippe Durand Project ID: P Expected Effectiveness Date: September 30, 2011 Lending Instrument: APL Additional Financing Type: Cost overrun & financing gap, Restructuring Project ID: P Basic Information - Additional Financing (AF) Project Name: Regional and Domestic Power Markets Development Project Sectors: Power Themes: Renewable energy, Regional integration, Utility strengthening Environmental category: B - Partial Assessment Expected Closing Date: June 30, 2016 Joint IFC: Joint Level: Basic Information - Original Project Environmental category: B - Partial Assessment Expected Closing Date: June 30, 2016 Lending Instrument: APL Joint IFC: Joint Level: AF Project Financing Data [ ] Loan [ ] Credit [X] Grant [ ] Guarantee [ ] Other: Proposed terms: AF Financing Plan (US$m) Source Total Amount (US $m) Total Project Cost: 429 Cofinancing: Borrower (SNEL) 26 KfW 88 AfDB 32 Total Bank Financing: 283 IBRD 0 IDA 283 New 283 Recommitted 0 Client Information vi

8 Recipient: Democratic Republic of Congo Responsible Agency: SNEL Contact Person: Jean-Pierre Saila Telephone No.: / Fax No.: AF Estimated Disbursements (Bank FY/US$m) FY Annual Cumulative Project Development Objective and Description Original project development objective: To improve operational efficiency in the electricity sector and expand generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration Revised project development objective: To improve operational efficiency in the electricity sector and expand renewable generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration Project description: The Project consists of five main components: (a) Generation - rehabilitation of Inga 1 and Inga 2 hydropower stations and intake canal (US$ million additional financing); (b) Transmission - construction of a new 400 kv transmission line from Inga to Kinshasa (no additional financing); (c) Distributionrehabilitation, reinforcement and expansion of the power distribution system in Kinshasa (US$ million additional financing); (d) Capacity building - strengthening of SNEL s operational capabilities including activities regarding utility governance and in the sector generally (US$ 20.1 million additional financing); and (e) Project Implementation provision of consulting services for engineering, management and supervision of implementation, procurement and financial management services (US$ 7 million additional financing). Safeguard and Exception to Policies Safeguard policies triggered: Environmental Assessment (OP/BP 4.01) [X]Yes [ ] No Natural Habitats (OP/BP 4.04) [ ]Yes [X] No Forests (OP/BP 4.36) [ ]Yes [X] No Pest Management (OP 4.09) [X]Yes [ ] No Physical Cultural Resources (OP/BP 4.11) [X]Yes [ ] No Indigenous Peoples (OP/BP 4.10) [ ]Yes [X] No Involuntary Resettlement (OP/BP 4.12) [X]Yes [ ] No Safety of Dams (OP/BP 4.37) [X]Yes [ ] No Projects on International Waters (OP/BP 7.50) [X]Yes [ ] No Projects in Disputed Areas (OP/BP 7.60) [ ]Yes [X] No Does the project require any exceptions from Bank policies? vii [X]Yes [ ] No

9 Have these been approved by Bank management? [ ]Yes [ ] No Financing Agreement (FA) / Project Agreement Amendment (PA) Reference FA (a) FA (b) FA Schedule 2, Section I, C,1 FA Schedule 2, Section I, F,3 Conditions and Legal Covenants: Description of Condition/Covenant Amendment of the existing Subsidiary Agreement between SNEL and the GoDRC The Project Implementing Entity has revised the EPP in form and substance satisfactory to the Association and has thereafter disclosed it to the general public. The Recipient shall carry out the Project and/or cause the project to be carried out in accordance with the Project Implementation Manual (PIM), which shall be updated by not later than three (3) months following the Effective Date SNEL s new Board is appointed Effectiveness Effectiveness Date Due Not later than three months following effectiveness December 31, 2011 FA Schedule 2, Section I, F,2 PA Section 4, 2 FA Schedule 2, Section II, B4(a) FA Schedule 2, Section II, B4(b) Signature of SNEL performance contract between SNEL and the State Opening and provisioning of dedicated account for Inga O&M Revision of the ToR of the International Internal Auditor to include the additional financing and to support gradual transfer of internal audit responsibility to SNEL Revision of ToR of external auditors of project accounts to include the additional financing viii March 31, 2012 December 31, 2011 Not later than three months following effectiveness Not later than three months following effectiveness

10 PA Section IV, 1 PA Section V, 1 FA Schedule 2 Section I F5 FA Schedule 2 Section IV B1(a) The Project Implementing Entity shall employ, not later than October 1, 2011, a consultant, selected in accordance with the provisions of Section III of the Schedule to this Agreement, for: (i) the design of operation and maintenance services for the Project, and (ii) the determination, on a quarterly basis, of the funding requirements to perform the operation and maintenance of the Project Implementing Entity s assets and facilities at the Inga hydroelectric site throughout the implementation of the Project. Appointment of two internal auditors (technical and financial) of the SNEL internal audit department to the PMEDE Project Signing of SNEL s TA services contract No withdrawal shall be made for payments made prior to the date of this Agreement, except that withdrawals may be made for payments not exceeding US$ 200,000 made prior to this date but on or after September 1, 2010, for Eligible Expenditures. October 31, 2011 Not later than three months following effectiveness March 31, 2012 ix

11 I. Introduction 1. The Regional and Domestic Markets Development Project (PMEDE, APL1b, P097201/P114782, Grant H-296-DRC) was one of the first regional energy projects supported by the Bank in the Africa region. With its intended scope to increase electricity supply from Inga hydropower plants to consumers in Kinshasa and the Katanga region of DRC and for exports to the Southern African Power Pool (SAPP) along with its companion project the Southern African Power Market Project (SAPMP, P069258) which is focused on transmission reinforcement - the Project set out to increase energy supply to meet both domestic and regional electricity demand. Hydro-power constitutes an enormous renewable energy potential for the Africa region, where installed capacity is limited to 74 GW and 31% of the overall population has access to electricity. The Inga Hydro Site on the Congo River alone has 45 GW of hydro generation capacity potential. Indeed, this resource can have transformative impact by significantly increasing household access to electricity in the sub-region and by displacing carbon-emitting thermal generation as a central part in the continent s climate change agenda. This is why the Government of the DRC and the World Bank agreed back in 2007 to embark on rehabilitating and upgrading the power system at Inga, as part of a series of regional projects under a horizontal APL, the Southern African Power Market Program (SAMP). 2. The PMEDE Project costs were originally estimated at US$499 million, of which IDA is financing US$297 million. A total US$157 million was financed by EIB, AfDB and DRC s electric utility (SNEL), and there was a financing gap of U$45 million, which is addressed under the proposed additional financing. Revised costs of the project are now estimated at US$883 million, resulting in a total financing gap of US$429 million (including the initial financing gap of US$45 million). IDA has been requested to increase its financing by US$283 million, corresponding to the increase in the components originally financed by IDA, plus part of the financing gap. The remaining gap of US$146 million will be financed by AfDB, KfW and SNEL. AfDB financing of the equivalent of US$32 million was approved in December 2010 and effectiveness is expected by July KfW credit committee has approved a first financing of the equivalent of US$54 million, which is pending Government of Germany confirmation expected in July 2011; KfW indicated it intends to process in 2012 a second financing of the equivalent of about US$34 million. SNEL is financing the remaining US$26 million. 3. The increase in cost is due to (i) underestimation of costs at appraisal; (ii) cost escalation due to market factors; and (iii) addition of new activities within existing components. 4. Underestimation of Project costs at appraisal is due to the fact that Inga s generating units were found by SNEL and the Owner s Engineer to be in worse condition following detailed assessment and several components of Inga s generating units originally identified for repair needed instead replacement using new components. Cost escalation also results from unanticipated increase in commodity prices that have significantly pushed up the cost of power plant equipment worldwide and a weak appetite for the DRC market among equipment suppliers and contractors resulting in few bidders. New activities include expansion of the distribution component as well as measures to enhance SNEL s operational and financial performances, such as a performance and technical assistance contract, an Inga maintenance program, an energy efficiency and demand-side management program, and a communication program. 1

12 5. Since approval of the PMEDE Project in 2007, a gradually constructive dialogue has been established between the Government of the DRC and the World Bank on sector reforms, notably in the areas of improving the governance and sustainability of the sector. This dialogue is reflected in the proposed additional financing s allocation of funds to step up efforts to improve SNEL s corporate governance, as well as its financial and operational performance. 6. This Project Paper seeks the approval of the Executive Directors to provide an additional grant in an amount of US$283 million equivalent to the DRC for the PMEDE Project to cover increases in costs due to under-estimation of costs at appraisal, price escalation, expansion of components, and unanticipated additional works on degraded energy facilities. The Project Paper also seeks approval for formal restructuring of the Project for the following changes: Modification of the Project Development Objectives (PDO) to better reflect the renewable energy dimension of the operation. The re-stated PDO which provides greater clarity with respect to the contribution to renewable energy in the Project s achievable goals is to improve operational efficiency in the electricity sector and expand renewable generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration. Extension of the Grant s Closing Date to enable completion of Project implementation from June 31, 2013 to June 30, Increase in the scope of the distribution component to alleviate congestion and increase domestic power supply, particularly in Kinshasa. Changes in the results framework, including mainly new indicators and targets to reflect the new Project implementation schedule, project restructuring and to capture additional focus on corporate governance 7. Based on revised project costs, about 90% of the proposed additional financing will cover increased cost of power generation and distribution equipment while the rest will be allocated to support improvement in SNEL s corporate governance and its operational and financial performance, and to support project execution. 8. The implementation experience of this operation, along with the SAPMP, has generated important lessons for the region, the sector and for projects in post-conflict and fragile settings, which have been incorporated in the proposed additional financing. These include (i) the need for more robust assessments to underpin cost estimates, including better assessments of conflictrelated damages; (ii) the need for larger contingency amounts to take into account uncertainties in the supplier market; (iii) realistic assessment of market interest when preparing bid documents and increased consultation with firms at pre-bid conferences; and (iv) longer implementation periods for projects in post-conflict situations to take into account risk of frequent change in sector leadership and institutional arrangements that necessitate greater Bank supervision. 2

13 9. The environment surrounding this project and its proposed additional financing will continue to remain challenging with respect to governance, reform, and implementation issues. Yet, the pivotal role of this project in domestic electrification services and positioning the region and even the entire Africa for competitiveness and growth through more reliable and climate friendly energy solutions warrants taking on the risks associated with this operation. This approach is well aligned with the foundation and the key objectives of the World Bank Group (WBG) new Africa Strategy, in particular the growth pillar and the governance foundation. It is also consistent with the 2011 World Development Report (WDR) recommendation of a carefully calculated step by step approach in fragile countries and development contexts, whereby implementing pragmatic, best-fit measures to institutions and governance tailored on the local political context in the short-term is needed to restore confidence in the country institutions and pave the way for effective results in the long term. Under these conditions, incremental progress in sector performance will be made possible through continued support of this Project and the other operations under the APL, as well as the renewed Government commitment to reform of SNEL under a phased approach. Finally, the project is fully aligned with the 2007 Country Assistance Strategy, in particular its pillars for promotion of good governace and for achievement of sustained and shared economic growth through infrastructure rehabilitation and expansion. 10. The additional financing is needed at this time since signed contracts under the project are expected to exceed available financing by September In the absence of the additional financing, the PMEDE PDOs could not be achieved and there would be serious impacts on the DRC economy as well as on regional integration prospects supported under the SAPMP project. II. Background and Rationale for Additional Financing A. Country Background 11. The DRC s size, resources, and location impact all of Central Africa and beyond. With an estimated population of about 66 million, vast natural resources, and massive agricultural potential, DRC is the second largest country in Sub-Saharan Africa and can potentially be a major player in Africa s future. DRC s development trajectory can have a significant impact on the economic growth and political stability of the continent. DRC borders nine countries in Central and Southern Africa, and has complex economic, migration, and political relations with each of them. With its vast, untapped hydropower resources, DRC holds the key to the continent s energy solutions in the form of clean, renewable and affordable power. 12. The civil war led to a rapid descent from relative prosperity during DRC s prosperity was primarily driven by copper and other commodity exports industry, which proved unsustainable when copper prices collapsed in the mid 1970s. Poor development and management of the mining sector, coupled with weak corporate and public institutions could not absorb the commodity-price shock and led to a catastrophic failure. Infrastructure collapsed, and today only four provincial capital cities can be reached by road from the national capital, Kinshasa. Furthermore, the conflict has affected existing assets through lack of maintenance and investment, creating even more serious service failures. 3

14 13. Post civil war DRC saw a resumption of growth. The end of the war coincided with a recovery in mining prices on international markets. Mines that were closed as a result of nationalization and war were reopened as part of joint ventures with international partners. The increase in mining production generated demand for transport and security services, as well as the financing of trade and construction projects. Owing to rapid development in the mining, construction and transportation sectors, which all experienced double digit annual growth rates, DRC experienced an average annual GDP growth of 6.6 percent during the period, compared to -5.2 percent over the period. This period of growth was interrupted in late 2008 as a consequence of the changing international environment resulting from the financial crisis. 14. The financial crisis of 2008/09 interrupted but did not derail a macroeconomic recovery. Inflation picked up in the wake of the crisis but was reduced to below 10 percent in 2010 thanks to a tightening of fiscal policy. The overall fiscal balance turned to a surplus in 2010 but a deficit is projected for 2011 due to increased expenditure in the public investment program. The current account balance improved in 2010 as exports volumes increased and the terms of trade improved in the wake of rising commodity prices. The favorable international economic conditions allow for a continued accumulation of reserves, up from US$1 billion in 2009, to US$1.3 billion in 2010 to a projected US$1.5 billion at the end of Poverty remains pervasive and poverty indicators remain low even by regional standards. In 2010, annual GDP per capita was about $300. About 75 percent of the population lives on less than a dollar a day. Widespread poverty exists as a result of conflict, poor governance, weak policies and insufficient investments. Health implications of this poverty are serious. Underfive child mortality rate is at approximately 15 percent. Less than a quarter of the population has access to safe drinking water, and less than a tenth of the population has access to reliable electricity. However, there are indications that poverty outcomes have been improving in recent years. Maternal deaths from childbirth declined from more than 1 percent of live births in 2001 to less than 0.6 percent in Primary school enrollment rates increased from 64 percent in 2005 to 71 percent in Women remain disadvantaged relative to men, but the inequity is gradually declining. Rapid growth in agricultural production during recent years may have contributed to these favorable outcomes; agriculture creates income-generating opportunities for the poor, and importantly it also reduces food prices, which dominate the low-income consumption basket. 16. In addition to impoverishing the population the war did lasting damage to DRC s institutions. Political support for institutions evaporated as elites became fragmented. Distrust for institutions increased in parallel with threat of force in reaching and adhering to agreements. This situation has led to poor governance affecting all institutions to the detriment of service delivery and economic development. 17. Improved governance is essential for DRC to address persistent poverty and threats to sustainable economic growth. Some governance issues were addressed in the context of HIPC debt relief, including appropriate macroeconomic policies supported by an IMF program and the adoption and implementation of a new Public Procurement Code. With strong support from the President, fragmented elites coalesced to deliver the HIPC/MDRI debt relief in early July

15 However, immediately after the HIPC/MDRI Completion Point, the reform momentum required significant Bank staff attention. The World Bank recent dialogue with the authorities in DRC has focused on the seriousness of weak governance, especially with regard to (i) strengthening accountability and transparency in concession and contract management in the mining, forestry, and oil sectors; (ii) ensuring that divestiture of assets of public enterprises is done in compliance with international best practices; and (iii) ensuring transparent and efficient use of public resources. In this regard, a series of measures have been agreed upon with the Government in 2010 and are under implementation, which should help increase State benefits from natural resource exploitation, and improve legal certainty of the business environment. 18. Poor governance also affects state-owned enterprises and their ability to provide services and maintain financial and operational viability. In this regard, the Government presented in 2007 a Governance Compact targeting three sector specific governance priorities: (i) reform of State Owned Enterprises; (ii) Mining Sector Reform; and (iii) Security Sector Reform; in addition to four cross cutting priorities: (i) Transparency; (ii) Decentralization; (iii) Public Financial Management; and (iv) Public Service Reform. SNEL is included in this Compact with the principle aim of improving its corporate governance. Annex 8 outlines actions that the current project is supporting in this regard, notably a performance contract between the State and SNEL. Implementation of governance issues in the sector will be closely monitored during supervision, engaging senior officials as needed. B. DRC Electricity Sector Recovery and Development Strategy 19. DRC has enormous hydropower potential 1. The 4,320 km long Congo River, which alone accounts for some 38 per cent of the continent s discharge into the oceans ranks second only to South America s Amazon River in terms of discharge and size of drainage basin. The Congo River basin alone holds almost 30 per cent of Africa s total fresh surface water reserves and the world s largest hydropower potential in any one single river basin. The greatest source of hydroelectric potential is the Inga rapids on the Congo River. With a potential hydropower output estimated at 774 TWh per annum, the DRC stands third behind China and Russia. When expressed as firm power capacity, the Congo River potential is equivalent to 100,000 MW or 13 percent of global hydropower potential. About 40% of this potential is located at the Inga site at an estimated potential capacity of 45,000 MW. With energy resources on this scale, DRC has the potential to play a pivotal role in meeting not only its future domestic energy needs for poverty reduction and economic development, but also the energy needs at the regional and continental levels. 20. Hydropower plays both mitigation and adaptation roles in addressing climate change. Avoided Grenhouse Gas (GHG) emissions through hydropower can be significant, particularly in Africa and specifically in DRC where forest resources are used for fuel. Increasing the share of hydropower in the energy generation portfolio in DRC or the region, can reduce CO2 emissions significantly by displacing other high carbon generation. In the Africa Region, increasing the share of hydropower through regional trade could save up to 70 million tonnes per year of CO2 emissions. At today s carbon prices, viable hydropower share can potentially increase by 50 1 See Appendix 1 Annex 4 for a detailed description of the Inga site. 5

16 percent. Increased generation at Inga site through rehabilitation of Inga 1 and 2 (this project) and in the future through Inga 3 and Grand Inga, will not only have low lifecycle GHG emissions, but could account for the majority of sub-saharan annual CO2 emissions reduction potential. Additionally, hydropower can help mitigate the local environmental problems associated with inefficient and polluting sources of energy (such as small diesel power generators) and add to the reliability and resiliency of power systems within DRC and the regional power pools. 21. This hydropower potential remains mostly untapped with serious household electricity access and development implications. Today, only a total installed power generating capacity of about 2,100 MW is in place in the Inga 1 and Inga 2 and other smaller hydropower stations, including those in the Katanga Province, of which less than half the capacity is operable. Lack of sufficient transmission and distribution capacity means that the vast majority of DRC s population and its economy are under-served. At about 9 percent, household access to electricity services is particularly low compared to the average of Sub-Saharan countries access rate of 31 percent. Power outages averaging more than three hours in length are experienced more than 180 days per year. As a result, firms are frequently forced to rely on expensive back-up generators. The economic cost of these outages can be conservatively estimated at 1.7 percent of GDP (AICD study, 2009). Under the current condition of its energy sector, DRC is neither able to benefit its citizens with low-cost reliable power access, nor export electricity in a region where demand far outstrips supply. One of the country s most immediate infrastructure challenges therefore is to reform the power sector, restore the financial health and operational efficiency of the power utility, rehabilitate and invest in its power assets and improve electricity access. 22. With appropriate development of the Inga site, DRC could potentially play a pivotal role in meeting both its domestic electricity needs and that of Southern Africa. Power supplied from DRC can be a critical factor for the development of a competitive power market in the region, with reliable low cost and low-carbon power supporting agricultural and industrial competitiveness, private sector investment, and regional growth and development. It also potentially represents an important source of foreign exchange and foreign direct investment for the country (see box). Inga 1 and Inga 2 rehabilitation to full capacity would open the way for the future development paths currently under discussion: Inga 3 with potential installed capacity of about 4,000 MW and Grand Inga with potential installed capacity of about 40,000 MW. The benefits of regional power trade Some 21 African countries are simply too small to generate power cost-effectively. If pursued to its full economic potential, regional trade would reduce around $0.01 per kilowatt-hour from the marginal cost of power generation in each of the power pools. The overall potential savings amount to around $2 billion a year in the costs of power system development and operation (equivalent to about 5 percent of total power system costs). Regional power trade also puts Africa on a cleaner development path in terms of carbon emissions. It would allow the share of hydropower in the continent s generation portfolio to increase from 36 percent to 48 percent, displacing 20,000 mega-watts of thermal plant in the process and saving 70 million tons a year of carbon emissions (8 percent of Sub-Saharan Africa s anticipated emissions through 2015). The future of power trade depends on the health of the power sector in a handful of key 6

17 exporting countries, endowed with exceptionally large and low-cost hydropower resources. DRC is one such country with the potential to become Africa s largest exporter of hydropower with significant economic returns. DRC currently exports slightly over 400 Gigawatt-hours of electricity annually into the Southern Africa Power Pool, which represents about 6 percent of current production. However, if the Inga site were fully developed, DRC could export more than 50,000 Gigawatt-hours annually. Net revenues could amount to more than US$500 million per year. Revenues from electricity exports through long term contracts, unlike revenues from other natural resource exports, are stable and are not prone to cyclical price movements. Source: AICD, World Bank internal documents 23. However, unleashing DRC transformational hydropower potential will require progress on the institutional front. The national utility SNEL faces major operational and financial challenges. Due to very high technical and commercial losses and low collection rates, SNEL recovers revenue for slightly over 1 kwh out of every 2 kwh produced. These inefficiencies absorb as much as 4 percent of GDP. 24. Overall, average domestic electricity tariffs remain very low at levels that are sufficient to cover current operating costs, but not the cost of capital. Domestic electricity tariffs are highly distorted; especially with regard to residential tariffs which are extremely low because of the lack of adjustment for local inflation and currency depreciation until 2009 (other tariff categories were regularly adjusted for the depreciation of the Congolese Franc against the US dollar). The distortions are aggravated by the difference in collection rates between customer categories. Overall, low voltage residential users account for more than 40% of domestic sales (in energy volume) but only 13% of the revenue actually collected by SNEL. Commercial users as a whole (including HV, MV and LV) consume a similar proportion of total domestic energy supply but provide SNEL with 6 times more revenue. Payment rate by parastatals is extremely low and has not improved since Payment rate by the GoDRC has improved in 2009/2010 although as a result of budget support from the World Bank and AfDB. Table 1 provides details on domestic tariffs and collection rates by customer category. Table 1: SNEL Domestic Tariffs and Collection Rates by Customer Category Sales in Volume Share of energy consumpt. GWh % Average price US cents/kwh Sales in Collection Value rate US$ million % Collection US$ million Share of Average revenue revenue collected US cents/kwh % Government 330 6% % % Parastatals % % % LV residential 2,417 43% % % LV commercial 210 4% % % MV private % % % HV private 1,430 25% % % 7

18 Total 5, % % % Sub-total commercial users 2,237 40% % % Source SNEL s commercial statistics Draft annual report During the course of year 2009, the GoDRC implemented the first stage of a phased tariff adjustment towards better aligning tariffs with costs. At the end of the four-stage process, LV residential tariffs would be around 8 US cents/kwh in average (with a lower 4 US cents/kwh tariff for the poorest users). Even without major tariff adjustment, the potential for increasing total revenue with improved collection is huge. Better payment discipline would also help redirect electricity consumption towards productive uses. 26. In recent years SNEL has improved its operational and financial performance but it still has a long way to go. Between 2006 and 2010, SNEL managed to improve its revenue collected by 88% to US$216 million. This improvement was driven in part by higher average electricity tariff, and in part by an improvement in the collection rate (from 54% to 68% over the same period). The improvement in collection has been particularly significant for exports (collection rate of 93% in 2010, recovering from levels between 40-70% over the period). Despite these improvements, collection from government remains a major problem. The ratio of customers per employee (which was just over 60 in 2010) is still very low for utility standards, and as a result of overstaffing and low collection ratios, salary costs currently represent almost one third of total SNEL revenues. 27. There is an important link between the challenges described above and the DRC s hopes to attract greater private sector participation. For private investors (other than perhaps for enclave mining projects), the sector s creditworthiness is a critical concern. At the moment, the sector and SNEL are not creditworthy counterparts for private investors: for several years, SNEL experienced widespread collections difficulties resulting in significant payment problems and arrears to suppliers and in tax payments (see Annex 7 for further discussion on SNEL s arrears). Improving these functions at the public utility SNEL will be a crucial first step toward attracting private investors. 28. The 2007 Poverty Reduction Strategy Paper (PRSP) recognized the economic and social development constraints imposed by the power sector, and the important role that a wellfunctioning electricity sector can play in poverty reduction. It also highlighted regional power trade opportunities and their contribution to regional political stability. Recent World Bank Economic and Sector Work Infrastructure Prioritization: A Spatial Approach identified power sector investments in the rehabilitation of the Inga site and associated transmission lines as providing by far the highest return of any single infrastructure investment in DRC. The magnitude of the returns was attributable to the substantial reduction in power costs and improvement in reliability that would be experienced across a range of users from households to large industries. These results indicate that improvements in power supply can have a transformational impact on the local economy, with important implications for employment and poverty reduction. 8

19 29. Availability and reliability of electricity supply at affordable prices plays a key role in generating broad-based growth. It is particularly critical for small and medium-size enterprises for which back-up generation imposes crippling cost. The 2006 Investment Climate Assessment for DRC found that at 47 percent of enterprises surveyed ranked electricity as the most severe constraint, followed by access to finance (13 percent). To date, small and medium-sized enterprises only employ about 200,000 people, less than 1 percent of the workforce, and SME employment has barely grown between 2006 and 2010 despite increasing security and overall economic growth. Activities with important SME potential (such as post harvest agricultural processing) have not picked up to a significant degree. Ensuring reliable access to competitively priced electricity is thus one critical factor in accelerating growth in employment intensive activities and in creating greater opportunities including for women in stable employment, and thereby begin to reduce poverty rates on a broader and diversified basis. 30. Finally, there is a close link between power availability and the achievement of the Millennium Development Goals (MDGs). Without access to modern and sustainable energy services, the poor are deprived of opportunities to improve their living standards. This is because modern energy services are indispensable to increasing productivity, creating enterprises, employment and incomes, and providing effective public services such as health, education and safe water. PMEDE is a first step towards unleashing the power sector potential which would help achieve larger benefits. 31. The Government articulated an electricity strategy in 2009 to address the objectives of development of hydropower potential, regional power trade, national energy access, SNEL reform, private participation and security of supply. Elements of the new strategy include: A new legal framework to facilitate reorganization and regulation of the sector: a draft Electricity Law is under consideration that would significantly and positively reorganize the power sector, by establishing an Electrification Agency and an Electrification Fund, as well as an Electricity Sector Regulator. The draft legislation, which has been submitted to Parliament, would also allow private participation in the sector and provide a legal framework for that participation. Parliament is expected to take up the draft in mid SNEL reform is proceeding under the approved SOE reform law. SNEL has been corporatized as of December 2010, with new statutes and ongoing financial restructuring. The promotion of public-private partnerships (PPPs) The government is pursuing potential private participation in the rehabilitation of Inga and in other electricity projects in the country. A legal review of private sector proposals for various power sector investments has been completed and a framework with guidelines for PPP investments is under preparation with support from an international law firm 2. A strategy of electricity access for poverty reduction radiating from growth poles. The GoDRC access strategy uses a growth pole approach a geospatial approach consistent 2 Development of an appropriate legal and regulatory framework for PPPs is also supported under a separate World Bank financed competitiveness Project. 9

20 with the overall spatial paradigm used for infrastructure prioritization in DRC. This approach aims first to tackle the access deficit in cities and large towns with underdeveloped economic potential, and second to encourage decentralized access in deep rural areas. In cities and large towns there are sufficient numbers of commercial, industry and households with the willingness to pay for access to reliable electricity, and which would contribute to employment generation and economic growth. Given the logistical and cost challenges of transporting liquid fuels, low-head (run of river) hydro or biomass (associated with the timber industry) are the likely least cost sources of most new generation in secondary towns and cities. 32. Power sector restructuring should be gradual and implemented in parallel with SNEL financial and operational recovery. Given the size of the power sytem (even with modest access increase and electricity demand growth), as well as the considerable geographical extent of the country, both functional and geographical unbundling of SNEL has merit in the medium term. Private participation in SNEL successor entities could be in various forms, ranging from contracting of some services to the private sector to outright divestiture of some business units such as electricity distribution. It is likely to take several years for the necessary consultations and forming of consensus and then to effect the policy and institutional reforms that will determine the eventual role of SNEL and its successor entities. Considering the present technical, managerial and governance weakness and fragility of the power sector, the implementation of the reform program will have to be implemented with care to avoid a collapse of the power sector. Transition strategies that allow incremental progress towards the eventual unbundling and private sector participation in the various businesses of SNEL will be required. International experience shows that sector reform is a long process which needs to be carefully designed and sequenced taking into account risks of reversal and political economy. This is even more the case in post-conflict and fragile countries. 33. In 2009, the Government, through the Public Enterprise Reform Steering Committee (COPIREP) undertook the preparation of private management contracts for SNEL and the water utility (Regideso), together with their corporatization and financial restructuring. This was the logical option for enhancing the operational performance of these utilities and the prospects for private participation and investment in the medium to long term. However in view of lack of interest of private operators for the Regideso management contract (which faces similar constraints to SNEL s), COPIREP opted for alternative arrangements. In the case of SNEL, these arrangements include an audited performance contract between the Government and SNEL, together with a TA service contract, finalization of SNEL corporatization and restructuring, and a corporate governance program. 34. In the short term, these measures are deemed the most realistic and feasible way to more effectively address the performance problems in the sectors and to lay the groundwork for further restructuring of SNEL with increased private participation and investment in the sector. The Government has demonstrated commitment to this path as evidenced by key steps taken such corporatization of SNEL, preparation of the new electricity law opening the sector up for private sector participation, as well as inclusion of SNEL in the Governance Compact referred to earlier. Three dated covenants in support of sector reform are proposed in the operation. 10

21 Appointment of SNEL s new Board (by December 31, 2011). Signature of SNEL performance contract between SNEL and the Government (by March 31, 2012). Signature of SNEL s TA services agreement with a consulting firm (by March 31, 2012). C. Project Background, Objectives and Scope 35. The PMEDE Project forms part of a three-phase Southern African Power Market Program on which the Bank and the Southern Africa Development Community (SADC) reached an understanding as the basis for development of the integrated Southern African Power Pool (SAPP). The Pool comprises power systems of twelve countries in Southern Africa 3. Together, the PMEDE and its companion project the SAPMP, are among the first major efforts by the Bank at promoting regional integration of power systems, based on the rehabilitation of clean, renewable hydropower plants and support of regional interconnections and electricity trade. The SAPMP (APL1) aims at improving electricity trading in the SAPP and increasing security of the SAPP system. Together with the PMEDE (APL1b), it will also make significant blocks of hydropower from the Inga hydropower complex in the DRC available to the SAPP, and thus reduce the role of thermal power generation in the region. 36. Following the Inga projects, the Bank and development partners have supported the interconnection between Malawi and Mozambique (APL2). Political issues unrelated to the Project caused this project to be canceled 3 years after it was approved by the Bank. However, the high capacity interconnection project between Mozambique and South Africa to enhance transmission capability and boost development of hydropower in Mozambique is proceeding. The Bank and other development partners are well advanced in its preparation as they explore an innovative PPP structure for its financing. Other regional transmission projects are under development in Zambia and Tanzania (APL3). Annex 1 provides further details on the SAPP design, while Annex 2 outlines the implementation status of the SAPMP Project and its links with the PMEDE Project. 37. The Bank approved an IDA Grant to DRC of US$296.7 million equivalent in May 2007 for the PMEDE. Its development objectives are to improve the operational efficiency in DRC electricity sector and expand generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration. The Project consists of five main components: (i) Generation - rehabilitation of Inga 1 and Inga 2 hydropower stations; (ii) Transmission - construction of a new 400 kv transmission line from Inga to Kinshasa; (iii) Distribution- rehabilitation, reinforcement and expansion of the power distribution system in Kinshasa; (iv) Capacity building - strengthening SNEL s operational capabilities including activities regarding the governance within the utility specifically and in the sector generally; and (v) Project Implementation provision of consulting services for engineering, management and supervision of implementation, procurement and financial 3 Angola, Botswana, Lesotho, Malawi, Mozambique, Namibia, South Africa, Swaziland, Zambia, Zimbabwe, Tanzania and DRC 11

22 management services. The PMEDE Project provides the required resources to develop the Government s goal of improving the governance of the sector and of SNEL s performance. Part of the benefits of the Project would only be realized if the SAPMP Project is properly executed and proceeds in tandem. A detailed description of the PMEDE project is included in Annex Component 1 (Generation) of the Project entails the rehabilitation of some of the generating units at the Inga 1 plant (4 out of 6 units, plus repair of one unit) and at the Inga 2 plant (4 out of 8 units), to make available about 1,300 MW of reliable production at the end of the rehabilitation program by Rehabilitation works are expected to increase the life span of rehabilitated units by an additional 30 years. A program for effective maintenance of Inga facilities will be designed under the Project and implemented with SNEL resources. The rehabilitation program also provides for investments in the Inga intake canal dredging and reprofiling to enhance production capacity at Inga. The water carrying capacity of the intake canal is currently sufficient for only about half of the installed capacity of Inga 1 and 2 plants. This represents the first phase of the rehabilitation. A further second phase of the program would in the future tackle the rehabilitation of the remaining 6 units. The revised Inga 1 and 2 rehabilitation strategy is summarized in Appendix 2, Annex The Project had significant cofinancing from partners in the total amount of US$157 million. These funds were contributed by the European Investment Bank (EIB), the African Development Bank (AfDB) and SNEL. Cofinancing for the Project, approved by AfDB and EIB in 2007 and 2008 respectively, is focused on key elements of the Project, including the second transmission line Inga-Kinshasa, the associated substation, and a household electricity access expansion program, as well as a contribution to Inga rehabilitation works. The co-financed components are seriously delayed, since the conditions for disbursement of both EIB and AfDB financing were only met in May 2011 with the completion and disclosure of the Resettlement Action Plan (RAP) for the second Inga-Kinshasa transmission line and substations, together with an amendment of AfDB financing agreement that was approved on April 29, Subsequently, a US$54 million KfW cofinancing towards rehabilitation of one unit of Inga-2 was approved in November 2010 and is pending confirmation by the Government of Germany. KfW has confirmed its intent to appraise in 2012 an additional financing for a second unit at Inga 2 under the Project. Procurement is yet to start under the KfW financing. In December 2010, AfDB also approved a $32 million equivalent additional financing for the PMEDE distribution component. EIB and KfW financing are on a loan basis, although on concessionary terms as per IMF definition, while AfDB financing is on a grant basis. 40. A Project Implementation Unit (PIU) has been established within SNEL to implement both the PMEDE and SAPMP Projects. The PIU is properly staffed, equipped and organized, with procedures and guidelines spelled out in a detailed Project Implementation Manual. SNEL has recruited an Owner s Engineer to support works design, tendering and implementation supervision. The PIU also draws on technical, legal and financial management expertise within SNEL s various departments, including: (i) operation and maintenance of Inga 1 and 2 facilities; (ii) transmission network, including the Inga/Kinshasa corridor addressed under the Project; (iii) distribution network in Kinshasa; and (iv) commercial operations in the Kinshasa area. SNEL has also established an Environmental and Social Management Unit (UGES), currently 12

23 consisting of five environmental staff and three social staff, with adequate organization, logistics and resources. 41. A Project Coordination Unit (PCU) is responsible for coordinating and monitoring implementation of the Project. The Project Coordination Unit (PCU) comprises staff from the Ministry of Energy (MoE), SNEL, the Ministry of Finance and COPIREP. The PCU is supported by the MoE s Cellule Technique d Appui à l Energie (CATE) which acts as its technical secretariat. The PCU has recruited an independent consultant as internal auditor for the Project. To substantially reduce the fiduciary risks, a Procurement and Financial Management (PFM) Agent, BCECO, has been engaged by MoE to carry out the procurement and financial management functions for the Project. 42. The Steering Committee for Public Enterprise Reform (COPIREP) implements the Project component to place SNEL under a performance contract, with a TA services agreement, and will finalize the transformation of SNEL into a limited liability company. The following diagram captures the implementation arrangements. MoE (CATE) Monitoring and Evaluation Sector Reform PCU COPIREP PIU Procurement and Financial Mng SNEL BCECO Owner s Engineer Safeguards SNEL (UGES) PMEDE and SAPMP PCU = Project Coordination Unit (staff from MoE, SNEL, MoF, COPIREP and CATE) PMU = Project Management Unit CATE = MoE Technical Secretariat D. Project Implementation, Status and Issues 43. The PMEDE Project has been plagued by delays and implementation problems from the very beginning. Though IDA financing for the Project received Board approval on May 29, 2007, it became effective only on April 2, 2008 after the Government complied with an effectiveness condition related to project fiduciary aspects. Implementation of Project activities 13

24 is now two years behind schedule and will not be completed by the current grant closing date of June 30, Several factors have contributed to the implementation challenge of this Project and the resulting delays. It is a technically complex Project implemented in a country and sector with particularly challenging political economy, a post-conflict low-capacity environment and governance issues. Its complexity is due in part to the difficulty of diagnosing the extent of repair required for old poorly maintained hydropower plants of the size and age of Inga prior to their dismantling, coupled with their remote location that poses logistical challenges. The rehabilitation effort is further complicated by the fact that several of the turbines while needing urgent repair, are functioning and producing the bulk of DRC s power supply. Therefore any program of rehabilitation has to consider keeping a minimum number of turbines operating. In addition only one turbine can be rehabilitated at any given time in each plant (Inga 1 and Inga 2) due to working space constraints. 45. Due to the enduring consequences of country conflict, weaknesses in the institutional and technical capacity have contributed to slow progress of the Project. It will take time and significant investments to recover from years of non-existent or deferred maintenance, as well as SNEL s financial and human resource weaknesses. The institutional challenges have been compounded by frequent changes in the sector leadership and key players. Three Energy Ministers have led the sector since the signing of the original Project. Even though Government has remained committed to the Project, the combined impact of capacity shortcomings and institutional changes has taken a toll on Project implementation. 46. On the Bank side, there were several shortcomings: (i) the complexities and challenges associated with implementation of the Project were seriously under-estimated at the time of appraisal; (ii) the assessment by the Bank of the capacity of SNEL and of the Project implementing unit was overestimated; (iii) the Bank had difficulty mobilizing the full complement of experts needed to supervise such a complex project, including placement of a Senior Power Engineer in Kinshasa (it took over a year and several attempts to recruit the appropriate staff); and (iv) the project was managed by three Task Team Leaders (TTLs) since it was approved by the Board. In addition to the practical lessons generated on the ground, the QAG review of Regional Projects (January 2010) which covered the PMEDE and SAPMP projects among others provided valuable lessons for going forward, with greater emphasis on: Bank support to implementation including through field presence; governance and performance incentives for implementing agencies; coordination and information mechanisms; proper assessment of scope and cost of rehabilitation works; optimitized procurement planning; limited use of conditions of effectiveness or disbursement; sufficient time for project implementation; better assessment and mitigation of project and country risks; and stronger attention to project and utility sustainability. 47. All these shortcomings have been addressed through implementation of measures aimed at building capacity and through stepping up of Bank implementation support as described below. 14

25 48. During the implementation of the Project, several operational changes were made to enhance the likelihood of the project to achieve its stated development objectives. A realistic step-by-step procurement and implementation schedule more attuned with SNEL and BCECO capacity, has been agreed with Borrower and SNEL to achieve the new proposed completion date of the Project, and is closely monitored by the Project Coordination Unit (PCU) under the strong leadership of the Minister of Energy. (See Annex 11). The Project Implementation Unit located within SNEL is reporting directly to SNEL senior management and has achieved effective participation from SNEL s technical experts, as well as appropriate support from the Owner s Engineer and SNEL s Environmental and Social management Unit (UGES); the PIU is being strengthened with support from a full time project management expert. BCECO has established a dedicated team for the Project, which is led by a senior procurement expert and includes three full time procurement specialists, two nearly full time procurement consultants and additional procurement consultants recruited on an asneeds basis per fluctuating work load; Special attention is being paid by the implementing agencies and the Bank to underlying factors for adequate competition between reputable bidders, including aspects such as: bid packaging; quality of bidding documents; sufficient lead time for bid preparation; thorough responses to bidders requests for clarifications; and timely bid evaluation and award. The Project s internal auditor (an experienced international consultant) will continue to advise the PCU on implementation improvement measures. 49. Under the PMEDE Project, a plan for Enhancing Governance in the Electricity Sector was agreed between the Government and the Bank. The plan aimed at (i) institutional strengthening, (ii) oversight and transparency; and (iii) strengthening Partnership arrangements. Progress was achieved with the preparation of a comprehensive diagnostic on SNEL management systems and the selection of a Procurement and Financial Management Fiduciary Agent. Auditing and transparency have been improved with the selection of an external auditor, auditing and publication of audited accounts for , and preparation of Annual reports for Financial management has also been improved with the analysis of cross debts between the Government and state owned enterprises, and most of the tariff exemptions had been abolished although there has been backtracking for key customers (e.g. breweries and others). Governance has been improved with the strengthening of the process for the selection of directors, the review of all partnerships agreements involving private partners, the development of a framework for future private-public partnerships, and the reinforcement of the legal department. 50. The full implementation of SNEL governance plan was expected through the transformation of SNEL into a limited liability company to be placed under a private Management Contract, effective in While SNEL was indeed corporatized in December 2010, lessons learned from the water sector led the Government to abandon the option of a 15

26 private management contract and opt for an alternative scheme to enhance SNEL s performance and governance. This revised strategy for the reform of SNEL is based on a more realistic assessment of political economy and takes into account forthcoming national elections, and it will also underpin greater empowerment of SNEL management and technical staff, with better prospects for strategy buy-in by SNEL and the Government. Under such an arrangement, a comprehensive program aimed to enhance SNEL s corporate governance and operational performance, and its financial and operational sustainability, is being supported under the Project (see details in Annex 8). This program, to be implemented over five years and financed under PMEDE, will comprise: An audited performance contract ( contrat de plan ) between the State and SNEL; A corporate governance program; SNEL s financial and institutional restructuring; A three-year TA services agreement; and Institutional and financing arrangements for appropriate O&M at the Inga plants. 51. In the immediate term, technical advisors have been recruited to work on critical measures for sector reform, including to: Advise on critical aspects underlying SNEL s financial performance, including billing and collection, financial management and accounting, procurement/purchases; Design an integrated commercial and financial management system to be financed under the Project; and Help SNEL address the recommendations made by the external auditor to SNEL management. 52. The above five year program for the emergency recovery of SNEL, will be followed by the design and implementation of a more comprehensive program for SNEL restructuring and reform, which preparation will start during the five year period. Options include geographical unbundling, vertical unbundling, private participation in various or all segments - under IPPs or PPPs- etc. As noted above, the international experience in countries similar to the DRC show that power sector reform is a long process which needs to be carefully designed and sequenced appropriately. 53. Table 2 summarizes the key reasons for project implementation delays and how these have been addressed based on an iterative process of lessons learned and improvements in the implementation arrangements. Table 2: Implementation Challenges and Measures Implementation Challenge Consequences/Lesson Learnt Mitigations/Changes Made during implementation Institutional and technical capacity inadequate due to post conflict nature of the country and sector setting Inability to organize the enabling framework and strategy for a project of this size and scope to be implemented Additional expert support engaged through the Project at the level of the Ministry and the implementing agencies particularly SNEL PIU 16

27 SNEL poorly organized and managed Lack of coordination and oversight by the Ministry of Energy BCECO carries out procurement functions for many projects and lacks sufficient staff capability Shortcomings in project management, procurement and contract management Multiplicity of implementing agencies spreads further scarce expertise and resources Poor maintenance of assets Indicators of operational, commercial and financial performance consistently below industry standards Follow up and key actions on important project issues are not done in timely fashion e.g. on reforms and contract execution and supervision Important decisions on project and related sector issues that impact on the project are not taken in a timely and efficient manner. Inappropriate discharge of the procurement and financial management functions by BCECO for the Project leads to delays and errors 17 Strengthened staffing and organizational arrangements for the PIU following merger of the PIUs of two Projects (PMEDE and SAPMP) under one structure, with international engineering and consultant support provided Improved coordination and collaboration between implementation actors as per procedures and arrangements in the revised implementation manual A program for systematic maintenance of assets in Inga and the transmission lines will be established and properly funded through dedicated account. Performance contract setting responsibilities and obligations of SNEL and Government, and governance program to provide adequate performance incentives Longer term, technical services contract to establish better business practices and systems in SNEL Enhanced support and field presence from the Project Engineer Tighter supervision and follow up by the Bank team, including through the senior staff located in Kinshasa Setting up a technical assistance cell inside the Ministry of Energy under the project to coordinate and follow up on key actions and offer advice to the Minister and his team as needed Operationalizing the project Coordination Unit (PCU) chaired by the Minister of Energy with active participation from other key project stakeholders Closer supervision by the Bank team including frequent video conference meetings with the Minister, SNEL CEO and their teams. Strengthen BCECO with additional staff assigned to the Project for procurement work The 2-year extension of the SNEL - BCECO contract financed by the Project,

28 includes provision for capacity building of the PIU (with contract-based incentives) in order to take over the Procurement and Financial Management functions related to the Project 54. The implementation arrangements have been enhanced considerably from the situation that prevailed a couple of years ago. A fully staffed World Bank team is in place, including a Senior Power Engineer based in Kinshasa, as well as financial management, procurement, social development, environmental and communication specialists also based in Kinshasa. Management focus was considerably increased, including through direct support from the country director and sector leadership, and funding for supervision was increased. The improvement in project performance since then certainly speaks to the importance of having an adequately staffed Bank team in place. 55. As a result of the measures described above, significant progress has been made in the last 18 months in relation to all components. Under the IDA project, as of March 31 st 2011, tendering was completed or ongoing for a total of US$290 million. Preparation of bidding documents for all other contracts is well advanced, and all pending tenders 4 are expected to be launched by September 2011 and corresponding contracts are expected to be signed by March The contract for the second Inga-Kinshasa transmission line under EIB and AfDB financing has been executed and disbursement is pending the disclosure of the RAP which took place in April The contracts for rehabilitation of one unit at Inga 1 and the expansion of substations and distribution systems to expand electrification in Kinshasa have also been executed. Procurement under the KfW financing is about to commence. Regarding disbursements, the IDA grant has disbursed US$30 million or about 11 percent of the initial grant value. Consistent with the above-noted progress on procurement actions, total disbursements from the IDA grant at end of CY11 and CY12 are projected to be US$95 million and US$153 million, respectively. Based on the Project s updated procurement plan, the current IDA grant amount for the Project (US$297 million) would be fully disbursed by early 2013 (see Table 24 and 25 in Annex 11). 57. In view of the implementation delays, the Project had been rated since December 2009 as Moderately Unsatisfactory for project implementation progress and development objectives, and was upgraded to Moderately Satisfactory only recently in March 2011, i.e. for less than 12 months to date. For this reason, a waiver of OP was sought and obtained for the proposed additional financing. 58. At the current implementation rate, the total amount of commitments under the Project, including bids currently being tendered, would exceed the current IDA grant amount as early as 4 There are only three remaining tenders for works financed by IDA, totaling an estimated US$193 million, including: i/ the rehabilitation of Inga intake canal (estimated cost of US$75 million); ii/ the rehabilitation of Inga G11 and G15 units and common facilities (US$80 million); and (iii) the M03 tender for distribution works in Kinshasa (US$38 million). In addition, there are two tenders for works remaining to be launched under KfW finamcing. 18

29 the first quarter of FY12, which is why the additional financing is needed for the Project and at this particular time. Importantly, additional financing will help consolidate improvements to date in project management, facilitate SNEL s institutional and operational progress now that it has been transformed into a limited liability company operating under commercial law and give impetus to the reform process. The Government has shown its political will to reform SNEL under a phased approach and it has also taken the necessary measures to accelerate project implementation and achieve the project outcomes. In the absence of the additional financing there would be serious impacts on the DRC economy as well as on regional integration prospects supported under the SAPMP project. 59. In order to ensure proper supervision of the Project and consolidate the measures taken so far, an Implementation Support Plan has been prepared (see Annex 9). The Plan includes a comprehensive presentation of implementation risks, strategies and actions aimed to mitigate those risks. It also presents a detailed schedule summarizing the required supervision missions, field visits and other key meetings between implementing agencies and the Task Team and the required effort and resource commitment in terms of implementation support to ensure successful implementation of the Project. 60. In addition to the Implementation Support Plan, due to the complex governance challenges and risks the Project implementation is facing, a Project Governance Framework has been developed to improve key aspects of project performance, such as financial management, procurement or implementation arrangements in a systematic way and therefore ultimately minimize potential project overruns, prevent corruptive practices, and allow the Project to achieve its overall development objectives (see Annex 16). The framework outlines the tools to enhance the positive project impacts and help transfer methods and practices developed to improve the overall sector governance context. It should be viewed as a complement to SNEL governance enhancement plan which is ultimately the cornerstone and major focus of this project with regard to power sector governance. In addition, this framework adds detection and transparency mechanisms and fraud/red flags indicators that will guide the supervision of the project governance aspects, including the recourse to the Department of Institutional Integrity (INT), in the case of failure to remedy to issues raised by Bank team with the client. The Project s Anti-Corruption Plan that was prepared in 2008 will continue to be applied and it forms part of the Project Implementation Manual, which will revised as needed to take into account the Project Governance Framework. E. Rationale for Additional Financing 61. The additional financing is required to cover (i) underestimation of costs at appraisal; (ii) cost escalation because of market factors; and (iii) addition of new activities within existing components. 62. Underestimation at appraisal stems from the following: (i) Inga s generating units were found to be in worse condition than assessed at the time of appraisal; (ii) several components of Inga s generating units originally identified for repair needed instead replacement by new components. Cost escalation resulted from (i) globally, unanticipated increase in commodity prices that have significantly pushed up the cost of power plant equipment; and (ii) a weak 19

30 appetite for the DRC market among equipment suppliers and contractors resulting in few bidders and limited competition. Table 3 below provides a summary of the factors causing cost overruns and how they have been addressed. New activities under the Project include measures to enhance SNEL s operational and financial performances, such as the performance contract, the TA services contract and the Energy Efficiency and DSM Program. Table 3: Measures to Address Cost Overruns Nature of the cost overruns Cost underestimation Cost escalation Factors An incomplete/shallow assessment of Inga plants condition at the time of project appraisal in 2006, leading to underestimating the scope of rehabilitation works required at Inga Degradation in the condition of Inga generation units due to a combination of factors: units old age (most are already beyond their standard life span), operation under nonoptimal conditions or long stand by periods, suboptimal maintenance, and project implementation lag. As a result, rehabilitation works now include a larger share of new components instead of simple rehabilitation Input cost increase: the continued escalation in the various raw materials cost since 2006 (mainly copper, aluminum and iron) and labor cost, as well as increased demand, resulted in a dramatic increase in electrical equipment costs. This upward trend is confirmed after a pause due to the financial crisis at end An underestimate of the impact on tenders of the conditions prevailing in the DRC: low interest by qualified firms due to country risk (resulting in limited competition), high transaction costs and complexities of doing business Mitigations/Changes Made during implementation Revised estimates of project costs were produced by the Project Engineer in its independent assessment report of October Revised estimates take into account all of the factors associated with cost overruns. Revised cost estimates for pending tenders include significant physical contingencies: between percent for generation unit rehabilitation components and between percent for civil works including for the re-profiling and dredging of Inga intake canal. For the transmission component, and the emergency distribution and generation components, costs are based on the results of already completed bidding processes Lessons were drawn from the rehabilitation of G23 unit to refine the level of physical contingencies Price adjustments formula break down the total price into components that are adjusted by price indexes specified for each component. Basic assumptions are in Annex 5, Appendix 1. Labor cost increase in the sector are also projected for all project components. Increased World Bank supervision and availability of additional financing will increase bidder s confidence. The Bank will support outreach to increase the potential number of bidders. Better understanding of economics and risk pricing related to the DRC country context (including lessons learned from SAPMP). 20

31 63. The provision of additional financing at this time when major procurement for turbines is ready to be launched will increase market confidence and thereby the number of bidders showing interest. Recently against the funding available in the current Project, bids for the rehabilitation of two turbines units were successful in closing at prices that are about 30 percent lower than the cost estimated by the Project Engineer for this contract. Hence, procurement for remaining turbines once the additional financing is in place could attract similar competition. In case additional cost overruns materialize in the future, alternative financing from other public or private funds may be considered as option, or otherwise the rehabilitation of the last turbine currently included under the PMEDE may be postponed to a later phase. 64. Consideration has been given to the timing of the Additional Financing, given that final costs will not be known until bids have been opened and prices are known. For the contracts for which IDA additional financing has been requested, the prices will only be known around October 2011, when the last bid is expected. The risk of issuing a tender in the market without a firm financing plan is however deemed too high given the already low appetite in the market for DRC power projects. Therefore, the risk of uncertainty around final cost is deemed more manageable than the risk of low bid response. An increase in the contingencies levied on the cost estimates will in part mitigate the risk as will the increased level of due diligence that went into revising the cost estimates to support the request for additional financing. Revised and robust estimates of project costs were produced by the Project Engineer in its independent assessment report of October These estimates take into account the technical, market and country-specific risk factors. III. Proposed Changes 65. The proposed changes are as follow: Modification of the Project Development Objective to better reflect the renewable energy emphasis through development of hydro-power in the operation. The restated PDO which provides greater clarity with respect to the contribution to renewable energy in the Project s achievable goals is to improve operational efficiency in the electricity sector and expand renewable generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration. Extension of the Grant s Closing Date to enable completion of Project implementation from June 30, 2013 to June 30, Increase in the scope of the Distribution component to alleviate congestion and increase domestic power supply, particularly in Kinshasa. Changes in the results framework, including mainly new indicators and targets to reflect the new Project implementation schedule, the project restructuring and capture the additional focus on corporate governance 21

32 66. It is important to emphasize that key monitoring indicators, including baseline data and targets, need to be revised to reflect the restructuring of the project (see Annex 3). In particular, the yearly target values have been redefined and adapted to the new proposed Project closing date and new indicators have been added to monitor more closely the scaling-up of some activities and the focus on improving SNEL s performance (collection rates from Government and SOEs, Inga maintenance budget, unserved energy, etc.). 67. The proposed additional grant will enable financing of generation and distribution components under the project as envisaged as well as scaling up support to improve the performance of SNEL and MoE. See details in Table 4 below. 68. Table 4 and 5 below show a comparison of initial versus revised costs and financing plan of the revised Project components (see details in Annex 4 Revised Description of Project Components, and Annex 5, Revised Costs). Table 4: Detailed Comparison of Initial Versus Revised Project Costs Initial component Change Initial cost ($M) Revised cost ($M) Comments 1. Generation Inga units rehabilitation Modified Significant cost overrun due to underestimate at appraisal Rehabilitation of 8 instead of initial 10 units (860 MW vs. 970MW) consistent with optimized rehabilitation schedule over , IDA/AfDB component switch (G14 rehabilitation vs. common facilities & substation) Intake canal rehabilitation Continued Cost overrun due to underestimate at appraisal Generation emergency works Modified 4 22 Significant additional works due to degraded facilities 2. Transmission 2 nd Inga-Kinshasa T-line Continued Cost under-run 3. Distribution Distribution expansion Modified Cost overrun (except on substation) due to underestimate at appraisal Reduction in number of new connections from 50,000 to 35,000 due to financing gap on AfDB Kimbanseke electrification component (covered in part by IDA additional financing). Network congestion reduction program Distribution emergency works Continued Cost overrun due to underestimate at appraisal (Note: part of program is financed under emergency distribution works below) Modified 4 78 Significant additional works due to degraded facilities. Includes part of congestion reduction program 22

33 4. Capacity building SNEL strengthening Modified SNEL corporate governance program and TA services agreement Inga maintenance funds (financed by SNEL) SNEL training program (financed by AfDB Additional meters Ministry of Energy strengthening Modified 5 17 Additional support to CATE/MoE operations Additional support on PPP, rural electrification and sector studies 5. Project execution Project execution Continued Cost overrun on three subcomponents: higher resettlement costs, amendments to Owner s engineer contract, higher operating costs for SNEL Note: The table above considers only the activities already existing in the original project and their revised costs, not the new activities included under the additional financing which accounts for about USD$12.9 million. Table 5: PMEDE - Summary of Revised Costs and Financing Plan 23

34 IV. Appraisal Summary A. Project Updated Economic and Financial Analysis Project 69. The economic and financial analysis of the revised Project has been updated to take into account Project cost increase, delayed implementation, revised energy output and increased economic and financial value of the incremental energy resulting from the Project (see details in Annex 6). The revised EIRR remains robust at 27.3 percent in the base case (initially 29%). Sensitivity analyses have been carried out and a worst case scenario has been identified, under which the net present value of the Project will be zero. This scenario assumes unit value of benefits lower by 20 percent, project cost higher by 20 percent, 2 year delay in works completion and an average load factor of only 55 percent compared to 70 percent as assumed in the base case and based on actual current load factor. 70. The Project FIRR is also robust at 19.5 percent in the base case (initially 20%), and 11.2 percent in the worst case scenario, which is well above the IDA Grant on-lending rate to SNEL of 5.0 percent. It is important to note that the FIRR is closely linked to implementation of the new tariff schedule. The analysis assumes this schedule will be applied although under a conservative timeframe. 71. It should be noted that despite the significant increase in project costs and delay in implementation, changes in revised EIRR and FIRR are relatively small. This is due to several reasons: i) initial analysis considered only the benefits of rehabilitation of 4 units, as a conservative assumption; and ii) higher values for willingness to pay for certain group of customers than in the initial analysis, in line with higher energy prices observed at the regional and global levels. 72. In addition to quantifiable benefits, the Project will also substantially improve the living standards of the general population by improving access to clean electricity. Furthermore, exports to SAPP are likely to substitute for coal-fired generation, currently the most economic base-load generation available in the region. Estimated exports to SAPP would reduce CO2 emissions by about 1.2 million tons annually as early as 2015, i.e. additional annual benefits of about US$ 25 million, based on pricing of 20$/ton of CO A review of the demand-supply balance was also conducted to assess prospects for SNEL to meet both energy and capacity demand in the DRC and for exports to SAPP, over time and under different scenarios. Until additional generation becomes available (e.g., Inga 3 is commissioned) the demand/supply balance will remain tight and would require actions at three levels: (a) enhancing energy efficiency and demand-side management (which entails significant potential because of currently weak incentives for energy saving by some customer categories); (b) managing carefully the additional capacity delivered by SNEL to the mining sector; and (c) ensuring timely financing and completion of projects to increase generation capacity (including Inga 3 and smaller hydropower projects). The projected actions to restore payment discipline and adjust the tariff structure, combined with the deployment of CFLs, should help limit the growth of demand from public sector users (government and SOEs) and the residential sector. On the generation side, the energy balance forecast confirms the need to go ahead in a timely fashion 24

35 with hydropower generation investments in addition to Inga, including rehabilitation or scaling up of existing capacity in the Western part of the system (Zongo 1 and 2) and in the Katanga province (Nseke, Nzilo, Buzanga). B. Financial Analysis of SNEL 74. Recent trends in SNEL financial performance have been mostly positive in terms of revenue collection, which has increased from US$115 million in 2006 to US$216 million in The improvement has been largely driven by higher tariffs for exports and industrial users, but there is a significant potential for further improvements in revenue collection from public sector customers and residential users, together with a progressive adjustment of residential tariffs that are currently well below cost of service. Since the beginning of the Project, and compared to the years prior 2007, increased revenues have allowed SNEL to increase expenditure on maintenance of assets and finance more investments from internal sources. However, a significant portion of the extra revenue has been absorbed by higher wage costs. SNEL is still not in a position to finance significant new investments, or even rehabilitation works, from its own internal cash-flow. As a result, major recent investments have been undertaken with the support of donors, or by private investors (notably debt financing by mining companies which are able to secure reimbursements of their loans to SNEL by reducing their electricity payments to SNEL). 75. Assuming the positive trend in revenue per unit is sustained (mostly through gradually improving collection rates), the cash-flow forecast over the period shows that SNEL will be able to continue to increase its operational expenditures and investments, while servicing its debt service obligations related to recent and ongoing investments. SNEL should be able to achieve financial recovery with only gradual performance improvements and modest tariff adjustments because it has a very favorable operating cost structure (low-cost hydropower generation) and is benefiting from large external investments mostly funded on concessional terms. However, in order to achieve a sustained financial recovery, SNEL also needs to reestablish adequate organization and internal controls in the core areas of the power utility business, including planning and maintenance, financial management and cost control, commercial operations (billing and collections), procurement and logistics. Achieving this transformation in corporate governance will require technical assistance to support SNEL management, but also external mechanisms to create the appropriate incentives and ensure that adequate resources are directed toward critical operational and maintenance requirements (see Annex 8: Enhancing SNEL s corporate governance and performance). 76. Under the Project, SNEL has recently hired full-time experts to support SNEL in the core managerial areas: financial management, commercial operations, procurement and logistics. One major short term objective for this assistance is to put in place an integrated information system, covering the key business functions (financial, commercial, procurement, human resources). While the integration of the various corporate functions might take some time, there is scope for rapidly introducing improvements in some areas, through short-term and concrete actions, that will be expanded in the medium term through a technical services agreement to be designed and financed under the Project. 25

36 77. Also, as part of this improvement in governance, SNEL is planning to put in place adequate accounting and financial reporting systems and procedures. Currently, SNEL annual financial statements provide information of limited relevance; because of a number of significant weaknesses in accounting systems (see Annex 7 for details). As of January 1, 2011, SNEL has been transformed into a limited liability company and operates under commercial law and new company statutes. The work on establishing the opening balance of the transformed SNEL is ongoing. As part of this work, remaining uncertainties regarding asset valuation, asset ownership, and debt and receivables levels and restructuring, are being addressed. C. Financial Management (FM), Reporting, Audit and Disbursement Arrangements. 78. The FM system and performance of BCECO (contracted as the Procurement and Financial Management Agent) under the initial project are acceptable to IDA. BCECO will be responsible for FM and remains the Bank focal point for fiduciary aspects. BCECO is very familiar with the Bank FM procedures and requirements and has managed and is currently managing several IDA-financed projects. The FM of the additional financing will follow the same approach as the implementation arrangements in place for the ongoing Project managed by BCECO. The current FM staffing is deemed acceptable; no additional FM staff will be recruited. TOMPRO, the multi-project accounting software, operates well and will be also used for the additional financing. The procedures manual, which is being updated (a revised draft has been adopted by SNEL and submitted to the Bank for comments), is acceptable to IDA. The residual FM risk after mitigation measures is deemed high. The risk of fraud and corruption within project activities is high given the country context, inherent risks of activities related to large infrastructure, construction activities and equipment acquisitions. The action plan derived from the implementation support mission of November 2010 as well as the recommendations of the 2009 external audit reports, have been or are being implemented well. The Interim un-audited Financial Reports (IFR) are prepared every quarter and submitted to the Bank regularly and on time (i.e. 45 days after the end of each quarter). The main issue facing the ongoing Project is the low disbursement rate estimated at 11 percent at end of March 2011, which is being addressed through above noted implementation enhancement arrangements. Finally, the extension of the existing MoU between BCECO and SNEL requires BCECO to build the capacity of SNEL to manage the fiduciary aspects of the PMEDE and SAPMP Projects. The objective is to transfer the fiduciary responsibility of the Projects to the PIU established within SNEL by end March The revised MoU between the PCU and BCECO contains details on BCECO responsibilities in building capacity at SNEL s PIU, as well as indicators that inform on the level of achievement of the transfer of capacity. Payments under the MoU are conditioned to the effective delivery of PIU capacity building activities by BCECO. An assessment will be conducted by Bank fiduciary team in due time prior to the final transfer of fiduciary responsibility to the PIU. 79. The internal audit function contracted to an individual international consultant operates well. However following the last mission of November 2010, it was decided to transfer gradually this function to SNEL s internal audit department by March Two staff will be assigned to the PMEDE Project and will cover also the activities of the SAPMP Project. The terms of reference (ToR) of the current internal auditor will be updated to reflect the additional financing and the capacity building arrangement of the SNEL internal auditors to be assigned to the 26

37 Projects. An assessment will be conducted by Bank FM team in due time prior to the final transfer of internal audit function s responsibility to the PIU. 80. There is no overdue audit report for the Project nor for SNEL at the time of preparation of this additional financing. The audit report of the Project accounts managed by BCECO covering the period that ended December 31, 2009 was submitted on time. The auditor expressed an unqualified opinion and the report was deemed acceptable to IDA. The next audit reports of the IDA-financed projects in DRC are due on June 30, However, the audit report of the entity (SNEL) 2009 financial statements was received with some delays and was qualified. The qualification was mainly due to a limitation on the audit scope, an overestimation of SNEL revenue and some internal control weaknesses. SNEL team took some measures to ensure timely delivery of audit reports in the future. A detailed action plan covering operational aspects (financial, accounting, technology system, human resources, etc) was submitted to the Bank by SNEL team to address the recommendations in the audit report and is currently under satisfactory implementation with close monitoring by the World Bank s project team. The accounts of the initial and additional financing will be audited on an annual basis and the external audit report including the management letter will be submitted to IDA within six months after the end of each calendar year. The ToR of the current external auditing firm will be updated to reflect the additional financing. The Project will comply with the Bank disclosure policy on audit reports and place the information provided on the official website within one month of the report being accepted as final by the Bank team. 81. Upon additional grant effectiveness, transaction-based disbursements will be used. The grant will finance 100 percent of eligible expenditures inclusive of taxes. Following a single project approach, the existing Designated Accounts (DA) denominated in US Dollars opened in a commercial bank on terms and conditions acceptable to IDA will be used for the AF. The ceiling of this DA will be increased to US$ 1,600,000, equivalent to four (4) months of forecasted expenditures expected to be paid from the DA; the new ceiling will be effective upon effectiveness of the additional grant. Disbursements will continue to be made against submission of Statements of Expenditures (SOE) reporting on the use of the initial/previous advance as specified in Disbursement Letter. The option to disburse against submission of quarterly unaudited Interim Financial Report (also known as the Report-based disbursements) could be considered, as soon as the Project meets all the criteria 5. The E-signature of Withdrawal Application (WA) is being used by the Project and WA will be prepared on a monthly basis. The other methods of disbursing the funds (reimbursement, direct payment and special commitment) will also be available to the project. The minimum value of applications for these methods is twenty percent of the DA ceiling. 82. Dated covenants for FM include: (i) revision of the ToRs of the international internal auditor; (ii) assignment of two internal auditors of the SNEL Internal Audit Department to PIU; and (iii) revision of the ToRs of the external auditor. These actions are due within 3 months of declared effectiveness of the proposed additional financing. Detailed FM and disbursement arrangements are provided in Annex e.g. the draft report of the eligibility assessment current underway revealed that the Project budgetary system and the quality of the financial reporting require some improvements before being considered for this method. 27

38 D. Procurement 83. The overall procurement risk rating for the Project is assessed as High given the weak capacity of implementation entities, governance challenges, and history of delays in procurement. BCECO will remain the procurement agent of the Project until April 2012 given the intensive procurement work during this period, at the end of which all contracts financed under the project are expected to be signed. SNEL s PIU and the MoE s CATE would thereafter be in charge of supervising contract implementation, with support from the Owner s Engineer in the case of works and goods contracts. BCECO MoU with the MoE includes activities to build procurement capacity within SNEL s PIU and the MoE so as to facilitate the transfer of procurement responsibility by April 2012, in addition to support and monitoring by BCECO until June There will be no major changes in procurement procedures or methods. Procurement activities under the Additional Financing will be carried out in accordance with the Bank s Guidelines: Procurement under IBRD Loans, and IDA Credits dated May 2004, revised October 2006 and May 2010; and Guidelines: Selection and Employment of Consultants by the World Bank Borrowers dated May 2004, revised October 2006 and May 2010, and the provisions stipulated in the Financial Agreement. The Project will also follow the"guidelines on Preventing and Combating Fraud and Corruption in Projects Financed by IBRD Loans and IDA Credits and Grants, dated October 15, 2006 and revised in January The revised implementation manual will define more clearly the roles and responsibilities of each actor/beneficiary in the management of the procurement cycle. See Annex 11 for details on procurement methods and Bank review 85. SNEL and BCECO have developed a procurement plan for the implementation of the Additional Financing, covering at least the first 12 months of the Project, which provides the basis for procurement methods to be use for each activity. The Procurement Plan will be updated, with the prior approval of the Bank on an annual basis or as required by the Bank to reflect the project implementation needs and improvements in institutional capacity. All contracts for works under ICB will be procured using post-qualification of bidders. 86. A realistic step-by-step procurement and implementation schedule more attuned with SNEL and BCECO capacity, has been agreed with Borrower and SNEL to achieve the new proposed completion date of the Project, and is closely monitored by the Project Coordination Unit (PCU) under the strong leadership of the Minister of Energy. The summarized project procurement plan until end of Project and the associated commitment and disbursement projections are shown in Tables 24 and 25 in Annex 11. The procurement plan reflects optimized, realistic milestones for bidding steps, including contract award, signature, effectiveness and actual start. It accounts for past procurement experience under the SAPMP and PMEDE projects as well as for measures to strengthen procurement performance, including: i/ a six-person procurement team at BCECO; ii/ ensuring appropriate participation of SNEL s PIU and technical departments in procurement processes, as well as timely and effective support from the Owner s Engineer; iii/ streamlined communication and collaboration between entities involved in Project procurement. 28

39 E. Communication Strategy 87. Due to the high potential of the Inga site and its regional relevance, the PMEDE is a highvisibility project which has attracted attention and scrutiny from a broad range of stakeholders, at local, provincial and national level as well as from international NGOs. In general, potential negative environmental and social impacts associated with the Project are limited, whereas the overall envisaged positive economic and social benefits arising from increased renewable energy generation, access to electricity, links with economic development in DRC and deeper regional integration, are considerable. However, those expected benefits are generally not well recognized. 88. There are understandable reasons for this perception deficit in particular: Delayed impacts in the face of high expectations. By their very nature, the project investments in generation and transmission require long lead times and their positive impacts are felt only after completion of works. Lack of tangible results on the ground at this stage and chronic power supply disruptions in DRC, which tend to exasperate customers on a daily basis, and reinforce negative perception of SNEL. Skepticism or concerns of some key stakeholders with regard to the impact of sector reform (SNEL employees worried by the changes brought by the commercial transformation of the utility, LV residential users in view of expected future increases in electricity tariffs). 89. In view of this context and the particularities of the current situation of the energy sector in the DRC, it is important to develop a communication strategy in order to promote the project, and better inform target audiences regarding its objectives, the opportunities it offers, as well as constraints faced for its implementation. This strategy will be developed along three main axes, the PIU, SNEL and the Government and will ensure a consistent, comprehensive, coordinated, integrated and culturally appropriated approach to communication regarding the Project 6 to a broad range of stakeholders. 90. The strategy will be implemented through a Project Communication Plan (PCP) aimed at addressing the communication and perception challenges explained above. Annex 15 provides further details about the strategy and the Plan outline. F. Safeguards 91. The Additional Financing is a Category B project, as is the case for the original project. It triggers six safeguards policies (Environmental Assessment, Pest Management, Physical Cultural Resources, Involuntary Resettlement, Dam Safety, and Projects on International Waterways). 6 Communication will relate to investments under the Project, but also to studies and TA for preparing future investments to increase electricity supply, access and service quality. 29

40 Several safeguards documents were prepared and disclosed in 2006 and and are still applicable and relevant for the Additional Financing. The updated RAP for the second Inga- Kinshasa line and substation has been cleared by the Bank, consulted upon and disclosed prior to appraisal of the Additional Financing - on April 18, 2011 in the DRC s Official Bulletin and on April 20, 2011 at the Bank s InfoShop; compensation will be financed by SNEL, which has already set aside US$1.3 million in an escrow account, which will be increased to the revised cost of the updated RAP (US$ 2.4 million). The Inga Emergency Preparedness Plan, prepared in draft form in 2007, is now being finalized by the same international consultant, and will be approved by SNEL and disclosed in July The contract with the WHO for support to the implementation of the onchocerciasis vector control program has been negotiated and is expected to be signed shortly. SNEL has also recruited a firm to remove asbestos that is present in some installations at the Inga power plant. Additional safeguards instruments (ESIAs, ESMPs, RAPs) will be prepared as necessary and completed before specific civil works commences. 92. The Government has laid a solid institutional foundation for managing and monitoring adverse environmental and social impacts. SNEL has established an Environmental and Social Management Unit which will monitor safeguards compliance of the project. The unit (Unité de Gestion Environnementale et Sociale, UGES) is composed of eight staff (5 environmental specialists and 3 social scientists.) The project is supporting UGES strengthening by a consulting firm, including the training of UGES staff in Bank safeguards policies. The day to day monitoring of safeguards compliance under Project-financed works contracts will be ensured by the Owner s Engineer recruited by SNEL. The contractors will prepare their own Environmental and Social Management Plan, which will be based on the Environmental and Social Management Plan and Framework prepared for the Project. The implementation and monitoring of the RAP for the Inga-Kinshasa line and substations will be supported by a local consulting firm financed under the Project. The Bank team based in Kinshasa (one senior environmental specialist and one senior social specialist) is providing support for effective implementation of environmental and social plans. 93. Annex 12 contains a detailed analysis on the safeguard status for the current PMEDE and any additional work included under the additional financing. G. Overall Risk Rating 94. The proposed overall risk rating is High (H). The reason for this risk rating is threefold: the Project remains complex from a technical perspective; DRC is still working its way out of its post-conflict context; and the restructuring of SNEL will be gradual. 95. Furthermore, risks are also posed by the potential impacts of the 2011 elections on the pace and scope of sector reform, the length of time it will take to fully address governance issues in the country and sector, and also the limitations in competitive market for infrastructure works in the DRC. The detailed risk analysis is presented in the ORAF (Annex 13). 7 Environmental and Social Management Framework (ESMF), Resettlement Policy Framework (RPF), Environmental and Social Impact Assessment (ESIA)/Environmental and Social Management Plan (ESMP), Resettlement Action Plan (RAP), Management of Cultural Heritage Framework (MCHF), and Pest Management Plan (PMP) 30

41 96. There is no doubt that the environment surrounding this project and its proposed additional financing will continue to be challenging, but the significant potential rewards of this Project for DRC and for the Southern Africa region warrants the risks. Improvements in electricity access and service quality resulting from the Project s physical investments will help create the political space that is required for the Government to continue advancing SNEL and sector reform. H. Conditions for additional financing The Financing Agreement and the Amended and Restated Project Agreement would include: Conditions for effectiveness (target: September 30, 2011) Amendment of the existing Subsidiary Agreement between SNEL and the GoDRC The Project Implementing Entity has revised the EPP in form and substance satisfactory to the Association and has thereafter disclosed it to the general public Dated covenants The Recipient shall carry out the Project and/or cause the project to be carried out in accordance with the Project Implementation Manual (PIM), which shall be updated by not later than three (3) months following the Effective Date SNEL s new Board is appointed by December 31, 2011 Signature of SNEL performance contract between SNEL and the State by March 31, 2012 Opening and provisioning of dedicated account for Inga O&M by December 31, 2011 Revision of the ToR of the International Internal Auditor to include the additional financing and to support gradual transfer of internal audit responsibility to SNEL by not later than three months following effectiveness Revision of ToR of external auditors of project accounts to include the additional financing by not later than three months following effectiveness The Project Implementing Entity shall employ, not later than October 1, 2011, a consultant, selected in accordance with the provisions of Section III of the Schedule to the FA, for: (i) the design of operation and maintenance services for the Project, and (ii) the determination, on a quarterly basis, of the funding requirements to perform the operation and maintenance of the Project Implementing Entity s assets and facilities at the Inga hydroelectric site throughout the implementation of the Project (Covenant to be fully complied with by October 31, 2011). 31

42 Appointment of two internal auditors (technical and financial) of the SNEL internal audit department to the PMEDE Project by not later than three months following effectiveness Signing of SNEL s TA services contract by March 31,

43 Annex 1: Description of the Southern African Power Market Program AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing 1. The Southern Africa Power Pool (SAPP) comprises power systems of 10 countries in Southern Africa 8. The total available generation capacity of the SAPP is about 45.3 GW (against an installed capacity of 51 GW in 2009). Demand has been growing at about 4 to 6 percent annually. South Africa (Eskom) is the largest economy of the 12 SAPP members with 78 percent generation capacity (39.8 GW) and about 82 percent of energy demand. Mozambique is the second largest inter-connected member with an installed capacity of 2,200 MW (or 4.4 percent of SAPP total). The power trade through SAPP is still small (~2% of total SAPP demand), mainly for short-term spot market for non-firm power surpluses among the utilities. SAPP is evolving and is seen as the anchor for the sub-region s energy development strategy. 2. The SAPP is organized under the Executive Committee, which acts as the board of directors of the pool and is responsible for overall pool policy, and a Management Committee, which oversees the administration of the Pool. Three subcommittees serve under the direction of the Management Committee and are in charge of technical issues: the Planning Subcommittee (which focuses on reviewing power wheeling rates annually and developing an indicative SAPP expansion plan every two years), the Environmental Subcommittee and the Operating Subcommittee with its associated Coordination Center. There are also special working groups, comprising representatives of member utilities with relevant expertise, that are formed on an asneeded basis to address specific issues that arise (e.g. the Telecommunications Working Group has developed recommendations for a suitable and financially viable telecommunication infrastructure to support competitive trading in the region and to facilitate secure and sound operations of the SAPP power grid; and the Quality of Supply Working Group is working to establish standards for quality of supply in the SAPP and their measurements, etc.). 3. The SAPP Agreements state that the purpose of the Pool is to allow its members to coordinate the planning and operation of their systems while maintaining reliability, a degree of autonomy, and sharing of the benefits - including reductions in required generating capacity and reserves, reductions in fuel costs and improved use of hydro-electric energy. The objectives include reduction in investment and operating costs and enhancement of the reliability of supply through providing opportunities to coordinate the installation and operation of generation and transmission facilities. 4. The SAPP members agreed to begin their pooling operations as a loose, or cooperative, pool. Loose pools emphasize optimizing economic and reliability benefits from trading within the parameters of maximum individual system autonomy. These pools do not employ central dispatch and tend to be characterized by long-term bilateral contracts for the supply of electricity between particular generators and customers, supplemented by short-term contracts and other agreements under the overall agreement framework. Loose pools may provide central services such as data gathering and provision-- including providing continuous real-time data to match 8 Angola, Botswana, Lesotho, Malawi, Mozambique, Namibia, South Africa, Swaziland, Zambia, Zimbabwe, Tanzania and DRC 33

44 generation and demand, producing indicative expansion plans, and implementing emergency procedures. Loose pools also establish detailed common design and operational standards to ensure system security and reliability, and to facilitate trades. 5. However, recently the SAPP has been focusing on moving from a cooperative pool to a tighter pool. Operating as a cooperative pool the SAPP brought to its members benefits of support in emergency situations and increased reliability of supply. Competition was not promoted between members and the cost of electricity was centered on recovery of operating costs. Moving to a tighter pool would require ensuring open access to transmission infrastructure and addressing the constraints posed by the differences in size of the utilities within the SAPP. 6. The rehabilitation of Inga 1 and Inga 2 facilities and the reconstruction and upgrade of the transmission lines that connect Inga to the SAPP via Zambia, comprise the first major regional investments in the SAPP by the Bank and development partners. The rehabilitation and efficient operation of these assets is crucial both for increasing power supply domestically in DRC and for unlocking the hydropower development potential in the region. Hydropower resources in the SAPP, including Inga, can potentially reduce the carbon emission intensity of the SAPP generation mix. The share of hydro in this mix could go up to 30 percent from the current 21 percent even as an additional 39,000 MW of new capacity is added in the SAPP by The shift towards increased hydropower in the subregion critically depends on DRC being able to realize the hydropower rehabilitation investments under the PMEDE and scale-up to the realization of other greenfield hydro projects. Therefore, the role of DRC in the SAPP is crucial given its large hydropower capacity and central location. One such project Inga 3, offering up to 4,300MW can be developed at the same site and the Government of DRC has initiated concrete steps to do so. The credibility of Inga 3 going forward depends on the Government being able to ensure the timely completion of the Inga1 and Inga 2 rehabilitation, construction of the SAPP transmission line to Zambia and organizing its power sector and the utility SNEL as an efficient and creditworthy enterprise. Together with South Africa as the major demand source, DRC forms the foundation for an interconnected and energy trading SAPP in ten years time. 8. Following the Inga projects, the Bank and development partners have supported the interconnection between Malawi and Mozambique. Political issues unrelated to the Project triggered this project to be canceled after a 3-year waiting period. However, the high capacity interconnection project between Mozambique and South Africa to enhance existing transmission capability and providing a boost to development of hydropower in Mozambique is going ahead. The Bank and other development partners are well advanced in its preparation as they explore an innovative PPP structure for its financing. Other regional transmission projects are under development in Zambia and Tanzania. 9. The Bank is contemplating critical institution and capacity building support for the SAPP and the Regional Electricity Regulators Association (RERA) to: (i) enhance security of supply 9 The SAPP Optimal Generation Expansion Study (Nexant, 2007) 34

45 with focus on technical, commercial and regulatory aspects; (ii) harmonize technical and commercial grid codes; (iii) develop cross border transmission pricing models; (iv) strengthen the power trading platform; (vi) promote adoption of regional power system planning; and (vii) enable RERA member's regulatory reach, including through self-regulation through standards and disclosures. 35

46 Annex 2: The Southern African Power Market Project (SAPMP - APL1): Linkage with the PMEDE, Status of Implementation and Lessons of Procurement and Implementation AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing Linkages between the PMEDE and SAPMP Projects 1. The PMEDE and SAPMP Projects are closely and uniquely linked and interdependent. The SAPMP is needed to convey the power produced from the rehabilitated generating units at the Inga hydropower stations to markets in the industrial heartland of DRC to support mining and industrial activities vital to the growth of the economy, and to meet the needs of a growing population; and for export markets in the Southern African Power Pool (SAPP). Conversely, the investments in the SAPMP are justified on the grounds of the power generating capability of the Inga hydropower stations. In addition, in emergency situation of catastrophic failure of the Inga hydropower stations, the SAPMP would provide the critical role of enabling power transfers from the SAPP into DRC to meet such emergency. The decision of the Government, supported by the Bank, to proceed first with SAPMP Project ahead of PMEDE was a rational one. As such, the implementation of the SAPMP is linked with that of the PMEDE for the SAPMP and would need to be fully completed and operational ahead of the completion of the PMEDE and to conform to the staged commissioning of the rehabilitated generating units of the Inga hydropower stations. 2. On the regional scene, the power supply deficit in Southern Africa has opened new opportunities for DRC to export power. The market for exports in the region has firmed up significantly in DRC s favor over the last few years This is demonstrated by the recent 5-7 sales agreements concluded by SNEL with Bostwana, Zambia, Namibia, and shorter-term ( 2 years) with Zimbabwe. The main export destination should continue to be Southern Africa, which will continue to face growing supply deficits and at higher prices in the future. In order to enter into secure, longer term agreements at attractive prices, DRC would need to demonstrate reliable availability of power supported with a capable and reliable transmission system that SAPMP would enable, to deliver it into the SAPP. The success of the PMEDE and the SAPMP is critical to DRC s long term regional trade aspirations, as well as to support the power needs of the growing DRC economy and of the growing DRC population. The SAPMP Project 3. On June 30, 2009, the Board approved an additional financing grant of US$ million for the SAPMP Project to complement the existing credit of US$177.5 million, approved in November 2003 for the Project. This brought the total IDA contribution to US$ million towards the financing of the total revised estimated project cost of US$ 430 million. At same time the Board approved a further 3 years extension of the Project Closing Date to December 31, 2012 bringing the total cumulative extension of the closing date to 5 years. The additional financing grant became effective on November 22, The Objective of the SAPMP is to facilitate further development of an efficient power market in the Southern Africa Development Community (SADC). The Project s specific focus is 36

47 to rehabilitate and reinforce the existing 2,000 kilometer high voltage transmission grid from the Inga hydropower stations to Kasumbalesa at the border with Zambia, which is the backbone of the DRC power transmission systems well as the main artery for conveying power to the Southern African Power Pool (SAPP) through Zambia The project also supports an additional high voltage transmission line to the border with Zambia on the existing alignment. In Zambia, activity complementing the project should result in reinforcement of the system s power transfer capability and improvement of its reliability with DRC and Zambia and into the SAPP. Furthermore, a modern optical fiber telecommunication system is to be installed in tandem with the power line to enhance SNEL s power operations and electricity trade with the SAPP and also for national and regional communication applications as well as interconnection capacity. 5. The SAPMP Project consists of the following: Rehabilitation and reinforcement of the converter and inverter stations at Inga and Kolwezi respectively, including the rehabilitation of synchronous compensators at Kolwezi, and removal of all Polychlorinated Biphenyls contaminated capacitor units and auxiliary transformers and their replacement with modern ones; Rehabilitation and reinforcement of the 3 high voltage AC substations at Fugurume, Panda, and Karavia, and installation of a modern transmission control center at Likasi; Construction of new high voltage AC 220 kv transmission lines from Fugurume to Kasumbalesa at the border with Zambia; Rehabilitation of the entire long-distance, 2,280 kilometers of HVDC and HVAC transmission lines from the Inga hydropower stations to Kasumbalesa, including the towers (11,200); Installation of a modern telecommunication system comprising about 2,300 kilometers of OPGW and associated electronic equipment from Kinshasa to Kasumbalesa to link with the SAPP telecommunication system; Community development in seven villages and towns in the Katanga. Implementation of the environmental and social mitigation measures of the Project Provision of engineering and project implementation management services by international consultants; Technical assistance for: (i) procurement, training in project management and supervision; (ii) acquisition of tools and equipment and management information system; (iii) selection of private O&M contractor for SNEL s transmission assets; (iv) selection of private operating management of telecommunication system; (v) services of an NGO to provide oversight of implementation of the environmental and social mitigation measures, and implementation of HIV/Aids awareness campaign 37

48 Construction of additional high voltage 220 kv lines to reinforce the interconnection of the DRC power system with that of Zambia and the SAPP from Kasumbalesa to Luano in Zambia. Implementation Status of SAPMP Project 6. The Project is being implemented under 10 main contracts, including the Engineering and Project Management Services, upon which the achievement of the objectives of the project depends. A total of eight of the main contracts are under IDA financing, of which 5 have been signed and are at various stages of satisfactory implementation progress. As such, total commitments under the IDA financing currently stand at about US$270 million. Two other main contracts have been signed and are under implementation: (i) for the rehabilitation of high voltage AC (Alternating Current) substations under the project financed by the European Investment Bank (EIB) for US$47 million equivalent; and (ii) the construction of additional high voltage transmission lines financed by the Copper Belt Energy Corporation (CEC) of Zambia for US$18 million to reinforce the interconnection of the DRC power system to that of Zambia and the Southern African Power Pool (SAPP) to enable power transfer capability of 500 MW from DRC into SAPP 7. Three of the remaining main contracts are undergoing re-tendering due to failure of the earlier tendering carried out to result in contract awards. Two of them (i) the rehabilitation of the long-distance HVDC and HVAC transmission lines and associated towers; and (ii) the installation of the OPGW cable on the transmission towers from Kinshasa to Kasumbalesa (border with Zambia) - are on the critical path of the project implementation schedule. The other seven main contracts are under implementation. The testing and commissioning of some the completed contracts would have to await the completion of these latter two contracts currently under re-tendering. Status of Disbursement 8. Disbursements, cumulatively, stand at US$83.9 million as of May 05, By the nature of the physical main contracts, there is a long lead-time of about months after contract effectiveness required to complete detailed designs, placement of orders, and manufacturing of equipment and materials and shipment and delivery to sites during which minimal disbursement of funds takes place. Most of the contracts under implementation are currently in this phase, and, therefore, disbursements are expected to rapidly pick up when this gestation period is over by early Lessons Learned from the SAPMP 9. Contracts should be appropriately packaged to attract bidder interest. When the telecommunication systems component was initially bided as one contract, it attracted only one bidder with a bid price far above the estimated cost. Subsequently, the component was bid as three separate contracts: (i) supply of optic fiber cables, (ii) installation of fiber optic cables, and (iii) supply and installation of telecommunication equipment. Seven bidders tendered for the first contract, five for the second contract, and one bidder for the third. Bid prices received for the 38

49 first and third contracts were near to the estimated costs while those for the second contract are currently being evaluated. 10. Rehabilitation works should be assessed in depth to properly estimate their cost and gather sufficient technical information for a successful bidding exercise. A first tender exercise for the contract to rehabilitate the high voltage transmission lines attracted only one unresponsive bidder because of the inadequate technical information gathered after a preliminary study. The contract was retendered after a thorough study which provided detailed technical information on the state of the lines. Five firms submitted bids with prices far above the cost estimated by the preliminary study and nearer to the price estimated by the second study. 11. Conditions for effectiveness of project financing should be simple to avoid delays in project implementation. One condition for effectiveness of the co-financing loan that the Government signed with the European Investment Bank (EIB) in December 2008 required the conclusion of a five party agreement between the Bank, EIB, the Government, SNEL and a bank in Luxemburg domiciling several project accounts. Reaching agreement between the five parties was a very tedious process which delayed the effectiveness of the EIB loan until November As a result, the contract financed by the EIB loan for the reinforcement and rehabilitation of high voltage substations has not yet started though it was signed in October The contract runs the risk of being on the critical path for the completion of the project. 12. In post conflict countries, projects require longer implementation periods and more frequent Bank supervisions. The SAPMP closing date, initially scheduled for December 2007, was first postponed to December 2009 and then to December In post conflict countries, executing agencies have weak capacity resulting in prolonged processes for procurement, disbursements and resolution of project issues. More frequent Bank supervisions can help identify and resolve problems thereby mitigating the risk of project extensions. 13. Impacts of Perception of Higher Level of Risk: In a post-conflict environment of DRC, there is perception of much higher risk level by international contracting firms than would be considered for other countries, especially in contracts that involve movement of equipment and personnel over long distance for implementation. Invariably bid-price mark-ups up in the range of 20-30% are included by contractors in their offers to hedge against perceived high risk of implementation delays and potential failure. This issue should be recognized in the estimation of project cost to allow for adequate contingency. 39

50 PDO Annex 3: Revised Results Framework and Monitoring AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing Revisions to the Results Framework Current (PAD) To improve operational efficiency in the electricity sector and expand generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration Proposed change Revised Comments/ Rationale for Change The renewable nature of Inga generation was recognized by adding "renewable" generation in the wording of the PDO, as well as in the associated PDO level indicator. PDO indicators Current (PAD) Proposed change Revenues collected by SNEL per generated kwh New To assess progress on the first PDO ( improve operational efficiency ) GWhs of renewable energy generated at Inga Revised To assess progress on the second PDO ( expand renewable generation capacity ). Word renewable added. Kilometers of second transmission line strung Continued To assess progress on the third PDO ( transmission capacity ). Number of people provided with access to electricity under the project by household connections Renewable Energy delivered from Inga to: - Kinshasa and Bas Congo - Katanga region Revised Revised To assess progress on the fourth PDO ( expand distribution capacity ). To assess progress on the fifth PDO ( better serve domestic demand ). Renewable Energy exported to SAPP Revised To assess progress on the sixth PDO ( support regional power market integration ). Intermediate Results indicators Current (PAD) Proposed change Total available capacity at the Inga 1 and 2 plants New To assess overall capacity available at Inga through rehabilitation Renewable capacity rehabilitated under the project Revised Word renewable added. Transmission losses second line Inga-Kinshasa New To assess progress on operational efficiency of transmission investments. Transmission capacity Inga-Kinshasa New To assess increased transmission capacity under the Project. Kilometers of distribution line strung Continued Reworded. Unserved Energy in Kinshasa New To better measures the Project impacts on beneficiaries in Kinshasa Annual hours of unavailability of Inga-Kinshasa transmission lines New Measures the quality of delivery to Kinshasa substations GWhs of energy delivered to Kinshasa distribution Revised Moved to PDO level indicator network from Inga GWhs delivered to SAPP countries and Katanga region Revised Moved to PDO level indicator. 40

51 Revisions to the Results Framework customers from Inga Revenues collected in Kinshasa per kwh delivered to Kinshasa Rate of collection of accounts receivable from SNEL s low voltage clients in Kinshasa Rate of collection of accounts receivable from SNEL s public clients Rate of collection of accounts receivable from SNEL s Dropped Continued New New Comments/ Rationale for Change Covered under the PDO level indicators. To monitor key aspect for SNEL s commercial efficiency To monitor key aspect for SNEL s commercial efficiency state-owned companies Ratio between number of costumers and SNEL employees New To monitor key aspect for SNEL s commercial efficiency SNEL s actual spending on Inga s maintenance New To monitor key aspect for sustainability of project investments Number of additional households connected in Kinshasa Revised Covered under the PDO level indicators. Number of qualifications to external audits Publication of public/private partnership agreements for electricity sector Continued Continued 41

52 REVISED PROJECT RESULTS FRAMEWORK Project Development Objective (PDO): To improve operational efficiency in the electricity sector and expand renewable generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration. PDO Level Results Indicators 1 1) Operational efficiency: Revenues collected by SNEL per generated kwh 2) Renewable Generation GWhs of renewable energy generated at Inga 3) Transmission capacity Transmission lines constructed under the project 4) Distribution capacity: Number of people provided with access to electricity under the project by household connections 5) Better Serve Domestic Demand: Renewable Energy delivered 4 to: - Kinshasa and Bas Congo - Katanga region 6). Support regional power market integration Renewable Energy 5 exported to Core UOM 2 Baseline Original Project Start (2007) Progress To Date (2010) 3 End 2012 Cumulative Target Values End 2013 End 2014 Project End $/kwh N/A GWh 3,715 4,809 5,920 6,071 5,798 9,039 Km Number of connect ions GWh Frequency Semiannual Semiannual Semiannual ,000 20,000 35,000 Annual N/A N/A 3,423 2,719, 3,847 2,882 4,077 3,255 4,322 3,672 4,581 4,012 Annual GWh N/A 97 1, ,349 Annual Data Source/ Methodolog y SNEL Monitoring SNEL Monitoring SNEL Monitoring SNEL Monitoring SNEL Monitoring SNEL Monitoring Responsibility for Data Collection SNEL SNEL SNEL SNEL SNEL SNEL Comments The values include transmission losses and they are averaged over the year for 2010 to No separate baseline is available for the Kinshasa and Bas- Congo and Katanga Region in the original Project. As above (no separate baseline for SAPP in the original Project). 1 Core indicators have not been formally approved yet for the energy sector. 2 UOM = Unit of Measurement. 3 For new indicators introduced as part of the additional financing, the progress to date column is used to reflect the baseline value. 4 The energy delivered to Kinshasa and Bas Congo will originate not only from Inga but other hydropower plants (eg Zongo) operating in the Western System. 42

53 SAPP Beneficiaries 6 Direct Project beneficiaries 7 Number , , ,000 Annual SNEL Monitoring SNEL. Of which female beneficiaries 8 Number ,400 83, ,600 Annual SNEL Monitoring SNEL Intermediate Results and Indicators Intermediate Results Indicators Core Unit of Measur ement Baseline Original Project Start (2007) Progress To Date (2010) End 2012 Target Values End 2013 End 2014 Project End Frequency Data Source/ Methodology Responsibility for Data Collection Comments Component 1 (Generation). Intermediate Result 1: Increased reliable generation at Inga 1 and 2 plants 1. Total available capacity at the Inga 1 and 2 plants MW Annual SNEL Monitoring SNEL 2. Renewable capacity rehabilitated under the project MW Annual SNEL Monitoring SNEL Component 2: Transmission. Intermediate Result 2: Increased transmission / power delivery capacity to Kinshasa from Inga site 1. Annual hours of unavailability of Inga-Kinshasa transmission lines h N/A 9 < 9 < 9 <9 Semiannual SNEL Monitoring SNEL Fully financed by EIB. 5 The energy delivered to SAPP will originate not only from Inga but other hydropower plants operating in the Western System and Southern System. 6 All projects are encouraged to identify and measure the number of project beneficiaries. The adoption and reporting on this indicator is required for investment projects which have an approval date of July 1, 2009 or later (for additional guidance please see 7 The above number of Project beneficiaries reflects only the number of additional connections under the project (with average household size of 8 persons); there will be many more beneficiaries from the increase in power generation capacity under the project, which however cannot be quantified as energy is delivered to the high voltage transmission network. 8 Assuming 52% of females in Kinshasa households (accordingly to SNEL estimates). 43

54 Intermediate Results and Indicators Intermediate Results Indicators Core Unit of Measur ement Baseline Original Project Start (2007) Progress To Date (2010) End 2012 Target Values End 2013 End 2014 Project End Frequency Data Source/ Methodology Responsibility for Data Collection Comments 2. Transmission losses Inga- Kinshasa lines % N/A 3% <3% <3% Annual SNEL Monitoring SNEL 3. Transmission capacity Inga- Kinshasa lines 9 MW N/A ,070 1,070 1,070 Annual SNEL Monitoring SNEL Component 3: Distribution. Intermediate Result 3: Increased connection in Kinshasa and electrification of previously un-electrified areas 1. Distribution lines constructed under the project Km (LV) 40 (MV) 350 (LV) 80 (MV) 500 (LV) 120 (MV) Semiannual 2. Unserved Energy in Kinshasa GWh N/A Annual SNEL Monitoring SNEL Monitoring Component 4: SNEL Capacity. Intermediate Result 4: Improved financial, commercial efficiency and corporate governance of SNEL and improved transparency in SNEL s external partnerships SNEL SNEL 1. Rate of collection of accounts receivable - from SNEL s low voltage clients in Kinshasa - from SNEL s public clients - from SNEL s state-owned companies 2. SNEL s actual spending on Inga maintenance based on operational maintenance plan % 35 N/A US$ million N/A N/A Semiannual Semiannual SNEL Monitoring SNEL Monitoring SNEL SNEL To be refined accordingly to the targets to be included in the SNEL performance contract. To be refined accordingly to the outcomes of the Study on O&M of Inga. 9 The capacity for the second line Inga-Kinshasa (400 kv) is 1,000 MW. However, the T-line will be used at 220 kv since no MV/HVsubstation is envisaged at Inga for the moment and therefore the capacity of the T-line will be 600 MW. 44

55 Intermediate Results and Indicators Intermediate Results Indicators Core Unit of Measur ement Baseline Original Project Start (2007) Progress To Date (2010) End 2012 Target Values End 2013 End 2014 Project End Frequency Data Source/ Methodology Responsibility for Data Collection Comments 3. Ratio between number of customers and SNEL employees Number N/A Semiannual SNEL Monitoring SNEL 4. Number of qualifications to external audits 5. Publication of public/private partnership agreements for electricity sector Number N/A 4 (for FY09) None None None None Annual Number None All All All All All Semi- Annual External Audits SNEL Board of Directors External Auditors; MoE (PCU); SNEL SNEL 45

56 Annex 4: Revised Project Description AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing 1. The Project consists of the same five components as in the initial project, as follow: Component 1: Generation (US$478 million): Rehabilitation of the hydroelectric facilities at Inga, including civil works on the intake canal to improve the water flow through the plant and rehabilitation of turbines to increase the operational capacity and reliability of the Inga plant (1 and 2) from the current maximum generation capacity of about 750 MW to about 1,300 MW of reliable production. Component 2: Transmission (US$92 million): Construction of a 400 KV Inga-Kinshasa transmission line. The second line will complement the existing 220 kv Inga/Kinshasa transmission line, relieving the current saturation of the existing line and thereby improving the security of transport of power from Inga to Kinshasa, as well as increasing the amount of power that can be delivered to Kinshasa. Component 3: Distribution (US$169 million): Expansion and strengthening the distribution system in Kinshasa, including the acquisition of low voltage cables and transformers, the extension of the grid into currently un-electrified areas of Kinshasa and the connection in these areas of a total of 35,000 new customers. Component 4: Capacity Building and Governance (US$89 million): The component comprises two subcomponents: o Subcomponent (a): Strengthening SNEL s operational capabilities, notably in commercial activities, planning, dam safety and technical training. The component will also support actions to enhance governance within the utility specifically and in the sector generally. o Subcomponent (b): Strengthening the Ministry of Energy s capacity to develop sector reform and to support the further development of the Inga site. Component 5: Project Execution (US$57 million), including Project preparatory activities): Effective implementation of the Project works, in an environmentally and socially sound manner, including appointment of supervisory engineering consultants, environmental/social consultants and the PFM Agent. Initial components and changes in the detailed scope and financing of each component are described below: Project Component 1: Generation (US$460 million, of which US$345million will be financed by IDA, US$27 million financed by AfDB and $88 million by KfW 2. This component includes the rehabilitation of 8 turbines (4 at the Inga 1 plant and 4 at the Inga 2 plant) for a total capacity of 860 MW, compared to the initial plan of rehabilitating 10 turbines (4 at the Inga 1 plant and all 6 at the Inga 2 plant) with a total capacity of 970 MW. Details of the rehabilitation strategy and schedule are shown in Appendix 1 and 2. Intake 46

57 canal dredging and reprofiling to improve its capacity and reliability will be done as initially planned. 3. The component also includes emergency works that are significantly more important in scope and cost than those planned in the initial project ($22 million versus $4 million), including the repair of the G16 unit (55 MW) and other emergency works on both Inga 1 and 2 plants. The component includes the provision of dam safety equipment, as well as the design and implementation of an effective maintenance program for Inga facilities. Project Component 2: Transmission (US$92 million, financed by EIB) 4. This component is unchanged and includes the construction of a second 260 km 400 kv transmission line from Inga to Kinshasa, with 220 kv connections to the Kimbanseke and Kingantoko substations, to allow increased and better quality supply to Kinshasa. Project Component 3: Distribution (US$190 million, of which US$135 million financed by IDA and US$55 million financed by AfDB. 5. This component includes the construction of a new substation at Kimbanseke with 15,000 new connections, network extensions in three areas in Kinshaha with 20,000 new connections and a program to reduce congestion in the distribution network in Kinshasa. 6. The component also includes emergency works to improve service quality that are significantly more important in scope and cost than those planned in the initial project. 7. Additionally, under the additional financing, a Energy Efficiency and Load management program will be implemented aimed at reducing the capacity and energy demand without loss of quality of service, and at incentivizing consumers to shift some of their demand from system peak hours to off-peak hours (see Annex 14 for details on the program). As part of this component, about 70,000 classic meters (about 60,000 monophase and the rest threephase) and about 32,000 prepaid meters (about 30,000 monophase and the rest three-phase) will be installed, together with the related electronic management system and accessories. Project Component 4: Capacity Building and Governance SNEL and MoE (US$81 million, of which US$55 million financed by IDA, US$22 million financed by SNEL, and US$4 million financed by AfDB) 8. This component includes a capacity building sub-component to benefit SNEL and a separate sub-component to benefit the Ministry of Energy. Subcomponent 4(a) - SNEL (US$64 million, of which US$37 million financed by IDA, US$22 million financed by SNEL, and US$4 million financed by AfDB): 9. This component will strengthen the capacity of SNEL in four principal ways (unchanged compared to initial project): (a) support to strengthen SNEL s commercial/financial management and operations (new financial and commercial management and control systems), (b) support for improved planning and maintenance, and environmental/social management (dam safety, onchocerciasis vector control); (c) improved training of SNEL staff, and (d) improved governance. (enhanced subcomponent). 10. The component will also include new features, including: a TA services contract with an experienced operator, a performance contract ( contrat de plan ) with M&E mechanisms, the transformation of SNEL into a limited liability company (including its financial restructuring) and the establishment of a financial mechanism (dedicated account set by SNEL with 47

58 revenues from secure customers) and institutional arrangements to ensure appropriate operation and maintenance of the Inga facilities. Subcomponent 4(b) - MoE (US$17 million, financed by IDA): 11. This component is unchanged and will support the MoE s capacity to foster the development of the Inga site and to develop adequate strategies for the sector in particular focusing on support to small hydropower PPP framework and development, electrification Development and energy efficiency. Project Component 5: Project Execution (US$60 million, of which US$45 million financed by IDA and US$15 million financed by SNEL) 12. This component entails unchanged activities to strengthen SNEL s and MoE s capacity to carry out the project activities, including: a project engineer, a procurement/financial management agent, support to the Project Coordination Unit (PCU) and its technical Secretariat (CATE), support to SNEL s Project Implementation Unit (PIU) in charge of implementation of both the PMEDE and SAPMP projects, and a communication program. SNEL will contribute its staff resources and logistical support to the Project (estimated at no less than US$11.7 million). 13. This component will also include support to SNEL s Environmental and Social Management Unit (UGES). 48

59 Appendix 1: The Inga hydropower site 1. The INGA site is located on the Congo River approximately sixty kilometers upstream of the port city of Matadi, which is 150 kilometers from the sea, at the furthest upstream point of the navigable channel on the river. The Inga site benefits from favorable topography (with potential head of 150 meters at Grand Inga and maximum head of 60 meters at Inga 1/2/3) and exceptional hydrology issuing from a huge watershed with varied climates. Average flow of 40,000 m3/s represents about 40 percent of the Amazon river s flow but the Congo s flow variability along the year is much less than the Amazon s. 2. Existing hydropower plants. The Inga hydropower complex currently consists of the following existing installations and structures: An intake on the right bank of the Congo River, with an 8.5km long channel parallel to the Congo River to feed the two existing (Inga 1 and Inga 2) Plants; Inga 1 Power generation station (with 6 Francis turbines) with a total rated power capacity of 351 MW i.e MW per unit; Inga 2 Power generation station (with 8 Francis turbines) with a total rated power capacity of MW i.e. 178 MW per unit; A switchyard receiving electricity from Inga 1 and 2 Plants; 49

60 A substation and double circuit 220 kv transmission line from Inga to Kinshasa; A direct current converter station and a 500 kv direct current (DC) power line from Inga to Kolwezi in the south-east of the country, connecting with transmission lines towards Zambia, Zimbabwe and Southern Africa. 3. The existing Inga 1&2 power plants face a triple challenge: Only 7 units out of 14 are operational (3 at Inga 1 and 4 at Inga 2), for a total available capacity of 745 MW currently i.e. half of the rated capacity. This is the result of deficient O&M. Several units are a long period past their scheduled major rehabilitation and could fail at any time, as evidenced by the recent failure of unit G15 at Inga 1. The intake canal can only carry half its design flow, due to sediment having accumulated over time and structural impediments (rock formations). The 220KV transmission line to Kinshasa has insufficient capacity to feed Kinshasa s demand. 4. World Bank support. The PMEDE project cofinanced by the WB, AfDB and EIB is designed to address the above-mentioned challenges, by financing: (a) the rehabilitation of 860 MW of power capacity at Inga between 2009 and 2015; (b) the dredging and reprofiling of the intake canal to bring its capacity back to about 3,000 m3/s; and (c) the construction of a second transmission line (400 KV) from Inga to Kinshasa to increase the power capacity from current 450MW to well over 700 MW. 5. Subsequent development of Inga site. Subsequent phases of development at Inga would include: (a) Inga 3, an up to 4,300 MW plant (estimated cost of $5-7 billion, excluding transmission lines), and/or (b) Grand Inga, a 40,000+ MW plant (estimated cost over $40-50 billion, excluding transmission lines) but both face major challenges and uncertainties in terms of market, financing and risks, clearly with higher challenges but higher potential rewards for Grand Inga than for Inga 3. Both projects have prefeasibility studies, dating from 2005 and 1997 respectively. The WB and AfDB are financing further preparatory studies, which should allow determining project sequencing and scoping of detailed feasibility studies. The government has requested IDA support for detailed feasibility studies of the Inga 3 project, which appears to be the next logical and reasonable step for Inga development. 6. A technical and financial analysis carried out under PPIAF financing points to a scenario that makes best use of the full potential of the Inga 3 site. It calls for the development of Inga 3 at full feasible capacity (4,300 MW); allocate 3,300 MW for domestic use and 1,000 MW for export. Of the 3,000 MW allocated to domestic use, around 1,500 can be sold to an anchor offtaker within DRC (e.g., BHP Billiton for its proposed aluminum smelter in the Bas-Congo province, with local economic benefits) while the remaining power would be available for domestic use (essentially mining and residential). This scenario meets the domestic needs, the needs of BHP Billiton, and provides for export. 50

61 Appendix 2: Inga rehabilitation strategy 1. The Inga rehabilitation program to be implemented under the PMEDE envisages rehabilitation of part of the generating units at the Inga 1 plant (4 out of 6 units, plus repair of one unit) and at the Inga 2 plant (4 out of 8 units), to make available about 1,300 MW of reliable production at the end of the rehabilitation program by Rehabilitation works are expected to increase the life span of rehabilitated units by an additional 30 years. The program also provides for investments in the Inga intake canal dredging and re-profiling to enhance production capacity at Inga. The water carrying capacity of the intake canal is currently sufficient for only about half of the installed capacity of Inga 1 and 2 plants. 2. The full rehabilitation of all the 14 Inga units (with a total nameplate capacity of 1626 MW and a total maximum capacity of 1775 MW) will take about 10 years, and will be conducted in two phases. The first phase to be conducted over with PMEDE financing will include the rehabilitation of 8 units, while the second phase (over ) will address the rehabilitation of the remaining six units, with financing still to be defined (SNEL is in discussion with a private mining firm for the rehabilitation of Units G25 and G26). The detailed rehabilitation program for the 14 units of the Inga 1 and 2 plants has been discussed and agreed upon with SNEL and its engineering consultants. 3. The overall rehabilitation strategy is based on the following criteria: (a) priority to be given to units that are currently not operating; (b) as there is a financing constraint, the least expensive units to rehabilitate receive priority (lowest $/kw restored); (c) no more than one functioning unit can be rehabilitated at any time due to dispatch requirements to meet demand, and (d) due to work-space limitations at Inga 1 only one unit can be rehabilitated at a time, and no more than two at a time at Inga 2. Employing these criteria, the first phase of this rehabilitation program covering 8 of the 14 units, common facilities and the intake canal of the Inga plants is conducted under the Project and is programmed to be completed in December The scope and schedule of the two phases of the proposed rehabilitation is shown in the diagram below (see Appendix 2 below). The rehabilitation program under the PMEDE includes seven non-operational units (i.e. the G11, G12, G14 and G15 at the Inga 1 plan for a total capacity of 220 MW, and the G21, G22 and G27 at the Inga 2 plant for a total; capacity of 480 MW), as well as one operational unit (G28 at the Inga 2 plant with a 162 MW capacity). The total capacity of rehabilitated units under the PMEDE will be 860 MW. The rehabilitation program also includes the re-profiling and dredging of Inga 8 km intake canal, to be complemented with a continuous dredging program conducted and financed by SNEL. Completion of the rehabilitation of the above 8 generating units will bring Inga to total generating capacity of 1,310 MW by end-2015 consistent with the carrying capacity of the rehabilitated intake canal. 5. The second phase of the rehabilitation will include six of the seven currently operational units (G13 and G16 at Inga 1, and G23, G24, G25 and G26 at Inga 2) and will be implemented over , after the completion of the PMEDE project. SNEL envisages to finance the second phase of the rehabilitation program with a combination of public funds and private finance. SNEL is already in advanced discussions with a large mining company operating in the DRC, which would provide debt financing under semicommercial competitive terms for investments procured under ICB/EPCs for the 51

62 rehabilitation of the G25 and G26 units at Inga 2 (324 MW at an estimated cost of about $70 millions), in addition to the rehabilitation and upgrade of the Inga Kolwezi transmission-line and substations. SNEL would deduct debt service from the mining company s electricity consumption bills and also commit to provide additional electricity capacity to this company (in quantity and time) at prevailing HV tariff. 6. The costs of the rehabilitation program under the PMEDE have been updated on the basis of a report produced by the Project Engineer in August 2010, to reflect the updated scope of the rehabilitation program, findings of additional engineering studies carried out in 2008, as well as the recent international market conditions for electrical equipment and materials, exchange rate fluctuations of the major international currencies, and the lessons learned from rehabilitation of unit G23 at Inga 2 and unit G12 at Inga 1 (ongoing), which showed that the scope of rehabilitation works for units in poor shape an under-maintained is generally higher than estimated at the time of feasibility studies. See details in Appendix 1, Annex 5. For these reasons, and as experienced with the SAPMP Project and other rehabilitation activities planned for DRC power sector, estimates of the rehabilitation costs for Inga 1 and 2 have significantly increased, leading to a considerable financing gap due to cost overruns. 52

63 Appendix 3: Schedule of Inga units rehabilitation (First phase under PMEDE: ) G12 -G14 -G21 -G22 -G23 -G26 -G27 breakdowns and repairs PMEDE Rehabilitation Program dredging of head race -G16 +G12 +G16 +G26 reprofiling of the head race +G11+G21 -G28-G25 +G27 -G11+G14 Available power at the end of PMEDE MW +G15-G16 +G16-G13-G24 +G25-G23 +G22-G26 G28 G16 G25 +G13 +G23 +G26 +G24 G26 G13 G23 G24 Rehabilitated installed power at the end of PMEDE: 948 MW End of the full rehabilitation of the INGA power plant GXY group/activities outside of the PMEDE Program GXY group/activities included in the PMEDE Total available power INGA I + II Rehabilitated installed power G22 G21 G11 G15 Increase of head race capacity by dredging and reprofiling in MW Total available power of origine INGA 1 & 2 Total maximum installed power of origine INGA 1 & G G12 G14 0 Jan 08 Jan 09 Jan 10 Jan 11 Jan 12 Jan 13 Jan 14 Jan 15 Jan 16 Jan 17 Jan 18 Jan 19 Jan 20 Jan 21 Jan 22 Jan 23 Jan 24 Jan 25 53

64 Annex 5: Revised Estimate of Project Costs AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing 54

65 Appendix 1: Basis for revised estimated costs of project generation, and T&D components 1. The need for additional financing arises mainly from project cost overruns that resulted essentially from the following factors: An incomplete/shallow assessment of Inga plants condition at the time of project appraisal in 2006, leading to underestimating the scope of rehabilitation works required at Inga. Degradation in the condition of Inga generation units due to a combination of factors: units old age (most are already beyond their standard life span), operation under non-optimal conditions or long stand by periods, suboptimal maintenance, and project implementation lag. As a result, rehabilitation works include now a largest share of new components instead of plain rehabilitation. Input cost increase: the continued escalation in the various raw material cost since 2006 (mainly copper, aluminum and iron) and labor cost, as well as increased demand, resulted in a dramatic increase in electrical equipment costs. This upward trend is confirmed after a pause due to the financial crisis at end An underestimate of the impact on tenders of the conditions prevailing in the DRC: low interest by qualified firms due to country risk (resulting in limited competition), high transaction costs and complexities of doing business. 2. Revised estimates of project costs were produced by the Project Engineer in its independent assessment report of October Revised estimates take into account all of the above factors regarding project components for which tenders have not started or bids have not been received yet. Scope of works was revised in 2008 after technical visits and additional engineering reviews by the Project Engineer. Lessons were drawn from the rehabilitation of G23 Unit to refine the level of physical contingencies. Finally, classic price adjustment formula and assumptions for US$/Euro exchange rate were used to obtain final cost estimates. For the transmission component, and the emergency distribution and generation components, figures proposed are based on the results of already completed bidding processes. 3. Revised cost estimates account for contracts already signed or awarded for emergency works in generation and distribution, as well as tenders for which bids were received. This applies in particular to Lot 1 (rehabilitation of the G21 and G22 units at Inga 2, which accounts for close to 20 percent of total project cost) for which two bids were received that are about 30 percent lower than the cost estimated by the Project Engineer for this contract. This reflects appropriate competition for this tender. 4. Revised cost estimates for pending tenders include significant physical contingencies: between percent for generation unit rehabilitation components and between percent for civil works for the re-profiling and dredging of Inga intake canal. Price adjustments formula break down the total price into components that are adjusted by price indexes specified for each component. Basic assumptions are as follows: Annual increase of copper cost +7.5% 55

66 Annual increase of aluminum cost :+15% Annual increase of other metals :+ 7.5% Annual increase of salaries : +2.5% Exchange rate 1 =1.35 USS (reference value during the period of the study). Labor cost increase in the sector are also projected for all project components. 5. As a result, HV and MV line component cost are projected to increase by 2.5 percent per year as a result of variation of aluminum and iron prices. The generation and transformer components cost is mainly impacted by copper and iron with an average projected increase of 2.2 percent/year. Finally, the distribution component cost will increase only by a projected 1.9 percent per year. 56

67 Annex 6: Economic and Financial Analysis AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing Forecast Electricity Demand and Supply Balance 1. Three main scenarios of electricity demand and supply balance have been prepared with SNEL to determine the actions required to achieve a stable demand and supply balance in the electricity market in DRC and to meet SNEL s export obligations. 2. There are two main interconnected markets in DRC: (i) the Western market dominated by Kinshasa as the main load center and the proposed BHP-Billiton aluminum plant once it comes into service about This segment of the DRC market is principally served by the Inga 1 and 2 plants until 2020, to be joined by Inga 3 by 2020; and (ii) the Southern market which serves mainly residential, mining and industrial complexes in the Katanga Province, served by local hydro plants and electricity transferred from the Western system through the Inga-Katanga transmission line. Exported electricity to SAPP countries has to transit through Katanga. 3. Both the Western and Southern systems need to be balanced and meet export commitments, taking into account the constraint of the capacity of the Inga-Katanga-Zambia high voltage line. 4. The export market in the short term comprises the power supply agreements entered into between SNEL, the Copperbelt Energy Corporation (CEC) of Zambia, the Botswana Power Corporation (BPC), and Namibia Power (NAMPOWER), and, in the medium term, the significant potential for exports into the SAPP power pool that would arise with the rehabilitation of Inga 1 and 2, and develop with the commissioning of Inga 3 around year On the supply side, for each scenario the assumptions are the same and as follow: Completion of full rehabilitation of Inga 1 and Inga 2 in 2021 with total available capacity of 1610 MW, as per the Rehabilitation Schedule of Annex 4, Appendix 3. Complete rehabilitation of all other existing hydropower plants - 87 MW in the Western system and 445 MW in the Katanga Province - by The construction of new green field power stations in the Western system - about 288 MW by and the construction of additional green field power stations in the Southern system - about 360 MW by Development of Inga 3 starting in 2020 to reach full capacity of 4,300 MW in The SAPMP is fully completed by end-2014 for the HVDC and HVAC transmission system for power transfer capability of 576 MW, to be completed by a doubling of the line with an additional capacity of 1,000 MW by

68 6. On the demand side, three scenarios were considered in the analysis: (i) a base scenario; (ii) high demand scenario; and (iii) a low demand scenario. For all scenarios, the growth in the demand is based on (i) the projected growth of Kinshasa demand and the gradual elimination of unserved demand; (ii) the impact on demand of energy conservation measures already engaged by SNEL; (iii) the impact of increased discipline in billing and collection which will curtail illegal consumption; and (iv) the implementation of the program of the Government aiming at increasing household electricity access. The demand from the industrial centers in Katanga province is based primarily on mining sector developments coming from signed and date certain or highly probable supply agreements. The export market growth is determined mainly by signed medium term supply contracts for a capacity of about 200 MW complemented by surplus available on the DRC domestic market, to be supplied to the SAPP regional market. 7. Tables 6, 7, 8, 9, 10 and 11 below show the supply demand balances for all three scenarios. 8. Baseline scenario. In the base case, the demand considered is the demand that can be met from the transmission and distribution system in its present and future state, assuming no constraint on production capacity, both for the Western and Southern markets. Starting from the demand situation in 2010, demand growth for Low Voltage clients is estimated at 6 percent per year, as a result of natural growth in electricity demand from households that is moderated by measures to control unpaid electricity consumption which currently represent close to 50 percent of residential demand. In addition, the growth rates above are already adjusted downwards to reflect the impact of Demand Side management and Energy Efficiency programs under implementation, which are expected to reduce low-voltage demand over time by up to 13 percent. Demand from the BHP aluminum smelter is added starting in Energy demand in the Western system is forecasted to grow from 3,705 GWh in 2010 to reach 6,654 in 2020 and 19,604 GWh in In the Southern system it is forecasted to grow from 2,719 GWh in 2010 to reach 9,772 GWh in 2020 and 11,675 GWh in Under this scenario, supply will be adequate to meet demand in the Western and Southern systems and to meet the export commitments. Also, the contracted mining load could be met but the additional mining projects would be difficult to accommodate. The transmission line Inga-Katanga-Zambia will be utilized at full capacity from 2021 onward. 10. Low demand scenario. Demand in the Western system is projected to increase at a slower pace (annual average rate of about 2 percent), assuming that the implementation of the Accelerated Access program and the absorption of un-served demand in Kinshasa is delayed. Energy demand in the Western system is projected to grow from 3,705 GWh in 2010 to reach 16,475 GWh in In the Southern system it is projected to grow from 2,719 GWh in 2010 to 9,190 GWh in Committed exports remain at the same level as in the Base Case, but the extra available energy can be used to increase export to the SAPP market because of the additional capacity made available through the higher surplus on the Western and Southern systems. It should be noted that in this scenario, the export capacity is constrained by the capacity of the transmission line from Inga to Katanga and Zambia. 11. This demand scenario may also reflect the situation that could prevail due to a strong implementation of measures to improve efficiency in the distribution system in Kinshasa. 58

69 This would be achieved through improved metering and collection, loss reduction, and overall reliability of supply. The comparison of demand and supply shows that there would be an excess supply mainly in the Western system, which could be exported to the SAPP market, provided the upgrade of the capacity of the Inga-Katanga-Zambia is accelerated. Alternatively, the construction of new plants in the Southern system could be delayed and exports maintained at their original level. 12. High demand scenario. This scenario considers an additional 4 percent growth rate per year of low voltage demand above the baseline scenario, due to mixed results of the illegal connections reduction program (total average per year of 10%). Energy demand in the Western system is projected to grow from 3,705 GWh in 2010 to reach 24,907 GWh in In the Southern system it is projected to grow from 2,719 GWh in 2010 to 15,888 GWh in Also in this case, committed exports remain at the same level as in the baseline scenario, but a shortage appears starting as early as The High Case displays a shortage of capacity both in the Western and Southern systems. To cover the capacity and energy shortage under this scenario, the following measures should be considered: Reducing the contracted supply of electricity to mining projects. The mines would have to develop their own power generation capacities and this may put some mining projects at risk. Seeking to accelerate the implementation of the EE programs, although the implementation of EE programs is difficult to accelerate, as it depends on the behavior of numerous consumers. Deferring the implementation of the Accelerated Access program, at the expenses of the social benefits of access to electricity. Reducing supplies to the SAPP markets, with a loss of revenues for DRC. 14. In conclusion, the following implications for the supply options are valid in order to meet the forecasted demand for all three scenarios: The rehabilitation program of Inga 1 and Inga 2 should be completed no later than The rehabilitation of the other existing hydropower plants, including those in the Katanga Province, should be completed no later than The new green field hydropower stations, Zongo 2, Nzilo 2, Busanga should be constructed and fully operational by Inga 3 development should start by no later than 2015 for first units installed and operational in by 2020, and full completion to 4,320 MW realized by

70 15. As part of the assessment of the proposed additional financing, the economic and financial analysis for the entire project has been updated. The baseline scenario above has been considered for the economic and financial analysis of the project. 60

71 Table 6: Demand-Supply Balance in Energy (GWh) Baseline Scenario 61

72 Table 7: Demand-Supply Balance in Capacity (MW) Baseline Scenario 62

73 Table 8: Demand-Supply Balance in Energy (GWh) Low-Demand Scenario 63

74 Table 9: Demand-Supply Balance in Capacity (MW) Low-Demand Scenario 64

75 Table 10: Demand-Supply Balance in Energy (GWh) High-Demand Scenario 65

76 Table 11: Demand-Supply Balance in Capacity (MW) High-Demand Scenario 66

77 Project Economic Analysis 16. Methodology and main assumptions. Events which have taken place since the preparation of the original project economic analysis have resulted in a modification of some of the key assumptions, as outlined below. 17. Costs of rehabilitation: the estimated cost for the rehabilitation has increased significantly, thereby affecting the project EIRR (and FIRR). Also, the project scope has been modified with the addition of activities (emergency distribution work, management contract and/or technical assistance services, SNEL social costs) whose justification and expected benefits are difficult to capture in a conventional economic analysis. 18. The implementation schedule for rehabilitation has been delayed. It is now envisaged that the planned rehabilitations will be completed by the end of 2015 (instead of 2012). The impact on the project profitability is limited, because the projects costs are also delayed and the string point for the economic and financial analysis is The value of the incremental energy supplied (economic and financial) has increased at the national, as well as the regional level. In particular: For the economic analysis, (i) the cost of self-generation has increased due to increase in price of petroleum products; (ii) the value of exports assumed in the original project document (2.5 US cents per kwh for exports to SAPP and supply to mining companies), appears very low based on existing export contracts which reflect better the context of energy shortages in the region, and (iii) the opportunity cost to mining companies is better known. For the financial analysis, the tariffs have been raised in 2009 and the Government has committed to revisions in the coming years which generally reflect the cost of electricity production, based on the 2009 tariff study. 20. Study timeframe and discount rate. The study timeframe is 20 years, from 2010 to All Net Present Values (NPV) for costs and benefits in the tables below have been calculated considering a (real) discount rate of 12 percent, representative of a high level of risk. 21. It is conservatively assumed that the average load factor for newly rehabilitated generation in Inga would be 70 percent, as per the original project analysis and SNEL actual data for However, due to the project activities, in particular the civil work on the intake canal, the load factor is expected to increase over time. Sensitivity analysis has been performed for lower values of the load factor. The assumptions for transmission losses have remained unchanged (3 percent for transmission to Kinshasa, 10 percent for the HVDC line). Distribution losses in Kinshasa are estimated at about 10 percent. Non-technical losses and non-billed energy are not taken into account in the economic analysis, assuming electricity stolen or unpaid generates the same economic benefits as paid electricity. 22. Project costs. The main quantifiable costs are the total investment costs, including the O&M costs. Table 12 summarizes the project costs used for this economic analysis. 67

78 Table 12: Summary of Project Costs Used in the Economic Analysis Costs US$ millions Generation Transmission 92 Distribution Capacity Building and Governance 81.3 Project Execution 59.8 TOTAL Project benefits. The project economic benefits would result from increased energy supply in Kinshasa and in Katanga (for exports and the local market) and from the extension of distribution in Kinshasa. It is assumed that about 50 percent of the flows of additional energy produced at Inga will go to meet the demand in Kinshasa, while the rest will go towards meeting the export and mining demand. 24. Similarly to the original project economic analysis, the economic benefits associated with the incremental electricity sales have been calculated using (a) the consumers willingness to pay as proxies of benefit for domestic sales; (b) the opportunity costs of alternative supply options for mining sales; and (c) the export tariff for sales outside DRC, as reported below. 25. The value of the willingness to pay (WTP) of consumers of electricity has been calculated as a function of the willingness to pay for three separate classes of customers: residential, commercial and industrial consumers. Residential Electricity Consumption. About 10 percent of present total residential electricity use can be considered minimum lighting requirements. In the absence of electricity supply, households would use kerosene lamps. This portion is valued at the economic cost of US cents 37.9/kWh. The remainder of consumption is conservatively assumed to be valued at US cents 3/kWh (a value lower than the amount of US cents 3.9/kWh envisaged after the tariff revision) at the margin. Commercial Electricity Consumption. For commercial consumers, the willingness to pay is based on a basket in which 30 percent of consumption is assumed to derive from gasoline fired engines at a cost estimated at US cents 20.61/kWh, with the balance provided by SNEL-equivalent sources at about US cents 7/kWh (conservatively, since the revised tariff will be higher or are already significantly so in the case of LV commercial users). Industrial Electricity Consumption. The willingness to pay for industrial customers is based on a basket in which 40 percent of industrial customers are assumed to use diesel engines at a cost estimated at US cents /kwh, and the balance is provided by SNEL-equivalent sources, assumed around US cents 5/kWh (as in the cases above, a value between the current and the revised tariff). 68

79 26. The weighted average WTP for a kwh of incremental electricity supply is derived using the consumption mix presented in the original project paper and in Table 13 below. Based on these factors, the Weighted Average WTP for domestic consumption is US cents 7.87/kWh. Table 13: Willingness to Pay Customer group Consumption mix Willingness to pay (US cents/kwh) Weighted Willingness to Pay (US cents/kwh) Residential 70% Commercial 20% Industrial 10% Aggregate Average An opportunity cost of US cents 12/kWh has been considered for the sales to the mining sector, since this would be approximately the costs associated with a captive HFO power plant to sustain production. For export, the conservative value of US cents 2.5/kWh has been used in the analysis. 27. In accordance with the latest procurement plan, the analysis assumes that the project investments will be finalized by the end of The analysis takes into consideration the economic benefits derived from project investments for the following 15 years. Beyond this horizon, additional rehabilitation might be required and the economic benefits from the project become more uncertain 28. Under these assumptions, the economic net present value (NPV) of the Project, calculated at a discount rate of 12 percent, is US$881.2 million and the internal rate of return is 27.3 percent. It therefore appears clear that although the costs of the project have increased, the benefits still largely overcome the costs of such investment. Table 14 below outline the project cost, benefits and associated NPV and EIRR. 69

80 Table 14: Project Cost-Benefit Analysis 29. Other benefits. In addition to the quantifiable benefits outlined in the economic analysis, the Project will also substantially improve the living standards of the general population by improving access to clean electricity. Although it is difficult to estimate the domestic reduction in CO2 emissions linked to the Project because the counterfactual scenario without Project is difficult to establish, estimated exports to SAPP are likely to substitute for coal-fired generation, currently the most economic base-load generation available in the region. Based on a conservative emission factor of CO2 800g/kWh of coal power generation, the exports to SAPP would reduce CO2 emission by about 1.2 million tons annually as early as This saving corresponds to an additional benefit of US$ 25 million annually, based on pricing of 20$/ton of CO Sensitivity Analysis. Sensitivity analysis has been carried out by considering eight different scenarios, assuming a variation in the distribution losses (5 percent and 15 percent), project costs (+20 percent and -20 percent), project benefits (+20 percent and -20 percent) and in the timeline of capital investments (2-year delay and 1 year advance). A sensitivity analysis has been also performed by varying the average load factor (+15 percent and -15 percent). The results show that the Project is still robust to significant variations in its main variables. It is worth mentioning that the worst case scenario, which combines a 20 percent reduction in revenues from Kinshasa, mining and exports, 20 percent increase in investment costs, two-year delay in capital investment and a 15% lower average load factor, represent a scenario of switching value for the investments (eg the NPV is zero). Results from the sensitivity analysis are presented in Table

81 Table 15: Economic Sensitivity Analysis 31. Additional sensitivity analysis has been performed on the values of distribution losses, since they are highly uncertain. In addition to the base case, values of 5 percent and 15 percent have been considered and the model shows a NPV of US$ million and EIRR percent for the lower value of the distribution losses and a NPV of US$ million and EIRR of 26.53% percent for the higher value. In addition, in order to reach the switching value because of cost overruns, an increase of about 110 percent in current costs would be needed. Project Financial Analysis 32. Assumptions. The financial analysis shares key technical and project costs assumptions with the economic analysis. However, only the project financial benefits accruing directly to SNEL are considered, and the project benefits are assumed to be immune from corporate tax. 33. Evaluation of benefits. The value of additional production and sales due to the project are evaluated through the SNEL present and projected revenues collected, based on average tariff to each of the main categories of consumers after deduction of the T&D and generation costs as appropriate, using the present tariff schedule and considering future adjustments decided by the government in For Kinshasa, the financial analysis assumes that the average retail price would be US cents 5 per kwh billed, accounting again for a 50 percent share of Inga production. Sales for the mining sector and export are valued at cents 7 per kwh billed and 2.5 per kwh billed respectively. 35. Technical and non-technical distribution losses (not including transmission) have been assumed at about 10 percent for all consumers, decreasing to 5 percent due to the 71

82 implementation of the SNEL Emergency Recovery program (Annex 8). It is important to note that current low level of distribution of non-technical distribution losses reflects the fact that the bulk of residential consumption is not metered and billing is based on estimates. 36. The lack of commercial performance with regard to the residential sector is therefore reflected in the significant portion of the revenue billed which is not collected. The assumption is that the collection rate to residential consumers would be 50 percent initially, based on SNEL present performance and increase gradually to 75 percent by Collection for industrial and exports is taken as 95 percent. Incremental transmission and distribution costs are assumed at 10 percent of the collected revenues. 37. With regard to exports and mines, it has been assumed that SNEL will be able to sell the incremental energy supplied at US cents 7 per kwh. Technical losses are deducted from the production of Inga directed to mines and exports (10 percent in 2010 decreasing slightly by 2025, as in the economic analysis). 38. Results. With a timeframe identical as the one used for the economic analysis (until the end of 2030), the model indicates a FIRR for the project entire project of 19.5 percent, well above the envisaged onlending rate of 5%. The Net Present Financial Value of the entire project is US$ million. Table 16 below outline the project cash flow and associated NPV and FIRR. Table 16: Project cash flow 39. Sensitivity Analysis. Similarly to the economic analysis, a sensitivity analysis has been carried out by considering the same eight different scenarios. Also in this case, the results show that the Project is still robust to significant variations in its main variables. Even in the low case scenario, which again represents a switching value for the Project, the FIRR 72

83 is about percent and above the envisaged onlending rate of 5%. The sensitivities are presented in Table 17. Table 17: Financial Sensitivity Analysis 40. Conclusions. From an economic perspective, the economic benefits of the project are clear and robust. However, given SNEL poor commercial performance, and current as well as projected tariffs (which are overall not cost reflective, and distorted), there are risks of the project financial return being lower than expected. This confirms the need to improve SNEL performance and to gradually adjust tariff (a process that has been initiated in 2009). 73

84 Annex 7: Financial Analysis of SNEL AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing Sources of information for the analysis 1. SNEL financial performance over the last few years and future prospects has been analyzed primarily in terms of cash-flow. The major source of financial information for this analysis is the treasury monitoring statement. 2. This statement retraces, by major categories of revenue and expenditure, the flows of funds into and out of the company. It is updated on a monthly basis. It is the primary instrument used by SNEL management to monitor and manage the finances of the utility. The monthly cash balance provided in the document can be reconciled with the Bank statements for SNEL Bank accounts, thereby providing a possibility of external validation. 3. SNEL also prepares annual financial statements, which have been reviewed and certified by external auditors, although with significant qualifications. SNEL annual financial statements are produced in large part for regulatory and taxation purposes, and provide information of lesser relevance, either for SNEL management, or for the analyst. The major reasons for this lack of relevance and reliability of the financial statement are as follows: (a) The statements are produced in Congolese Franc (FC) while the economic currency for SNEL operations is the US Dollar (US$). As a result, the conversion of P&L and Balance Sheet operations from US$ to FC involves the use of multiple exchange rates and the inscription of foreign exchange differences on both sides of the balance sheet. (b) With the collapse of the Congolese economy, SNEL has stopped receiving payments for a large portion of its revenues (with Government entities and parastatals in particular). Likewise, SNEL has mostly stopped paying some of its creditors or servicing its debt (primarily on-lent by the GoC). There are considerable uncertainties regarding the valuation of SNEL fixed assets. On the one hand, any valuation based on depreciated historical costs will tend to understate considerably the value of long lived transmission and generation assets. On the other, SNEL s assets have not been properly maintained and rehabilitated. (c) SNEL has still not put in place a unified financial information system, and the same operation has to be entered separately for the purpose of treasury management and budget monitoring on the one hand, and corporate accounting on the other. Treasury monitoring is a critical concern for SNEL managers, and as a result the information produced needs to be up to date and reliable. This is not the case for accounting: the operations are entered with significant delays and in the absence or systematic reconciliation procedures, should be considered as less reliable. (d) As of January 1, 2011, SNEL has been transformed into a limited liability company and operates under commercial law and new company statutes. However the opening balance of the transformed SNEL has not been produced yet, due to remaining uncertainties regarding asset valuation, asset ownership, debt and receivables restructuring, etc. This 74

85 project supports activities and hands-on technical assistance that will help putting in place a reliable financial information system integrating the major corporate functions (treasury, accounting, commercial, procurement, HR, etc) as well as adequate internal controls. Given the limited implementation capacity and the multiplicity of the challenges that need addressing, this process can proceed only in a gradual manner based on a realistic sequencing of activities. SNEL recent financial performance 4. The original 2007 Project document summarized SNEL s financial performance at the time as follows: the overall picture remains that of a very weak utility, which has not properly maintained or renewed its assets. Two major structural reasons were highlighted for the SNEL s inadequate financial and technical performance. The first one was insufficient revenue collection, attributable to a combination of distorted and non-cost recovering tariffs and low collection rates for some customer categories. Largely as a result of insufficient revenue, SNEL had for years foregone maintenance of the network resulting in lowering the quantity and quality of electricity supply that has in turn impacted negatively on revenue collection. 5. This diagnosis remains largely valid today. SNEL still suffers from the same structural weaknesses. However, the positive trend that was noted in 2007 has also been confirmed over the last 3 years. SNEL has been able to continue to increase revenue collected and has significantly increased its expenditures on maintenance and investments. From 2006 to 2010, the annual revenue collected by SNEL has increased year after year and gone from 115 to 216 MUS$. The increase in SNEL generation has been modest over the same period and the improvement has come essentially from an increase in the revenue per kwh sold which has gone from 1.9 to 3.3 US cents per kwh sold, as a result from improved collection rates, combined with a limited increase in the average tariff per kwh. 6. Overall, average domestic electricity tariffs remain very low at levels that are sufficient to cover current operating costs, but not the cost of capital. Domestic electricity tariffs are highly distorted; especially with regard to residential tariffs which are extremely low because of the lack of indexing for local inflation until 2009 (other tariff categories were regularly adjusted for the depreciation of the Congolese Franc against the US dollar). The distortions are aggravated by the difference in collection rates between customer categories. Overall, low voltage residential users consume more than 40% of domestic sales (in energy volume) but only 13% of the revenue actually collected by SNEL. Commercial users as a whole (including HV, MV and LV) consume a similar proportion of total domestic energy supply but provide SNEL with 6 times more revenue. Payment rate by parastatals is extremely low and has not improved since 2005 while payment rate by the GoDRC has improved. See Table 18 for details on the domestic tariffs and collection by customer category. 75

86 Table 18: SNEL Domestic Tariffs and Collection by Customer Category Sales in Volume Share of energy consumed. GWh % Average price US cents/kwh Sales in Collection Value rate Million US$ % Collection Million US$ Share of Average revenue revenue collected US cents/kwh % Government 330 6% % % Parastatals % % % LV residential 2,417 43% % % LV commercial 210 4% % % MV private % % % HV private 1,430 25% % % Total 5, % % % Sub-total commercial users 2,237 40% % % Source SNEL - commercial statistics annual report During the course of year 2009, the GoDRC implemented the first stage of a phased tariff adjustment that should bring them more in line with costs. At the end of the process, LV residential tariffs would be around 8 US cents/kwh (with a lower 4 US cents/kwh tariff for the poorest users). Even without major tariff adjustment, the potential for increasing total revenue with improved collection is huge. Better payment discipline would also help redirect electricity uses towards productive uses. The current average electricity price (5.0 US cents per kwh) and revenue collection rate (estimated at 68 percent for 2010 including collection on billing for previous years) remain low and leave room for significant further improvement in revenue. Many Sub-Saharan power distribution utilities achieve collection rates in excess of 95 percent. 8. In spite of the increase in revenue, SNEL current cash flow from operations has remained modest in comparison with the size of the utility and its assets. Investments from internal sources have remained limited as a result. The bulk of SNEL s investments have been financed by donors and mining companies which are SNEL s customers (and are able to ensure repayment of their loan by a reduction of their electricity payment to SNEL). SNEL is not a creditworthy entity and does not have access to unsecured commercial loans. On the other hand, its debt service obligations are low, though increasing due to the recent increase in investments 76

87 Table 19: SNEL Summary Cash flow statement and performance indicators SNEL - Cash Flow Statement Total Generation GWh 7,246 7,641 7,850 Energy sold GWh 5,823 6,323 6,597 Revenue collected MUS$ Personnel MUS$ Other operating costs MUS$ Taxes MUS$ Current Operating expenses MUS$ Cash flow from current operations as a % of revenue 15% 22% 21% Investments from internal funds MUS$ Investments from external funds MUS$ Total Investments MUS$ Debt service MUS$ Debt drawdown MUS$ Total - financing activities MUS$ Change in cash balance MUS$ Closing Cash Balance MUS$ Transmission and distribution losses % 19.6% 17.2% 16.0% Revenue collected per kwh sold US cents/kwh Self-financing ratio % 14% 20% 19% Financial Forecast ( ) Assumptions 9. Forecast generation is based on the Energy balance scenario, base case, but includes in addition the generation outside SNEL main interconnected network (Kivu region and isolated centers). The project costs and timing also corresponds to the base case of the economic analysis. 10. The revenue collected per kwh sold would continue to increase over the period as a result of a combination of increased collection rate and gradual tariff adjustments. It would reach 4.7 US cents per kwh in 2016, against 3.3 US cents per kwh in The level of revenue per kwh assumed for 2016 would be achievable without increase in the average tariff if the collection rate reached 95 percent (against an estimated 68 percent in 2010). 11. The detail of SNEL opening balance sheet on January 1 st 2011 is not yet available. Based on the reconciliation of cross debt with the GoC and other parastatals, SNEL appears to be a net creditor. However, given the financial situation of other SOEs, this forecast assumes no repayment to SNEL by other SOEs. It does not take into account potential liabilities for SNEL related to the debt held by FG Hémsiphere. Otherwise, SNEL would assume the debt service for recent investments financed by mining companies as well as for ongoing donor- 77

88 financed projects. The onlending terms for donor-financed investment would be the following: 5 percent interest rate, repayment over 20 years (including a 5 year grace period). The grace period explains the low initial level of debt service in the forecast. Financial Forecast ( ) Results and discussion 12. Based on the above assumptions, the forecast indicates that SNEL would be able to meet its financial obligations throughout the period while maintaining a net positive cash position (except momentarily at the end of 2014). Improved cash flow from current operations would allow SNEL to increase maintenance expenditures as well as the investments financed with internal resources (though the bulk of investments would be financed externally until 2015 as indicated by the self financing ratio). With gradually improved performance and thanks to a large investment program financed in majority with concessional terms, the objective of transforming SNEL into a financially self-sustaining utility within a five-year horizon appears achievable. Table 20: SNEL Summary Cash flow forecast SNEL - Cash Flow Statement Total Generation GWh 7,850 7,979 9,611 9,695 9,455 12,092 14,451 Energy sold GWh 6,597 6,702 8,083 8,173 7,989 10,230 12,226 Revenue collected MUS$ Personnel MUS$ Other operating costs MUS$ Taxes MUS$ Current Operating expenses MUS$ Cash flow from current operations as a % of revenue 21% 25% 34% 36% 36% 44% 48% Investments from internal funds MUS$ Investments from external funds MUS$ Total Investments MUS$ Debt service MUS$ Debt drawdown MUS$ Total - financing activities MUS$ Change in cash balance MUS $ Closing Cash Balance MUS Transmission and distribut. Losses % 16.0% 16.0% 15.9% 15.7% 15.5% 15.4% 15.4% US Revenue collected per kwh sold cents/kwh Self-financing ratio % 19% 12% 10% 10% 6% 41% 69% DSCR

89 13. Continued financial fragility. However, the forecast also illustrates that SNEL financial position would remain fragile. For instance, the reduction in generation expected in 2014 (resulting from the rehabilitation of a turbine previously in operation), would lead to worsening financial indicators (negative cash position, drop in the DSCR). If the base case assumptions for project cost and additional generation were not met, actions on the part of SNEL and or the Congolese authorities would be required to maintain the solvency of the utility. In addition to further tariff adjustments, modulating the schedule of capital repayment on the onlent debt would be a possibility, especially if SNEL faces problems that are expected to be temporary. 14. Improving collection. The major leverage for achieving the expected growth in revenue is the collection rate. SNEL will need the support of the authorities to achieve adequate level of collection, because the three major consumer categories with very low payment rate are: governmental entities, parastatals and residential low voltage customers. In comparison, collection rates are adequate for private commercial users (LV, MV and HV). The issue of payment by governmental entities will be addressed as part of the Project. With regard to parastatals, SNEL needs, with GoC support, to start to enforce payment discipline more systematically and to credibly threaten to cut supply for non payment of new consumption (arrears would be dealt with on the basis of the agreement reached following the exercise of cross debt reconciliation). This restoration of payment discipline should intervene without delay for SOE which are commercial enterprises operating in competitive sectors (for instance Gécamines). With regard to parastatals in charge of critical public services, the objective of restoring payment discipline is also relevant, but should realistically be implemented in a phased approach. This is in particular the case for Regideso, the water utility, whose current cash-flow situation might not allow it to pay SNEL for current consumption let alone accumulated arrears. For the third customer category (residential users), the primary responsibility for improving collection lies with SNEL and will involve a complete overhaul of commercial operations (procedures, information system, metering). 15. Organizational and governance challenges. For a long time, as a result of the conflict situation in DRC, SNEL found itself in a situation where revenue collected barely allowed covering incompressible current expenses. With the increase in revenue, SNEL is now able to devote more resources to maintenance, rehabilitation and investments. However, the organizational capacity with regard to maintenance and investment planning has largely been lost. Also, the procedures and internal controls for managing the additional revenue remain inadequate. In addition, better cost control needs to be put in place, including with regard to personnel costs which have increased significantly since 2006 (+49 percent) and have not been accompanied improvement in labor productivity. These issues are being addressed as part of the Project through the implementation of the corporate governance plan and targeted technical assistance. In addition, as part of the Project, and following the example of SAPMP, binding mechanisms will be put in place, resulting in dedicated funding of Inga s maintenance, so as to ensure that adequate resources are devoted to the maintenance of generation and transmission facilities. 79

90 Improving the quality of SNEL Financial reporting 16. As mentioned in introduction of this analysis, SNEL annual financial statements do not currently reflect the financial reality of the company and cannot be reconciled with cashflow, which is the relevant financial constraint for SNEL. For this reason, SNEL Income Statement and Balance Sheet is not presented in this analysis. Going forward, it will be essential however to move back SNEL towards a situation of normality, in which annual financial statements, verified by external auditors, reflect the financial reality of the company. Some of the required steps in this process are already ongoing or completed as part of the reform of the status and commercialization of the SOE. The preparation of a new opening balance for SNEL entails in particular a reconciliation of cross-debts, and a review of fixed assets (including technical audits, clarification of the ownership regime of some of the assets operated by SNEL but financed by the GoC, review of the rules of reevaluation and depreciation). 17. Given the major weaknesses in SNEL s accounting systems, the financial statements do not provide a reliable image of SNEL s financial liabilities. However, SNEL has a carried out a reconciliation exercise to assess its cross-debts with other public sector entities as of January 1st The amounts were recorded in minutes signed by both parties. The result of the exercise was disclosed by SNEL in March At the beginning of 2008, the confirmed amounts owed by other parastatals to SNEL totaled $ million. The main debtor was Gécamines (292.3) followed by REGIDESO (111.4) and the Kinshasa municipality (103.4). The remainder was owed by about 30 other SOE or public institutions. SNEL owed $ 22.9 million to other parastatals and was therefore a net creditor for more than $ 539 million. A similar exercise of debt reconciliation and certification is carried out between SNEL and the GoC (represented by OGEDEP, the office in charge of managing public debt) semiregularly. On this basis, taking into account only reconciled debt recognized by both parties, a financial consultant (professional auditor) has estimated SNEL was owed $ million by the GoC for unpaid electricity consumption at the end of 2008 (SOFRECO study March 2010 Analyse des conditions de réalisation de l équilibre financier de la SNEL ). At the same debt, SNEL owed $ 69.6 million to the GoC for the onlending of concessional debt (most of which in arrear). Also, the consultant estimated that at the time, SNEL owed $ 63.8 million to the GoC in taxes (this estimate has not been reconciled however). To summarize the situation, in spite of the significant uncertainties, it appears clearly that SNEL is a net creditor with the rest of the public sector (GoC included). The prospect of SNEL being able to collect a significant portion of arrears are however limited. The priority for reestablishing sound sector governance is therefore to restore payment discipline for fresh consumption. 18. With a clean balance sheet, SNEL financial statements would better reflect the current value of its assets and liabilities. But this would not address the disconnect between the financial statements (accounting) and cash-flow statements (treasury). The first and most important step to address this problem is to put in place an integrated financial information system, starting with a unique entry of each operation (instead of two separate entries for treasury and accounting as currently practiced). This would allow reconciliation between the accounting information and bank statements, which is a basic control without which a certification of SNEL financial statements without qualification would not be conceivable. For this reason, the implementation of this single entry is a key objective of the ongoing 80

91 technical assistance to SNEL in the area of financial management. Multiple follow up activities will be needed to put in place adequate procedures, internal controls and accounting rules to address the qualifications formulated by SNEL successive auditors in several areas (provisions, suppliers, inventories, asset register, loans to SNEL staff ). Another target of the short term technical assistance, is improving commercial procedures and commercial information system. Reliable and auditable information on collection and customer receivables is a critical input accounting. The above activities could be implemented over a period of two years, corresponding to an objective of obtaining a certification of SNEL annual financial statements without major qualifications for the year

92 Annex 8: Enhancing SNEL s corporate governance and performance AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing A. SUMMARY 1. Several actions will be supported and/or financed under the Project to enhance SNEL s corporate governance and operational performance, and its financial position and operational sustainability, along the following main lines: (a) a performance contract ( contrat de plan ) between the State and SNEL; (b) a corporate governance plan; (c) SNEL restructuring; (d) a TA services agreement; and v/ Institutional and financing arrangements for appropriate O&M at the Inga plants. The outline of this program is provided below. Main features of the proposed performance contract ( contrat de plan ) and monitoring system 2. Stipulates the respective obligations and commitments of the electric utility (SNEL) and the State to achieve sector objectives over time (as measured by timebound indicators/targets) financial equilibrium of SNEL through a combination of measures such as: cost reflective tariff, reduction of tariff distortions/exemptions, financial restructuring, and operational performance improvements (e.g. cost and loss reductions); improved quality of service; and increased access to electricity. 3. Actions include completion of transformation of SNEL into a limited liability company (see below), mechanisms for settling of debt and future payments for electricity consumption by State and State-owned companies, corporate governance arrangements (see below), State commitment to tariff adjustment and/or financial compensation to reach financial equilibrium; definition and implementation of a corporate strategy to improve SNEL s organization, management, investments, reporting, etc. 4. Includes dispositions for the monitoring and audit of the performance contract, as well as quantitative performance indicators and targets Main features of the corporate governance plan Board composition and appropriate functioning Internal control and reporting mechanism External audits Procurement audits Strengthening human resource actions and performance incentives Guidelines for mobilizing private investment and PPPs, and for contract review 82

93 Communication strategy Disclosure of performance indicators/results Main features of SNEL restructuring Completion of the opening balance for the transformed SNEL (limited liability company since 1/1/2011), including government decisions on asset property (e.g. transfer or not of Inga s assets), asset valuation, balance sheet cleaning up. Debt and receivables restructuring (particularly receivables from SOEs) Definition of SNEL organizational restructuring and staff retrenchment plan Main features of the proposed TA services agreement 5. To include continuous TA on key operational aspects (commercial, financial, accounting, procurement) in counterpart management positions, plus spot TA on specialized aspects, and to support installation of and associated training for improved commercial and financial systems] Institutional and financing arrangements for appropriate O&M at the Inga HEP 6. On the basis of independent evaluation of Inga s operation and maintenance (Consultant is to be recruited by September 2011): Restructuring and strengthening of SNEL s Inga O&M organization, staffing and procedures Costing/programming of appropriate maintenance at Inga Establishment of a financial mechanism (dedicated account with periodic audit of disbursement) to ensure availability of funds for O&M Review and selection of option for Inga O&M institutional arrangements in the medium to long term (option of private operator, possibly with ROT concession for second phase of Inga rehabilitation program, opportunity of combination with Inga 3 development) B. DETAILED PROGRAM Objectives and expected results 7. The objectives of the Emergency Recovery Plan are: Restoring SNELs creditworthiness Restoring the reliability of electricity supply, which is a critical contributing factor to economic growth and poverty reduction; and Creating the conditions for accelerating access to electricity in line with GODRC s objectives. The time horizon of the Plan is five years (from July 2011 to June 2016) 83

94 8. The Plan will comprise actions converging to achieve the stated objectives at two levels: Sector and SNEL corporate governance SNEL internal management Guiding Principles 9. The guiding principles are that (a) SNEL s cash flow should be strengthened to allow the sustainability of maintenance and investment and to encourage PPP financing; (b) the conditions for increased transparency and accountability for performance should be created thanks to improved and systematic technical and financial reporting, as well as increased disclosure of information (both within SNEL and between SNEL and the GODRC); (c) hidden liabilities should be evaluated and integrated in SNEL balance sheet and SNEL accounting systems and internal controls improved to a level consistent with the production of annual financial statements meeting international standards ; (d) reliability of supply and quality of service should be gradually improved; and (e) specific managerial, financial and organizational arrangements should be put in place for Inga facilities in order to ensure sustainability of the rehabilitation investments and to facilitate the development of the site. Actions included in the plan 10. Commercialization of SNEL o Adoption of new Electricity Law o SNEL conversion to commercial status (completed) Appointment of independent Board o SNEL internal management system Schedule for the design and implementation of management systems Implementation of new management system Advisor to ADG for Management system; Introduction of performance incentives for SNEL staff o Putting in place adequate accounting systems and financial control, and create the condition for SNEL to produce annual financial statements meeting international standards by the end of plan. Establish clean opening balance sheet and inventory of assets Put in place an integrated financial information system (see details in SNEL financial analysis) Settlement and rescheduling of Government and SOEs debts (Government Commission) Payment of rescheduled debts by end 2015 Escrow account for debtors until full payment of rescheduled debt managed by a commercial bank Design of procedures to ensure effective collection from Government and SOEs and reliable billing (pre-payment Government, Permanent payment order to the Central Bank for a set amount; public sector, remote metering, SOEs, etc) 84

95 Procedure for payment of SOEs electricity bills o Disclosure of performance indicators and results for internal management and monitoring of Contractual Plan o Implementation of cost reflective tariff according to Government schedule 11. Management efficiency and accountability o Performance contract (Contractual Plan) between Government and SNEL and within SNEL Implementation of a TA program in support of Contractual Plan Preparation of Emergency Plan Implementation road map Independent audit of Contractual Plan and technical performance by external auditor o Billing and collection plan o Staff redeployment, including reduction of staff by attrition and implementation of a Training Plan for reallocation of staff to operational activities 12. Organizational Restructuring o Decentralization and restructuring implemented with increased managerial autonomy of regions o Financially sustainable management of Inga Clarification of ownership of Inga assets and licenses Restructuring of Inga management, staffing and management procedures for operation as a profit center Establishment of ring fenced finances for Inga to ensure sustainability (revenues earmarked for Inga, independent maintenance expenditures budget, management structure with increased autonomy and accountable for performance) Evaluation of technically sound O&M needs to ensure that the O&M budget is adequate and consistent with the sustainability of the investment Independent audit of Inga s operations to assess if maintenance and operations are in line with sound international standards 13. Demand management and Energy Efficiency program in public buildings and private sector to reduce peak demand and electricity bills. 85

96 Governance Area Action Commercialization Electricity Law Submitted to Parliament Adoption of new law at the latest in the first quarter SNEL conversion to Effective Jan commercial status Appointment of independent Board December 2011 Internal management system Operational December 2013 Design of management systems Selection of Experts March 2012 Implementation of management systems Accounting system auditable December 2012 Other management systems December 2013 Advisor to ADG for Management April-December 2011 performance incentives for SNEL staff Implemented by March 2012 Clean financial Audits Clean opening balance sheet and inventory of assets Auditable BS by March 2012 Settlement and rescheduling of Government and SOEs debts December 2011: conclusion of the negotiations and rescheduling schedule Payment of rescheduled debts First payment June 2012 Last payment 2015 Design of Procedures for collection from Government and SOEs July proposal of detailed mechanisms for mechanisms operational on Jan 1st continued implementation and monitoring reconciliation and collection of fresh electricity bills. Collection procedure in place December 2011 Continued monitoring of implementation Continued monitoring of implementation Disclosure of performance indicators SNEL to put in place adequate and to maintain website and disclose information to the public Cost reflective tariff Tariff decree with phased adjustment schedule (in 4 stages) already adopted in 2009 Second adjustment Third adjustment 86

97 Management efficiency and transparency Performance contract Presented to Government July 2011 Disbursement TA program TORs ready by September 2011 Preparation of Emergency Plan Implementation Road End June 2011 map Independent audit of Performance Contract Procurement launched in 2011 Billing and collection September 2011 Implementation Implementation plan Staff redeployment Based on completed study on SNEL Training Strategy Formal adoption of Implemented over two years Implemented over two and action Plan and already contracted human resource redeployment strategy and (ends December 2013) years (ends December redeployment study action plan by SNEL 2013) board in March 2012 Restructuring Decentralization and Starts March 2012 End December 2013 Phase 1 restructuring Financially sustainable Increased managerial and organizational autonomy for Full separate management management of Inga Inga s operation, accompanied by systematic measuring system (procedures, of performance for accountability budgeting, management indicators) established (December) Clarification of Inga s asset legal ownership status July 2011 condition for assets establishing opening balance sheet Adequate and ring-fenced funding for Inga s O&M Dedicated maintenance Transfer of fund as per agreed annual O&M budget account opened by Audit of the appropriate use of funds September 2011 Evaluation of technically sound O&M needs Study of maintenance March 2012 based on requirement by external study results, adoption after consultant consultation with Inga financiers of pluri-annual maintenance budget 87

98 Monitoring of technical and financial performance and independent audit Modalities to be determined could be included in scope of work of existing auditors (outsourced SNEL internal auditor, external auditor, monitoring of performance contract) Demand management and EE in public and private sector Preparation and approval of an EE plan preparation Finalization and approval (March) - Implementation Implementation 88

99 Issues 14. Although the members of the Board are appointed by the Government as long as SNEL is 100 percent state owned, the Board members will be given full independence in the management of SNEL and will be responsible for the implementation of the performance contract. They should include representative of consumers and be selected on the basis of their managerial competence and reputation of professional integrity. 15. The management systems of SNEL are inadequate, in large part because of the absence of systematic and reliable internal reporting. Under the recovery plan, SNEL management, with the support of their TA advisors and external experts, will put in place modern but simple management systems, taking into account the decentralized nature of SNEL and the separation of Inga as a separately managed profit center. The new systems will be deployed over the period, with a parallel training program for SNEL staff for the operation of the systems and the circulation and use of the information produced. 16. SNEL management will have a Register of Assets established; the status of disputed assets will be settled and suitably documented. Due to the large number of physical assets and their geographical dispersion, the inventory will deal in priority with major operational assets. In parallel, a system for the update in real time of changes in the asset base will be developed, and SNEL staff will be trained to ensure the maintenance of the data base and the integrity of the information contained in the system. 17. Based on the reconciliation of the debts of SOEs to SNEL will have been confirmed and suitably documented, it is expect that a repayment schedule will be agreed, a mechanism will be put in place to ensure that the repayment schedule of the main debtors is adhered to. It will include the establishment of escrow accounts for the top ten debtors, which will be obliged to assign revenues from selected high quality clients to a specific escrow account in a commercial bank, from which repayments following the agreed schedule will be taken and transferred to SNEL in priority. 18. In order to avoid the recurrence of the bill payments problems with the Government administrations and the SOEs, the following measures will be taken: (a) for the Government administrations, pre-payment meters will be systematically installed in public buildings. For the consumption of Administrations which cannot have pre-payment meters, a standing payment instruction to the Ministry of Finance or to the Central Bank will be issued for a monthly amount corresponding to the consumption of the Administrations, to be reconciled with actual consumption at the end of the year. 19. The TA program will include support to SNEL managers on key operational aspects (commercial, financial, accounting, procurement) in counterpart management positions, plus just in time TA on specialized aspects including improving billing system, preparation of maintenance plans by function, management of network extension, management of metering installations, and to support for the installation of and associated training for improved commercial and financial systems. The following management areas will be covered through the TA program: finance, commercial, Inga management, generation and transmission, procurement and supplies, Kinshasa Region management and Human Resources management. 89

100 20. The performance contract ( Contrat Plan ) and monitoring system will have the format of a contractual plan between the Government (ministries of Finance and of Energy) and SNEL General Manager. It will stipulate the respective obligations and commitments of the electric utility (SNEL) and the Government to achieve sector objectives over time (as measured by time bound indicators/targets). The Plan will list the actions to be taken by SNEL to achieve the contractual targets, and the enabling measures to be taken on the government side. The Plan will engage the personal responsibility of the General Manager, will be approved by the Board of SNEL and be recognized by the Board as the main instrument to evaluate the performance of the General Manager. The focus of the Plan will be: i/ the financial equilibrium of SNEL through a combination of measures such as: cost reflective tariff, reduction of tariff distortions/exemptions, financial restructuring, and operational performance improvements (e.g. cost and loss reductions) ii/ improved quality of service iii/ increased access to electricity The Plan will have an independent monitoring system based on the semi-annual evaluation of the performance of SNEL management and the Government in fulfilling their respective obligations, and a set of agreed performance indicators. 21. The billing and collection plan will spell out measures to improve billing and collection in a sequenced and targeted manner. Government, and SOEs will be targeted in priority, because their current payment rate is low. Additional measures would be put in place to secure and improve further collection from private industries and commercial activities (which currently contribute to a disproportionate share of SNEL s revenue). In a subsequent phase, the plan would target collection from low voltage residential customers, which remains very low (below 50 percent). The plan will combine technology based measures (pre-payment, remote metering, computerized management of client account), financial instruments such as escrow accounts and guarantee deposits, internal actions within SNEL (e.g. positive and/or negative incentives for staff and management), and possibly the outsourcing of some functions (SNEL has experimented with outsourcing of revenue collection but not metering and billing in some residential areas of Kinshasa). 22. Staff redeployment will have two components: (a) reduction in number through attrition; SNEL s age pyramid shows that a large number of staff will retire soon. Retiring staff will not be replaced, except in key technical positions, and incentives for early retirement will be offered; (b) in response to the observation that SNEL has excess staff in administrative and management positions, while there is a shortage in operational and intermediate level positions, a program of re-deployment will be implemented, providing training for redeployment of administrative staff in operational positions. 90

101 23. SNEL restructuring program will be the first step of a comprehensive sector restructuring as defined in the new Electricity Law. It will include: Completion of the opening balance for the transformed SNEL (limited liability company since 1/1/2011), including government decisions on asset property (eg decision regarding Inga assets), balance sheet cleaning up and development of suitable internal control systems to allow the audit of SNEL s accounts following international standards. Decentralization of responsibilities to the regional level and structuring of Inga as an autonomously managed department Development of a self-contained management structure for Inga, within SNEL to comply with international standards Dedicated financing for maintenance of Inga s facilities based on international standards (ToRs already approved), monitored by international technical and financial auditors, with separate accounts and financial management authority. Separate escrow accounts have already been established for financing Transmission O&M, with the allocation of quality clients to replenish the escrow account as needed. Mechanisms serving similar purposes will be established for Inga s maintenance. Internal transfer price system will be progressively established between Inga and the rest of SNEL to determine the revenue to be allocated to Inga. 91

102 Appendix 1: SNEL s Performance Indicators. Indicators /03/11 1. Hydroelectric and thermal power plants total installed capacity (MW) 2. Hydroelectric power plants total available capacity (MW) Available capacity Inga 1&2 (%) Total energy produced (GWh) Gross energy produced Inga I and II (GWh) Exported energy (GWh) Unavailability T-line Inga-Kinshasa (hours per year) 60,85 74,87 22,33 18,63 8,66 8. Unavailability T-line Inga-Kolwezi ( hours per year ) 630,39 474,88 994,52 781,09 467,1 975,70 9. Distribution losses (%) (3) - (3) - (3) - (3) 10. Non distributed energy (%) (3) - (3) - (3) - (3) 11. Total collection rate (%) 43,79 54,27 59,44 60,81 51, Collection rate with governmental entities (5) (%) , Collection rate SOEs (%) 29,6 37,1 32,6 30,9 20, Collection rate exports (%) Arrears towards private suppliers (US$ million) Tax Arrears (US$ million) Billed energy (GWh) Total number of client Number of client - residential Number of employees SNEL Ratio clients/employees SNEL 70,65 68,42 66,82 69,38 59,87 62, Average tariff ($/kwh) 0,030 0,032 0,048 0,048 0,05 0,05 0, Average residential tariff ($/kwh) 0,023 0,023 0,031 0,039 0, Collected revenues per kwh generated ($/kwh) 0,010 0,013 0,018 0,023 0,019 0, Collected revenues per kwh billed ($/kwh)) 0,0243 0,0278 0,0234 0, Total sales ($ millions) Total collection ($ millions) , , , Personnel costs (US$ millions) 45,635 49,701 49,965 51,506 67,168 18, Actual expenditure on generation maintenance ($ millions) 4,1 (4) 4,5 (4) 3,7 (4 3,9 (4) 30. Actual expenditure T&D ($ millions) 5,6 (4) 7,9 (4) 4,1(4) 10,6 (4) 31. Number of metered customers (%) (2) - (2) - (2) - (2) 32. Operating income (± $ millions) Exit from the workforce (1) Most residential customers are not metered and therefore billing is based on consumption estimates ; (2) : Lack of meters for residential customers makes difficult to measure reliably distribution losses and non-distributed energy ; (3) : Difficult to assess due to the lack of metering at substations ; (4) Data relative to West network (Kinshasa-Bas Congo-Bandundu) ;; (5) State, public institutions, city halls, etc. 92

103 Annex 9: Implementation Support Plan AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing 97. A detailed Implementation Support Plan has been designed to ensure timely and effective implementation of the Project. This plan builds on the lessons learned from the original Project, and the accompanying SAPMP transmission line project, as well as the stepped up measures put in place over the last 18 months to address the implementation challenges. The aim is to align the implementation support required with the Project s expected risks and results. The Plan will be updated every six months, in line with the progress made by the Project. 98. The Plan includes a presentation of implementation risks, strategies and actions aimed to mitigate those risks (as presented in Table 21), a detailed schedule summarizing the required supervision missions, field visits, and other meetings (Table 22), and the required effort and resource commitment in terms of implementation support to ensure successful implementation of the Project (Table 23). 99. Implementation risks associated with Project implementation are presented in Table 21. The table also contains the strategy identified by the team to mitigate those risks and a set of detailed actions to be put in place to sustain those strategies. The risks are extracted from the ORAF (Annex 13), while the set of actions build on lessons learned over the life of the Project and the measures put in place over the last 18 months to improve Project performance. 93

104 Table 21: Implementation Risks, Strategies and Proposed Actions Implementation Risk Implementation Support Strategy Actions Project Quality and Delivery Risk to the quality of Project implementation and result delivery posed by the Project s technical complexity, lack of capacity, lack of resources for proper implementation support. Strengthening of the World Bank team and increased resources for implementation support. TTLship envisaged to be with Senior Power Engineer based in Kinshasa starting from July 1 st. Frequent supervision of the Project with weekly follow up by the team. Formal implementation support missions planned for every quarter until mid-2013 as shown in mission schedule below. Commitment of resources to ensure appropriate implementation support. Appropriate skills mix of staff focusing on the Project both from HQ, from the Country Office in Kinshasa and from within region, eg Senegal, Uganda, Kenya (see Table 23 below). Governance Lack of accountability and poor sector performance due to weak decision making process in Government and SNEL, alongside weak transparency and oversight mechanism in the sector. Risks associated with lack of transparency and capacity in procurement Monitoring appropriate capacity of Implementing Agencies. Monitoring of the Project indicators as included in the Project Result Framework and Monitoring (Annex 3). SNEL corporate governance plan properly designed and implemented. Adhering to mission schedule as outlined in the Implementation Support Plan (see Table 22 below). World Bank Task Team to annually update capacity assessment of implementing agencies. Task Team with the support of the M&E specialist to assess and monitor the values of the Project indicators target during each supervision mission. Field visits to monitor Project outcomes and outputs at least twice a year. Thorough and timely contributions and oversight by World Bank s specialists in the design and implementation of the performance contract between SNEL and the State, SNEL s TA Services Agreement, as well as the completion of SNEL s corporatization. Close monitoring of SNEL Performance Indicators (technical, commercial, financial, human resources, etc). Monitoring of compliance with GoDRC and SOEs obligations and commitments, particularly electricity bill payments. Full discussion of results of annual audit of Performance Contract with Government and SNEL and agreement on action plan for the following year as required. Ensuring transparent and effective Task team to continue close supervision of procurement actions and contract 94

105 and FM management. procurement and financial management by BCECO. Work towards timely transfer of procurement and FM responsibilities from BCECO to SNEL PIU. execution, as per the agreed Procurement Plan. The Team will promptly report any red flags on procurement process and decisions to INT immediately. Support from INT Advisory Services (including through participation in implementation support missions) to enhance BCECO governance structure and oversight mechanisms. Safeguard Risk associated with environmental and social potential negative impacts from Project activities. Financing and Sustainability Additional cost overruns could materialize. Delays in cofinancing of project activities. Operation and Maintenance plan not properly funded, compromising sustainability of project investments. SNEL financial condition worsening Close monitoring of safeguards (dam safety, environment and social issues) to avoid potential negative impacts associated with the project. Avoiding Project cost overruns and mitigation in case they materialize. Close dialogue and collaboration with the co-financiers (AfDB, KfW, EIB). Increasing resource commitment to ensure sustainability of Project activities. FM/Procurement Bank staff in Kinshasa to (i) verify agreed delivery by BCECO of SNEL PIU capacity building in procurement and financial management, as included in agreement between BCECO and Government, and (ii) provide additional capacity building as needed. Close supervision of project activities by the Sr. Environmental Specialist and the Sr. Social Specialist, both based in Kinshasa, including RAPs and ESMPs implementation. Participation of the World Bank Lead Dam Specialist in supervision mission at least once a year as well as review of reports delivered by the Independent Panel of Experts on Inga Dam Safety and recommendations of improvements as required. Conservative physical and price contingencies were considered for additional financing project cost estimates. Additionally, appropriate actions to increase bidder s interest and competition including bidding conferences and technical assessments may be undertaken. Specific actions will be discussed with the RPM and the INT Advisory Services staff. The World Bank team will ensure close support and monitoring and advice to the procurement processes and costing. Sources of potential cost overruns will be identified and brought to the attention of Government and Implementing Agencies for design of appropriate alternative financing. Joint supervision mission with co-financiers will be organized when possible. Live contacts with co-financiers will be maintained on common issues of interest.. Task team to support and closely supervise the design and implementation of the program for maintenance of assets in Inga and the transmission lines, and ensure it is properly funded through escrow account established under the Financial Agreement covenants and side letter. 95

106 and inability to ensure service for Project onlending. Project Stakeholders Inadequate or ineffective stakeholder participation and capacity could undermine success or sustainability of project activities. Implementation of the strategy to improve SNEL corporate governance and performance. Continuous engagement and dialogue with the Government and SNEL to agree on corrective measures and critical decisions needed. Continuous engagement and dialogue with civil society and communities. As mentioned in the Governance section of the Table, the task team will closely support the design and implementation of the performance contract between SNEL and the State, SNEL s TA Services Agreement, as well as the completion of SNEL s corporatization. Those actions will ensure improvement in SNEL and sector financials mitigating the risk of SNEL not servicing the on-lending terms. Scheduled monthly meeting between World Bank Country Director and GoDRC and SNEL CEO, and ad hoc additional meetings as needed. Key issues discussed at Annual and Spring meetings with World Bank s Senior Management. Communication strategy and action plan to be designed and implemented with the involvement of EXT and the Communication specialist based in Kinshasa. Key project documents disclosed in project areas. NGOs and civil society opposition to the project. Task Team and communication specialist to deliver public briefings on Project activities and results at least once a year. Timely World Bank response to information request /complaints from stakeholders. 96

107 100. In order to implement the actions contained in Table 21, close supervision of Project activities is needed. Table 22 outlines a proposed schedule in terms of implementation support mission and key supervision meetings. In particular, in order to consolidate the progress made so far, a heavy mission schedule is envisaged during 2011, 2012 and first two quarters of Missions will be led by the TTL and scheduled jointly with co-financier to the extent possible, to insure alignment in the progress of the different Project components. Mid-term review of the Project is expected in April 2012, when all contracts are expected to have been signed and awarded and the final costs and timeline will be fully known. Weekly meeting carried out between the World Bank team in Kinshasa and the implementing agencies and frequent implementation support missions will also ensure timely contract implementation by monitoring progress on a regular basis and raising issues of concern and potential delays early in the process. It is expected that the measures identified in this Plan will show major progress and the implementation will be set on a satisfactory path. Therefore, starting from the third quarter of 2013, the need for intensified implementation support missions will decrease thereafter to 2016, during which the ICR mission is expected. The calendar below is flexible and will be reviewed twice a year, together with the overall Plan, to ensure adaptability to evolving Project conditions. In addition, field visits will be carried out at least twice a year to ensure appropriate delivery of outputs Weekly meetings will be carried out between the Sr. Power Engineer based in Kinshasa and the Project implementing agencies. As mentioned above, it is envisaged that the TTLship will be transferred to the same Kinshasa-based Sr. Power Engineer starting from July 1, Monthly meetings between Country Director and GoDRC will be carried out to ensure high level oversight and commitment to Project implementation activities. Those meetings will allow for an early identification of problems and implementation issues to be resolved. Appropriate discussion of Project issues will also be carried out during Spring and Annual meetings with World Bank s Senior Management. Table 22: Timeline Implementation Support Missions I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV Supervision Mission X X X X X X X X X X X X X X X Mid Term Review X Field Visits X X X X X X X X X X X Meeting with the PIU Management Meeting Weekly Monthly Senior Management Meeting Semi Annual 102. A significant staff effort is envisaged to meet the implementation challenges characterizing this Project. The Team shows the appropriate skills mix and experience, including staff both from the Country Office in Kinshasa and in Headquarters in Washington, required to successfully implement the Plan. Table 23 outlines the relative staff weeks and travel required to make sure the actions and schedule above are appropriately resourced. Based on this, the overall estimated supervision costs is US$ 460,

108 Table 23: Implementation Support Team Name Title Unit Staff Weeks (per year) Marie-Francoise Country Director (Kinshasa) AFCC2 Marie-Nelly 1 Vijay Iyer Sector Manager AFTEG 2 Philippe Durand Program Coordinator and TTL (until July1, 2011) Hemchand Rai Heeroo Sr. Power Engineer (Kinshasa) AFTEG 8 TTL (from July 1, 2011) Travel (US$ Thousand) AFTEG 8 4x8 Vahid Alavian Adviser, Water and Hydropower AFTEG 1 1x8 Kyran O Sullivan Sr. Energy Specialist (Nairobi) AFTEG 4 2x3 Jean-Charles Kra Sr. Financial Management AFTFM 6 Specialist (Kinshasa) Fabrice Bertholet Sr. Financial Analyst AFTEG 3 2x15 Bourama Diaite Senior Procurement Specialist AFTPC (Kinshasa) 4 Alessandro Palmieri Lead Dam Specialist OPCQC 1 1x15 Manuel Berlengiero Energy Specialist AFTEG 8 4x15 Ananda Covindassamy Consultant AFTEG 3 1x15 Paul Martin Sr. Environmental Specialist AFTEN (Kinshasa) 4 Antoine Lema Sr. Social Specialist (Kinshasa) AFTCS 5 Alexandra Bezeredi Regional Safeguards Advisor AFTOS 1 Louise Mekonda Sr. Communication Officer Engulu (Kinshasa) AFRSC 4 Leonce Kazumba Team Assistant (Kinshasa) AFCC2 4 Raima Oyeneyin Language Program Assistant AFTEG 4 INT Staff 2 1x15 Gilles Veuillot Legal Consultant 1 1x10 Evariste Niyonkuru (Carine Karitini Doganis) Christophe Rockmore Governance Specialist Consultant AFTPR 1 1x15 Sr. Public Sector Management AFTPR 1 Specialist (Kinshasa) M&E Specialist (Kinshasa) AFTDE 1 98

109 Annex 10: Financial Management and Disbursement arrangements AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing 1. BCECO contracted as FMA will remain the Bank focal point for fiduciary aspects. BCECO is very familiar with the Bank Financial Management (FM) procedures and requirements. The FM of the Additional Financing (AF) will follow the same approach as the implementation arrangements in place for the ongoing phase of the project, and are considered acceptable to IDA. The Interim un-audited Financial Reports (IFR) are prepared every quarter and submitted to the Bank regularly (i.e. 45 days after the end of each quarter) in a form and substance that are globally acceptable to IDA requirements, and are current. The FM performance of the project was rated satisfactory following the last implementation support mission conducted in November 2010 and there is no overdue audit report in the projects managed by BCECO or in the sector. The overall FM risk is assessed high. The risk of fraud and corruption within project activities is high given the country context, inherent risks of activities related to large infrastructure, construction activities and equipment acquisitions. SNEL financial statements audit report are also current. It also envisaged the option to transfer by April 2012, the fiduciary responsibility of the project to SNEL including the internal audit function, subject to a satisfactory capacity assessment of the FM Unit put in place to manage the PMEDE and SAPMP within SNEL. The extension of the existing MoU between BCECO and the PCU requires BCECO to build the fiduciary capacity of the FM unit already in place within SNEL. The extended existing MoU provides details on the obligations of both parties (e.g. indicators that will inform on the level of achievement of this aspect of BCECO s contract, reporting, etc). (a) Staffing: the FM aspects of the AF will be handled by the current FM team of BCECO headed by an experienced and qualified FM Director. The current FM staffing arrangement is deemed acceptable to IDA; no additional staff will be recruited. (b) Budgeting and planning: The preparation and approval procedures of the annual work program and budget will follow the same arrangements currently in place and is in compliance with the FM procedures manual (e.g. work program and budget and detailed disbursement forecasts approved by the MoE/SNEL board of directors and submitted to IDA before end of each year). (c) Accounting software: The multi-projects version of the current accounting software TOMPRO already installed at BCECO will be used to manage this AF. Similar accounting software is already installed at SNEL and used. The PIU (CDP-SNEL) uses the Assets management module of the TOMPRO to monitor the projects assets. For the purposes of the transfer of FM responsibility to the PIU, the existing version of the TOMPRO will be updated. (d) Internal controls/ FM procedures manual: The version of the revised FM procedures manual prepared and submitted by the project is deemed acceptable to IDA and can be 99

110 used for the AF. Inclusion of the comments and suggestions from the Bank team following the review of this revised FM procedures manual will be monitored as part of the normal support to implementation of the project (e) Internal audit: The internal audit function of the project is currently contracted to an individual international consultant and such an arrangement operates well. However, following the supervision of the November 2010, it was decided to transfer gradually this function to the internal audit department of the SNEL. Two staff of SNEL will be assigned to the PMEDE but will also cover the activities of the SAPMP. The ToRs of the current internal auditor will be revised within 3 months after the AF effectiveness to reflect the AF but also the need to support the transfer of responsibility of the internal audit function of the two projects to the SNEL internal audit department.. The internal audit function is expected to be transferred to the PIU by March 2012, subject to a satisfactory assessment of the capacity of the team put in place with support of the international internal auditor. (f) Financial reporting: The current content and format of the consolidated IFR are deemed acceptable to IDA. The IFR of the AF will use the same format and content. The IFR of the AF will be prepared every quarter and submitted to the Bank (e.g. 45 days after the end of each quarter) in a form and substance that comply with IDA Financial Management requirements. If and when IFRs are used as the basis of disbursements, the contents and format will be revised to include disbursement-related information. At the end of each fiscal year, the project will prepare annual financial statement with content similar to the ongoing project. There is no overdue IFR at the time of the preparation of the Project Paper for this AF. Disbursement arrangements and flows of funds 2. Flows of Funds - Designated Account. Following a single project approach, the existing Designated Accounts (DA) denominated in US Dollars opened in a commercial bank on terms and conditions acceptable to IDA will be used for the AF. This DA will be maintained by BCECO to receive IDA advances, and to pay for project expenditures eligible for IDA financing. Interest income received on the DA will be deposited into the project account. Additional advances to the DA will be made on a monthly basis against withdrawal applications supported by Statements of Expenditures (SOE) or records as specified in the Disbursement Letter (DL). The ceiling of this DA will be increased to US$ 1,600,000, equivalent to four (4) months of forecasted expenditures expected to be paid from the DA; the new ceiling will be effective upon grant effectiveness... An additional initial advance of US$ 1,300,000 up to the ceiling of the DA will be made into the DA, and subsequent disbursements will be made against submission of Statements of Expenditures (SOE) reporting on the use of the initial/previous advance 3. Disbursement arrangements. Upon AF effectiveness, transaction-based disbursements will be used as for the ongoing project.. The ceiling of this DA will be increased to US$ 1,600,000, equivalent to four (4) months of forecasted expenditures expected to be paid from the DA; the new ceiling will be effective upon grant effectiveness. An additional initial advance of 100

111 US$ 1,300,000 will be made into the DA and subsequent disbursements will be made on a monthly basis against submission of SOE or records as specified in the DL. Thereafter, the option to disburse against submission of quarterly unaudited IFR (also known as the Reportbased disbursements) could be considered subject to the quality and timeliness of the IFRs submitted to the Bank and the overall FM performance as assessed in due course. In the case of the use of the report-based disbursement, the DA ceiling will be equal to the cash forecast for two quarters as provided in the quarterly unaudited Interim Financial Report. If and when IFRs are used as the basis of disbursements, the contents and format will be revised to include disbursement-related information. 4. The grant can be disbursed on the basis of SOE for expenditures under contracts for: (a) goods costing less than US$250,000 equivalent per contract; (b) works costing less than $500,000 equivalent per contract; (c) services of individual consultants costing less than $50,000 equivalent per contract; (d) services of consulting firms under contracts costing less than $100,000 equivalent per contract. In addition to the advance method, the option of disbursing the funds through direct payments to a third party, for contracts above a pre-determined threshold for eligible expenditures (e.g. 20 percent of the DA ceiling), will also be available. Another acceptable method of withdrawing proceeds from the IDA grant is the special commitment method whereby IDA may pay amounts to a third party for eligible expenditures to be paid by the Recipient under an irrevocable Letter of Credit (LC). 5. The grant will disburse 100 percent of eligible expenditures (inclusive of taxes) in line Country Financing Parameters (CFP) for DRC. The proceeds of the grant have been allocated as follows: Category Description Amount Allocated (in US$) 1) Works under Part 1 of the Project 129, 000, % 2) Works under Part 3 of the Project 91,970, % 3) Goods: Percentage of expenditure to be financed (inclusive of taxes) a) Parts 3, 4(a) and 5(a) of the Project 19,400, % b) Part 5(c) of the Project 900,000 4) Pesticides 0 100% 5) Consultants services under: 0 a) Parts 4(a) of the Project 8,560, % b) Part 4(b) of the Project 10,700,

112 c) Part 4(c) of the Project 6) Consultants services: a) For Project management under Parts 1, [2], 3, and 4(a) of the Project b) For PFM agent c) For audits d) For communication program under Part 5 (f) of the Project 7) Operating Costs a) Parts 5(a), (b), of the Project b) Part 5(c) of the Project ,600, % 100% 8) Cost of Establishing Letters of Credit under Part 5(e) of the Project 3,000, % 9) Unallocated 17,820, % Total 282,950, Disbursement of Funds to Service Providers, Contractors and Suppliers. BCECO will make disbursements to service providers, contractors and suppliers of goods and services for specified activities under the AF and will follow the same arrangements of the ongoing project. Payments will be made based on terms and conditions of each contract. 7. Disbursement of Funds to MinEnergie (CATE & PIU). The existing disbursement of funds arrangements to the MinEnerg/SNEL will apply to this AF. BCECO will make disbursements to SNEL (CATE & PIU) for operating expenses and other small amounts based on budget transfers, as set out in a Memorandum of Understanding (MoU) agreed between BCECO and SNEL and the Ministry of Energy. The MoU provides all details on the terms and conditions of the replenishment of the account set up at the MoE and the transfers themselves would be accompanied by supporting documentation in the form of IFRs or SOEs. Payments will be made in accordance with the payment modalities, as specified in the MoU, with an initial advance not to exceed US$50,000. Payments will be made into commercial bank accounts opened by SNEL/CATE & PIU. BCECO will effect subsequent payments to MoE/SNEL upon submission of supporting documentation for the previous payment, as specified in the MoU (IFR, and a Statement of Expenditures (SOE)). In addition, BCECO will rely on the findings and recommendations of the internal auditor for the processing of payments where applicable. BCECO, with the assistance of the internal auditor, will reserve the right to verify the expenditures ex-post and refunds might be requested if contractual clauses were not respected. 102

113 Funds Flow Diagram Overall funds flow is described in the chart below: IDA Designated Account MoE/SNEL (CATE / PIU ) Service providers, contractors, suppliers 8. External Audit: The AF audit arrangements will be similar to the ongoing initial project: project accounts will be audited annually and report submitted to IDA no later than 6 months after the end of each year. Since the AF is expected to become effective in the second semester of 2011, the first audit report may be due on June 30, The ToRs of the project external auditor covering the project expenditures including those incurred by CATE and PIU will be updated, taking into account the AF aspects no later than 3 months following the AF effectiveness. At the time of the preparation of this AF Project Paper, there is no overdue audit report facing the project accounts or the sector. The 2009 audit report of the project accounts was clean whilst the auditor expressed a qualified opinion on the SNEL accounts mainly due to limitation of scope, discrepancies between the accounting data and other sources of information and some internal control weaknesses. Actions have been taken by SNEL management to shorten the delays and implement the recommendations of the audit report. A detailed action plan covering operational aspects (financial, accounting, technology system, human resources, etc) was submitted to the Bank by the SNEL team and is currently under satisfactory implementation with close monitoring by the World Bank s project team. The project (AF) will comply with the Bank disclosure policy of audit reports (e.g. make publicly available, promptly after receipt of all final financial audit reports (including qualified audit reports) and place the information provided on the official website within one month of the report being accepted as final by the team. 9. Governance and Accountability: The risk of fraud and corruption for contracts of service providers and suppliers of goods and services and misuse of funds is assessed as High. The risk of fraud and corruption within this project is high given the country context, inherent risks of activities related to large infrastructure. Therefore, the existing anti-corruption plan (as updated and included in the Project Implementation Manual), as well as the Project Governance Framework (Annex 16), will be used and updated as needed. 10. Governance: PFM reform: The platform presented by the government in 2007 has a strong emphasis on governance, notably in the Contrat sur la Gouvernance or Governance Compact. The platform outlines three sector specific governance priorities (reform of State Owned Enterprises, Mining sector reform and security sector reform), and four cross cutting 103

114 priorities (Transparency, Decentralization, Public Financial Management and Public Service Reform). The PSCDP contributes to the fourth cross-cutting objective, to enhance transparency, mainly the mining sector and reform of the management of the country s prominent State Owned Entreprises- SOEs. More details are provided in annex 8 of the Project Paper: Enhancing SNEL s corporate governance & operational performance. Following various studies carried out between 2002 and 2009 ( e.g. PER, CFAA, PEFA, Aide memoires from IMF ), the Government has adopted a Strategic Plan for Public Financial Management Reform (PFM Action Plan) in March 2010 for three years ( ), the implementation of which was officially launched in August The Strategic Plan outlines short and medium term priorities in PFM. In August 2009 a Steering Committee, the Comité d Orientation de la Réforme des Finances Publiques (COREF) was put in place by the government to coordinate and lead the preparation of public finance reforms and their implementation. 11. Supervision plan: Based on the current overall residual FM risk, the project will be supervised at least twice a year to ensure that project FM arrangements still operate well and funds are used for the intended purposes and in an efficient way. 12. FM Risk assessment and mitigation. The Bank s principal concern is to ensure that project funds are used economically and efficiently for the intended purpose. Assessment of the risks that the project funds will not be so used is an important part of the financial management assessment work. The risk features are determined over two elements: (i) the risk associated to the project as a whole (inherent risk), and (ii) the risk linked to a weak control environment of the project implementation (control risk). The content of these risks is described below: Risk Risk Rati ng Risk Mitigating Measures Incorporated into Project Design Conditions for Effectiveness (Y/N) Residual Risk Inherent risk H H Country level The CFAA, PER and the PEFA reports outlined PFM weaknesses at central and decentralized levels H An ongoing PFM reform is being implemented supported by international donors but may not have any impact on the project N H Entity level None except additional workload and governance issues Project level The resources of the project may not reach all beneficiaries and used for the intended purposes. M-I H BCECO is familiar with IDA FM procedures and staffed with experienced fiduciary consultants; It is expected to transfer gradually fiduciary responsibility of the project to PIU by June 2012 BCECO will strengthen ex-ante and ex-post control of funds and FM procedures manual operational and international internal auditor appointed. N (already in place) Control Risk M-I M-I M-I Annual work plan and budget N (already in M-I Budgeting: weak budgetary execution and control leading to over-expense budgetary or require by December 31, of each year. The project FM Procedures Manual defined the arrangements for place) N M-I H 104

115 Risk inefficient used of the funds. Accounting : increase of the FM team workload leading to some delays Internal Control: Specific aspects of the AF may not be applied or reflected in the FM procedures manual; and procurement internal controls not applied Risk Rati ng L M-I Risk Mitigating Measures Incorporated into Project Design budgeting, budgetary control and the requirements for budgeting revisions. The current FM staffing arrangement is deemed appropriateno need to increase FM staff. Revision of the FM Procedures Manual including specific sections on the AF aspects; use of the international internal auditor to ensure that the project complies with the procedures; increase procurement reviews integrated SPN missions Conditions for Effectiveness (Y/N) N (already in place) N Residual Risk L M-I Funds Flow: Risk of misused and inefficient use of funds and delays in transfer and justification of advances made to Ministry of Energy agencies (PIU, CATE); low disbursement rate Financial Reporting Delay in submission of IFR due to the increase in BCECO activities; format and content of the IFR may not appropriate to report-based disbursement method. Auditing: Delays in submission of audit reports or delays in implementing the recommendations of the management letter or quality of the audit report is a concern Governance and Accountability Possibility of colluding practices as bribes, abuse of administrative & political positions, misprocurement and misuse of funds etc, are a critical issue. M-I M-I M-I H (i) Implementation of the last SPN mission action plan will mitigate delays in justification of the use of funds transferred to these agencies; (ii) ToRs of internal auditors include reviews of use of funds by Ministry of Energy entities (CATE, PIU ); (iii) implementation of E-signature of WA, (iv) option to move toward IFR- Based disbursement.. (i) A computerized accounting system in place.; (e.g. multi projects version) and adequate FM staffing arrangements in place; (ii) IFR format and content to be redesigned to include disbursement-related information Auditing arrangements will follow the existing ones with acceptable external auditors to IDA - no new need to implement specific actions. Greater focus on audit report of SNEL accounts Robust FM arrangements designed to mitigate the fiduciary risks in addition to the PCU overall internal control systems. A Project Governance Framework has been developed ( Annex 16) OVERALL FM RISK H H The overall residual FM risk rating taking into account the mitigation measures is deemed High. Financial Management Action Plan 13. The Financial Management Action Plan described below has been developed to mitigate the overall financial management risks. N N N N M-I M-I M-I H 105

116 Issue Remedial action recommended Responsible entity Revision of the ToRs of the current BCECO/ internal auditor to reflect the AF SNEL and the capacity building activities for the transfer of the function to the IAD of SNEL Internal auditing Internal auditing External auditing Selection of two internal auditors of SNEL to be assigned to the PMEDE and SAPMP. Revision of the ToRs of the current external auditor (project accounts) to reflect the AF BCECO and SNEL BCECO and SNEL Completion date Three month after effectiveness, three month after effectiveness Three months after effectiveness (1): These actions will be monitored as part of the Bank regular support to implementation. FM Conditions No (1) No (1) No (1) 106

117 Annex 11: Procurement arrangements AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-1b) Additional Financing 1. The overall procurement risk rating for the Project is assessed as High given the weak capacity of implementation entities, governance challenges, and history of delays in procurement. Institutional arrangements for the execution of the Additional Financing take into account the need for reinforcing the fiduciary management capacities of the Ministry of Energy (MoE) and SNEL, so as to reduce the risks of delaying decisions and execution of project activities. BCECO will remain the procurement agent of the Project until April 2012 given the intensive procurement work during this period, at the end of which all contracts financed under the project are expected to be signed. SNEL s PIU and the MoE s CATE would thereafter be in charge of supervising contract implementation, with support from the Owner s Engineer in the case of works and goods contracts. BCECO contract with the MoE includes activities to build procurement capacity within SNEL s PIU and the MoE so as to facilitate the transfer of procurement responsibility. An evaluation will be carried out during the project Mid-Term Review (MTR), not later than March 31, 2012, to examine the appropriateness and conditions of the proposed transfer of procurement responsibility. In the meantime, measures to improve procurement execution include the following: (a) (b) (c) (d) BCECO has strengthened its procurement capacity with the establishment of a dedicated team for the Project, which is led by a procurement expert and includes three full time procurement specialists, two almost full time procurement consultants and additional procurement consultants recruited on a needs basis ; More responsibility has been given to SNEL s PIU coordinator in managing and monitoring procurement activities, and ensuring appropriate participation of SNEL s technical departments as well as timely and effective support from the Owner s Engineer. MoE and SNEL management will ensure timely and effective participation of their technical staff in bids/proposals evaluation processes. Streamlined communication and collaboration between entities involved in Project procurement. 2. The procurement section of the revised implementation manual for the Project will include the above measures. The contract extension to be signed with BCECO in March 2011 will include a detailed annex on the mechanism to build capacity and transfer procurement competences to the MoE and SNEL. 3. Procurement methods to be used: There will be no major changes on how procurement will be carried out. This means that the procurement activities under the Additional Financing will be carried out in accordance with the Bank s Guidelines: Procurement under IBRD Loans, and IDA Credits dated May 2004, revised October 2006 and May 2010 ; and Guidelines: Selection and Employment of Consultants by the World Bank Borrowers dated May 2004, revised October 2006 and May 2010, and the provisions stipulated in the Financial Agreement. The existing implementation manual, to be updated will define more clearly the role and 107

118 responsibility of each actor/beneficiary in the management of the procurement cycle. In cases where there are jointly co-financed activities, the procurement process will follow Bank rules and procedures. There will be no exceptions to this rule. Otherwise parallel financing will be used. 4. The procurement reform in DRC began soon after the 2004 CPAR with assistance from the Bank, including the drafting of an Act on the Public Procurement Code (PPL). Progress with the formulation and approval of the Act has been slow, Recent events however can be taken as an indication that the Government and Parliament are committed to moving the reform forward. The law is already approved and was promulgated in April The implementation of the new PPL that is part of the dialog with the government on economic governance is ongoing and key decisions have been agreed to complete the establishment of the new institution not later than April In that sense, the board of ARMP (regulatory body), the staff of the entity in charge of prior reviewing procurement documents (DGCMP) and contract units in pilot ministries are already in place and appropriately staffed; key personal of these institutions are trained on the law itself and the functioning of the whole system. Once the operational staff of the ARMP will be in place and operational, the national procurement procedures will be applicable for all contracts which are not advertised internationally. For this purpose, the Bank procurement team and the government including the project team will discuss and agree on appropriate modifications to clauses of the said code that are not entirely or partially applicable to a Bank-financed project. Any time the PPL itself or its texts of application are modified, the agreed document will be updated accordingly 5. Procurement plan. Before negotiations, the Borrower developed a procurement plan for the implementation of the Additional Financing, covering at least the first 12 months of the Project, which provides the basis for procurement methods to be used for each activity. The Procurement Plan will be updated, with the prior approval of the Bank on an annual basis or as required by the Bank to reflect the project implementation needs and improvements in institutional capacity. 6. Procurement methods and Bank review (a) Contracts for goods and works Procurement Method Threshold for the method in 1000 US$ (a) International Competitive US$ 3,000 or more for works, US$ Bidding (ICB) 500 or more for goods other than (b) National Competitive Bidding drugs and US$ 300 for drugs All contracts estimated below the ICB threshold and above shopping ceiling Bank review in 1000 US$ All contracts The first two contracts (c) Shopping Below US$ 100 for works and US$ 50 for goods Post review (d) UN procurement agencies N/A (e) Community participation in Implementation manual to Post review 108

119 procurement determine the process (f) Direct contracting N/A All contracts (b) Contracts for consultant services Selection Bank review in 1000 US$ methods in 1000 US$ N/A All contracts estimated above US$ 100 N/A All contracts estimated above US$ All contracts estimated above US$ 100 Procurement Method (a) Selection based on quality and cost (b) Least Cost Selection (LCS) (c)selection Based on the Consultants Qualifications (SQC) N/A (d) Individual Consultants (e) Single Source Selection N/A All contracts All contracts estimated above US$ The agreed and approved procurement plan determines procurement methods and the contracts to be submitted to Bank review and no objection. All contracts for works under ICB will be procured using post-qualification of bidders. The term of reference for all services under the Project will be subject to the Bank s prior review. 8. The Bank standard bid documents for goods and the one for works and the Bank standard RFP (Requests for Proposals) will be used for all ICB contracts and contracts for consultants advertised internationally. The same documents will be used for contracts advertised locally until the country has its own standard documents found acceptable by the Bank. For the purpose of clause 2.7 of the Consultant Guidelines, for all contracts estimated below the equivalent value of US$ 75,000, the short list may comprise only local firms. 9. The summarized project procurement plan until end of Project and the associated commitment and disbursement projections are shown in Tables 24 and 25 below. 109

120 Table 24: Updated Project Procurement Plan Description 1. TRAVAUX ET FOURNITURES PROGRAMME DE BASE Lot 1 - Réhabilitation des groupes G21 et G22 d'inga 2 Lot Réhabilitation du groupe G14 Lot Réhabilitation des groupes G11 et G15 d'inga 1 et services communs Lot Réhabilitation du G27-40 millions de EUROS Lot Réhabilitattion du Poste de Dispersion d'inga Lot Réhabilitation du G28 Lot 3 - Reprofilage et Dragage du Canal d'amenée (Travaux) Montant du Marché (en milliers de US$) Date de l'appel d'offres Date de remise des offres Date de rapport d'évaluation Date d'attribution du marché Date de signature de contrat Date de début d'exécution de la mission Date d'achèvement de la mission 129, /10/2010 3/8/2011 5/4/2011 7/18/2011 7/27/2011 1/26/ /15/ , /23/ /16/2010 2/12/2011 6/15/2011 6/24/ /22/ /20/ , /3/ /3/ /31/2011 1/9/2012 1/20/ /23/2013 6/19/ , /14/2012 9/11/ /9/ /17/ /28/2012 7/4/ /26/ , /28/ /26/ /23/2011 2/10/2012 2/23/2012 8/23/2012 9/18/ , /14/2012 7/12/2012 8/10/ /18/ /30/2012 7/2/2014 5/4/ , /28/ /1/ /13/2011 2/1/2012 3/14/2012 9/12/ /7/

121 Lot 5 - Construction de la deuxième Ligne 400 kv Inga Kinshasa Lot 6-1 Electrification de Kimbanseke - Réseau de distribution MT/BT et Raccordement des abonnés Lot 6-2 Electrification de Kimbanseke - Réseau de distribution MT/BT et Raccordement des abonnés Lot 7 - Electrification des poches noires Lot 8 - Electrification de Kimbanseke - Poste 220/20kV, 40 MVA, et ligne 220 kv de 1 km Lot 9 - Programme de décharge - Partie BAD Lot 10 - Acquisition des compteurs Lot 11- Acquisition des lampes de basse 92, /03/ /08/2010 9/21/ /28/ /22/2010 6/22/2011 6/17/ , /31/ /23/2010 1/27/2011 6/23/2011 7/8/2011 1/5/ /7/ , /22/2011 2/17/2012 3/16/2012 6/1/2012 6/15/ /12/2012 9/16/ , /07/2011 4/21/2011 6/6/2011 8/9/2011 8/23/2011 2/21/ /13/2013 8, /25/2011 2/24/2011 5/6/2011 7/25/2011 8/9/2011 2/7/2012 2/3/ , /16/ /14/2011 1/12/2012 3/30/2012 4/16/ /15/ /10/ , /19/ /17/ /15/2011 1/13/2012 1/13/2012 5/16/ /9/2012 3, /19/2011 1/20/2012 2/17/2012 3/2/2012 3/16/2012 7/17/2012 1/14/

122 consommation MESURES D'URGENCE M01 - AOIR - F&M - Compensation réactive à Kimwenza (3x30 MVAr) M02 - ED - F&M - Révision / Remplacement des changeurs de prise en charge M03 - AOIR - F&M - Réhabilitation de Liminga / Lingwala / Mitendi / Autres travaux dans les injecteurs / Travaux dans les sous-stations / Nouvelle Sousstation UPN M04 - AOIR - Fourniture et Installation des Transformateurs de puissance (Dévinière, Kinsuka, Centre des affaires, Limete et Ndolo) M05 - AOIR / 5,71 M - Fourniture et Installation des 3, /08/ /03/ /23/ /23/2009 8/9/2010 6/7/2011 3/2/ /8/ /8/2008 3/13/2009 7/7/2009 8/10/ /20/2010 3/22/ , /3/2011 8/3/2011 8/31/ /2/ /16/2011 5/18/2012 6/12/2014 8, /25/ /10/2009 5/20/2010 9/6/2010 9/13/2010 7/13/ /3/2012 8, /6/ /9/ /21/2010 3/24/ /02/2011 8/4/ /25/

123 lignes aériennes 30kV (Liminga- Sendwe, Liminga- Masina, Limingalimete, Lingwala- Sendwe et Makala- Badiadingi) M06 - AONR - Fourniture et Installation des Protections de la boucle 30 kv (Différentes travées à Sendwe, Gombe, Limete et Masina) M07 - CF - Fourniture des Câbles MT 30 kv pour la remise en état des tronçons de câbles défectueux M08 - AONR - Fourniture et Pose des câbles 20 kv (aériens et souterrains) et AVENANT N 1 M09 - AONR / 0,35 M - Fourniture des 33 transfo 20/0,4 kv, 630 kva pour la conversion en 20 kv des 18 cabines existantes 6,6 kv à Ndjili et 15 cabines 6,6 kv à Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 Intégré dans M03 1, /05/ /15/2009 3/23/ /30/2010 4/14/ /28/2010 5/23/ /14/2009 6/11/ /6/ /12/2009 4/14/ /29/ /25/

124 Kisenso et AVENANT N 1 M10 - AOIR - Travaux de Fourniture et 'Installation des 35 cabines 20/0,4 kv, 630 kva M11 - CF- Fournitures - Equipements et matériel pour les cabines existantes MT/BT (Ruptofusibles MT, disjoncteurs magnétiques BT, base de fusibles) M12 - CF - Fourniture d'équipements pour le réseau BT (câbles aériens et souterrains et accessoires) M13 - CF - Fourniture des Moyens d'intervention (outillage, appareillage, localisateur de défauts, logiciel, etc.) M14 - AONR - Installation d'un transformateur 30/20 kv, Fourniture d'une travée 10, /3/2010 3/15/2011 5/6/2011 6/27/2011 7/12/2011 1/9/2012 2/5/ /13/ /24/2009 3/23/2010 3/29/2010 9/13/2010 3/14/ /09/2011 1, /9/2010 8/12/2010 9/16/2010 9/20/ /24/2010 2/25/2011 8/25/2011 1, /09/ /12/ /10/ /22/ /8/2010 2/9/2011 8/9/2011 Intégré dans M03 et Lot 07 Intégré dans M03 et Lot 07 Intégré dans M03 et Lot 07 Intégré dans M03 et Lot 07 Intégré dans M03 et Lot 07 Intégré dans M03 et Lot 07 Intégré dans M03 et Lot 07 Intégré dans M03 et Lot

125 transfo30/20 kv et cellules 20 kv - Parachèvement des cabines MT/BT de décharge (Acquisition de transfos MT/BT et autres matériels) M15 - AONR - Fourniture et Pose des câbles pour remise en état des départs 6,6 kv des S/S Dévinière, Kinsuka et Poste de Mitendi M16 - AOI - Fourniture et Installation de 3 transfos triphasés 220/30/6,6 kv, 75 MVA pour les Postes de Liminga et Lingwala M17 - AOIR - Finition du Groupe G12 (Fourniture et montage) M18 - AOIR - Jeu de batardeaux amont Inga 1 (18-1), Sécurisation G15 et G16 (18-2), Refrigération Inga 1 (18-3), et Refrigération primaire / secondaire G24, 2, /29/ /26/2009 3/31/2010 4/6/2010 4/21/ /28/ /27/2011 Intégré dans le M03 Intégré dans le M03 Intégré dans le M03 Intégré dans le M03 Intégré dans le M05 Intégré dans le M03 Intégré dans le M03 Intégré dans le M03 20, /14/ /22/2009 1/1/2010 2/5/ /19/ /16/ /24/ , /08/ /15/2009 1/28/2011 6/21/2011 6/28/ /26/ /19/

126 G25 et G28 et Système de traitement des eaux centrales 2A et 2B (18-4) M19 - AOIR - Tableau de distribution CC et CA d'inga 1 (19-2) et Tableau de distribution basse tension des centrales d'inga 2 TGBT + TAGC (Fourniture et montage) M20 - AOI - Système de drainage : Acquisition des pompes d'exhaure d'inga 1 et Contrôle commande (M20.1) ; et Acquisition des pompes d'exhaure d'inga 2A et 2B (M20.2) (Fournitures) TRAVAUX DES BATIMENTS Aménagement des bureaux de la Coordination des Projets de SNEL Réhabilitation du Centre de Formation de Sanga (BAD) par 7, /24/2010 8/26/ /1/2010 2/1/2011 2/15/2011 8/17/2011 7/11/2013 3, /24/2010 8/26/ /1/2010 2/10/2011 2/24/2011 8/26/2011 9/19/ /14/2011 8/16/2011 8/30/ /12/ /13/ /13/2011 6/12/ /7/2012 3/8/2012 3/22/2012 5/8/2012 5/15/2012 6/28/ /21/

127 AON FOURNITURES Mobiliers et Equipements pour les bureaux de la CDP/SNEL Achat des Insecticides (Perméthrine) Bateau épandeur des pesticides Acquisition des véhicules pour la CDP/SNEL Acquisition d'un véhicule pour l'uges /SNEL Matériels informatique, de reprographie, de bureau et divers pour la CDP/SNEL Matériel de bureau pour Cellule Environnementale / UGES Acquisition (6) motos pour Cellule Environnementale /UGES Fourniture matériel pour Laboratoire d'analyse des sédiments du /19/ /31/ /14/ /28/ /12/2011 1/27/2012 7/24/2012 1, /30/ /11/ /25/ /9/ /23/2011 2/9/ /30/ /30/ /11/ /25/ /9/ /23/2011 2/9/ /2/ /17/2011 4/28/2011 5/13/2011 6/28/2011 7/13/2011 7/14/ /9/ /19/2010 2/22/2010 3/8/2010 3/23/2010 4/26/ /1/ /8/ /25/2011 7/7/2011 7/21/2011 9/5/2011 9/19/2011 9/20/2011 1/18/ /25/2008 9/15/2008 NA 9/22/ /20/ /17/2008 1/2/ /29/2008 8/20/2008 NA 8/27/2008 9/24/ /22/2008 1/9/ /14/2011 8/5/2011 NA 9/9/2011 9/23/ /21/ /20/

128 canal d'amenée d'inga Acquisition des logiciels professionnels pour le centre de Formation de Sanga (CFS) - BAD Equipements pédagogiques pour le Centre de Formation de Sanga (CFS) 2. CONSULTANT S Etudes et Surveillance des travaux de réhabilitation des bureaux de la CDP/SNEL Assistance technique à l'unité de Gestion Environnementale et Sociale (UGES) de la SNEL Renforcement du système de gestion financière, administrative et comptable de la SNEL Renforcement du système de gestion commerciale de la SNEL /2/2012 3/15/2012 3/29/2012 4/27/2012 6/12/2012 7/10/ /19/ /8/2011 7/22/2011 8/5/ /4/ /15/ /13/2011 4/25/ /14/ /19/ /29/2010 3/26/2011 3/31/2011 4/30/2011 4/30/ /2/2010 3/11/2010 6/1/2010 8/10/2010 8/24/ /20/2010 4/10/2012 7, /6/ /18/ /1/ /27/2011 1/3/2012 3/5/2012 3/5/2013 8, /6/ /18/ /1/ /27/2011 1/3/2012 3/5/2012 6/5/

129 Plan Directeur de Développement du secteur de l'électricité Réalisation de l'étude de l'onde de submersion (LOMBARDI) dans le cadre de la sécutité des barrages d'inga Recrutement du panel d'experts pour le PMEDE Diagnostic et renforcement de la structure de maintenance Préparation du Plan de réinstallation des populations affectées par le PMEDE Mise en œuvre du Plan de réinstallation des populations affectées par le PMEDE Recrutement des 2 sociologues pour les Ayants-droit d'inga Recrutement de l'expert International en Gestion de Projets Analyse des conditions de 2, /6/ /18/ /1/ /27/2011 1/3/2012 3/5/2012 3/5/ NA 10/18/ /1/ /29/ /20/2010 3/1/2011 7/1/2011 1, /20/2011 NA NA 3/24/2011 3/24/2011 4/15/2011 4/14/ /15/2011 6/25/2011 7/8/2011 9/4/2011 9/10/ /12/2011 6/12/ /8/2010 1/25/2010 NA 7/5/2010 7/26/2010 9/22/2010 3/15/ /12/ /11/ /8/2010 1/27/2011 2/4/2011 4/15/2011 8/15/ /8/2010 NA NA 12/17/2010 1/26/2011 2/25/2011 5/25/ /12/2010 NA NA 2/1/2011 4/15/2011 5/1/ /1/ /20/2009 4/21/2009 5/28/2009 7/24/2009 8/10/ /20/2009 7/7/

130 réalisation de l'équilibre financier de la SNEL Elaboration du cahier des charges et du dossier d'appel d'offres du contrat de gestion de la SNEL Elaboration du Plan social de restructuration de la SNEL Elaboration du Plan de formation des agents de la SNEL Assistance technique à la mise en place d'un système intégré d'informations comptables et financières à la SNEL dans le cadre du plan d'urgence pour l'amélioration des performances de la SNEL Assistance technique en gestion de la facturation et du recouvrement dans le cadre du plan d'urgence pour l'amélioration des /20/2009 4/21/2009 5/28/2009 7/24/2009 8/10/2009 9/8/2009 7/8/ /20/2009 4/21/2009 5/28/2009 7/24/2009 8/7/ /19/2009 6/19/ /20/2009 4/21/2009 5/28/2009 7/24/2009 9/25/ /19/2009 5/20/ /19/2010 NA NA 2/8/2011 2/15/2011 4/15/2011 1/15/ /19/2010 NA NA 2/8/2011 2/15/2011 4/15/2011 1/15/

131 performances de la SNEL Assistance technique en gestion des approvisionnemen ts dans le cadre du plan d'urgence pour l'amélioration des performances de la SNEL Elaboration des APD, Spécifications techniques et DAO - Phase 1 FICHTNER Supervision des travaux - Phase 2 FICHTNER Avenant n 1 à la Phase 1 FICHTNER - Elaboration des DAO des Mesures d'urgence et du Programme de base réaménagé Avenant n 2 à la Phase 1 FICHTNER - La réalisation des Etudes bathymétrique et hydraulique Avenant n 1 à la Phase 2 "Supervision des travaux /19/2010 NA NA 2/8/2011 2/15/2011 4/15/2011 1/15/2012 4, /19/ /13/ /18/ /04/2008 3/25/2008 4/1/ /31/ , /19/ /13/ /18/ /04/2008 3/25/ /1/ /31/2015 4, NA NA NA 2/9/2011 2/12/2011 1/19/ /31/ NA NA NA 7/24/2009 9/11/2009 2/19/2010 2/15/2011 6, NA NA NA 2/9/2011 2/12/ /1/ /31/

132 Expert en Passation de Marchés de l'agence Fiduciaire (BCECO) Expert en Passation de Marchés de l'agence Fiduciaire (BCECO) - Avenant 1 Archivage Electronique du BCECO Audit de l'application des actions environnementale s et sociales Audit de passation des marchés à la SNEL Audit des Etats Financiers de SNEL Assistance technique (OMS) pour la mission entomologique à Inga Renforcement de la communication au sein de SNEL y compris la production des rapports annuels Programme de sécurité des NA NA NA 12/30/ /30/2009 1/2/ /31/ NA NA NA 12/30/ /30/2009 1/2/2011 3/31/ NA NA NA 8/7/2011 8/15/2011 9/15/2011 3/15/ /6/2011 7/19/2011 8/3/2011 9/28/ /5/ /2/ /2/ NA NA NA NA 2/7/2011 3/7/ /31/ /1/ /1/ /22/ /12/ /22/2009 1/26/ /31/2015 1, /12/2010 NA NA 2/1/2011 2/8/2011 3/10/2011 3/10/ NA NA NA 12/30/ /30/2009 1/2/ /2/ /6/2011 7/19/2011 8/3/2011 9/28/ /5/ /2/ /2/

133 barrages d'inga Etude de désalignement des arbres des groupes d'inga 2B Evaluation des besoins de réhabilitation du Centre de Formation de Sanga (CFS) Evaluation des besoins en logiciels et équipements pédagogiques du Centre de Formation de Sanga (CFS) Formation des Formateurs et Recyclage des agents de la SNEL 3. RENFORCEME NTS DES CAPACITES Appui à la CATE et au Ministère de l'energie (5,4 Mios) Consultants Equipements Frais opérationnels Appui Juridique et Financier à Inga 3 1, /15/2011 6/25/2011 7/8/2011 9/4/2011 9/10/ /12/ /12/ /10/2011 4/21/2011 6/20/2011 7/28/2011 8/5/2011 8/19/ /30/ NA NA NA 6/8/2011 6/22/2011 7/21/ /30/ /13/2010 5/28/2010 NA 3/19/2011 3/26/2011 4/24/2011 6/30/2011 2, Année Année , Année 2008 Année 2008 Année 2008 Année /1/ /31/2015 3, Mar-12 NA Mar-12 Mar-12 12/31/

134 Appui aux Partenariat- Public-Privé (PPP) - Miniers hydroélectriques Appui Programme d'électrification décentralisée Programme d'éfficacite énergetique Préparation et Supervision du contrat la Performance de SNEL SNEL TA Services Fonds pour la Maintenance des installations - Partie SNEL/RDC Centre de Formation de 3, Sep-11 NA Sep-11 Sep-11 12/31/2015 4, Sep-11 NA Sep-11 Sep-11 12/31/2015 2, Sep-11 NA Sep-11 Sep-11 12/31/2015 1, Sep-11 NA Sep-11 Sep-11 12/31/2015 9, Sep-11 NA Sep-11 Sep-11 12/31/ , Mar-12 Année 2011 Mar-12 2, à partir de Sept 2011 SANGA 4. EXECUTION DU PROJET Ingénieur-conseil du Projet (FICHTNER) - voir ci-dessus à partir de Sept 2011 Mar-12 Agence de Passation des marchés et de gestion financière - (Bceco, 1 an, 2 ans, 1 an + 3 mois d'appui ponctuel) 3, Année 2009 Année 2009 NA NA 3/1/2008 Plan de Reinstallation volontaire (2ème Ligne) (3,4 mios US$) Mar-11 Compensation 3, Jun-11 Jun-11 Infrastructure Sep-11 Sep

135 Sociale (2ème ligne) Frais de fonctionnement de la CDP SNEL et Equipements (4,0 Mios US$) Frais de fonctionnement CDP sur le PMEDE Emission de Lettre de credit projet Frais de fonctionnement de l'uges et Equipements (1,7 Mios US$) Equipements UGES Frais de fonctionnement UGES Communication Programme Staff de la CDP et Acquisition d'équipements - Partie SNEL/RDC Projet Preparation Facilities (PPF) 1, Mar-11 Mar-11 3, Mar-12 Mar Jun-11 Sep-11 Jun-11 1, Mar-11 Mar-11 1, Jun-11 Jun-11 11, Année 2008 Année , Année 2007 Année 2006 Année 2008 Année /1/ /31/2015 1/1/ /31/

136 Table 25: Commitment and disbursement projections for IDA grant and the whole Project 126