· document of the world bank for official use only report no: 69115-zr project paper on a...

Document ofThe World Bank

FOR OFFICIAL USE ONLY

Report No: 69115-ZR

PROJECT PAPER

ON A

PROPOSED SECOND ADDITIONAL GRANTAND

RESTRUCTURING

IN THE AMOUNT OF SDR 130 MILLION(US$201.5 MILLION EQUIVALENT)

TO THE

DEMOCRATIC REPUBLIC OF CONGO

FOR THE

SOUTHERN AFRICAN POWER MARKET PROJECT (APL1)

AND

RESTRUCTURING

FOR THE

SOUTHERN AFRICAN POWER MARKET PROGRAM (SAPMP)

June 1, 2012

Energy GroupSustainable Development DepartmentAfrica RegionCountry Departments AFCRI and AFCC2This 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.

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CURRENCY EQUIVALENTS

(Exchange Rate Effective April 30, 2012)

Currency Unit = Congolese Franc (CF)CF 904 = US$1

US$ 1.55055 = SDR 1

FISCAL YEARJanuary 1 – December 31

ABBREVIATIONS AND ACRONYMS

AfDB African Development BankAICD Africa Infrastructure Country Diagnotic StudyAPL Adaptable Program LoanBCECO Bureau Central de Coordination (Central Coordination Office)CAPP Central African Power Pool comprising DRC, Republic of Congo,

Angola, Chad, Cameroon, Sao Tome and Principe, Gabon, Equatorial Guinea, and Central African Republic

CAS Country Assistance StrategyCATE Cellule d’Appui Technique à l’Energie, the unit within the MoE

responsible for providing guidance on sectoral strategies and project coordination

CEC Copperbelt Energy CorporationCFAA Country Financial Accountability Assessment CP Compensation Action PlanCPAR Country Procurement Assessment ReviewCQS Selection based on Consultant QualificationsCSO Civil Society OrganizationCOPIREP Comité de Pilotage de la Réforme des Entreprises Publiques, the

Steering Committee for Public Enterprise reformDRC Democratic Republic of CongoEAPP Eastern African Power PoolEIB European Investment BankEIRR Economic Internal Rate of ReturnESIA Environmental and Social Impact AssessmentESMF Environmental and Social Management FrameworkESMP Environmental and Social Management PlanESMU SNEL’s Environmental and Social Management UnitFIRR Financial Internal Rate of ReturnFM Financial ManagementFMR Financial Management ReportsGDP Gross Domestic ProductGoDRC Government of DRCGWh Gigawatt hours (of energy)HIPCHVHVAC

Highly Indebted Poor CountryHigh VoltageHigh Voltage Alternating Current

HVDC High voltage, direct current transmission line

iii

ICBICTIDA

International Competitive BiddingInformation and Communication TechnologiesInternational Development Association

IFC International Finance CorporationInga 1 and 2 The two existing power plants located at the Inga siteInga 3 The proposed new hydroelectric plant at the Inga siteIPP Independent Power ProducerIRR Internal Rate of ReturnLV Low VoltageMoE Ministry of Energy of DRCMV Medium VoltageMW MegawattNGO Non-Governmental OrganizationNPV Net Present ValueO&MOPGWOwner’s Engineer

PADPDOPCB

Operations and MaintenanceOptical Ground WireThe consulting firm providing engineering services to support tender execution and contract supervision under the ProjectProject Appraisal DocumentProject Development ObjectivePolychlorinated Biphenyl

PCU Project Coordination UnitPFM Agent

PIU

The procurement and financial management agent (BCECO) employed by MoE under the ProjectProject Implementation Unit (CDP under French acronym), located within SNEL

PMEDE Regional and Domestic Power Market Development ProjectPPP Public Private PartnershipPRSP Poverty Reduction Strategy PaperRAPRPF

Resettlement Action PlanResettlement Policy Framework

SADC Southern African Development CommunitySAPMP The Southern African Power Market Program (AF1 – First Additional

Financing, AF2 – Second Additional Financing)SAPP Southern African Power Pool SCADA System Control and Data AcquisitionSBD Standard Bidding DocumentsSDR Special Drawing RightsSNEL Société Nationale d’Electricité, DRC’s national power utilitySOE Statement of ExpendituresSOEsSSS

State-Owned EnterprisesSingle Source Selection

TA Technical AssistanceWDR World Development ReportWHO World Health OrganizationWTP Willingness to pay

Vice President: Makhtar DiopCountry Director: Eustache Ouayoro

Regional Integration Acting Director: Elizabeth LuleSector Director: Jamal SaghirSector Manager: Lucio Monari

Task Team Leader: Manuel Berlengiero

iv

DEMOCRATIC REPUBLIC OF CONGOSOUTHERN AFRICAN POWER MARKET PROJECT (APL1)

SECOND ADDITIONAL FINANCING AND RESTRUCTURING

AND

AFRICASOUTHERN AFRICAN POWER MARKET PROGRAM (SAPMP)

RESTRUCTURING

CONTENTS

Data Sheet ........................................................................................................................................... vi

Project Paper

I. Introduction .................................................................................................................................... 1

II. Background and Rationale for the Proposed Additional Financing........................................ 7

A. SAPP and Regional Context ............................................................................................ 7

B. Country Background ...................................................................................................... 10

C. DRC Electricity Sector ................................................................................................... 14

D. Project Background, Objective and Scope ................................................................... 19

E. Project Implementation Status and Issues ................................................................... 21

F. Rationale for Additional Financing............................................................................... 26

III. Proposed Changes ...................................................................................................................... 29

IV. Appraisal Summary .................................................................................................................. 32

A. Project Economic and Financial Re-evaluation ........................................................... 32

B. Financial Analysis of SNEL ........................................................................................... 36

C. Financial Management (FM), Reporting, Audit and Disbursement Arrangements 37

D. Procurement .................................................................................................................... 39

E. Safeguards ....................................................................................................................... 40

F. Results and Overall Risk Rating ................................................................................... 42

Annexes

Annex 1: Revised Results Framework and Monitoring..................................................................... 45

Annex 2: Operational Risk Assessment Framework (ORAF)............................................................ 51

Annex 3: Revised Implementation Arrangements............................................................................. 55

Attachment 1: Transfer of fiduciary responsibilities from BCECO to SNEL’s PIU.................... 72

v

Annex 4: Revised Project Description, Costs and Implementation Status ........................................ 74

Attachment 1: Detailed analysis of proposed additional financing and basis for revised estimated costs................................................................................................................................... 81

Attachment 2: Key contracts under the project ............................................................................ 95

Attachment 3: Revised Estimate of Project Costs......................................................................... 96

Attachment 4: Financing Plan ...................................................................................................... 97

Attachment 5: Required Additional Financing and Original and revised financing plan ........... 98

Attachment 6: SAPMP – Progress and Actions taken since AF1 ................................................. 99

Attachment 7: Revised Implementation Schedule ...................................................................... 103

Attachment 8: Compliance with Legal Covenants...................................................................... 104

Attachment 9: Estimated Revised Disbursement of Total IDA Financing.................................. 106

Annex 5: Description of the Regional Context and Southern African Power Market Program....... 107

Annex 6: The Regional and Domestic Power Markets Development Project (PMEDE): Links with the SAPMP project. Implementation Status and Update since June 2011 ................................. 120

Attachment 1: Enhancing SNEL’s corporate governance and performance............................. 130

Annex 7: Economic and Financial Project Re-evaluation ................................................................ 140

Annex 8: Financial Analysis of SNEL............................................................................................. 149

Annex 9: Implementation Support Plan............................................................................................ 154

Annex 10: Project Preparation and Appraisal Team Members ........................................................ 165

Maps.................................................................................................................................................. 166

vi



AND


RESTRUCTURING

DATA SHEET

Basic Information - Additional Financing (AF)Country Director: Eustache OuayoroSector Director: Jamal SaghirSector Manager: Lucio MonariTeam Leader: Manuel BerlengieroProject ID: P126421Expected Effectiveness Date: 30 September 2012Lending Instrument: Adaptable Program Loan (APL)Additional Financing Type: Cost overrun

Sectors: PowerThemes: Renewable Energy, Regional IntegrationEnvironmental category: A (Full Assessment)Expected Closing Date: December 31, 2015Joint IFC:Joint Level:

Basic Information - Original ProjectProject ID: P069258 Environmental category: A, Full AssessmentProject Name: Southern African Power Market Project

Expected Closing Date: December 31, 2015

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: Co-financing:

EIBCECSNEL

Borrower: Total Bank Financing:

IBRDIDA

NewRecommitted

208.87.34.8

2.5

201.5

201.5

vii

Client InformationRecipient: Democratic Republic of CongoResponsible Agency: Société Nationale d’Electricité (SNEL)Contact Person: Leon Masoso BumbaTelephone No.: +243 813010382Fax No.:Email: [email protected]

Estimated Disbursements (Bank FY/US$m) FY FY13 FY14 FY15 FY16Annual 50.4 60.5 60.5 30.2Cumulative 50.4 110.9 171.3 201.5

Project Development Objective and DescriptionProgram Development Objective:

Original: “The program will increase the availability and reliability of low cost, environmentally friendly electric energy in the Southern African region, thereby increasing competitiveness of industry and fostering economic growth, a key objective set by SADC in its long term Regional Indicative Strategic Development Plan (RISDP). It will help prevent development of uneconomic generation schemes in the region and foster conditions that would be attractive to private developers seeking to invest in the generation sector”.

Revised AF1: N/A

Revised Program Development Objective: “The program will increase the availability and reliability of low cost, environmentally friendly electric energy in the Southern African Power Pool, as well as support further integration and trade between SAPP countries."

Project Development Objective:

Original: “To facilitate the development of an efficient regional power market which would: (i) decelerate the increase of electricity prices in the Southern African Development Community countries through increased competition; (ii) increase industrial competitiveness of the region; (iii) create the conditions for accelerated investment in the power sector, including by the private sector; and (iv) foster regional integration.”

Revised Project Development Objective (AF1): “To facilitate further development of an efficient power market in the Southern African Development Community.”

Revised Project Development Objective (AF2): “To expand transmission capacity to better serve domestic and regional power demand."

viii

Project Description:

Component 1: Support to the SAPP Co-ordination Center;

Component 2: Rehabilitation and reinforcement of the high voltage transmission corridor from Inga to Kasumbalesa at the border with Zambia (the full amount of the proposed additional financing is envisaged for this component);

Component 3: Construction of a double circuit 220 kV line by Copperbelt Energy Corporation (CEC) from Luano substation in Zambia to link the DRC transmission system at Kasumbalesa; and

Component 4: A feasibility and preliminary design study of an interconnector between Zambia and Tanzania that would connect the Southern Africa Power Pool (SAPP) to the East African Power Pool (EAPP).

Safeguard and Exception to PoliciesSafeguard Policies Triggered:Environmental Assessment (OP/BP 4.01) Natural Habitats (OP/BP 4.04) Forests (OP/BP 4.36) Pest Management (OP 4.09) Physical Cultural Resources (OP/BP 4.11) Indigenous Peoples (OP/BP 4.10) Involuntary Resettlement (OP/BP 4.12)Safety of Dams (OP/BP 4.37)Projects on International Waterways (OP/BP 7.50) Projects in Disputed Areas (OP/BP 7.60)

[X]Yes [ ] No[X]Yes [ ] No[ ]Yes [X] No[ ]Yes [X] No[ ]Yes [X] No[ ]Yes [X] No[X]Yes [ ] No[ ]Yes [X] No[ ]Yes [X] No[ ]Yes [X] No

Does the project require any waivers of Bank policies?Have these been endorsed or approved by Bank management?Since the proposed AF2 closing date exceeds three years from the approval date of the AF1 (2009), endorsement by the Managing Director of a waiver to OP/BP 13.20 has been obtained.

[X]Yes [ ] No[X]Yes [ ] No

Conditions and Legal Covenants:Legal

Agreements Reference

Description of Condition/Covenant Date Due

Financing Agreement (FA) –Section 5.01

The Subsidiary Agreement has been executed on behalf of the Recipient and the Project Implementing Entity, in form and substance satisfactory to the Association

Effectiveness

FA – Section 5.01

BCECO and the Project Implementing Entity have signed an amendment to the Protocole d’Accord in form and substance satisfactory to the Association.

Effectiveness

Project Agreement (PA) –Schedule, Section II,B,3

The Recipient shall recruit the Project’s external auditors under terms and conditions satisfactory to the Association.

Not later than three months after effectiveness

ix

PA -Schedule, Section IV, 1

The Project Implementing Entity shall communicate to the public on a semestrial basis, not later than January 31 and July 30 each year, or such later date to be agreed with the Association, throughout the implementation of the Project, an executive summary of its Annual Report and the rates of recovery of invoices by category of customer, in form and substance satisfactory to the Association. The Project Implementing Entity shall make its Annual Report available to the public upon request.

Recurrent

FA –Schedule 2, Section V, 1

The Recipient shall recruit a consultant, selected in accordance with the provisions of Section III of the Schedule to this Agreement, to carry out an independent audit of the performance of both parties under the Performance Contract by not later than March 31 each year throughout the implementation of the Project and shall thereafter implement the recommendations, acceptable to the Association, if any, of such audits by not later than June 30 each year throughout the implementation of the Project.

Recurrent

FA –Schedule 2, Section V, 2

The Recipient shall ensure that the Project Implementing Entity has sufficient funds available to cover its operational costs and to attain the objectives of the Performance Contract. To this effect, the Recipient shall clear its electricity bill arrears vis-à-vis the Project Implementing Entity by not later than December 31, 2012. or such later date to be agreed with the Association, and thereafter remain current in the payment of their future electricity bills to the Project Implementing Entity.

December 31, 2012, then Recurrent

PA –Schedule, Section I, C, 2

The Project Implementing Entity shall update the Project Implementation Manual to, among others, take into account the modification to the fiduciary, procurement and financial management provisions and procedures to be carried out by the Project Implementing Entity.

Not later than September 30, 2012

PA –Schedule, Section I, D, 5

The Project Implementing Entity shall implement the recommendation set forth in the Resettlement Action Plan Audit Report, including the compensation plan, in a manner satisfactory to the Association.

Not later than October 30, 2012

PA –Schedule, Section I, B, 2, a

The Project Implementing Entity shall employ a consultant (the “Technical 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, (ii) the drafting of terms of reference (including the required qualifications and experience) for the appointment of the Operation and Maintenance Contractor (as defined in Paragraph (b) below), (iii) the delineation of the high voltage transmission system for the Operation and Maintenance services; and (iv) the determination, on a quarterly basis, until the Operation and Maintenance Contract has been signed and has become effective, of the funding requirements to perform the Operation and Maintenance of the Project Implementing Entity’s Power Transmission Assets.

Not later than October 30 2012

PA –Schedule, Section I, B, 2, b

The Project Implementing Entity shall employ an entity (the “Operation and Maintenance Contractor”) selected in accordance with the provisions of Section III of the Schedule to this Agreement, for the Operation and Maintenance of the Project Implementing Entity’s Power Transmission Assets, and the provision of training of the Project Implementing Entity’s staff (the “Operation and Maintenance Contract”), for a period of five (5) years.


x

PA –Schedule, Section I, B, 2, c

The Project Implementing Entity shall maintain two (2) foreign exchange accounts (collectively the “O&M Accounts”), each with a commercial bank acceptable to the Association, and on terms and conditions satisfactory to the Association. Each of the O&M Accounts shall be provisioned by the Project Implementing Entity in accordance with terms and conditions, including amounts and timing of each deposit, previously agreed in writing among the Association, the Recipient and the Project Implementing Entity, for the purpose of meeting timely payment of amounts needed for the financing of spare parts, equipment and materials for the Operation and Maintenance of the Project Implementing Entity’s Power Transmission Assets, and payments due under the Operation and Maintenance Contract.

Recurrent

PA –Schedule, Section I, B, 3, a

The Project Implementing Entity shall monitor, review and implement when appropriate the recommendations issued by the consultant selected in accordance with the provisions of Section III of the Schedule to this Agreement for the commercialization of the excess telecommunication capacity.

Recurrent

PA –Schedule, Section I, B, 3, b

Provided the study carried out under paragraph above confirms the Project Implementing Entity’s ability to recruit a Telecom Operator, the Project Implementing Entity shall employ the Telecom Operator, selected in accordance with the provisions of Section III of the Schedule to the Financing Agreement.


FA –Schedule 2, Section I,A,2

The Recipient shall take all measures if appropriate, necessary on its part in order to enable the Project Implementing Entity to recruit the Telecom Operator in accordance with the provisions of Section I.B.3 (b) of the Schedule to the Project Agreement.


PA –Schedule, Section I, A,2

Without limitation upon the provisions of subparagraph (a), the Project Implementation Entity shall maintain in the PMU the following staff, each with terms of reference, qualifications and experience satisfactory to the Association: (i) a Project coordinator; (ii) engineers; (iii) finance and procurement specialists (not later than September 30, 2012 for the latter or such later date to be agreed with the Association); (iv) two environmental specialists; (v) two social scientists; and (vi) support staff.

Recurrent

PA –Schedule, Section II, A, 3

The Project Implementing Entity shall provide to the Recipient not later than December 31, 2015, or such later date to be agreed with the Association, for incorporation in the report referred to in Section 4.08 (c) of the General Conditions all such information as the Recipient or the Association shall reasonably request for the purposes of such Section.

December 2015

FA -Schedule 2, Section I, C, 1

Without limitation on its obligations set forth in Section 4.01 of the General Conditions, the Recipient shall cause an amount equivalent to not less than five million seven hundred and fifty thousand Dollars ($5,750,000) to be provided from the Recipient’s state budget or through the Project Implementing Entity, for the financing of the Project, as counterpart funds

Recurrent

1



AND


RESTRUCTURING

PROJECT PAPER

I. INTRODUCTION1. This Project Paper seeks the approval of the Executive Directors to (i) provide a second additional grant (AF2) in an amount of US$201.5 million to the Democratic Republic of Congo (DRC) for the Southern African Power Market Project (SAPMP) and (ii) restructure the programincluding an extension of the project closing date, and changes in the PDO and results indicators. This project paper also seeks approval of the Executive Directors for a policy waiver to OP 13.20 for the extension of the closing date of the credit beyond three years from the original project closing date at the time of the first additional grant (AF1).

2. Energy is critical to economic development and poverty reduction. Energy service delivery, especially to the poor, contributes to the achievement of the Millennium Development Goals. Without energy, economies cannot grow and poverty cannot be reduced. Energy is an important input to all sectors of the economy, fueling transport to move goods and people and providing electricity to industry, commerce, agriculture, and important social services such as education and health. Electricity availability can have a great impact on social services to poor people in Africa.

3. Sub Saharan Africa faces a desperate power situation. Only 31 percent of the population has access to electricity - the lowest rate in the world. The total installed generation capacity of 68 GW for the whole region, with a population of 800 million, is less than that of Spain, whichhas a population of only 40 million. One consequence is lower enterprise productivity, competitiveness, and employment, and a severe constraint on economic activity and growth. Lack of electrification of schools and clinics also limits public service delivery capability. If current trends continue, fewer than 50 percent of Sub-Saharan countries will reach universal access by 2050, and the absolute number of people without connection will increase. Turning this situation around will call for expanding power generation capacity by around seven percent annually. This means effectively doubling generation capacity each decade. This is the only way the region can keep pace with burgeoning economic growth and social demands for universal access.

4. Large scale hydropower is the solution to increase cost effective and low carbon electricity supply. It is estimated that the most cost-effective way of meeting power needs over the next decade is to double the share of hydro in the region’s generation portfolio adding 25GW to the installed capacity of 18 GW (existing capacity represents no more that 8 percent of regional hydro potential). In addition, this increase would displace 20 GW of thermal plant that

2

would otherwise be built, saving 70 million per year of carbon dioxide emissions (about 8 percent of the region’s anticipated emissions through this period).

5. Untapped hydro resources are concentrated in half a dozen countries; most of them relatively small economies and a few of them fragile states. The hydro-potential in each of these countries is well beyond what could either be consumed or financed domestically for the foreseeable future. Large hydropower projects that may not be economically viable for one of these countries alone become highly valuable when they accommodate demand from multiple countries. Hence, the importance of closer integration of Africa’s power pools to provide the transmission infrastructure needed to export surplus hydro-power potential into the region. A regional approach to hydro-power development is therefore mandatory.

6. All these considerations are at the basis of the creation of the Southern Africa Power Pool (SAPP). Integration of physical infrastructure and regional power trade are vital steps to address supply constraints in this sub region. Integration allows centers of high demand in the south, which are already or close to becoming energy constrained and have traditionally relied on very expensive, oil-based generation, to import more cost-efficient energy, and markedly hydropower, from centers of supply in the north. With power demand projected to grow, a primary challenge for the Southern Africa region is the expansion of power generation and transmission capacity in order to improve security and reliability of supply and cater to future economic and social growth. It is estimated that the region may be losing up to 4 percent of GDP annually as a result of unmet power demand reducing economic investment, productivity and employment.

7. With half of the continent’s water resources, DRC alone has a hydro-power potential of 100 GW. With 40 GW, Inga alone is the largest hydropower site in the world and one of the continent’s most cost-effective power sources (US$0.025/kWh). Inga’s development will allow for a transformational reduction in power costs across the sub-region. Inga 3 is the first phase of the Inga site development. It has been selected by the African Caucus as one of the three hydropower projects in Africa, together with Lom Pangar in Cameroon and Souapiti/Kaleta in Guinea, demanding particular attention from the World Bank. The project could generate up to 4.5 GW without deviating the river’s natural water flow and will cost around US$8 billion (without transmission lines). It has already entered the early phase of development and will be accompanied by a Technical Assistance project, funded by the Bank, and expected to be presented at the board in FY13.

8. The rehabilitation and expansion of the existing high voltage transmission line to the border with Zambia and existing Inga hydropower capacity are currently underway, and are a major stepping stone to power supply in DRC and in the SAPP. The Regional and Domestic Power Markets Development Project (PMEDE – APL1B) will increase the output of the Inga power stations 1 and 2 through the rehabilitation of eight of the twelve existing generating units at Inga to make available about 1,300 MW of reliable production by 2016. The Southern African Power Market Project (SAPMP) will reinforce the power interconnection between the Inga hydropower stations, the industrialized and mining region of Katanga and the Zambian border.

9. The two projects are expected to bring major transformation to the Southern Africa power system by bringing about 2,500 GWh per year of DRC’s greener and cost-effective hydropower into the region, and will lead to an overall reduction in the average cost of electricity within the SAPP, with beneficial effects on industrial competitiveness and growth. Benefits from future development of the Inga site will also materialize for the Central Africa Power Pool

3

(CAPP) and neighboring countries such as Republic of Congo and Angola once the Inga 3 project comes on stream and additional generation capacity for exports becomes available.

10. The two projects will also benefit DRC by providing about 1,000 GWh per year of firm and reliable power supplied to mines, and other consumers in the Katanga Province. Additional domestic benefits will derive from the Community Development Program and the commercialization of the telecommunication services, key for potential development of the private sector and ICT infrastructure along the Inga- Zambia corridor. This adds to the new electricity connections for 280,000 people in Kinshasa, of which about 150,000 are women, financed under PMEDE. By improving the financial revenues, performances and governance ofSociété Nationale d’Electricité (SNEL), the ongoing energy program will also provide support to steer the power sector in DRC towards a sustainable path, enabling SNEL to provide in the long run the much-needed investments to improve the country’s dismal current electricity access rate of only 9 percent.

11. The achievement of the objectives of both projects (accounting together for a total IDA financing of over US$0.8 billion excluding the proposed AF2) depends on the full rehabilitation of the eight generating units at Inga and the long-distance high voltage transmission system from Inga to the border with Zambia.

12. In November 2003, the Bank approved a credit of US$177.5 million for the SAPMP.Once approved, the project immediately faced a series of implementation challenges arising mainly from DRC’s post-conflict situation, and from the technical complexity of the project itself. The Bank approved a first Additional Financing grant (AF1) of US$180.62 million for the project in June 2009. The purpose was to meet an increase in project cost arising from restructuring of the project to scale up and add new activities to ensure that the PDO could be achieved and sustained.

13. Revised cost estimates under AF1 were mainly based on contracts already awarded. For these contracts, base contract prices were known before AF1’s consideration by the Board. As described in the Project Paper for AF1, detailed studies, however, remained to be performed for an outstanding contract covering the rehabilitation of about 2,400 km of high voltage transmission lines (contract 4). The studies included an aerial survey and laboratory testing and revealed that the extent of necessary rehabilitation works on the insulators had been severely underestimated at the time of the AF1, and that the entire 720,000 insulators need to be replaced. This has resulted in a considerable increase in the cost estimate of contract 4, from an estimate of about US$23 million in 2009, to a now-known base cost of about US$181 million in 2012 (i.e. a difference of US$158 million not covered under AF1).

4

Figure 1: Summary Breakdown of Financing Gap

14. The proposed AF2 is therefore required to cover the costs of the replacement of all insulators (80 percent of the proposed additional grant) as well as provide financing for cost overruns due to worse-than-expected conditions for other electrical equipments, such as the need to rehabilitate all three synchronous compensators required for the proper functioning of the transmission system at Kolwezi, for community development activities, and for appropriate physical and price contingencies on all other contracts.

15. The revised set of contingencies has been identified through a quantitative risk analysis carried out by SNEL and its consulting engineer and reviewed by the task team (see detailed analysis in Annex 4). Contingencies now cover also for elements of the transmission system not covered under the SAPMP contracts, but whose availability is essential for the success of the project. The figure above depicts the summary breakdown of the financing gap (taking also in consideration existing savings). This time, contrarily to what happened at the time of the AF1, all major contracts, including contract 4, have been signed and base prices associated with the contracts are known with certainty.

16. The pivotal role of this Additional Financing in positioning the entire Southern Africa region for competitiveness and growth through more reliable and climate friendly energy solutions warrants taking on the risks associated with this operation, including those linked with operating in DRC where the hydropower potential stands, in particular the governance of the national power utility (SNEL).

17. The additional financing would build on the Government’s renewed commitment to reform SNEL under a phased approach with the support of the cluster of energy projects. In fact,

5

the Government and SNEL have completed and made progress on a series of key actions as agreed under the PMEDE, such as (i) the appointment in September 2011 of a new independent Board and General Manager for SNEL; (ii) the signing of the performance contract between SNEL and the Government, in advance of the targeted date of March 31, 2012; (iii) the finalization of the Request for Proposal for the SNEL Technical Assistance services agreement and the initiation of the recruitment process.

18. The team is also working closely with the World Bank’s Integrity Vice-Presidency (INT)to ensure integrity of implementation activities going forward. INT supported the team in developing an Implementation Support Plan (see Annex 9) including a series of anti-corruption and transparency measures, in line with what was supported under the additional financing for PMEDE, including the identification of early warning red flags and mitigating measures.

19. The IDA contribution to the additional financing would be managed under the sameinstitutional arrangements until September 30, 2012. A capacity building program has been designed to ensure the transfer of fiduciary responsibilities from BCECO to the PIU/SNEL on October 1, 2012 (see Attachment 1, Annex 3). The implementation of the program will be closely monitored by the Bank’s fiduciary team in Kinshasa and will ensure that there is enough capacity in SNEL to carry out fiduciary functions without jeopardizing project implementation.

20. Improving governance at different levels of the project implementation environment is paramount for the materialization of the benefits associated with the program and other Bank operations. The Box below summarizes the different levels of governance intervention and how the Bank is providing support for each one of them. Further details could be found in the respective sections of the Project Paper.

Table 1: Improving Governance – Key Actions and Bank’s SupportLevel Key actions Bank instrument

Regional Support to the SAPP institutions to improved regional planning, coordination, technical and regulatory capacity.

SAPMP (Component 1 and 4)

Other Bank’s operations including the Kafue Town –Muzuma –Victoria Falls Transmission Line Reinforcement

Country Improving DRC legal and governance framework and transparency in revenue management of natural resources activities.

High level discussion on the Country Economic Governance Matrix

Other Bank’s operation in the natural resource sector (eg Promines)

Sector Improving SNEL governance and performance.

Key actions include i) signed Performance Contract between State and SNEL; ii) Technical Assistance Service Agreement for SNEL; iii) short term Action Plan to improve SNEL performances and institutional arrangements in key areas (billing and collection rateimprovement, financial management and

PMEDE and specific dated covenants under SAPMP

6

procurement). Recommendations from the consultants will be implemented by SNEL in the short-term and considered in the preparation of the Enterprise Business Plan, a key initial action that is part of the signed performance plan.

Project Implementation of designed Action Plans to improve the project implementation performance.Key actions include: i) timebound actions to be carried out over the next 3 months by theOwner’s Engineer to address identified performance shortcomings; and ii) increased Bank’s supervision

Ensure integrity of project implementation activities, including a series of anti-corruption and transparency measures, identification of early warning red flags and mitigating measures.

Building SNEL PIU capacity to manage the project and allow the transfer of fiduciary responsibility from BCECO to PIU SNEL

PMEDE and SAPMP

21. The Additional Financing is consistent with the current Country Assistance Strategy for DRC, the Bank’s Africa Strategy, and the 2010 and 2011 World Development Reports (WDR).One of the strategic elements of the CAS is that rehabilitating and expanding of electricity transmission systems and supporting DRC’s central role within the development of regional power networks will achieve high, sustained and shared economic growth. The competitiveness and employment pillar of the Africa Strategy comprises targeted interventions to address infrastructure constraint with a focus on cross-border transmission lines and a fiber-optic backbone. The Additional Financing is also aligned with the 2011 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. According to the WDR 2010, climate change must be urgently addressed with means such as regional power trade which can provide the least cost energy supply with reduced carbon emissions. While affirming that providing security, justice and jobs is crucial to break cycles of violence, the WDR 2011 also stresses the importance of electricity for jobs and security.

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II. BACKGROUND AND RATIONALE FOR THE SECOND ADDITIONAL GRANT (AF2)

A. SAPP and Regional Context

22. The Southern Africa Power Pool (SAPP) connects the power systems of twelve countries, including ten countries of the Southern Africa sub-region (Angola, Botswana, Lesotho, Malawi, Mozambique, Namibia, South Africa, Swaziland, Zambia, Zimbabwe) and Tanzania and DRC. Nine of these are operating members, namely linked to the interconnected grid that carries around 97 percent of the energy produced in SAPP. The non-operating members – which are yet to construct transmission links to the regional grid – are Angola, Malawi and Tanzania.

23. The SAPP region spans a vast geographical area of nearly 9.09 million square km, which is home to over 250 million people. Overall, the economic geography of the region is challenging. Of the 12 member countries, six are landlocked, six have populations below 15 million people, five have economies smaller than US$10 billion per annum, and several rely on transnational river basins for their water resources. Nevertheless, the region as a whole has experienced strong economic growth in the last decade, until the onset of the global financial and economic crisis. Historical figures show that regional demand has increased at an average rate of nearly 3 percent between 1998 and 2005, reaching up to 4-5 percent between 2005 and 2008.Growth has also rebounded after the crisis and is expected to remain steady in the foreseeable future. Accordingly to the 2011 IMF World Economic Outlook, regional GDP and average GDP per capita are predicted to increase by 6 and 4 percent per annum respectively from 2010 to 2016 (see Annex 5).

24. Demand growth has been largely driven by the mining and manufacturing sectors in South Africa and the BLNS countries (Botswana, Lesotho, Namibia and Swaziland) as well as in DRC, Zambia and Zimbabwe. However, population growth, rural electrification and improved economic performance have also resulted in a steady increase in residential demand. The electrification rate in the region has significantly grown over time, from less than 20 percent in 1999, to nearly 26 percent in 2010. The total number of electricity customers of the combined national interconnected systems has reached 66 million. Total peak demand has reached 45,761 MW in 2010, with South Africa accounting for about 80 percent of the regional consumption.

25. Conversely, excess capacity – which had been an enduring feature of the region’s electricity sector over two decades – has been shrinking since 2007, when the SAPP began to face serious supply deficits. Regional demand growth, deferral of major generation investments and retirement of aging plants have all contributed to this outcome. In 2007–2008, South Africa experienced severe supply shortages leading to power cuts and load shedding seriously affecting industrial and residential consumption alike. Historically, South Africa had exported electricity to many SAPP countries including Botswana, Lesotho, Namibia and Swaziland, which were relying on South Africa for a significant proportion of their energy supply. Faced with domestic supply constraints, South Africa started curtailing electricity exports. All SAPP countries, with the exception of Mozambique and Tanzania, are now short of generation capacity to meet their domestic demand.

26. With power demand projected to grow, a primary challenge for the Southern Africa region is the expansion of power generation and transmission capacity in order to improve

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security and reliability of supply and cater to future economic and social growth. It is estimated that the region may be losing up to 4 percent of GDP annually as a result of unmet power demand reducing economic investment, productivity and employment (SAPP Pool Plan, 2009). Integration of physical infrastructure and regional power trade are vital steps to address supply constraints. Security and reliability of supply can be greatly improved by taking advantage of different resources and different peak demand times across the SAPP region and by sharing generation reserve margins among several utilities or countries. All these considerations are at the basis of the creation of the SAPP.

27. The SAPMP 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 the development of the integrated Southern African Power Pool (SAPP). Together, the SAPMP and its companion project the PMEDE, 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.

28. 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 asignificant portion of the electricity generated from the Inga hydropower complex in the DRC available to the SAPP, and thus reduce the role of thermal power generation in the region. Annex 5 contains a detailed description of the SAPP program and analysis of the regional context summarized below, while Annex 6 provides an update on the PMEDE implementation status and its links with SAPMP.

29. Besides the SAPMP (APL1) and the PMEDE (APL1B), the Bank and other development partners have supported the Malawi – Mozambique (APL2) and the Mozambique – South Africa interconnections. Unrelated political issues lead to the cancellation of the Malawi –Mozambique interconnection three years after its approval by the Bank. The preparation of the Mozambique – South Africa interconnection, which will boost development of hydropower in Mozambique, is at an advanced stage. The Bank and other development partners are exploring an innovative PPP structure for its financing. Other regional transmission projects are under development in Zambia and Tanzania to link SAPP and EAPP.

30. The transfer of power through the Inga-Zambia Interconnection financed under the SAPMP constitutes a transformative opportunity for the Southern Africa region. Once completed, the project will support exports of about 2,500 GWh1 per year of DRC’s greener and cost-effective hydropower into the region and will lead to an overall reduction in the average cost of electricity within the SAPP, with beneficial effects on industrial competitiveness and growth in the Southern Africa region. Those benefits will increase even further once Inga 3 comes on stream and additional generation capacity for exports become available.

31. The Africa Infrastructure Country Diagnostic Study (AICD), completed in 2010 by the World Bank, estimates the benefits of full expansion of regional power trade in the SAPP region, which hinges on the development of 7,640 MW of hydropower in DRC to be dedicated to supplying export markets in neighboring countries. The displacement of thermal generation with

1 This corresponds to about 300 MW of capacity. The rest, about 200MW or 1,600 GWH per year, will go to meet domestic demand in the Katanga region. Those estimates are based on SNEL’s current and potential export Power Purchase Agreements (see Annex 5, Para. 21 to 27).

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cost-effective hydropower from DRC could save the SAPP region US$1.1 billion annually in power costs and reduce the long run marginal cost of power from US$0.07 to US$0.06 per KWhor 5 percent overall. The largest benefits would be felt by small countries with thermal-basedsystems, which could save as much as US$0.05 per KWh or more than 40 percent of power costs overall. The investments associated with additional generation capacity and regional interconnections needed to enable power trade would be recouped in less than a year and yield a return of 167 percent to the region as a whole. The shift to cleaner energy would reduce regional carbon emissions by a significant 41 million tons annually.

32. The SAPMP also holds great signaling potential and is critical to DRC’s long term regional trade aspirations. Hydropower imports in particular may significantly contribute to strengthen base-load capacity in several countries, allowing them to avoid brownouts or blackouts. As a result, economic gains from imports would be significant. The cost of unserved energy is extremely high among SAPP countries, reaching up to US$3.00/kWh in South Africa2.

33. There is great momentum for DRC’s greater participation in the regional power market. Trade opportunities have firmed up significantly in DRC’s favor over the last decade, as demonstrated by the various sale agreements finalized or negotiated by SNEL in recent years. Two Power Purchase Agreements (the one with CEC for transfer of power to Botswana and one with Zimbabwe) are currently operational for a total trade of 100MW of firm power. This may increase to a maximum of 150 MW if surplus of supply becomes available within DRC.However, due to supply shortages in DRC and poor transmission capacity both within DRC and partner countries, trade has largely stalled. The rehabilitation of the Inga-Zambia Interconnection constitutes the first step to address the main bottlenecks that prevent the transfer of DRC’s hydropower into the SAPP (a full description on the status of other key transmissionlinks that support trade in the SAPP is provided in Annex 5).

34. In the long run, DRC is poised to become a primary power exporter to SAPP, filling the void in supply created by South Africa’s withdrawal due the need to satisfy its own increasing domestic demand. Given the fast growing demand in the region, the SAPP market can absorb as much electricity as DRC will be able to export once new power generation and transmission capacity come on stream. Suitable export destinations will be South Africa, Zambia, Namibia, Botswana, and Angola in the medium- to long-term. A series of complementary investments are planned and currently taking place in Zambia and other SAPP countries which will enable the take-up of the additional electricity supply from DRC (see Annex 5 for details).

35. To gain the confidence of SAPP members and be able to secure long-term agreements at attractive prices, DRC needs to be perceived as a reliable supplier. This mainly hinges upon its ability to adequately expand generation capacity and build a capable and reliable transmission system. Regional partners are expected to remain engaged to ensure successful implementation of this project and possible follow up projects. The project realizes only a fraction of the potential of the DRC as a regional power supplier. The well-known potential and the rapidly growing demand for power create incentives for successful implementation of this project to ensure continued engagement of all partners. It will also exert pressure on DRC to improve its economic governance framework and sector performance to ensure that the regional benefits materialize.

2 Eskom in its 10th Integrated Strategic Electricity Plan estimated the cost of unserved energy at around US$3.00 per kWh.

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36. Finally, transmission linkages already need to be in place by the time generation capacity becomes available. The existence of a viable interconnection to the SAPP provides grounding and justification for further developments at the Inga site, including Inga 3 and most notably,Grand Inga. A project of the size of Grand Inga makes sense only in a regional context, but this requires that power is simultaneously transferred at the same time that it is produced. Reinforcement of the Interconnection between Inga and the SAPP cannot be put on hold until enough power supply for exports is available, but should rather anticipate it.

B. Country Background

37. The DRC is a fundamental player in the region and given its size, resources, and location, its impacts go beyond that. With an estimated population of about 71 million, vast natural resources, and massive agricultural potential, DRC is the 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.

38. The civil war from 1997 to 2003, led to a rapid descent from the relative prosperity of the period 1960–70. DRC’s prosperity was primarily driven by the export of copper and other industrial commodities, which proved unsustainable when copper prices collapsed in the mid 1970s. The 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 affected existing assets through a lack of maintenance and investment thereby creating even more serious service failures.

39. In addition to impoverishing the population, the war did lasting damage to DRC’s institutions. The political support for institutions evaporated as elites became fragmented. Distrust for institutions increased in parallel with the 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.

40. During the post civil war period, DRC saw a resumption of growth. The end of the war coincided with a recovery in mining prices on the international market. 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 2002 –2008 period, compared to -5.2 percent over the 1991-2001 period. This period of growth was interrupted in late 2008, as a consequence of the changing international environment resulting from the financial crisis.

41. 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

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to a tightening fiscal policy. The overall fiscal balance turned to a surplus on a cash basis in 2010, but a deficit is projected for 2011, due to increased expenditures in the public investment program. The current account balance improved in 2010 as export 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$1.4 billion at the end of 2011. Power exports will contribute to fiscal and macroeconomic stability in particular because of the import content, albeit modest, after the project is well established. At the same time, the significant governance risks associated with the macroeconomic aspects of the project are mitigated to the extent possible. The project has made every effort to avoid diversion of export revenues and improve the management of the national power company SNEL to ensure that the benefits materialize.

42. The context after the 2011 elections is still fluid and under assessment. As noted above, elections were held at the end of November 2011, and although the credibility of the elections was seriously challenged by some national and international actors, the previously tense security situation has returned to stable after the swearing in of President Kabila. The Bank’s country team is closely monitoring developments going forward.

43. Poverty remains pervasive and poverty indicators are high even by regional standards. In 2010, annual GDP per capita was about US$185. 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. The under-five child mortality rate is 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 2007. Primary school enrollment rates increased from 64 percent in 2005, to 71 percent in 2007. Women remain disadvantaged relative to men, but the inequality 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. Improved governance is essential for DRC to address persistent poverty and reduce 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 2010. However, immediately after the HIPC/MDRI Completion Point, the reform momentum required significant Bank staff attention.

44. The World Bank’s 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 DRC laws and 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.

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45. Progress in the DRC economic governance matrix is essential in order for the regional benefits to materialize. However, the Bank believes that this project should go ahead based on its regional nature and its importance to provide the building blocks for future Bank engagement as mentioned above, while recognizing that progress on governance has been mixed. Agreed actions were taken on several fronts: for example, 100 percent of the existing petroleum contracts and about 80 percent of the existing mining contracts have been published, and procurement reform has also progressed. However, the Bank remains concerned by slow progress on the following issues: (i) adoption by the Parliament of the 1958 New York Convention on international arbitration; and (ii) publication of the outstanding mining contracts and clarification of their legal basis. Bank management is closely monitoring those issues.

46. Poor governance also affects state-owned enterprises and their ability to provide services and maintain financial and operational viability. In this regard in 2007, the Government presented a Governance Compact targeting the following 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 principal aim of improving its corporate governance.

47. The Project is consistent with the Current Country Assistance Strategy (CAS) for DRC,the Africa Regional Integration Assistance Strategy (RIAS), approved by the Board in April 2011 and the Bank’s Africa Strategy. One of the strategic elements of the CAS is that the Bank will help efforts to achieve high, sustained and shared economic growth by several avenues including playing a prominent role in the rehabilitation and expansion of electricity transmission systems and supporting DRC’s central role within the development of regional power networks. The first pillar of the Africa Strategy on competitiveness and employment comprises targeted interventions to address the infrastructure constraint with a focus on regional projects that include cross-border transmission lines and a fiber-optic backbone; the project focus on SNEL’s corporate governance enhancement is fully in line with the governance foundation of the Africa Strategy.

48. The project is also at the heart of the nexus between development, security, and governance, and is fully aligned with the recommendations of the World Development Reports (WDR) 2010 and 2011. According to the WDR 2010, climate change must be urgently addressed with means such as regional power trade which can provide the least cost energy supply with reduced carbon emissions.

49. By fostering regional cooperation and development of national institutions, the project will build on existing measures taken in the context of the wider Bank’s dialogue and operations in DRC and in the Region essential to exploit the development potential created by this project.For instance, foreign institutional structures are increasingly important in the management of DRC mineral wealth and are expected to become equally important in the management of the power sector. Gradual implementation of the Extractive Industries Transparency Initiative, for instance, will help to ensure that DRC’s mineral wealth benefits are widely shared. The development of the DRC’s power potential is likely to benefit the Sub-Saharan region, which will over time develop into a regional institutional structure able to exercise pressure on DRC and ensure that these developments also benefit the broader DRC population. Such regional institutional structures are likely to evolve gradually and increasingly rely on advanced technologies and social accountability networks to ensure service delivery.

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50. Such interventions in the power sector are paramount to achieve poverty reduction as highlighted in the box below. The social and economic stability in DRC is crucial to the success of the project. The transmission line crosses through a large area that receives initially only limited benefits of this power transmission. The risks of political unrest in this region are mitigated by the integration of a back-bone telecommunications component, which yields immediate benefits for growth and poverty alleviation, limiting the material risks to the project(see also Box in Para 63).

Box 1: Energy Services and Poverty Alleviation in DRC

The 2011 Poverty Reduction Strategy Paper (PRSP) recognized the economic and social development constraints imposed by the power sector, and the important role that a well-functioning 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.

The 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-sized enterprises (SME) for which back-up generation imposes crippling costs. The 2010 Investment Climate Assessment for DRC found that electricity and access to finance are the most severe constraints. About 92% of companies surveyed have experienced power outages in 2009. During a typical month, the formal sector companies reported power outages of an average of 5.2 hours, and informal sector enterprises have reported outages on average of 6.8 hours. These failures have cost an estimated 17% of their annual sales in the informal sector and 25% of their annual sales in the formal sector. To overcome these massive cuts, 48% of formal sector companies and 18% of informal sector companies rely on self-generation.

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 beginning to reduce poverty rates on a more broad and diversified basis. To date, SMEsemploy only 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. The governance actions supported under PMEDE, as presented below and in Annex 6, are key to addressing some of these shortcomings.

Without access to modern and sustainable energy services, the poor are deprived of opportunities to improve their living standards. Although energy is not explicitly mentioned among the targets, there is a close link between power availability and the achievement of the Millennium Development Goals (MDGs). 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.

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C. DRC Electricity Sector

51. DRC has enormous hydropower potential. 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, 13 percent of global hydropower potential and twice overall Sub-Saharan Africa’s total installed capacity of about 48,000 MW. More than 40% of this potential is located at the Inga site at anestimated potential capacity of 45,000 MW. With energy resources on this scale, DRC can 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.

52. Hydropower plays both mitigation and adaptation roles in addressing climate change. Avoided Greenhouse Gas (GHG) emissions through hydropower can be significant, particularly in Africa and specifically in DRC where forest resources are also 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 per year of CO2 emissions. At today’s carbon prices, viable hydropower share can potentially increase by 50 percent. Increased generation at the Inga site through rehabilitation of the existing Inga 1 and 2 power stations 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 Africa’s 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.

53. Today, however, this hydropower potential remains mostly untapped with serious household electricity access and development implications. Only a total installed power generating capacity below 2,500 MW is in place with the Inga 1 and Inga 2 plants and other smaller hydropower stations, including those in the Katanga Province, of which less than half the capacity is operable.

54. The lack of sufficient power generation, transmission and distribution capacity means that the vast majority of DRC’s population and its economy are under-served. At about 9 percent currently, 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,

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restore the financial health and operational efficiency of the power utility, rehabilitate and invest in its power assets and improve electricity access.

55. However, unleashing DRC’s transformational potential will require progress on the institutional front to provide incentives for enhancing operational performance as well as corporate governance of SNEL (the national power 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. Together with atariff that is below marginal cost, these inefficiencies absorb as much as about 4 percent of GDP.

56. 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%. This improvement was driven in part by a higher average electricity tariff, and in part by an improvement in the collection rate, particularly significant for exports (from 40-70% to 93% in 2010).

57. In fact, the GoDRC has started to implement a phased process of tariff rebalancing in order to reduce the considerable underpricing of electricity for most residential users. The third adjustment (out of 4 planned) has just been implemented. At the end of the four-stage process, residential tariffs would be around 8 US cents/kWh on average (with a lower 4 US cents/kWh tariff for the poorest users). However, tariff adjustment is obviously a politically and socially sensitive process, especially given the low quality of service and frequent supply disruption.Even without a major tariff adjustment, however, the potential for increasing total revenue with improved collection is significant. While much remains to be done in this area, SNEL performance has improved over the last 5 years (as documented in Annexes on the financial analysis and SNEL performance indicators). Despite these improvements, collection from the government remains a major problem. The ratio of customers per employee (which was just over 60 in 2010) is still very low by utility standards, and as a result of overstaffing and low collection ratios, salary costs currently represent almost one third of total SNEL revenues.

58. The PMEDE project is supporting SNEL to improve its governance, as well as its technical and commercial performance. A detailed update on the main key indicators and actions is provided in Annex 6. Good progress has been made since the additional financing of PMEDE and both the Government and SNEL have demonstrated commitment to this path as evidenced by the following key steps taken (this is noteworthy given the recent election turmoil):

Appointment of SNEL’s new Board and Senior Management. A new Board of SNEL was appointed in September 2011 (before the scheduled date of December 31, 2011, as targeted under the PMEDE project). The Chairman of the Board of Directors has significant management experience from the private sector and a clear vision on the effort needed on corporate culture, performance incentives, corporate governance, and the autonomy and accountability of SNEL. The new CEO has conducted a performance evaluation on the basis of technical skills for the senior positions before confirmations of new appointments.

Signing of the Performance Contract between SNEL and the Government. COPIREP (Comité de Pilotage de la Réforme des Entreprises Publiques), in consultation with the Government and SNEL, has finalized, with the assistance of its consultants, the proposed performance contract between the Government and SNEL. The contract was signed on February 27, one month ahead of March 31, 2012, targeted deadline. The document

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contains all the principles appropriate to the performance improvement and corporate governance of SNEL, in terms of roles and commitments of the parties, targets and indicators, and monitoring and evaluation mechanism. SNEL is also recruiting a consultant to develop the business plan required to achieve the outcomes specified in the performance contract.

Finalization of the Terms of Reference for SNEL’s TA Services Agreement. COPIREP has prepared draft Term of References for the technical assistance service contract and draft terms of reference for the independent audit of the performance contract. The notice of expressions of interest for technical assistance services to SNEL was published in October 2011, and the request for proposals was launched in March 2012. The contract is expected to be signed by December 2012.

Arrangements for appropriate O&M of SNEL’s transmission and hydropower facilities.Under a multi-party agreement between SNEL, EIB, the World Bank and a private bank (the so-called “Accord de mécanisme de paiement”), escrow accounts have been established abroad for appropriate financing of O&M of SNEL’s transmission assets, which are automatically provisioned by sales to six large mining customers. SNEL has also opened a dedicated account for O&M of Inga hydropower facilities and recruited a consulting firm to design appropriate O&M costing, procedures and organization for these facilities. The recruitment of the technical audit and design of the private O&M contract for SNEL transmission facilities is underway.

59. The box below provides details on the program for SNEL recovery and power sector reform.

Box 2: SNEL Recovery and Sector Reform

As part of the PMEDE project, the Government designed in March 2011, a comprehensive five-year program for the financial and operational recovery of SNEL and to enhance SNEL’s corporate governance. The program is being implemented under the leadership of COPIREP, with guidance from the Ministry of Portfolio and the Ministry of Energy, and it includes five main components:

1. A Performance Contract between the State and SNEL: The performance contract stipulates the respective roles and obligations of SNEL and the State to achieve sector objectives over time (as measured by timebound indicators/targets), including mainly financial equilibrium of SNEL, improved quality of electricity service, and increased access to electricity. The contract includes the completion of SNEL transformation into a limited liability company; mechanisms for settling of debt and future payments for electricity consumption by the State and by State-owned companies, corporate governance arrangements; State commitment to tariff adjustment and/or financial compensation to reach financial equilibrium; the definition and implementation of a corporate strategy (“Plan d’Entreprise”) to improve SNEL’s organization, management, investments, technical and commercial performance, communication and reporting; and the monitoring and audit of the performance of both parties, as well as progress on performance targets.

2. A Corporate Governance Plan: The corporate governance plan addresses the following aspects: Board composition and functioning; internal control systems; external financial and procurement audits; strengthening human resource actions and performance incentives; guidelines for mobilizing private investment and PPPs, and for contract review; operational information disclosure.

3. SNEL’s Institutional and Financial Restructuring: In December 2010, SNEL was transformed into a limited liability company. The first phase of SNEL restructuring is designed around SNEL’s current institutional structure,

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i.e., a vertically and horizontally integrated electric utility. Actions include: establishment of opening balance, including asset property and valuation; and public and private debt/receivables restructuring. The first phase of SNEL restructuring will also include the preparation of a strategy for the further restructuring of SNEL.

4. A Technical Assistance Services Agreement: A three year TA Services Agreement is to be entered into with a reputable operator or management consulting firm. Permanent technical assistance in counterpart management positions will be provided on key operational aspects (such as commercial, financial, accounting, procurement, etc). Short term technical assistance will also be provided on specialized aspects (such as improving billing system, preparation of maintenance plans by function, management of network extension, management of metering installations, etc.), and to support installation of and associated training for improved commercial and financial systems. Significant financing is provided under the PMEDE for improving commercial, financial and purchase systems, as well as for rehabilitating generation, transmission and distribution facilities.

5. Institutional and Financing Arrangements for O&M of SNEL’s Transmission and Hydropower Facilities:Appropriate O&M of transmission and generation assets is essential for the sustainability and normal lifespan of these assets. In the long term, the gradual improvement of SNEL’s financial position will ensure sufficient resources to finance O&M. In the short term, specific institutional and financing arrangements have been agreed upon with SNEL. For transmission facilities: establishment of dedicated escrow accounts for O&M financing, automatically provisioned by identified mining customers; technical audit of transmission O&M and recruitment of a private O&M contractor. For Inga hydropower facilities: restructuring and strengthening of SNEL’s Inga O&M organization, staffing and procedures; establishment of a financial mechanism (dedicated account with periodic audit of disbursement) to ensure availability of O&M funds; in the medium term, PPP for Inga O&M, possibly together with Inga 3 development.

Performance targets at the end of the five-year performance contract are rather ambitious and include mainly: losses16%; bill collection 95%; clients per employee 175; Government and SOEs’ collection 100%; Inga availability 75%; clients with meters 100%; reduced Government electricity consumption; and actual yearly review & adjustment of electricity tariff.

Options for future sector restructuring will be assessed during the implementation of SNEL recovery program. Such restructuring could possibly include vertical unbundling (i.e. separation of Inga generation, separate transmission company, etc.) and horizontal unbundling (i.e., subnational distribution utilities), as well as for increased private participation in sector financing and operations. An electricity law is expected to be enacted by 2013, which will provide incentives for private investment in the sector and will set up the institutional and financing framework for accelerating rural electrification.

60. As explained in the PMEDE project paper, the path for sector reform and improvements in SNEL performance will be long. However, the measures identified for the next five years are deemed the most realistic and feasible to effectively address the performance problems in the sectors in the short-term and to lay the groundwork for further restructuring of SNEL with an increased private participation and investment in the sector. 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 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.

61. 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

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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. Improving these functions at the public utility SNEL will be a crucial first step toward attracting private investors. The Government should also resolve any outstanding issues related to existing claims from creditors to avoid further hampering private sector interests.

62. Although the program has a strong regional dimension, it will also produce considerable domestic benefits for the DRC and contribute to poverty alleviation in the country. Those benefits are summarized in the Box below. Trade-offs will materialize between satisfying an increasing domestic demand and exporting electricity to the whole region. To address those concerns, a close dialogue is carried out by the Bank with the Government to support a series of activities aimed at increasing the current extremely low electricity access rate. Those initiatives include a plan to develop decentralized small and micro hydropower plants, foster partnershipswith mining companies for the development of decentralized hydropower generation opportunities and technical assistance for the development of Inga 3. Those activities are currently being considered as part of a TA project currently under preparation.

Box 3: The Poverty Dimension of the Program: Domestic Benefits for DRC (SAPMP and PMEDE)

The program will provide about 1,500 GWh per year of firm and reliable power supplied to mines, and other consumers in the Katanga Province. This will adds to the 4,500 GWh of power for Kinshasa and Bas-Congo, once the rehabilitation of Inga 1 and 2, and the second line Inga-Kinshasa are completed.

More than 700 km of new distribution lines will be built to connect about 280,000 people in Kinshasa, of which about 150,000 are women. This will significantly improve the living standards of the general population by improving access to clean electricity. The program will not only connect about 35,000 low-income households but also improve electricity service quality for all existing customers in Kinshasa.

Exports are an important and reliable source of revenues to help SNEL meet its operating costs and improve shortcomings in the sector, also fostering the development of SMEs and small businesses. Full development of DRC’s hydropower potential at Inga would guarantee to the country a more stable and significant stream of income than the exports of physical resources, with large effects on the country overall macro-economic situation. On the long run, together with the governance measures implemented under PMEDE, export revenue will also enable SNEL to provide the much-needed investments to improve the dismal current country’s electricity access rate (currently 9 percent) and pursue rural electrification initiatives.

Provision of social infrastructure to the communities along the Inga-Zambia transmission line corridor under the Project comprising water supply and sanitation systems, construction of schools and clinics, electrification of certain areas and the implementation of HIV/Aids awareness campaign, which will enhance the quality of life of the communities, and generate additional economic activity. Benefit sharing with communities along the line will also improve SNEL’s stakeholder engagement, in particular in remote areas such as the Oriental Kasai, and it is important to prevent the power lines and telecommunication system from being exposed to security risks.

Excess telecommunication capacity would be made available for various forms of communication and information for private and public business, and household applications. At the microeconomic level, ICT provides farmers, workers and entrepreneurs opportunities to reduce transaction costs (increase revenues of local population), increase market coverage and improve competitiveness. They lack information relevant to their particular situation and thus have difficulty interacting with other community members or other communities. ICTs, such as radio, telephone and email, can be of great value in bringing people together, bridging geographic distances and providing relevant information to the poor. The correlation coefficient across countries of the Human Development Index

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(HDI) and the Networked Economy Index (NEI) is above 0.8, suggesting a link between welfare and the use of ICT in developing countries. SAPMP will provide the first broad-band telecommunication back-bone infrastructure for DRC, and it is expected to reduce the cost of telecommunication services by about two-thirds.

ICT can also enable accountable, transparent governance and empowers women. Citizens are increasingly using social media to amplify voice and to hold governments accountable through collaboration and collective action. Cell phones can also alleviate time and mobility constraints for women by increasing their ability to coordinate their family and work lives, reducing the cost of money transfers, and cutting down the physical labor or travel required to discover information.

The catalytic effect of the Project in attracting private investments into the rehabilitation of Inga 1&2, as well as of Inga 3 because of the access it will provide to the power market in the Katanga Province and in the SAPP.

Lower CO2 emissions by substituting thermal self generation in Katanga with renewable hydropower. Each GWh of HFO displaced with clean hydropower would save 672.7 tons of Co2 emissions, giving about 1,000 kilotons per year of avoided emission for 1,500 GWh, i.e. additional annual benefits of about US$20 million, based on pricing of US$20 million/ton of CO2.

D. Project Background, Objective and Scope

63. In November 2003, the Bank approved a credit of US$177.5 million for the original SAPMP project. The original project development objective (PDO) was to facilitate further development of an efficient power market in the Southern African Development Community. The project has the following components:

Component 1: Support to the SAPP Co-ordination Center;

Component 2: Rehabilitation and reinforcement of the high voltage transmission corridor from Inga to Kasumbalesa at the border with Zambia;

Component 3: Construction of a double circuit 220 kV line by CEC from Luano substation in Zambia to link the DRC transmission system at Kasumbalesa; and

Component 4: A feasibility and preliminary design study of an interconnector between Zambia and Tanzania that would connect the SAPP to the EAPP.

64. The Bank approved a first Additional Financing grant (AF1) of US$180.62 million for the project in June 2009. The purpose was to meet an increase in project cost arising from the restructuring of the project to scale up and add new activities under Component 2 and thus ensure that the PDO could be achieved and sustained. Component 1 and 4 were already successfully completed by December 2007, well before the processing of the first additional financing. AF1 also provided financing for cost overruns due to underestimation of the rehabilitation needs at appraisal in 2003.

65. The scaled up activities under the AF 1 included3:

installation of a new optical fiber telecommunication system for power operations and other national and regional telecommunication requirements. It was determined that the

3 A presentational revision of the component description is presented in Annex 4 to simplify and better reflect the project documents.

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earlier project alternative of repairs to the existing system were not technically and economically appropriate;

replacement of control systems of the converter/inverter stations instead of repair of the existing dilapidated and technologically obsolete systems;

upgrade of the System Control and Data Acquisition (SCADA) facility at Likasi Transmission Control Center;

increased emphasis on the implementation of the environmental and social mitigation measures;

enhanced support for community development comprising: construction of schools, clinics, water supply and systems, supply of basic medicine, electrification, and an HIV/AIDS awareness campaign for communities along the transmission line corridor;and

expanded technical assistance activities to establish: (a) a five year operation and maintenance contract for the power transmission assets, including training of the power utility staff to take over thereafter; (b) a private operator to manage the commercialization of excess telecommunication capacity, as well as its operation and maintenance; and (c) an entity with international experience such as a non-Governmental Organization (NGO) to provide additional oversight for the implementation of the Resettlement Action and Compensation Plans.

66. In addition to the World Bank, also the European Investment Bank (EIB), the Norwegian Agency for Development Cooperation (NORAD), the United States Agency for International Development (USAID), the Copperbelt Energy Corporation (CEC), and SNEL are co-financing the project. NORAD and USAID provided full financing for the activities under Component 1 (US$3.36 million), now concluded. The EIB approved a loan of EUR110 million for the SAPMP and PMEDE projects in June 2008, to finance the reinforcement of substations as well as the supply and installation of a transmission system control centre under Component 2 of the SAPMP. The CEC, a private company and owner of the transmission network in Zambia into which SNEL exports power, is fully financing Component 3 by providing US$18 million to finance the reinforcement of the transmission lines in Zambia that link with the transmissionlines being constructed under the project in DRC (the original estimate were about US$9.7 reassessed at US$18 million during the AF1). SNEL is contributing US$9.4 million towards meeting part of local costs related to the supply and installation of electrical equipment, the supply of goods, works, and engineering services and towards the financing of the implementation of the resettlement action plan.

67. The timing of the AF1 was driven by the procurement context. Approval of the first additional financing in June 2009 was in fact timely to secure continuity of project implementation. Procurement of the main contracts under Component 2 began in late 2005 and by end December 2008, the process for two of the large contracts was concluded (Contract 1 on the rehabilitation of the Inga and Kolvezi substations and Contract 3 on the constructions of the new transmission lines from Fungurume to Kasumbalesa). Progress was being made on the procurement of the remaining four main contracts and the process was expected to be completed by October 2009. At that point, the total estimated value of the contracts far exceeded the available financing under the existing credit.

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68. With the rather prolonged procurement process for the main contracts, and the participation of a few interested international firms, timely availability of financing was considered critical to avoid loss of interest of the firms. Furthermore, there was no guarantee that re-tendering could attract the interest of the firms to participate in a re-bid or result in cost effective offers or any offers at all.

69. The phenomena of limited market interest and therefore few bidders attracted to power projects in DRC is an unfortunate reality that reduces planning to short-term cycles and in some ways to contract by contract. It was, therefore, critical for the AF1 financing to be available in a timely manner to enable the closure of the procurement process for the very large contracts. For example, the signing of Contract 1, the largest contract then of value US$120 million had to await the approval of the Board of the AF1. The tendering process for the contract began in May 2007, and was completed with award of contract to the single bidder in May 2009. Uncertainties about availability of financing would likely have stopped the process causing further procurement and implementation delays.

E. Project Implementation Status and Issues

70. The project is rated Moderately Satisfactory for progress towards achievement of project development objectives and overall implementation progress since June 30, 2009. The ratings reflect the progress that has been achieved under the project so far, including completion of Component 1 and 4, but hampered by the delays in implementation and slow procurement and disbursements on Component 2 and 3.

71. A waiver to OP 13.20 was requested at the time of the approval for the first additional financing due to the moderately unsatisfactory rating for the project at that time. Significant progress has been made since then and includes: (i) conclusion of the detailed review of the rehabilitation need for the transmission line Inga-Zambia, which was used as a basis for the revised tender of Contract 4 (see Box in Para. 83) and revised cost estimates; (ii) signing of all major contracts; (iii) construction of the new 220 kV Overhead Lines from Fungurume to Kasumbalesa is well advanced and expected to be completed in December 2012; (iv) progressing on schedule for the rehabilitation and reinforcement of substations in Inga, Kolvezi, Fungurume, Panda, etc.; (v) supply and delivery of most of the equipment, including the modern optical fiber telecommunication cable needed for Contract 5.2; and (vi) a joint Project Implementation Unit has been established within SNEL to implement both the PMEDE and SAPMP Projects. Annex 4 provides further details on the measures put in place to improve implementation since June 2009, when AF1 was processed.

72. In addition, the progress mentioned above in terms of enhancing SNEL’s operational and commercial performance, including signing the performance contract and preparing the TA services contract, is enabling SNEL to improve its ability to operate and maintain the assets financed under SAPMP.

73. The original SAPMP was prepared under a challenging context, immediately after the conflict in the DRC ended and under the supervision of a transitional Government. Since its approval, the project immediately faced a series of implementation challenges arising mainly from DRC’s post-conflict country situation, weak institutional capacity and lack of human resources and from the technical complexity of the project itself. Similarly to PMEDE, the

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complexity is due to the difficulty of diagnosing the extent of repair required for old poorly maintained electrical equipment prior to beginning of works. In addition, the transmission line to be rehabilitated stretches along more than 2,400 km which, coupled with the remote location, poses logistical challenges, in particular during preparation and appraisal of the original project.

74. As a result of the fragile conditions following the civil war, it has taken the Government and SNEL time to develop the requisite institutional capacity and address the project’s procurement activities. Within the Bank, staff transitions posed a major challenge for efficient supervision and monitoring of implementation.

75. Components 1 and 4 have been successfully completed already by the original project completion date of December 31, 2007, before the first additional financing. A continuation of the technical assistance program for the SAPP Coordination Center is under discussion under another proposed Bank operation.

76. Under Component 3, the project provides for the construction of new high voltage transmission lines in Zambia to link with the new transmission lines being built in DRC and the extension of existing substations to connect the new lines with the Zambian transmission grid. The contract for the construction of the new transmission lines has been signed whereas that for the extension of the substations has been awarded but has not yet been signed. The two contracts would be completed within 12-14 months and before the commissioning of the new high voltage lines in DRC.

77. In a recent meeting with SNEL, however, CEC, the private company responsible for the construction of the line, indicated that commercial issues surrounding the performance of the existing PPA may create some resistance by its Board in starting construction works until a revised version of the PPA is negotiated and signed with SNEL. Those commercial issues relate to the difficulties SNEL is facing to meet its exports commitment in the PPA due to technical constraints caused by the deterioration of the existing Inga-Zambia interconnection. Given the key importance of the Zambian portion for the success of the SAPMP and its regional nature, therevised PPA between CEC and SNEL was signed on March 31, 2012, removing any outstandingissue for the construction of the line in Zambia.

78. As for Component 2, within the past two years significant progress has been achieved in the implementation of the project with five of the seven main contracts signed and at various stages of implementation. Procurement of the two remaining main contracts, namely the rehabilitation of the long-distance high voltage transmission line (contract 4) and the installation of the optical fiber cable (OPGW) for the telecommunication system on the high voltage transmission towers (contract 5.2) was completed and contract awarded in February 2012.However, since the available financing is insufficient, contract 4 will become effective only after effectiveness of the proposed AF2.

79. A detailed list of contracts and their status is presented in Annex 4. All contracts currently under implementation would be completed in Q1 2013 apart from Contract 4 and 5. However, the associated testing and commissioning activities for hand-over of installations would have to await the completion of contract 5.2 in October 2013 and contract 4 in January 2015. In addition, the CEC component to reinforce the transmission link between the DRC and Zambia power systems is also scheduled to be terminated before project closing (although no IDA financing is involved in this component). Annex 4 gives a more detailed account of the status of each component, and revised implementation timeline.

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80. Cumulative disbursement to date for both the original credit and the additional grant stands at about US$149.3 million (May 2012), or about 40 percent of total Bank financing, and is projected to reach about US197.3 million by end-June 2012 accounting for 55 percent of total Bank’s financing (original project and AF1). Since almost all funds were already committed under the original credit, the signing of contract 4 has resulted in commitments exceeding available financing by more than 20 percent. Therefore, as noted, the approval and effectiveness of the proposed AF2 will be a condition for effectiveness of contract 4. Annex 4 (Attachment 8) includes details on historical and estimated projected disbursement for total IDA financing (including the proposed AF2).

Project Implementation Arrangement

81. The project is implemented under the same institutional, procurement and disbursement arrangements as for the PMEDE with the PIU at SNEL being the implementing entity and the Bureau Centrale de Coordination (BCECO) responsible for fiduciary aspects of the project (see Annex 3). Under PMEDE, it was envisaged to transfer fiduciary responsibility from BCECO to SNEL by end of April 2012. However, the World Bank fiduciary team assessed SNEL capacity to take over those functions and noted that there was not enough capacity in SNEL to carry out fiduciary functions without jeopardizing project implementation. The main source of delay was the unavailability of SNEL personnel to be assigned to the new financial management and procurement roles in the PIU, despite good effort on the side of BCECO to start the training and capacity building activities.

82. In order to accelerate this transfer of fiduciary responsibility, the Bank's FM and procurement team, together with SNEL, have prepared action plans to be implemented between April and September 2012 identifying a series of key actions in order to allow a full transfer by end September 2012. Transfer of responsibility will be gradual and key actions are presented in Attachment 1 of Annex 3.

83. The program will be tailored to the experience of the staff recruited to manage fiduciary responsibilities. The World Bank FM and Procurement team will closely monitor the implementation of the action plan and flag any delays as early as possible, identifying the source of delay and remedial actions to solve outstanding issues putting at risk the achievement of the complete transfer by end September 2012.

84. Legal Covenants. All but two of the legal covenants for the original credit and the AF1 are complied with (see status of compliance in Annex 4). In particular, covenants related to aspects such as audits, safeguards and implementation arrangements have been complied with since the project’s start. Project and SNEL audits were completed for each year, though with delays in some years, and were always certified, usually with minor qualifications in the case of project audits. Qualifications in SNEL audits were more serious, due to the poor quality of SNEL accounting and financial management systems, which however are being gradually improved with support under the companion PMEDE project. SNEL has a fully staffed Social and Environmental Management Unit (UGES) with ability to conduct environmental and social impact assessments and to monitor the implementation of Environmental and Social Management Plans and Resettlement Action Plans for SAPMP investments. Fiduciary aspects are handled by BCECO and SNEL has established and maintained a fully staffed project implementation unit with appropriate incentives and procedures (as detailed in a Project

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Implementation Manual that is periodically updated), which handles implementation of both the SAPMP and PMEDE projects.

85. However, several dated covenants for AF1 have lapsed, essentially due to the long time taken (almost one year after Board approval) to design and sign the Accord de Mécanisme de Paiement (AMP) for the creation of a secured mechanism for the provisioning of operation and maintenance funds for SNEL transmission assets and for the servicing of EIB debt. It took a long time to finalize the agreement because of its complexity. The AMP was a cross effectiveness condition for IDA AF1 and EIB co-financing for the project’s contract 2 whichcaused the AF1 to become effective only after a long delay of about one year after Board approval. This consequently delayed the setting up and provisioning of the escrow accounts in Luxembourg and the local transmission O&M account, as well as the audit of transmission O&M and the recruitment of a private operator for O&M of SNEL’s transmission assets. Also, in part due to delays in the construction and rehabilitation of transmission lines together with installation of fiber optic cables, SNEL did not meet the dated covenant on the recruitment of a private operator for the commercialization of the fiber optic excess capacity.

86. The status of the two outstanding covenants and the agreed action plan discussed with SNEL to reach compliance as soon as possible is presented below. Amendments to revise the due dates of covenants have been made to the legal documents of AF1 as part of Board presentation of the proposed AF2. A third covenant, also presented below, regarding the counterpart financing and the provisioning of the local O&M accounts has been fulfilled as condition of negotiations for the SAPMP AF2.

87. Regarding the two still outstanding covenants, namely the appointment of the contractor for the O&M of SNEL transmission assets and the recruitment of the internationally experienced private operator to commercialize the excess capacity of the telecommunications system under Open Access regime, it is proposed to postpone dates for compliance (otherwise the formulation of covenants will remain unchanged). The new deadlines take in consideration the delays in project implementation and are driven by a realistic country-specific timeline to carry out the procurement activities to hire first the consultants and secondly the operators to support the Government in the activities outlined below for each covenants.

Table 2: Status of Original Legal Covenants and Proposed ChangesOriginalCovenant

Appointment of the Contractor for the Operation and Maintenance of SNEL Transmission Assets:

No later than April 30, 2010, SNEL/PIUshould appoint a consultant for the design of operation and maintenance services for SNEL’s transmission assets; drafting of terms of reference (including required qualifications and experience) for the appointment of the O&M Contractor; the delineation of the high voltage transmission system to be covered by the O&M contract; determining the funding requirements to perform the operation and maintenance of the power transmission assets until the O&M contractor has been recruited.

No later than September 30, 2012, appointment by SNEL of the O&M Contractor.

Comments:

The consultant will conduct the technical audit of SNEL transmission assets that is foreseen under the AMP (Accord de Mécanisme de Paiement).

New deadline: October 30, 2012

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The O&M contractor should be operational not later than three months before completion of project activities.

New deadline: September 30, 2014Status Expression of Interest published and Request for Proposal (RfP) finalized for the recruitment

of the consultant as part of the SAPMP AF2 process.Agreed actions and due date

Recruitment to be concluded by October 30, 2012 (revised legal covenants for SAPMP AF2).

Original Covenant

Provisioning of the project accounts as per schedule agreed upon between DRC, SNEL and IDA.

Comments:

Amounts and timetables are established in the AMP and in the side letter signed between three parties

StatusBased on SNEL expenditure until now and projected until June 2012:

The local account for the operation and maintenance of SNEL transmission assets (O & M Account B) has been provisioned up to the amount agreed upon with IDA before appraisal of the AF2..

Counterpart Funds Account provisioned up to the amount agreed upon with IDAbefore appraisal of the AF2.

Local Maintenance Fund for Inga provisioned up to the amount agreed upon with IDA before appraisal of the AF2.

Agreed action and due date

As per agreed recurrent legal covenants, SNEL will provision the above accounts regularly for the rest of the project duration, as per schedule agreed upon between DRC, SNEL and IDA in the AMP and in the side letter to be revised and signed between the three parties.

Original Covenant Appointment of an internationally experienced private operator to commercialize the excess capacity of the telecommunications system under Open Access regime:

No later than December 31, 2009, recruitment by SNEL of a consultant to: (i) design the services to be provided for the management, maintenance, operation and commercialization of the excess telecommunication capacity; (ii) assist with the recruitment of an internationally experienced private operator for the commercialization of excess telecommunication capacity under Open Access regime; and (iii) assist with the necessary interconnection agreements.

No later than September 30, 2012,

Comments

Covenant not applicable anymore (consultant already recruited as condition for negotiations of the SAPMP AF2)

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appointment by SNEL of the international private telecom operator.

The private telecom operator should be operational not later than three months before completion of project activities.

New deadline: September 30, 2014

Status Consultant selected as part of the SAPMP AF2 processing.Agreed action and due date

SNEL to closely supervise the consultant work (legal covenant SAPMP AF2).

F. Rationale for the Second Additional Grant

88. The rationale for the seond additional grant (AF2) is essentially based on the cost overruns associated with the rehabilitation needs of the high voltage transmission lines under Component 2 (contract 4), as well as minor cost overruns on other contracts. The AF2 will provide funds for a revised set of contingencies that may arise during the rest of the project’s implementation period, identified through a quantitative risk analysis carried out by SNEL and its consulting engineer and reviewed by the task team. This reflects a strong lesson learned during the implementation of both PMEDE and SAPMP and also projects in the transport sector. Namely, that the implementation environment in DRC remains difficult to analyze ex-ante and requires flexibility including on financing as project implementation gets underway.

89. Based on the analysis, it is estimated that the amount required under the second AF is US$201.5 million. A further cost breakdown is presented in detail for each project component in Annex 4 – Attachment 2, together with the detailed cost analysis. The Table below summarizes the cost changes by Project component, while Table 4 presents the revised financing plan.

Table 3: Cost Table

Component Initial Cost Revised Costafter the AF1

Revised Costafter AF2

Component 1 3.36 Completed CompletedComponent 2 186.11 412.00 638.3Component 3 9.70 18.00 18.00Component 4 1.02 1.0 1.0

TOTAL 200.19 430.00 657.3In US$ million

Cost Overruns under Component 2

90. The rehabilitation activities envisaged under the AF1 comprised only the repair or replacement of broken or missing parts, including about 2,000 insulators known to be damaged at that time. In March 2010, after the detailed assessment which included field work as well as laboratory tests in France, it was discovered that all the 720,000 insulators in both DC lines were likely to have a shorter lifespan than the norm (about 40 years) due to manufacturing material inadequate to meet the line-specific challenging operating conditions. Therefore they all needed to be replaced to assure required reliability levels in the operation of the lines.

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91. The new insulators to be installed under the rehabilitation works are the most modern and are made of high resistivity dielectric materials to prevent degradation over time. Details are provided in Annex 4 – Attachment 1.

Better Factoring Risks and Contingencies

92. Cost underestimations, and larger than expected rehabilitation works are endemic issues for energy and infrastructure projects in DRC. However, the methodology presented below provides reassurance that the AF2 will provide sufficient financing for completing the project.

93. At this stage, all large contracts have been signed and their associated base costs are known with certainty. In addition, as part of each contract, standard clauses on quality of equipment and performance guarantee are included to avoid potential problems with faultymaterials. The new project cost estimates are based on a quantitative detailed cost and risk analysis carried out by the owner’s engineer and the Bank’s team (see Annex 4 for further details).

94. The methodology used to assess the revised project costs benefits from the experience and lessons learned from cost escalation in PMEDE and SAPMP AF1. In the past, contingencies and base costs were benchmarked against worldwide market prices taken at face value, without considering the specific market reality and technical challenges associated with the different characteristics of each contract. In addition, close interdependency between contracts was underestimated and cost overruns associated with delays in contract implementation deemed not significant.

95. In the case of the proposed AF2, a systematic analysis of risks has been carried out and tailored to the nature, implementation status and detailed technical characteristics of each contract. A series of risk have been identified, including exogenous factors which may compromise the effectiveness of the investments (such as failures in electrical equipments not covered under a specific contract but whose availability is essential for the effectiveness and sustainability of the project). Physical contingencies were assessed separately depending on the nature of each contract and are deemed largely sufficient to cover potential change orders in each contract.

96. Each risk category has been priced and contingency appropriately added to the project costs to minimize the risk of future costs overruns. For each contract, physical and price contingencies were added to the known base costs. Price contingencies include price revisions, exchange rate fluctuations and administrative costs that would result from implementation delays.

97. To ensure proper pricing and integrity of implementation activities going forward, the team has worked closely with INT to identify a series of measures aimed at strengthening supervision and ensure transparency in line with what was supported under the additional financing for PMEDE (see Annex 9). INT staff has also supported the team in reviewing some of the existing procurement packages to identify red flags and mitigating measures.

98. Of the total amount of US$201.5 million for the AF2, about US$150 million are due to the unexpected need to change all the insulators along the line. The associated contract 4 was signed in February 2012 and effectiveness of the contract is conditional to the proposed additional financing being approved by the Board and effective. The box below presents a

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summary of the history and technical due diligence of contract 4 (see Annex 4 for further details).

Box 4: Rehabilitation of the high voltage direct current overhead lines and the high voltage alternating current overhead lines (Contract 4)

History and technical due diligence

Original and AF 1 Cost Estimates. Cost estimate in the original project was US$4 million. The first tender in May 2007 attracted only one unresponsive bidder mainly due to lack of definition in the bidding documents which had been prepared without appropriate prior technical studies. Processing of the AF1 could not wait for additional studies to be carried out on the lines and the cost estimates were revised to US$ 23 million – still based on limited available technical information.

The “Flycom” Study. In late 2009, a detailed technical study was conducted to investigate the technical status and rehabilitation needs of the line. The study, carried out by a company called “Flycom”, included high definition pictures of each element of the transmission system and thermal analysis of the structure to assess structural integrity of each one of the 11,000 towers (See Annex 4 for samples of the pictures). Based on this detailed assessment, cost estimates for the contract were readjusted to about US$80 million – based on the need to change only 70% of the total number of insulators and a specific set of rehabilitation works as identified by the high resolution pictures taken during the line inspection. The detailed conclusions from the Flycom study were used in the revised bidding documents (mid 2010).

The Laboratory Tests on Insulators. Given the dilapidated status of the insulators it was then decided by SNEL and the project team that a representative sample of insulators from both the HVDC and HVAC towers would be tested in an independent laboratory in France. The tests concluded that in fact the totality of insulators should have been replaced. This was, however, not included in the revised bidding documents.

Final Bids. Bids were received at a much higher price than expected. The awarded bid amounts to about US$180 million and includes: (i) 100% of the insulators; (ii) all the other rehabilitation works as identified by the Flycom study, (iii) access requirements to all towers.

Scope of Rehabilitation Works. Contract 4 is a bill of quantities contract that includes the replacement of all insulators and access to towers, as well as rehabilitation or replacement of all other elements identified in the 2009/2010 Flycom assessment. Those other elements include towers (steel), foundations, conductors, clamps and small accessories. In this regard, change orders are possible (based on unit costs as quoted by the bidder), given the nature of the rehabilitations, but they are deemed to be fully covered by the physical contingencies included in the revised cost estimates as outlined in the detailed technical note prepared by the owner’s engineer and revised to the Bank’s team satisfaction.

99. The scope of the project cannot be reduced. All main contracts, which constitute the core of the project installations, are uniquely linked with each other and interdependent. They all need to be fully implemented as designed (or redesigned) in order to achieve the expected benefits of the project. Procurement has been completed for all the main contracts under the existing SAPMP. For this reason, looking at alternative source of financing, such as other donors and/or private sector companies, would prove difficult and it is unlikely that other agencies will be ready to come on board at such a late stage of implementation. Finally, SNEL’s financial position prevents it from mobilizing additional co-financing.

100. The remaining alternative of not going ahead with the project is undesirable if power market integration in Southern Africa is to be realized and also to support DRC’s economic growth. Indeed, the project is necessary to allow the available energy generated from the Inga

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hydropower stations to be transported to the existing markets in the Katanga Province, including the mining and industrial complexes critical to the economy of DRC, and the power exports into the Southern African Power Pool (SAPP). Furthermore, as already mentioned, the SAPMP and the PMEDE, for which the Board approved an additional financing grant of US$283 million in June 2011, are interdependent. Without the completion of the SAPMP, the benefits of the PMEDE would not be fully realized, and vice-versa. Consequently, the achievement of the objectives of both projects (accounting together for a total IDA financing of over US$1.1 billion4) depends on the full rehabilitation of the long-distance high voltage transmission system from Inga to the border with Zambia.

III. PROPOSED CHANGES

Proposed Changes to the Grant’s and Credit’s Closing Date and Implementation Schedule

101. The extension of the original credit and additional grant is proposed from December 31, 2012 to December 31, 2015, to enable completion of Project implementation. However, since the proposed AF2 closing date exceeds three years from the approval date of the AF1 (2009) endorsement by the Managing Director of a waiver to OP/BP 13.20 has been obtained.

102. An extension of the closing date is needed to accommodate the delays associated with the activities under contract 4 and contract 5.2 (installation of fiber optic on the transmission line, which is required for the commissioning of contract 4 outputs). In fact, it was initially envisaged that bidding for Contract 4 would start in October 2009, and result in contract award in June 2010 allowing its commencement in the third quarter of 2010, and its completion two years later in the third quarter of 2012. However, the bidding for the contract started only in May 2010, as a result of it being split into two lots to attract more bidders and was completed in July 2011.

103. The contract was signed in February 2012. Its execution, which is on the critical path for the completion of the project, is due to commence in the fourth quarter of 2012, soon after effectiveness of the AF2. Although the contract is envisaged to be completed in two years, i.e. in the fourth quarter of 2014/first quarter of 2015, owing to the difficult terrain over which the contract will be executed, the revised implementation schedule includes a slack period of about 9 months to mitigate the risk of delays, hence the new closing date for the project (see Annex 4 for a detailed implementation schedule and linkages between key contracts, such as contract 4 and 5.2).

104. This is the first extension for the additional Grant and the fourth for the Credit. In April 2007, GoDRC requested the additional grant to meet the cost increases faced by the Project and a four year extension of the Credit Closing Date from December 31, 2007, to December 31, 2011. The Bank granted a one year extension to December 31, 2008. In November 2008, at the request of GoDRC, a second extension to December 31, 2009 was granted, with a further extension to December 31, 2012 approved along with the AF1.

4 The US$1.1 billion include the original SAPMP and PMEDE projects (US$177.5 million and US$296.7 million respectively), the two additional financing (US$180.62 million for SAPMP and US$283 million for PMEDE) and the proposed second additional financing for SAPMP (US$201.5 million).

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Proposed Changes in the Project Component Description

105. While the substance has not been modified, Annex 4 presents a reorganization of components and subcomponents to better reflect the activities associated with the project along the line of transmission investments, community development, advisory services and technical assistance.

106. It is important however, to emphasize that the proposed additional financing is mainly linked with the scope of rehabilitation and activities under Component 2 (specifically contract 4) and it does not foresee any new activity compared to the project description at the time of the first additional financing.

Proposed Changes to the Program and Project Development Objective

107. A modification of the Project Development Objective is proposed to better reflect the project area of influence and physical investments. The stated PDO “To facilitate further development of an efficient power market in the Southern African Development Community (SADC)” is proposed to be modified as follows “To expand transmission capacity to better serve domestic and regional power demand”.

108. The re-stated PDO provides greater clarity about the focus of the project on the infrastructure needed to support regional integration as well as domestic needs.

109. Similarly, a modification to the Program Objective is proposed to better reflect the activities implemented so far or under consideration as part the APL (see Annex 5). The stated Program Objective in the original project “The program will increase the availability and reliability o f low cost, environmentally friendly electric energy in the Southern African region, thereby increasing competitiveness of industry and fostering economic growth, a key objective set by SADC in its long term Regional Indicative Strategic Development Plan (RISDP). It will help prevent development of uneconomic generation schemes in the region and foster conditions that would be attractive to private developers seeking to invest in the generation sector” is proposed to be modified as follow “The program will increase the availability and reliability of low cost, environmentally friendly electric energy in the Southern African Power Pool, as well as support further integration and trade between SAPP countries”.

Proposed Changes in the Project Results Framework

110. A series of changes are proposed in the project results and monitoring framework, including mainly new indicators and targets to reflect the new Project implementation schedule and restructuring (see Annex 1). 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 implementation progress.

Proposed Changes in the Financing Plan

111. The financiers of the original project were IDA, SNEL, NORAD, USAID and CEC. In the restructured project, EIB also participated in the financing. For the AF2, only IDA will provide additional funding. SNEL and EIB revised contribution accounts for additional funds earmarked for the compensation in the Katanga region (SNEL) and extra contingencies for

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implementation of Contract 2 and related activities (EIB). The contributions of the various financing agencies in the original credit, AF1 and AF2 are provided in the following table:

Table 4: Original and Revised Financing Plan

Institutions Original contribution

Contribution after AF1 Revised contribution

after AF2Initial Revised contribution due to exchange rate savings

IDA 177.5 358.1(177.5+180.6)

376.6(192.8+182.8)

578.1(376.6+201.5)

SNEL 8.5 6.9 6.9 9.4

CEC 9.6 18.0 18.0 18.00

EIB 0.0 47.0 47.0 51.8

Total 195.6 430.0 455.5 657.3Note: Contributions in US$ million

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IV. APPRAISAL SUMMARY

A. Project Economic and Financial Re-evaluation

Project Economic Analysis

112. The economic analysis of the project prepared as part of the processing of the first additional financing in 2009, concluded in the base case scenario that the Economic Internal Rate of Return (EIRR) of the Project was 31% and its Net Present Value (NPV) US$817 million with a discount rate of 10%.

113. The economic and financial re-evaluation of the Project assessed the impact of cost overruns on the economic justification of the Project. This re-evaluation also took into account changes in assumptions for other significant parameters, including the revision of the project implementation schedule, higher cost estimates for energy supplied into the transmission system, and a lower volume of incremental energy transferred on the transmission line (see details in Annex 7).

114. On this basis, the revised EIRR for the project in the “base scenario” is 17.5% and the NPV US$324 million. In addition, a “pessimistic” scenario, with very unfavorable assumptions for the major economic and technical parameters, has been modeled. In this scenario, the project EIRR would be 9.2% and the NPV negative US$30 million. The table below summarizes the main assumptions and conclusions of the re-evaluation, compared with the AF1.

Table 5: Economic Analysis – Revision in Assumptions and Results

2009analysis

2012reestimate

base scenario

2012reestimate pessimistic

scenarioAssumptionsTotal Project costs MUSD 394.0 659.0 692.0

Annual O&M costsMUSD

%12

3%13

1.9%13

1.8%Annual Energy injected GWh 5,880 3,942 3,504 Losses % 6% 9% 9%Net annual energy transferred GWh 5,521 3,587 3,189 Unit cost of energy injected (until 2020) US$c/kWh 2.0 2.4 2.9Unit cost of energy injected (after 2020) US$c/kWh 2.0 3.8 4.6Unit value of energy transferred US$c/kWh 7.0 7.5 7.3ResultsEconomic Rate of Return % 31.0% 17.5% 9.2%Net Present Value MUSD 817 324 (30)

115. The increase in project costs has obviously a significant impact on the project EIRR. The total project cost estimate in the ‘base scenario” is US$659 million, a US$265 million increase compared to the 2009 cost estimate for AF1. This revised estimate is based on the reevaluation of project costs including physical and price contingencies. In the pessimistic scenario, an additional 5% is added to project costs.

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116. The revision in the estimated cost of the energy injected from Inga on the T-Line also has a significant impact on the project EIRR and NPV. The 2009 estimate was 2.0 US$c/kWh basedon the expected cost of incremental energy from Inga 3 at the time. However, the transmission line will start to operate several years before Inga 3 comes online. Initially, the rehabilitation of Inga 1 and 2 will provide the required additional generation. Therefore, the revised estimate for the cost of injected energy is based on: the expected cost of Inga 2 rehabilitations until 2020, the estimate for the levelized cost of incremental energy from Inga 3 from 2021 onwards.

117. The cost estimate for additional generation from Inga 2 is based on a signed contract for turbine rehabilitation, as well as on the total expected cost of the intake canal reprofiling for Inga 2 (plus contingencies in both cases). As a result, the cost of energy from Inga 2 is estimated at 2.4 US$c/kWh in the base case.

118. The revised estimate for Inga 3 energy cost is based on a recent prefeasibility study of a phased development of the Inga site, in which Inga 3 would be the first phase of the development of Grand Inga. The revised cost estimate of Inga 3 under this scenario is significantly above the assumptions used in 2009 (see table below for the comparison). In addition, to arrive at the revised energy cost from Inga 3, interests during construction (over 5 years – without discounting), and contingencies have been considered, resulting in an estimated cost of energy of 3.85 US$c/kWh in the base case. In the “pessimistic” scenario, energy costs for both Inga 2 and 3 are increased by 20%.

Table 6: Inga 3 – Cost AssumptionsInga 3 – cost assumptions 2009 2012

Investment costs MUSD 4,320 6,400 Maximum capacity MW 4,320 3,968 Net annual generation GWh 30,876 28,136

119. For AF1 economic analysis of the project, an estimate of 7.0 US$c/kWh was used for the valuation of the energy delivered through the Transmission line. This estimate was established on the basis of the estimated net-back value of the Average Incremental Cost (AIC) of bulk supply at the level of the SAPP. This net-back value is equal to the estimated AIC for SAPP (8.7 US$c/kWh at the time) minus transmission costs (including incremental technical losses). The outlook for the long term supply-demand balance in the SAPP has not changed radically since 2009; thus, the SAPP netback value has been kept unchanged.

120. In addition, part of the incremental energy transmitted will be used in Katanga, in particular to meet demand from the mining sector. The alternative sources of supply for mining companies located in Katanga would be thermal self generation (with costs above 20 US$c/kWh), additional hydropower generation from Katanga (with long lead times and difficult to estimate costs for greenfield projects), or imports from SAPP. The economic value of the incremental energy supplied in Katanga would therefore be at least equal to the AIC in SAPP. Taking into account the higher value of energy in Katanga, the weighted average economic value of the energy transmitted is slightly higher than in the 2009 estimate (7.5 instead of 7.0 US$c/kWh).

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121. The revised assumptions for the volume of energy injected in the DC line are also much more conservative than in the 2009 analysis at 3,942 GWh annually (instead of 5,880 GWh), representing an average transfer of 450 MW out of a total capacity of 560 MW. In the conservative scenario, the average volume of energy transmitted would be lower, a risk that could materialize for a variety of reasons (delays in additional generation, technical problems with the T-line). The annual net energy transfer in the base case scenario would be 3,587 GWh per year based on a rate of technical losses of 9%, which is based on the current rate of loss observed on the line (conservative considering that rehabilitation of the line may reduce losses over time).

122. The primary technical justification of the telecom component of the project is to allow more efficient operation of SNEL’s transmission network. SNEL will also be able to resellexcess broadband capacity (about 80%) of the total to telecom operators provided the technical assistance funded under this Project to this effect concludes this option is legally viable. This excess telecommunication capacity will be made available for all the various forms of communication and information for private and public business, and household applications. It will provide the first broad-band telecommunication back-bone infrastructure for DRC, and is expected to reduce significantly the cost of telecommunication services. A conservative estimate of additional revenues that would accrue to SNEL as a result has been included in the assessment of the economic benefits from the project. The NPV of these additional benefits is estimated at US$11.0 million (detail of the assumption in Annex 7).

123. Switching values: The project NPV would become negative in case the modeling parameters reach the following values:

The average transfer on the line falls below 326 MW (58.3% of the 560 MW transit capacity);

The cost of energy injected into the system increases by more than 42% compared to the base case (this would appear unlikely, especially for Inga 2 for which the estimate is based on signed rehabilitation contracts plus contingencies); and

Total project costs increase by more than 65% above the baseline (corresponding to US$1,087 million). This would appear extremely unlikely now, given that project cost estimates are derived from signed contracts and conservative contingencies have beenincluded in revised project costs.

124. In addition to quantifiable benefits, other benefits of the Project were not considered in the above analysis, in particular on the domestic side, including:

Benefits for consumers of additional telecommunication services: only the additional revenue for SNEL from selling excess broadband capacity has been considered in the economic analysis. It appears likely that significant economic benefits will accrue to users of telecom services under the form of consumer surplus. The 2010 Africa Infrastructure Country Diagnostic (AICD) study estimates that improvements in information and communication technologies (ICT) linked to sector reforms have added as much as 1 percentage point to Africa’s per capita growth rate, accounting for over half of Africa’s improved growth performance and more than any other sector. At the microeconomic level, ICT provides farmers, workers and entrepreneurs opportunities to reduce transaction costs (increase revenues of local population), increase market

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coverage and improve competitiveness. They lack information relevant to their particular situation and thus have difficulty interacting with other community members or other communities. ICTs, such as radio, telephone and email, can be of great value in bringing people together, bridging geographic distances and providing relevant information to the poor.

Provision of social infrastructure to the communities along the transmission line corridor under the Project, comprising water supply and sanitation systems, construction of schools and clinics and the implementation of an HIV/Aids awareness campaign. Thisinfrastructure will enhance the quality of life of the communities, and generate additional economic activity.

The catalytic effect of the Project in attracting private investments into the rehabilitation of Inga 1&2, as well as of Inga 3 because of the access it will provide to the power markets in the Katanga Province and in the SAPP.

The benefits of increased regional integration and of allowing energy trade between the SAPP and the Central African Power Pool (Inga is already inter-connected with the Republic of Congo electrical grid). The Project will also contribute in fostering the dialogue and coordination in the region, building a platform through which countries can work together to solve potential conflictual issues.

Lower CO2 emissions by substituting thermal generation in SAPP or Katanga with renewable hydropower.

125. Additional economic benefits of the Project may be achieved by upgrading the power transfer capability of the existing transmission system to 1,000 MW at an additional cost of aboutUS$200 million5 by 2020, to complement the transmission development associated with Inga 3. Although those investments are outside the scope of the project, if realized, they will increase the economic viability of the SAPMP, resulting in an EIRR of about 20.9% and corresponding to a NPV of US$676 million.

Project Financial Analysis

126. The Project Financial Analysis considers only the revenue derived by SNEL form the project and the costs (investments and operation) incurred by SNEL. The bulk of project costs will be supported by SNEL (with the exception of investments borne by CEC) and a large part of the project economic benefits will accrue to consumers, given that electricity prices are well below the willingness to pay. By construction, the Project Financial Internal Rate of Return (FIRR) is much lower than the EIRR.

127. The additional revenue from the project has been estimated based on the expected destination of the incremental energy transmitted. The estimate is that 60% of the incremental energy would go towards exports, and the rest towards HV (20%), MV (15%) and LV (5%) in Katanga. Based on current electricity export prices and tariffs for electricity, this would result in an average price of 4.5 US$c/kWh, and in effectively collected revenue of 3.8 US$c/kWh (given a low collection rate on some domestic customer categories). Under such a scenario, the project

5 The proposed additional financing will support SNEL by financing the services of an international consulting firm to assess the feasibility of increasing the transit capacity of the transmission system from Inga through Kolwezi to Kasumbalesa and associated detailed costs. See Annex 4 for details.

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would have a negative financial rate of return for SNEL. The project FIRR would be positive only if average revenue per kWh is at least 4.7 US$c /kWh. In order to break even in terms of financial NPV (using a 5% discount rate which is the expected IDA Grant on-lending rate to SNEL), the revenue per kWh would need to be 5.0 US$c or more.

128. The team has identified a “break even scenario” (see Annex 7 for details of “current tariffs and collection scenario” and “break even scenario”) that would allow to achieve a revenue of 5.0 US$c/kWh. This scenario does not appear out of reach, since from 2006 to 2011, SNEL has already significantly improved it revenue collected per kWh. The scenario would imply to increase the average export price to 4.5 US$c/kWh. With regard to domestic sales, the scenario would require to improve collection for HV and MV sales and modestly adjust HV tariffs. No change is assumed with regard to LV tariffs and collection rate.

129. In fact, SNEL and the GoDRC should set more ambitious targets with regard to tariff adjustment and collection. The ongoing price/tariff adjustment process should be continued, and contracts with mining and exports renegotiated in parallel with the improvement expected in reliability of supply. In terms of enforcing stricter payment discipline, SNEL should be supported by the GoDRC. In particular, the State-owned mining company Gécamines should be forced to pay its electricity consumption fully and timely A legal covenant in this regard has been included as part of the proposed second additional financing to ensure that the State pays its arrears and remains current with regard to its electricity bills.

130. These results could not be compared with the SAPMP AF 1 since no project financial analysis was carried out during the appraisal of the first additional financing. This is likely linked with the fact that the main benefits for the SAPMP project come from its regional nature and overall economic benefits and not from its financial profitability to SNEL (despite the fact that the project should be financially sustainable).

B. Financial Analysis of SNEL

131. Recent trends in SNEL’s financial performance have been mostly positive in terms of revenue collected, which has more than doubled between 2006 and 2011. 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 the cost of service. SNEL is still not in a position to finance major new investments, 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).

132. Assuming the positive trend in revenue per unit is sustained (mostly through gradually improving collection rates), the cash-flow forecast over the period 2012-2019 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 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 re-

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establish 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. Binding legal and financial mechanisms to ensure that adequate funding will be available to operate and maintain the assets financed by this project are already in place. In addition, the PMEDE Project includes several components dedicated to improving SNEL’s corporate governance and performance (see Annex 6 for further details).

C. Financial Management (FM), Reporting, Audit and Disbursement Arrangements

133. Current Institutional Arrangement: The FM system and performance of BCECO (contracted as the Procurement and Financial Management Agent) under the initial project are acceptable to IDA. BCECO is responsible for financial management (FM) and remains the Bank focal point for fiduciary aspects until the agreement for transfer of responsibility to the PIU becomes effective. BCECO is very familiar with the Bank FM procedures and requirements and has managed and is currently managing several IDA-financed projects. The FM arrangements of the additional financing will follow the same approach as the implementation arrangements in place for the ongoing Project. The current FM staffing is deemed acceptable; no additional FM staff needs to be recruited. TOMPRO, the multi-project accounting software, operates well and will be also used for the additional financing. The procedures manual, which has been updated during the preparation of the first AF of the PMEDE is acceptable to IDA.

134. However, 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 and large infrastructure, construction activities and equipment acquisitions. The actions plan derived from the implementation support mission of July 2011, as well as the recommendations of the 2010 external audit reports have been or are being implemented well.

135. The Interim un-audited Financial Reports (IFR) are prepared every quarter and submitted to the Bank regularly and on time (e.g. 45 days after the end of each quarter). The key FM issues facing the project related to: (i) the weak compliance with the project expenditures eligibility leading ineligible expenditures in the amount of US$ 613,595 (contrary to the terms and conditions of the initial Financing Agreement, SNEL did not contribute to local costs and all the categories of expenditures were 100% funded by IDA resources) – this amount had been reimbursed to IDA; and (ii) delays in payment of the government counterpart funds.

136. Transfer of the FM function from BCECO to SNEL’s PIU: Finally, a program of capacity building and transfer of fiduciary responsibility from BCECO to SNEL’s PIU is being implemented. The objective of the program was to transfer the fiduciary responsibility of the projects (PMEDE and SAPMP) to SNEL’s PIU by April 2012. The assessment of the implementation of the program revealed some delays and therefore the initial due date was not met because of the following issues: (i) staffing arrangements of the PIU is not completed yet; (ii) training of PIU staff by BCECO still underway; and (iii) accounting software and training of the staff not yet completed. Therefore, it was agreed to postpone the transfer to SNEL’s PIU by end September 2012. The action plan has been updated and is presented in Attachment 1 of

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Annex 3. An assessment will be conducted by Bank fiduciary team in due time prior to the final transfer of fiduciary responsibility to PIU.

137. Internal Audit Function: The internal audit function contracted to an individual international consultant operates well. Similarly to the FM function, it was decided to gradually transfer the internal audit function to the SNEL internal audit department. Two staff will be assigned to the PMEDE and will cover also the activities of the SAPMP. For the same reasons as above, the deadline has been postponed to September 2012. An assessment will be conducted by Bank FM team in due time prior to the final transfer of internal audit function’s responsibility to PIU.

138. Audit Reports: There is no overdue audit report for the project, for SNEL and for the sector 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, 2010 was submitted on time. The auditor expressed an unqualified opinion and the report deemed acceptable to IDA. The next audit reports of the IDA-financed projects in the sector in DRC are due on June 30, 2012. However, the audit report of the entity’s (SNEL) 2010 financial statements was received with some delays and was qualified. The qualification was mainly due to a limitation on the audit scope, an overestimate of SNEL’s revenue and some internal control weaknesses. SNEL’steam took some measures to shorten the delays and to implement the action plan derived from the audit report. A detailed action plan covering operational aspects (financial, accounting, technology system, human resources, etc.) was submitted to the Bank by SNEL’s team and is currently under satisfactory implementation with close monitoring by the World Bank’s project team. Three international consultants were appointed to provide technical assistance to SNEL’steam. The accounts of the 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 of audit reports and place the information provided on the official website within one month of the report being accepted as final by the team.

139. Designated Accounts: The existing designated account (DA) opened under AF1 will be used for AF2 and the ceiling may be increased during project implementation if needed and at request of the GoDRC. It is, however, expected that most of the payments related to AF2 for contract 4 (in the amount US$ 180 million) will be made using direct payments or special commitments due to the size of the payments under this large contract.

140. Upon Grant effectiveness, the project will continue to use transaction-based disbursements. The project will continue to disburse against submission of Statements of Expenditures (SOE) reporting on the use of the previous advances. The option to disburseagainst submission of quarterly unaudited Interim Financial Report (also known as the Report-based disbursements) could be considered, as soon as the Project meets the criteria6. The electronic submission of Withdrawal Application (WA) will continue to be used by the Projectand 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.

6 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.

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141. The full proceeds of the grant have been allocated to Category 1 (which includes the main rehabilitation contracts including Contract no. 4). This amount may be reallocated to other categories to supplement initial amounts allocated to the disbursement categories of the originalfinancing or AF1 if deemed necessary. A reallocation of proceeds of the AF1 is also proposed to redistribute funds to better reflect the revised project costs and risk analysis carried out during the processing of the AF2. The financing percentages for each category of expenditure, including for local expenditures covered at 90 percent or 85 percent depending on the category, under the AF2 will be aligned with the financing percentages of original project and AF1, as shown in Annex 3.

142. Detailed FM and disbursement arrangements are provided in Annex 3.

D. Procurement

143. Current Institutional Arrangements: Procurement activities under the Additional Financing will be carried out in accordance with the Bank’s “Guidelines: Procurement of Goods, Works and Non-consulting Services under IBRD Loans and IDA Credits and Grants by World Bank Borrowers” dated January 2011, and “Guidelines: Selection and Employment of Consultants under IBRD Loans and IDA Credits and Grants by World Bank Borrowers” dated January 2011, and the provisions stipulated in the Financing Agreement. However, for contracts not advertised internationally, the provisions of new national procurement law should be applied subject to IDA approval. The existing implementation manual which was validated under the original project will remain in force and apply to the Additional Financing. This manual defines well the role and responsibility of each actor/beneficiary in the management of the procurement cycle and the processes to be followed. For each contract to be financed by the AF, the different procurement methods or consultant selection methods, the need for pre-qualification, estimated costs, prior review requirements, and time frame will be agreed between the SAPMP team and the Bank in the Procurement Plan. 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 2011 will also apply to the project.

144. For the time being, all procurement operations of the two Bank financed projects of the Energy Sector are handled by BCECO through a contract of technical assistance.

145. Transfer of the Procurement Function from BCECO to SNEL’s PIU: The procurement capacity of the implementing agency within SNEL was assessed by the Bank Procurement Team, on February 2012. The assessment found that the procurement capacity in SNEL, including the Project Coordination Unit, was very weak and inappropriate, and recommended strengthening through specialized technical assistance and training. In this technical assistance contract, BCECO has among other responsibilities to assist SNEL to establish its Procurement Unit within SNEL’s PIU for the SAPMP and PMEDE projects. To this end four selected SNEL staffs have been trained formally and on the job by BCECO. In addition a specific action plan to allow the transfer of procurement responsibility from BCECO to SNEL’s PIU by end September 2012, has been developed and is presented in Attachment 1 of Annex 3.

146. The overall project risk implementation for procurement is high due to the Country context and the weak procurement capacity of the implementing agency, SNEL.

147. Procurement Plan: The Borrower has already submitted a revised procurement plan for the implementation of the Additional Financing, covering activities under the project until

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closing date, 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.

E. Safeguards

148. The project is Category A. Safeguards policies triggered include: (i) Environmental Assessment (OP/BP 4.01); (ii) Natural Habitats (OP/BP 4.04) and (iii) Involuntary Resettlement (OP/BP 4.12). Safeguards instruments prepared to mitigate potential adverse environmental or social impacts were: an Environmental Impact Assessment (EIA) and a Resettlement Action Plan (RAP) and Environmental and Social Management Plans (ESMPs). An independent consultant prepared the instruments, which were cleared by the client (SNEL) and the Bank, and disclosed in 2004, both in DRC and Zambia. In 2008, the safeguards instruments were updated, cleared and re-disclosed, by the client and by the Bank.

On the DRC Side

149. The client set up an environmental unit in SNEL (eight staff – five environmental specialists and three social development specialist), in line with the project requirements and the loan agreement.

150. The RAP implementation for the construction of a new HV alternating current (AC) transmission line from Fungurume to Kasumbalesa in Katanga, onto the Zambian border, financed under Component 2, was started in 2010, in conjunction with the commencement of civil works for the transmission line. While the implementation of the ESMPs was satisfactory,shortcomings were noted in the implementation of the RAP and a resettlement audit was triggered.

151. The findings of the audit suggested that: i) the original RAP from 2008 contained several weaknesses (eg limited engagement with local authorities, weak grievance mechanism in place, vulnerable people not properly assessed); ii) the number of households adversely affected by the construction of the transmission line was estimated at 435 in 2008, against about 865 as established by the audit in 2012. The auditor and SNEL inventoried 285 cases of complaints. Of this total, 155 were judged not eligible and 29 cases were identified as eligible, 101 cases remain to be addressed (a grievance process has been put in place to determine how many of the remaining households are eligible for compensation); compensation has been negotiated according to the principle of replacement cost at market value.

152. An Action Plan was completed by the auditor and endorsed by SNEL to address any shortcomings in the resettlement process. Key actions include: i) hiring of an independent consultant to carry out remaining outstanding compensation; ii) the establishment of a multi-stakeholder Compensation and Resettlement Committee, which will include community representative, local authorities and SNEL staff; iii) strengthening UGES presence on the ground; iv) ensuring that the RAP institutional arrangements and a proper grievance mechanism are in place. These actions will be fully completed by October 2012. Close monitoring ofprogress on those actions will be part of the Bank’s supervision and is a dated covenant under the AF2 project agreement. A summary of the conclusions of the audit and action plan has been disclosed in country and on InfoShop.

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153. In addition, to enhance the benefits of local communities, SAPMP includes a component for community infrastructure development along the transmission line from Fungurume to Kasumbalesa; seven selected villages are targeted. The objective of the component was, and still is, to increase the social benefits of the project, particularly, to electrify the selected villages. The combined effect of electrification and community infrastructures is expected to trigger an induced development and transform those villages to local growth pools. Criteria used for village selection included, proximity to the transmission line (the closer to the line, the better), population size (the larger the population, the better), and poor access to public services. Infrastructures to be built are: schools, health clinics and centers, and water wells in addition to the provision of village electrification.

154. A review of the environmental and social documentation of the community infrastructure designs, ahead of the commencement of the civil works, revealed several shortcomings, both in terms of design of the investments and environmental and social documentation. Remedial actions were identified prior to commencement of civil works and they included: i) consultations with provincial and local stakeholders; ii) the preparation of an Environmental and Social Management Framework (ESMF) and Environmental and Social Management Plan (ESMP); iii) the preparation of a Medical Waste Management Plan (MWMP); (iii) the creation of a local community infrastructure working group (including: SNEL, relevant sector representatives of the Katanga provincial administration, and the supervision consultant) to closely review the needs, designs and construction of the community infrastructures. The studies were consulted upon and disclosed in-country and at the InfoShop.

155. The World Bank team is closely supervising this component. As already provisioned in the AF1, the AF2 will continue to provide social and environmental support to finance social and environmental studies as needed during implementation (such as abbreviated social assessment surveys or beneficiary assessments) to better tailor the investments to the local context and tomonitor and evaluate the outcomes of the component to ensure it fully achieves its intended objectives.

On the Zambian Side

156. In Zambia, a similar safeguards process took place, but without the deficiencies encountered in DRC. The Copperbelt Energy Corporation (CEC) took the direct responsibility for the safeguards instruments. Already for the original project, in June 2003, CEC prepared an ESIA, ESMPs and RAP for the population to be affected by the construction of the additional transmission line between Luano (Zambia) and Kasumbalesa (DRC). The studies were approved by the Zambia Environmental Council (ZEC) and in line with the Bank’s safeguard policies.

157. The 2003 ESIA was then revised and disclosed in January 2009, to take into account the results of the public disclosures, and submitted to the ZEC for its review and approval. The Bank’s review confirmed full compliance of the updated ESIA with the Bank’s safeguard policies, and has been subsequently disclosed in the InfoShop and in country in February 2009.

158. The ESIA and RAP assessed any potential issues associated with the line routing. On the environmental side, the final line routing will follow the right-of-way for the already existing 220kV Zambia-DRC interconnector and traverse two National Forest Reserves7. According to

7 Kamenza Forest reserve No. 19 and Luano Forest Reserve No. 12, which are legally protected areas and classified as IUCN Category VI protected areas.

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the ESIA, the conversion of the critical natural habitats for power line construction is not significant, as it does not threaten the integrity of the forests involved. The existing right-of-way will be used (land already converted) and the damage to the forest (which appears to be degraded) is expected to be very limited in extent.

159. The recommendations included in the studies have since then been fully and satisfactorily implemented in line with the ESIA and Bank’s environmental and social guidelines. Similarly, the Bank also found the implementation of the RAP in compliance with the requirements of the ESIA, the Bank and Zambia guidelines. However, due to the delays in the implementation of the corresponding investment in DRC, this additional line has not been built. ESMPs related to construction works have therefore not been implemented yet.

160. As part of the AF1, CEC has committed to SNEL and IDA that it would comply with the Bank’s and Zambian environmental and social safeguards requirements. IDA may exercise its remedies under the Financing Agreement if CEC’s commitment does not become effective by the agreed date or if, having become effective, it is breached. Furthermore, Zambia, under separate Development Credit Agreement, which was amended on August 2009 as a condition for effectiveness of AF1, has committed to cause CEC to comply with the Bank’s and Zambian environmental and social safeguards requirements.

161. Similar mechanisms will be put in place for the SAPMP AF2 to ensure that CEC complies with both Zambia’s and Bank’s environmental and social policies before beginning of any construction work for the line. In addition, the team will review with CEC whether an additional update of the ESIA and RAP is needed, which will be financed by CEC.

F. Results and Overall Risk Rating

162. The PDO and result framework for the project have been reviewed and a revised matrix for the results indicators is shown in Annex 1.

163. 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.

164. Furthermore, risks are also posed by the development of the post-election context, in terms of the potential impacts 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. 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.

165. The risk assessment in the ORAF (Annex 2) reflects a better understanding of the context in which these projects are prepared and implemented. In addition, a project Implementation Support Plan (see Annex 9) has been prepared to ensure that the proper mitigating measures are put in place and implemented.

166. In retrospect, projects characterized by such challenging technical difficulties, prepared and implemented in a complex territory and environment required a stronger supervision from the very beginning. To reinforce the Bank’s Implementation Support for the program, the supervision arrangements/strategy on the Bank’s side currently includes dual TTL-ship in

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Washington, with the support of two senior level staff (based in Dakar and Kinshasa), a strong team of experts (including a senior hydro specialist and a senior financial analyst). A new field based energy specialist should be recruited as soon as possible. The project and all other related regional and DRC energy operations also benefit from very close managerial oversight at level of Sector Manager and Sustainable Development department Senior Manager as well as strong support by the Country Director. An Implementation Support Plan has been prepared and presented in Annex 9. The Plan also includes a series of specific actions to ensure proper supervision in terms of transparency and anti-corruption issues, developed with the support of INT.

167. Deficiencies were also noted in the owner’s engineer performances, including insufficient presence and decision-making process in the field, causing delays in procurement and implementation. SNEL and its owner’s engineer have agreed to resolve those performance issues by identifying key actions to be taken over the next three months (for further details seeAnnex 9). By July 2012, SNEL will carry out an audit of the owner’s engineer performances and conclude whether the key actions were satisfactorily implemented and adequate for a satisfactory performance of the owner’s engineer.

168. In addition, the risk associated with additional cost overruns and major increases in the scope of work due to further deterioration of the transmission system were significantly underestimated during AF1. Additional technical support in transmission network engineering has also been brought in during preparation and appraisal to ensure a deep assessment of the outstanding issues and confirmation of proper costing and contingency estimation. In-depth studies and analysis have now established the full scope of the rehabilitation work. In addition, a series of measures have been taken to ensure the sustainability of the investments. Those include a series of arrangements of Operation and Maintenance as summarized in the Box below. Details are included in Annex 6, together with the actions to improve SNEL governance and performance.

Box 5: O&M Arrangements to Ensure Sustainability (SAPMP and PMEDE)

Appropriate O&M of transmission and generation assets financed under the SAPMP and PMEDE projects is an essential element to achieve the sustainability and normal lifespan of these assets. The gradual improvement of SNEL’s financial position will ensure in the medium term sufficient resources to finance O&M activities as required. In the short to medium term, specific institutional and financing arrangements have been agreed upon with SNEL to ensure appropriate O&M of transmission and Inga hydropower assets.

Improvement of transmission facilities operation and maintenance includes the following aspects:

Establishment of dedicated escrow accounts for O&M financing, automatically provisioned by identified mining customers;Technical audit of transmission O&M, to define appropriate O&M costs and organization; andRecruitment of a private contractor for O&M of SNEL high voltage transmission assets.

Improvement of Inga facilities operation and maintenance includes the following aspects:

Restructuring and strengthening of SNEL’s Inga O&M organization, staffing and procedures;Costing/programming of appropriate maintenance at Inga;

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Establishment of a financial mechanism (dedicated account with periodic audit of disbursement) to ensure availability of funds for O&M; andReview 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, with opportunity of combination with Inga 3 development)

169. Given its complexity and the fragile context, despite the mitigating measures put in place, the project implementation is still deemed to be affected by substantial risks. The project costs are now known with greater details since all the major rehabilitation contracts have been signed. The team has also worked closely with SNEL and the Owner Engineer to identify and price the risks that may cause further cost overruns to materialize and appropriate contingencies have been identified. A table summarizing the risk ratings summary is presented below.

Table 7: Summary of Risk ratings for the AF2Stakeholder Risk HImplementing Agency Risk- Capacity S- Governance H

Project Risk- Design H- Social and Environmental H- Program and Donor L- Delivery Monitoring and Sustainability H

Overall Implementation Risk H

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Annex 1: Revised Results Framework and Monitoring

AFRICA: Southern African Power Market Project APL1 (SAPMP) Second Additional Financing

Revisions to the Results Framework Comments/Rationale for Change

PDOCurrent (PAD) Proposed changeTo facilitate further development of an efficient power market in the Southern African Development Community (SADC).

To expand transmission capacity to better serve domestic and regional power demand

The revised PDO would better reflect the project area of influence and physical investments.

PDO indicatorsCurrent PAD Proposed change

Power transfer capability of HVDC and HVAC transmission system from Inga to the border with Zambia restored to its original installed capacity of 576 MW (2x288MW)

New: To evaluate progress towards restoring the transmission corridor from Inga to the Zambia border.

Targets will be confirmed during appraisal.

Quantity of firm and reliable electricity exports from DRC to the SAPP

Quantity of energy exported from DRC to the SAPP system (GWh)

Expansion of transmission capacity to exports will be better captured by measuring the quantity of energy exported to the SAPP.


Quantity of firm and reliable power supplied to mines, and other consumers in the Katanga Province

Quantity of energy delivered to Katanga region (mines and consumers in the Katanga province) (GWh)

The new indicator will capture the energy available thanks to the project for serving the domestic demand.


Direct Project beneficiaries8 New

of which female New

Un-direct Project beneficiaries9 New

Commercial and technical information about local and regional electricity supply and market available on a regular basis

Dropped This is more an intermediate indicator. (see intermediate indicator 1)

8 Direct beneficiaries will be calculated based on the number of persons directly impacted by the Community Development component.9 Based on SNEL’s number of customers (wit average household size of 8 persons)

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Intermediate Results IndicatorsCurrent (PAD) Proposed change

Tie line flows based on predictive load flows available to pool participants on a regular basis

Unchanged Will capture the results of Component 1.

Power transfer capability of HVDC and HVAC transmission system from Inga to the border with Zambia restored to its original installed capacity of 576 MW (2x288MW)

Indicators included at PDO level Will evaluate progress towards restoring the transmission corridor from Inga to the Zambia border.

Availability at Full Load Dropped Redundant with DO indicator number 1.

Transmission Loss level Dropped Replaced by Intermediate indicator number 2.2

Stable frequency (50Hz) of current maintained

Dropped

Stable HVDC voltage maintained Dropped

Feasibility Studies completed for DRC /Zambia interconnectors, and for Zambia/ Tanzania interconnector

Proposed change: Indicator 4.1: “Feasibility and preliminary design of an interconnector between Zambia and Tanzania completed”

Intermediate indicator for Component 4.

Environmental and Social Studies completed for Zambia – TZ Interconnection

Dropped Activity completed

New New:Length in km of new operational high voltage transmission line constructed under the project

Core Indicator

New New:Length in km of rehabilitated and reinforced operational high voltage transmission line under the project

Core Indicator

New New:

Number of km of modern OPGW fiber cable installed over the high voltage transmission line from Kinshasa to the border with Zambia

To measure results of sub-component 5

Number of community project completed

Number of social infrastructures constructed under the project in the Katanga province:

Education related: number of classrooms at primary level.

Health related: number of health facilities constructed, renovated or equipped

Water related: number of water facilities (wells) built.

Detail proposed between education, health, water and HIV/Aids related results.

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Number of household under RAP Dropped Activity almost completed

Number of communities participating in the HIV/Aids campaign

Unchanged

New Number of km of double circuit 220kV line constructed from the Luano substation to link the DRC transmission system

Result indicator for component 3.

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REVISED PROJECT RESULTS FRAMEWORK

Project Development Objective (PDO): To expand transmission capacity in order to better serve domestic power demand

PDO Level Results Indicators1

Cor

e

UOM2

BaselineOriginalProjectStart

(2003)

Progress To Date(2011)3

Cumulative Target Values

FrequencyData Source/Methodology

Responsibility for Data

CollectionCommentsEnd 2012 End 2013 End 2014 Project

End

1. Power transfer capability of HVDC and HVAC transmission system from Inga to the border with Zambia restored to its original installed capacity of 560 MW

MW N/A 150 230 560 560 560* Semi-annual

SNEL Monitoring SNEL

2. Quantity of energy exported from DRC to the SAPP system (GWh)

GWh N/A 0 216 1,296 1,296 4,320 Semi-annual


3. Quantity of energy delivered to Katanga region (mines and consumers in the Katanga province) (GWh)

GWh N/A 2,540 2,915 3,260 3,913 5,515 Semi-annual


Beneficiaries

4. Direct Project beneficiaries4 Number 0 0 0 2,400 6,500 10,000 Annual SNEL

Monitoring SNEL

of which female % 0 0 0 50 50 50 Annual SNEL Monitoring SNEL

5. Un-direct Project beneficiaries5 Number (in

million) N/A 6,93 7,28 7,69 8,02 8,43 Annual SNEL Monitoring SNEL

*Power transfer capability guaranteed even in case of one major failure on the HVDC and HVAC transmission system from Inga to the border with Zambia

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 Direct beneficiaries will be calculated based on the number of persons directly impacted by the Community Development component.5 Based on SNEL’s number of customers (with average household size of 10 persons) assuming a 5% increase per year.

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Intermediate Results and Indicators

Intermediate Results Indicators C

ore Unit of

Measurement

BaselineOriginal ProjectStart

(2003)

Progress To Date(2011)

Target Values

Frequency Data Source/Methodology


CollectionCommentsEnd

2012End 2013

End 2014

Project End

Intermediate Result 1: Support to the SAPP Co-ordination Center

6. Tie line flows based on predictive load flows available to pool participants on regular basis

Y/N No Yes Yes Yes Yes Yes Semi-annual

Reports issued by the SAPP Co-ordination center

SAPP coordination

center

Intermediate Result 2: Rehabilitation and reinforcement of the high voltage transmission corridor from Inga to Kasumbalesa at the border with Zambia7. Length in km of new operational high voltage transmission line constructed under the project

km 0 95 250 286 286 286 Semi-annual

SNEL Monitoring SNEL .

8. Length in km of rehabilitated and reinforced operational high voltage transmission line under the project

km 0 0 0 1,500 3,000 4,000 Semi-annual


9. Number of km of modern OPGW fiber cable installed over the high voltage transmission line from Kinshasa to the border with Zambia

km 0 0 500 1,500 2,300 2,300 Semi-annual


10. Number of social infrastructures constructed under the project in the Katanga province:

Education related:number of classrooms at primary level.

Health related: number of health facilities constructed, renovated or equipped

Water related:

Number

0

0

0

0

0

0

36

0

24

42

7

36

42

7

36

42

7

36

Semi-annual


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Intermediate Results and Indicators

Intermediate Results Indicators C

ore Unit of

Measurement

BaselineOriginal ProjectStart

(2003)

Progress To Date(2011)

Target Values

Frequency Data Source/Methodology


CollectionCommentsEnd

2012End 2013

End 2014

Project End

number of water facilities (wells) built

11. HIV/Aids related:number of communities participating in the HIV/Aids campaign

Number 0 168 168 168 168 168 Semi-annual


Intermediate Result 3: Construction of a double circuit 220kV line by CEC from Luano substation in Zambia to link the DRC transmission system at Kasumbalesa12. Number of km of double circuit 220kV line constructed from the Luano substation to link the DRC transmission system

km 0 0 0 0 40 40 Semi-annual CEC Monitoring CEC

Intermediate Result 4: A feasibility and preliminary design of an interconnector between Zambia and Tanzania that would be formed by interconnecting Tanzania, Uganda and Kenya13. Feasibility and preliminary design of an interconnector between Zambia and Tanzania completed

Y/N No Yes Yes Yes Yes Yes Semi-annual

Reports issued by the SAPP Co-ordination center

SAPP coordination

center

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Annex 2: Operational Risk Assessment Framework (ORAF)

AFRICA: Southern African Power Market Project APL1 (SAPMP) – Second Additional Financing

1. Project Stakeholder Risks Rating HighDescription :

Inadequate or ineffective stakeholder participation and capacity could undermine success or sustainability of project activities.

The PMEDE project has attracted the attention of several NGOs. Given the association of the project with the rehabilitation and development of the Inga site, and the high scrutiny on those activities, there is the risk that the project may be controversial.

Risk Management :

Stakeholder communications and dialogue with Government and civil society is ongoing under the existing PMEDE and SAPMP operations.

Transparency is provided through disclosing key documents at strategic locations in DRC and on the Bank’s website, and consultation with local governments, traditional leaders, affected communities and NGOs, as well as through continuing communications and dialogue with civil society.Resp: World Bank Stage: Preparation Due Date : Ongoing Status: Ongoing

2. Implementing Agency Risks (including fiduciary)3.1. Capacity Rating: SubstantialDescription :Implementation entities affected by weak capacity, potential delays in procurement and governance challenges.

There is a risk of further delays in the transfer of fiduciary responsibility from BCECo to SNEL.

Risk Management :

The PMEDE includes ongoing mitigation measures to strengthen SNEL capacity. A comprehensive program aimed to enhance SNEL’s corporate governance and operational performance, and its financial position and operational sustainability, is also being put in place. As mentioned, the performance contract, which was a dated covenant for the PMEDE AF and a condition of appraisal for SAPMP AF2, has been signed. The launch of the RfP for the recruitment of the consultant for the TA service agreement was a condition for appraisal for the SAPMP AF2 and fully achieved.

Reinforcement of the Project Engineering Consultants has been carried out (with more staff on the ground in Kinshasa and in Katanga). SNEL PIU has also been strengthened with the recruitment of a top-level Project Management Adviser with experience in managing large projects. Strong implementation support will be provided by the Bank team and further capacity building and operational practices and systems improvements will be carried out under the PMEDE.

Capacity building activities envisaged under the PMEDE additional financing to support the transfer of fiduciary responsibility from BCECO to SNEL have been delayed. An action plan has been agreed between SNEL and the Bank’s FM and procurement team to ensure that this transfer is completedby September 2012 (see Attachment 1 in Annex 3).

Resp: Government and World Bank

Stage: Preparation and Implementation Due Date :Ongoing Status: Ongoing

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3.2. Governance Rating: HighDescription :The main risk is the weak and slow decision making process in term of accountability, transparency and oversight challenges in the sector.

Risk Management :

The PMEDE includes a comprehensive program aimed to enhance SNEL’s corporate governance and operational performance, and its financial position and operational sustainability. It will comprise: (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 (e) institutional and financing arrangements for appropriate O&M at the Inga plants.

SAPMP also include financing arrangements for appropriate O&M of the rehabilitated transmission line. EoI published and RfP finalized for the recruitment of the consultant to prepare the bidding documents for the recruitment of the O&M operator for SNEL’s HV transmission system was acondition for appraisal for the SAPMP AF2.

Resp: SNEL Stage: Implementation Due Date : Ongoing Status: Ongoing4. Project Risks4.1. Design Rating: HighDescription :The two main source of risks in project design are (i) more than expected dilapidated infrastructures; (ii) less than expected PPAs for exports; and (iii) lack of transmission capacity in neighboring countries;

The power transmission capacity constraints that have developed in the countries South of DRC over the past two years, mainly in Zimbabwe has become a significant bottleneck to the north-south power trade in the SAPP, as well as the export of power from DRC to importing countries in the SAPP. Also, a constrain of supply due to delays associated with the rehabilitation of Inga hydropower plants and lack of demand at regional level may hamper SNEL’s capacity to enter in long term PPAs with other regional partners.

Risk Management :

The proposed additional financing is based on the most recent and available technical information regarding the outstanding project activities and scope of the rehabilitation. For each contract, a risk analysis has been performed and contingencies identified to address potential future risks.

SNEL has a number of PPAs finalized and/or under negotiations. The team has been working closely with SNEL to identify any issues potentially hampering exports and it will continue to do so during project implementation. Market analysis and supply demand balances will be carried out during appraisal to ensure proper assessment of market risk. Close supervision of the activities under PMEDE will ensure that the rehabilitation of Inga power plants is implemented within the agreed timeframe. Financing by Bank and other donors for enhancing transmission capacity in countries South of DRC is also considered under a wider regional approach to sustain the development of the SAPP. Annex 5 on the regional analysis provides further details on the identification of bottlenecks and other Bank operations to ease this risk. The signing of the PPA between CEC and SNEL was a condition of negotiations for the SAPMP AF2.

Resp: World BankStage: Preparation/Implementation

Due Date : Ongoing Status: Ongoing

4.2. Social & Environmental Rating: HighDescription :Risk associated with environmental and social potential negative impacts from Project activities.

Risk Management :

The Environmental and Social Impact Assessments and Resettlement Action Plan prepared in

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A specific risk is linked with the resolution of any outstanding issue related to the resettlement for the new line in the Katanga region.

2002/2003 were updated in 2008/2009. The environmental and social unit in SNEL has been established, properly staffed and equipped, and is being strengthened under PMEDE and SAPMP projects. 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.

Project affected persons have been compensated under the oversight of a NGO. A resettlement audit has been carried out to ensure adherence with World Bank policy. Completion of key actions part of the Remedial Action Plan produced by the auditor and endorsed by SNEL is a legal covenant for the SAPMP AF2 (to be fulfilled by October, 30 2012).Resp: SNEL and World Bank

Stage: Preparation and Implementation Due Date : Ongoing Status: Ongoing

4.3. Program & Donor Rating: LowDescription :The Project is co-financed by EIB whose loan is already effective. EIB is financing a critical component of the project and therefore a delays in this component may affect the overall Project implementation

Risk Management :

A close dialogue is being maintained with EIB to ensure good coordination.

Resp: World Bank Stage: Preparation and Implementation Due Date : Ongoing Status: Ongoing

4.4. Delivery Monitoring & Sustainability Rating: HighDescription :

The price of contracts under implementation could increase due to their delayed commissioning following late completion of the telecommunication system and unforeseen circumstances.

Timely and effective contracts management and completion of works may be an issue. Need for an additional extension of the deadline for the closing date of the project.

A key risk is also the lack of sustainability of investments due to weak operation and maintenance arrangements.

Risk Management :

All contracts have been signed and their base costs are known. The estimate for the additional financing contains contingencies to cover for unexpected events and change orders. The proposed contingencies are based on a rigorous risk analysis carried out by the SNEL, the owner’s engineer and discussed with the task team. An additional sub-component (2.9) has been added to cover for equipment not currently included in any contract, whose defects may hamper project sustainability.

Measures to enhance collaboration and process efficiency among project agencies (SNEL PIU, BCECO, the Engineer and the Ministry of Energy) have been incorporated in the revised project implementation manual. All major contracts have been signed. A slack period of one year has been added to the implementation period of the contract for the rehabilitation of transmission lines since it faces major logistical challenges.

The overall program to enhance SNEL performance together with full implementation of April 2009 phased tariff increases and continued development partner support for sector reforms, should enhance SNEL’s operational efficiency and financial position and ensure appropriate O&M arrangements and financing for SNEL’s assets. EoI published and RfP finalized for the recruitment of the consultant to prepare the bidding documents for the recruitment of the O&M operator fir SNEL’s HV transmission system was a condition for appraisal for the SAPMP AF2. In addition, provisioning of the O&M

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accounts was a condition for negotiations of the SAPMP AF2.

Resp: World Bank Stage: Implementation Due Date : Ongoing Status: Ongoing5 Implementation Risk Rating: HIGHComments:Implementation risk is High. The SAPMP should be recognized as a complex operation implemented in a particularly difficult country and sector context. The high rating reflects the fact that the wide spectrum of risks affecting this operation, trickling down from Country to sector and project level, would have an impact on the implementation and overall sustainability of the project outcomes, despite the array of mitigating measures in place. The risk has been increased from substantial to high mainly due to the risks associated with contract management and supervision of contractors’ on-the-ground activities. However, several measures have been identified in this regards to mitigate those risks (mainly outlined in Annex 9).

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Annex 3: Revised Implementation Arrangements


A. Safeguards Policies Issues

1. Project Preparation – The Project is Category A. Safeguards policies triggered include: a) Environmental Assessment (OP/BP 4.01); b) Natural Habitats (OP/BP 4.04) and c) Involuntary Resettlement (OP/BP 4.12). Triggering the policies was project component 2 and 3,the construction of a new HV alternating current (AC) transmission line from Fungurume to Kasumbalesa in Katanga, onto the Zambian boarder and the new transmission line between Luano and Kasumbalesa in Zambia.

2. Safeguards instruments prepared to mitigate potential adverse environmental or social impacts were: an Environmental Impact Assessment (EIA) and a Resettlement Action Plan (RAP) and Environmental and Social Management Plans (ESMPs). An independent consultant prepared the instruments, which were cleared by the client (SNEL) and the Bank, and disclosed in 2003. In 2008, the two safeguards instruments were updated, cleared and re-disclosed, by the client and by the Bank. The client set up an environmental unit (eight staff – five environmental experts and three social experts), in line with the PAD requirements and the legal agreement. The staff, with university degrees in related fields of agronomy, forestry and sociology/psychology received on the job training by selected international consultants. A similar process was followed on the Zambia side (see details below).

On the DRC side

3. Project Implementation – The RAP implementation for the construction of a new HV alternating current (AC) transmission line from Fungurume to Kasumbalesa in Katanga, onto the Zambian border, financed under Component 2, started in 2010, in conjunction with the commencement of civil works for the transmission line. While the implementation of the ESMPs was satisfactory, shortcomings were noted in the implementation of the RAP and a resettlement audit was triggered.

4. The findings of the audit suggested that: i) the original RAP from 2008 contained several weaknesses (eg limited engagement with local authorities, weak grievance mechanism in place, vulnerable people not properly assessed); ii) the number of households adversely affected by the construction of the transmission line was estimated at 435 in 2008 against about 865 as established by the audit in 2012. The auditor and SNEL inventoried 285 cases of complaints. Of this total, 155 were judged not eligible and 29 cases were identified as eligible, 101 cases remain to be addressed (a grievance process has been put in place to determine how many of the remaining households are eligible for compensation); compensation has been negotiated according to the principle of replacement cost at market value.

5. The change in numbers was not only the result of some Project Affected Persons (PAPs) moving into the project area to benefit from the project and induced development, but also the result of flaws in the original and the updated RAP. For instance, the village of Kimafia (460 inhabitants), which is right under the transmission line, was neither identified in the original RAP

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nor in the updated version. An assessment of the village was carried out and revealed that the village was about 60 years old. It was once resettled in the 1970s, due to the construction the transmission line from Inga to Kolwezi, in Katanga. To avert a second resettlement of Kimafia village, the current alignment of the transmission line was shifted.

6. An Action Plan was completed by the auditor and endorsed by SNEL to address any shortcomings in the resettlement process. Key actions include: (i) hiring of an independent consultant to carry out remaining outstanding compensation; (ii) the establishment of a multi-stakeholder Compensation and Resettlement Committee, which will include community representative, local authorities and SNEL staff; (iii) strengthening UGES presence on the ground; (iv) ensuring that the RAP institutional arrangements and a proper grievance mechanism are in place. These actions will be fully completed by October 2012. Close monitoring of progress on those actions will be part of the Bank’s supervision and is a dated covenant under the AF2 project agreement. A summary of the conclusions of the audit and action plan has been disclosed in country and at the InfoShop.

7. Social Development – SAPMP includes a component for community infrastructure development along the transmission line from Fungurume to Kasumbalesa; seven selected villages are targeted. The distance between the first village Nsinga and the last village Nguba, is 225 km. The objective of the component was, and still is, to increase the social benefits of the project, particularly, to electrify the selected villages. The combined effect of electrification and community infrastructures, is, expected to trigger an induced development and transform those villages to local growth pools. Criteria used for village selection included, proximity to the transmission line (the closer to the line, the better), population size (the larger the population, the better), and poor access to public services. Infrastructures to be built are: schools, health clinics and centers, and water wells; in addition the provision of village electrification.

8. This component was perceived and conceived as an infrastructure building project. The component, however, has a high socio-political visibility and has transpired to be more than an infrastructure building activity. An audit of the community infrastructure designs, ahead of the commencement of the civil works, however, revealed major flaws: (i) the Environmental and Social Management Framework (ESMF) for the infrastructure investments was not prepared, likewise, a Medical Waste Management Plan (MWMP); (ii) a social baseline study to assess, demography, social organization, social capital, existing social services and community infrastructures in the 7 villages was not conducted – some of the selected villages, had already acquired some of the infrastructures planed by the project, given the time elapsed between project preparation (2002– 2003) and project implementation (2010), and finally, (iii) the social and cultural aptness of the designs were flawed. For instance: (a) flush toilets were planned for the village schools; yet, the schools would be unable to buy toilet paper, and the water supply could not be guaranteed. Moreover the toilet mechanics were most likely to fail, within a year, leaving the children without toilets, as the schools are most unlikely to afford the repairs; (b) the building of water wells did not include community training for well management or maintenance; (c) the number of students to be served by the schools was unknown; (d) village electrification implied providing electricity to the head of the village, to the school, to the health clinic and some “street” lights; (e) the transfer mechanism for the completed community infrastructures to appropriate stakeholders was unclear; and (f) the health centers’ designs did not

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include waste pits for maternity wards, incinerators, sanctuaries for fetuses/stillborn babies, or dry morgues etc, which are traditional in the Katanga region.

9. Remedial actions were identified prior to commencement of civil works and they included: (i) consultations with provincial and local stakeholders; (ii) the preparation of an Environmental and Social Management Framework (ESMF) and Environmental and SocialManagement Plan (ESMP); (iii) the preparation of a Medical Waste Management Plan (MWMP); (iv) the creation of a local community infrastructure working group including: SNEL, relevant sector representatives of the Katanga provincial administration, and the supervision consultant to closely review the needs, designs and construction of the community infrastructures.

10. The World Bank team is closely supervising this component. As already provisioned in the AF1, the AF2 will continue to provide social and environmental support to finance social and environmental studies as needed during implementation (such as abbreviated social assessment surveys or beneficiary assessments) to better tailor the investments to the local context and to monitor and evaluate the outcomes of the component to ensure it fully achieves its intended objectives.

Table 9: Safeguards Action Table (DRC)Safeguard Instrument Preparation Implementation

1 Environmental and Social Impact Assessment (ESIA)

2003 – Updated 2008 2010 – 2012

2 Resettlement Action Plan (RAP) 2003 – Updated 2008 2010 – 20123 Creation of SNEL’s environmental unit 2003 2009 – 2011

4Environmental and Social Management Framework (ESMF) for Community Infrastructures

2009 2010 – 2012

5 Medical Waste Management Plan (MWMP) for Community Infrastructures

2009 2010 – 2012

6 Resettlement Audit 2011 2012

8 Cost estimates for Resettlement/Rehabilitation US $ 1,660.000 million

in (2003)US $ 3,016.994

million in (2012)9 Cost estimates for Community Infrastructure US $ 4.400 million

(2003)US $ 10,000,000 million in (2012)

Note: key safeguards instruments above were consulted upon and disclosed in-country and at InfoShop.

On the Zambian side

11. In Zambia, a similar safeguards process took place, but without the deficiencies encountered in DRC. The Copperbelt Energy Corporation (CEC) took the direct responsibility for the safeguards instruments. Already for the original project, in June 2003 CEC prepared an ESIA, RAP and ESMPs for the population to be affected by the construction of the additional transmission line between Luano (Zambia) and Kasumbalesa (DRC). The studies were approved by the Zambia Environmental Council (ZEC) and in line with the Bank’s safeguard policies.

12. The 2003 ESIA was then revised and disclosed in January 2009 to take into account the results of the public disclosures, and submitted to the ZEC for its review and approval. The

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Bank’s review confirmed full compliance of the updated ESIA with the Bank’s safeguard policies, and has been subsequently disclosed in the InfoShop and in country in February 2009.

13. The ESIA and RAP assessed any potential issues associated with the line routing. On the environmental side, the final line routing will follow the right-of-way for the already existing 220kV Zambia-DRC interconnector and traverse two National Forest Reserves15. According to the ESIA, the conversion of the critical natural habitats for power line construction is not significant, as it does not threaten the integrity of the forests involved. The existing right-of-way will be used (land already converted) and the damage to the forest (which appears to be degraded) is expected to be very limited in extent.

14. The recommendations included in the studies have since then been fully and satisfactorily implemented in line with the ESIA and Bank’s environmental and social guidelines. Similarly, the Bank also found the implementation of the RAP in compliance with the requirements of the ESIA, the Bank and Zambia guidelines. However, due to the delays in the implementation of the corresponding investment in DRC, this additional line has not been built. ESMPs related to construction works have therefore not been implemented yet.

15. As part of the AF1, CEC has committed to SNEL and IDA that it would comply with the Bank’s and Zambian environmental and social safeguards requirements. IDA may exercise its remedies under the Financing Agreement if CEC’s commitment does not become effective by the agreed date or if, having become effective, it is breached. Furthermore, Zambia, under separate Development Credit Agreement, which was amended on August 2009 as condition for effectiveness of AF1, has committed to cause CEC to comply with the Bank’s and Zambian environmental and social safeguards requirements.

16. Similar mechanisms will be put in place for the SAPMP AF2 to ensure that CEC complies with both Zambia’s and Bank’s environmental and social policies before beginning of any construction work for the line. In addition, the team will review with CEC whether an additional update of the ESIA and RAP is needed, which will be financed by CEC.

B. Implementation Arrangements

17. 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. SNEL has also established an Environmental and Social Management Unit (UGES)with adequate organization, logistics and resources. The PIU is responsible for coordinating and monitoring implementation of the Project. The PIU comprises staff from the Ministry of Energy (MoE), SNEL, the Ministry of Finance and the Steering Committee for Public Enterprises Reform (COPIREP) and 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.

15 Kamenza Forest reserve No. 19 and Luano Forest Reserve No. 12, which are legally protected areas and classified as IUCN Category VI protected areas.

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18. 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.

19. Transfer of fiduciary responsibilities from BCECO to SNEL’s PIU: The second AF will be initially implemented under the same institutional, procurement and disbursement arrangements as for the original and AF1 project with the PIU at SNEL being the implementing entity and the Bureau Centrale de Coordination (BCECO) responsible for fiduciary aspects of the project. However, under PMEDE, it was envisaged to transfer fiduciary responsibility from BCECO to SNEL by end of April 2012. The World Bank fiduciary team, assessed in February 2012 SNEL’s capacity to take over those functions and concluded that additional actions need to be conducted to allow the transfer. New action plans have been developed and agreed with SNEL and BCECO to allow this transfer by end September 2012 (see details in FM and procurement sections below). However it is clear that the transfer will be carried out only when financial and procurement assessments demonstrate that there is enough capacity in SNEL to carry out fiduciary functions without jeopardizing project implementation.

20. 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.

Figure 2: Summary of Implementation Arrangements

C. Financial Management

21. BCECO contracted as FMA will remain the Bank focal point for fiduciary aspects until the arrangement agreed to transfer the responsibility to PIU/SNEL become effective. BCECO is very familiar with the Bank Financial Management (FM) procedures and requirements. The FM

PIU

MoE(CATE)

BCECO

PMEDE and SAPMP

SNEL (UGES)Owner’s Engineer

COPIREP

Procurement and Financial Mng

Safeguards

Sector Reform

SNEL

PCU

Monitoring and Evaluation

PCU = Project Coordination Unit (staff from MoE, SNEL, MoF, COPIREP and CATE)PMU = Project Management UnitCATE = MoE Technical Secretariat

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of the second Additional Financing (AF2) will follow the same approach as the implementation arrangements in place for the ongoing initial phase and AF1 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 (e.g. 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 July 2011 and there is no overdue audit report in the projects managed byBCECO 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 and large infrastructure, construction activities and equipment acquisitions. The SNEL financial statements audit report are also current.

22. Finally, an ongoing program of capacity building and transfer of fiduciary responsibility from BCECO to PIU/SNEL is being implemented. The objective of the program was to transfer the fiduciary responsibility of the projects to SNEL’s PIU by end March 2012. The assessment of the implementation of the program revealed some delays and therefore the initial due date will not be met because of the following issues: (i) staffing arrangements of the PIU is not completed yet; (ii) training of staffing by BCECO still underway; and (iii) accounting software and training of the staffing not yet completed . Therefore, it was agreed to postpone the deadline until end September 2012. An action plan has been finalized and discussed with BCECO and SNEL and is presented in the Attachment 1 of this annex. An assessment will be conducted by Bank fiduciary team in due time prior to the final transfer of fiduciary responsibility to PIU/SNEL.

23. Staffing: the FM aspects of the AF2 will be handled by the current FM team of BCECO headed by an experienced and qualified FM Director until the decision is made to transfer the fiduciary responsibility to PIU/SNEL team. The current FM staffing arrangement is deemed acceptable to IDA; no additional staff will be recruited.

24. 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).

25. Accounting software: The multi-projects version of the current accounting software TOMPRO already installed at BCECO will be used to manage this second AF. Similar accounting software is already installed at SNEL and used. The PIU (PIU/SNEL) uses the “Assets management module” of the TOMPRO to monitor the projects assets. For the purposesof the transfer of FM responsibility to the PIU, the existing version of the TOMPRO will be fully installed at PIU/SNEL.

26. Internal controls/ FM procedures manual: The existing version of the revised FM procedures manual is deemed acceptable to IDA and could be used for the second AF. No specific revision is required. The team and IA have been trained on the use of this manual.

27. Internal audit: The internal audit function of the project is currently contracted to an individual international consultant and such an arrangement operates well. The SAPMP is also

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included in the scope of the IAD of BCECO. 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 two projects PMEDE and SAPMP. Due to some delays, the deadline has been postponed. The final decision of transfer of the internal audit function is subject to a satisfactory assessment of the capacity of the team put in place with support of the international internal auditor to manage the function effectively.

28. Financial reporting: The current content and format of the consolidated IFR are deemed acceptable to IDA. The IFR of the AF2 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 (initial phase and AF2). There is no overdue IFR at the time of the preparation of the Project Paper for this AF2.

D. Disbursement arrangements and flows of funds

29. Flows of Funds – The existing designated account (DA) opened under AF1 will be usedfor AF2 and the ceiling may be increased during project implementation if needed and at request of the GoDRC. It is, however, expected that most of the payments related to AF2 for contract 4 (in the amount US$ 180 million) will be made using direct payments or special commitments due to the size of the payments under this large contract.

30. Disbursement arrangements. Upon Grant effectiveness, the project will continue to use transaction-based disbursements. The project will continue to disburse against submission of Statements of Expenditures (SOE) reporting on the use of the previous advances. 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 the criteria16. The electronic submission of Withdrawal Application (WA) will continue to be 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. 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 andwhen IFRs are used as the basis of disbursements, the contents and format will be revised to include disbursement-related information.

31. 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 US$500,000 equivalent per contract; (c) services of individual consultants costing less than US$50,000 equivalent per contract; (d) services of consulting firms under contracts costing less than US$100,000 equivalent per contract. 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

16 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.

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IDA may pay amounts to a third party for eligible expenditures to be paid by the Recipient under an irrevocable Letter of Credit (LC).

32. The proceeds of the grant have been allocated as follows:

Category

Amount of the Financing Allocated (Expressed in SDREquivalent)

% of Expenditures to be Financed

(Taxes excluded)

(1) Supply and Installation of Electrical Equipments under Parts B1, B2, B3 and B4 of the Project 130,000,000

100% of foreign

expenditures and 90%

of local expenditures

(2) Engineering and Construction Supervision under Part B5 of the Project

0

100% of foreign



(3) Consultants Services including Audits under Parts B6, B8 (a), B10 (a) and B11 (a), (c) and (d) of the Project 0-

100%

(4) Training and Operating Costs for the PMU under Parts B10 (c) and (d) of the Project0 0

100%

(5) Goods and Works under Part B9 of the Project

0

100% of foreign



(6) Goods and Services under Parts B8 and B10 of the Project

0

100% of foreign



(7) Engineering Studies for the O&M Contract under Part B7 (a) of the Project

0

100% of foreign



(8) Supply of Goods and start up cost for the O&M Contract under Parts B7 (c) and (b) of the Project 0

100% of foreign



(9) Operating Costs of BCECO under Part B11 (b) of the Project 0

100%

(10) Cost of Establishing Letters of Credit under Part B 12 of the 0 100%

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Project

(11) Unallocated 0

TOTAL 130,000,000

33. A reallocation of the AF1 is also proposed as follow:

Category

Amount of the Financing Allocated (Expressed in SDR)

% of Expenditures to be Financed

(Taxes excluded)

(1) Supply and Installation of Electrical Equipments under Parts B1, B2, B3 and B4 of the Project

88,400,000 100% of foreign



(2) Engineering and Construction Supervision under Part B5 of the Project

5,000,000 100% of foreign



(3) Consultants Services including Audits under Parts B6, B8 (a), B10 (a) and B11 (a), (c) and (d) of the Project

- 100%

(4) Training and Operating Costs for the PMU under Parts B10 (c) and (d) of the Project0

1,200,000 100%

(5) Goods and Works under Part B9 of the Project

1,900,000 100% of foreign



(6) Goods and Services under Parts B8 and B10 of the Project

800,000 100% of foreign



(7) Engineering Studies for the O&M Contract under Part B7 (a) of the Project

300,000 100% of foreign



(8) Supply of Goods and start up cost for the O&M Contract under Parts B7 (c) and (b) of the Project

8,500,000 100% of foreign



(9) Operating Costs of BCECO under Part B11 (b) of the Project

600,000 100%

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(10) Cost of Establishing Letters of Credit under Part B 12 of the Project

2,000,000 100%

(11) Unallocated 8,000,000TOTAL 116,700,000

34. A summary table of the current allocation for each category for the original project, AF1 and AF2 is presented below.

Table 10: Summary Allocation

35. 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 AF2 and will follow the same arrangements of the ongoing project. Payments will be made based on terms and conditions of each contract.

36. Disbursement of Funds to Ministry of Energy (CATE & PIU). The existing disbursement of funds arrangements to the MinEnerg/SNEL will apply to this AF2. 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 auditors for the processing of payments where applicable.

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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.

37. Counterpart Funds. The GoDRC will provide an amount equivalent to not less than five million seven hundred and fifty thousand Dollars ($5,750,000) to be provided from the Recipient's state budget or through the Project Implementing Entity, for the financing of the Project, as counterpart funds which will be subject the project's fiduciary oversight arrangements.

38. Funds Flow Diagram: Overall funds flow is described in the chart below:

39. External Audit: The AF2 audit arrangements will be similar to the ongoing initial and AF1 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 AF2 is expected to become effective in the secondsemester of 2012, the first audit report may be due on June 30, 2013. The ToRs of the project external auditor covering the project expenditures including those incurred by CATE and PIUwill 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 AF2 Project Paper, there is no overdue audit report facing the project accounts or the sector. The 2010 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 with close monitoring by the World Bank’s project team. The project 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.

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40. 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 activities is high given the country context, inherent risks of activities and large infrastructure activities Therefore, similar to the ongoing initial project, the existing anti-corruption plan and implementation support plan will be used and updated as needed (ref. Annex 9).

41. 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 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 the annex regarding the enhancement ofSNEL’s corporate governance and operational performance (Annex 6). 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 (2010-2012), the implementation of which was officially launched in August 2010. 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.

42. 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.

43. 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 Rating

Risk Mitigating Measures Incorporated into Project Design

Conditions for Effectiveness (Y/N)

Residual Risk

Inherent risk H HCountry levelThe 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 levelNone except additional workload and governance issues

S BCECO is familiar with IDA FM procedures and staffed with experienced fiduciary consultants;

N (already in place)

S

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Risk Risk Rating



Residual Risk

It is expected to transfer gradually fiduciary responsibility of the project to PIU.

Project levelThe resources of the project may not reach all beneficiaries and used for the intended purposes.

H BCECO will strengthen ex-ante and ex-post control of funds and FM procedures manual operational and international internal auditor appointed.

N H

Control Risk S S

Budgeting: weak budgetary execution and control leading to over-expense budgetary or inefficient used of the funds.

S Annual work plan and budget require by December 31, of each year. The project FM Procedures Manual defined the arrangements for budgeting, budgetary control and the requirements for budgeting revisions.


S

Accounting : increase of the FM team workload leading to some delays

L The current FM staffing arrangement is deemed appropriate- no need to increase FM staff.


L

Internal Control: Specific aspects of the AF may not be applied or reflected in the FM procedures manual; and procurement internal controls not applied

S FM manual revised; use of the international internal auditor to ensure that the project complies with the procedures; increase procurement reviews integrated SPN missions

N S

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; none compliance with the project expenditures eligibility criteria; delays in payment of government counterpart funding

S (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)

N S

H Payment of government funding and reimbursement of the portion of 15% of expenditures wrongly paid with IDA resources and arrears of US$ 613.630,74.

N S

Financial ReportingDelay 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.

S (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

N ( already in place)

S

Auditing:Delays in submission of audit reports or delays in implementing the recommendations of the

S Auditing arrangements will follow the existing ones with acceptable external auditors to IDA – no new need to implement specific actions.

N S

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Risk Risk Rating



Residual Risk

management letter or quality of the audit report is a concernGovernance and AccountabilityPossibility of colluding practices as bribes, abuse of administrative & political positions, misprocurement and misuse of funds etc, are a critical issue.

H Robust FM arrangements designed to mitigate the fiduciary risks in addition to the PCU overall internal control systems. An Implementation Support Plan has been developed (Annex 9)

N H

OVERALL FM RISK H H

44. The overall residual FM risk rating taking into account the mitigation measures is deemed high.

45. Financial Management Action Plan. The Financial Management Action Plan described below has been developed to mitigate the overall financial management risks.

Issue Remedial action recommended

Responsible entity

Completion date

FM Conditions

Transfer of fiduciary’s responsibility from BCECO to PIU/SNEL(see action plan in attachment 1)

Finalize the PIU FM and Internal auditor staffing arrangements and implement the capacity building program

PIU/SNEL and BCECO

See Attachment 1

No (1)

External auditing Revision of the ToRs of the current external auditors (project accounts) to reflect the AF N0 2

BCECO and SNEL

Three months after effectiveness

No (1)

(1): These actions have been reflected in the Minutes of Negotiations and will be monitored as part of the Bank regular support to implementation.

E. Procurement arrangements

46. Procurement activities under the Additional Financing will be carried out in accordance with the Bank’s “Guidelines: Procurement of Goods, Works and Non-consulting Services under IBRD Loans and IDA Credits and Grants by World Bank Borrowers” dated January 2011, and “Guidelines: Selection and Employment of Consultants under IBRD Loans and IDA Credits and Grants by World Bank Borrowers” dated January 2011, and the provisions stipulated in the Financing Agreement. However, for contracts not advertised internationally, the provisions of new national procurement law should be applied subject to IDA approval. The existing implementation manual which was validated under the original project will remain in force and apply to the Additional Financing. This manual defines well the role and responsibility of each actor/beneficiary in the management of the procurement cycle and the processes to be followed. For each contract to be financed by the AF, the different procurement methods or consultant selection methods, the need for pre-qualification, estimated costs, prior review requirements, and time frame will be agreed between the SAPMP team and the Bank in the Procurement Plan. The Procurement Plan will be updated at least annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. The “Guidelines on

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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 2011 will also apply to the project.

47. The procurement capacity of the implementing agency within the SNEL was assessed by the Bank Procurement Team stationed at the World Bank Office in Kinshasa, on February 2012, during the latest supervision mission. The assessment found that the procurement capacity in SNEL, including the Project Coordination Unit, was very weak and inappropriate, and recommended strengthening through specialized technical assistance and training. For the time being, all procurement operations of the two Bank financed projects of the Energy Sector are handled by BCECO through a contract of technical assistance. In this contract, BCECO has among other responsibilities to assist SNEL to establish its Procurement Unit. To this end four selected SNEL staffs have been trained formally and on the Job by BCECO.

48. The risks factors for procurement performance include those posed by the country context and those due to the low procurement capacity of SNEL. Regarding the country context, the last Country Procurement Assessment Review (CPAR) published in 2004 and the experience of other World Bank assisted projects indicate that procurement on the projects is likely to involve the following risks:

A weak governance environment, insufficient accountability, and an overall lack of transparency in conducting procurement processes entail a significant risk of corruption, collusion and fraud.

The administrative system as it operates in practice creates opportunities for informal interference in the procurement process by senior officials and politicians, which may result in waste, mismanagement, nepotism, corruption, collusion, and fraud.

Government officials who are involved in procurement through tender communities may not be familiar with procurement procedures.

Lack of a large competition in the procurement process: in fact, for certain kinds of goods and works, only a few companies are interested in providing them under the current conditions, especially in the eastern part of the country, where goods may be in short supply available only at exorbitant price.

49. The overall project risk implementation for procurement is high due to the Country context and the weak procurement capacity of the implementing agency, SNEL.

50. The new procurement code has been promulgated on April 27, 2010, and it is effective and operational by now. The most important steps achieved to date include the following: (i) the nomination and installation of the key personnel of the new institutions including those in line ministries; (ii) the launching of the new procurement system by the prime minister; (iii) the examination and approval of a number of specific procurement plans for 2011 budget and (iv) the selection of a technical assistance firm to assist and train the main actors involved in public procurement transactions. Once the Bank has completed its review of this new procurement code, it will be applicable for all contracts under the AF which are not advertised internationally.

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For this purpose, as well as for other relevant Bank financed projects, the Bank procurement team intends to identify and clarify clauses of the code that are not entirely or partially applicable to a Bank financed project, and agree on appropriate modifications. These modifications would be set out in an agreement between the government of DRC and the Bank. If the government modifies the Procurement Public Law (PPL) or one or more texts of application after the said agreement on the clauses that require modification or to be neutralized, the Bank will review the said modifications so as to check to what extent they are in compliance with Bank procurement rules and procedures. After this review, the Bank will notify the government of its request on the clauses that may still need to be modified or neutralized. This exercise will be done any time the government modifies the PPL or the related texts of application.

51. As the overall project risk implementation for procurement is high, and taking into account that the new procurement code is operational by now, the following risk mitigating measures will be applied to tackle the above risk factors:

One of the provisions of the new procurement code is to establish in selected Ministries and SOEs independent procurement units to avoid corruption, collusion and fraud, nepotism and politician interference in procurement process;

As part of the new procurement code, a capacity building program including the training of Government officials involved in procurement process through tender communities will organized by an international reputed firm and awareness campaigns in the importance of the independence, transparence, equity, economy in a procurement process will be held for procurement unities;

The lack of a large competition linked to the Country context remains a concern.

52. In addition to these measures and specifically for the transfer of all procurement responsibilities to SNEL, we suggest what follows:

the procurement activities will be carried out by the Procurement Unit of SNEL to be established within the PIU, as stipulated by the provisions of the New Procurement Code;

the SNEL Procurement Unit will take advantage of the existing Direction des Approvisionnements of the same entity and will be staffed with the four Procurement Specialists;

the SNEL Procurement Unit will continue to benefit from Technical Assistance on procurement from BCECO through a new contract or accord de partenariat;

the BCECO will guarantee the internal quality review of the procurement processing and two experienced BCECO procurement Specialists will be placed within the PIU/SNEL Procurement Unit to provide advisory support until December 2012; and

the implementing agency, SNEL, will remain accountable of all procurement process through its Procurement Unit.

53. The Procedures Manual of the implementing agency will be updated to reflect the above arrangements which are supposed to be in place as soon as achievable without jeopardizing the project implementation.

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54. Procurement plan. The Borrower has already submitted a revised procurement plan for the implementation of the Additional Financing, covering activities under the project until closing date, 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.

55. Procurement methods and Bank review criteria are listed below:

(a) Contracts for goods and works

Procurement Method Threshold for the method in 1000 USD Bank review in ‘000 US$

(a) International Competitive Bidding (ICB)

USD 3,000 or more for works, USD 500 or more for goods other than drugs and

USD 300 for drugs

All contracts

(b) National Competitive Bidding All contracts estimated below the ICB threshold and above shopping ceiling

The first two contracts

I Shopping Below USD 100 for works and USD 50 for goods Post review

( d) UN procurement agencies N/A(e) Community participation in procurement

Implementation manual to determine the process

Post review

(f) Direct contracting N/A All contracts

(b) Contracts for consultant services

Procurement MethodSelection methods in

1000 USDBank review in ‘000 US$

(a) Selection based on quality and cost

N/A All contracts estimated above USD 100

(b) Least Cost Selection (LCS) N/A All contracts estimated above USD 100ISelection Based on the Consultants’ Qualifications (SQC)

100 All contracts estimated above USD 100

(d) Individual Consultants N/A All contracts estimated above USD 50(eg Single Source Selection) N/A All contracts

56. The agreed and approved procurement plan will determine procurement methods and the contracts to be submitted to Bank review and no objection

57. 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 consultant 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 ofclause 2.7 of the consultant guidelines, for all contracts estimated below the equivalent value of USD 100,000, the short list may comprise only local firms

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Attachment 1: Transfer of fiduciary responsibilities from BCECO to SNEL’s PIU

1. The second AF will be initially implemented under the same institutional, procurement and disbursement arrangements as for the original and AF1 project with the PIU at SNEL being the implementing entity and the Bureau Centrale de Coordination (BCECO) responsible for fiduciary aspects of the project. However, under PMEDE, it was envisaged to transfer fiduciary responsibility from BCECO to SNEL by end of April 2012. The World Bank fiduciary team, assessed in February 2012 SNEL’s capacity to take over those functions and preliminary conclusions note that additional actions need to be conducted to allow the transfer. New action plans have been developed and agreed with SNEL and BCECO to allow this transfer by end September 2012. However it is clear that the transfer will be carried out only when financial and procurement assessments demonstrate that there is enough capacity in SNEL to carry out fiduciary functions without jeopardizing project implementation.

2. Key actions for the transfer of FM responsibility:

Actions/ Detailed activities or measures Deadlines Responsibility

01 Appoint an international consultant to :(i) assess the staffing, organizational, and financial management capacity of SNEL; (ii) identify the gaps and develop the Terms of Reference and profiles of the positions;(iii) develop the Terms of Reference of the accounting software and operational manual;(iv) assist SNEL in the recruitment of the new staff and provide initial training

June 30, 2012

02 Assist SNEL in the implementation of the recommendations (i.e. appointment of new staff, development of an accounting software and the operational manual)

From July 1st,2012 to

September 30, 2012

SNEL/International consultant

3. Key actions for the transfer of procurement responsibility:

Actions/ Detailed activities or measures Deadlines

01 Assessment of PIU/SNEL capacity on procurement (completed) April 30,2012

02 Draft the action plan for assuring procurement function by PIU/SNEL (Completed -Action plan endorsed by SNEL)

May 31,2012

03 Identify within SNEL staff to fill the procurement positions and send their CV to the IDA

June 15,2012

04 Recruit an international procurement expertToRs drafted and approved Position advertised Staff selected and contract signed

August 1st, 2012

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Staff in place

05 SNEL to provide office space ready for use Sept. 1st, 2012

06 Procurement team including BCECO experts and international procurement expert in place

Sept. 1st, 2012

07 Specific training of PIU/SNEL staff on procurement and immersion training within BCECO of PIU/SNEL procurement staff

July to September 2012

08 Capacity Assessment by IDA (to verify the extent to which PIU/SNEL has the qualification and experience to operate without light technical assistance and define the date for final transfer of responsibility )

September 2012

09 BCECO to provide technical assistance and advisory services including capacity building

From Oct. 1st, 2012 to Dec. 31, 2012

10 Assessment of PIU/SNEL’s procurement capabilities by IDA Dec. 31, 2012

11 Technical assistance and advisory services including training and capacity building to PIU/SNEL

Technical assistance and advisory services by the selected international expert until.

Technical assistance and advisory services by the selected expert only (periodic interventions of four months in total during the second year) until.

June 30, 2013June 30, 2014

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Annex 4: Revised Project Description, Costs and Implementation StatusAFRICA: Southern African Power Market Project APL1 (SAPMP)

Second Additional Financing

1. It is proposed to revise the project as follow to better reflect and present the activities financed under the project.

2. This Annex has nine attachments as follow:

Attachment 1: Detailed analysis of proposed additional financing and basis for revised estimated costs

Attachment 2: Key contracts under the project

Attachment 3: Revised Estimate of Project Costs

Attachment 4: Financing Plan

Attachment 5: Original and Revised Financing Plan

Attachment 6: Progress and Actions taken since the AF1

Attachment 7: Revised Implementation Schedule

Attachment 8: Compliance with Legal Covenants

Attachment 9: Estimated Revised Disbursement of Total IDA Financing

Detailed Project Description

Component 1 – Support to the SAPP Co-ordination Center (US$ 3.36 million)

3. This component provided technical assistance in strengthening the SAPP Coordination Center with the aim to facilitate more rapid development of the power trade in the region. The activities under this component were entirely financed by USAID and NORAD and completed by end 2007.

Component 2: Rehabilitation and reinforcement of the high voltage transmission corridor from Inga to Kasumbalesa at the border with Zambia (US$ 638.3 million)

4. This component is break down in several sub-components or activities. Those sub-components are proposed to be revised as follow.

Sub-component 1: Rehabilitation and Reinforcement of: (i) Converter and Inverter Sub-Stations at Inga and Kolwezi (Financing Agreement, Schedule 1, Part B1); and (ii) 220 kV Substations at Fungurume, Panda, and Karavia, and Installation of Modern SCADA System at Likasi(Financing Agreement, Schedule 1, Part A)

5. This sub-component includes two main contracts currently under implementation.

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a. The first one comprises the replacement of the core systems of the two converter and inverter stations at Inga and at Kolwezi respectively. As the rehabilitation of the existing installation has not proven feasible it has been decided that the valves, cooling and control systems should be replaced in order to obtain reliable and modern stations. The replacement will enable also to increase the rating of the equipment from the original 2x288 MW (total 576 MW) to 2x500 MW (total 1,000 MW). This upgrade is possible with minimal additional cost due to the high power thyristors used in the modern installations. The overall capacity will, however, remain at the original installed capacity level after rehabilitation since the converter transformers and the filters on the AC side will not be replaced or upgraded under the project to enable the capacity of 1,000 MW.

This contract includes also a major rehabilitation of the AC 220 kV switchyard equipment and its protection. The replacements of the circuit breakers and its control/protection will substantially improve the overall reliability.

A further component of this contract is the repair and rehabilitation of the three synchronous compensators, required for the converter operation in Kolwezi. One damaged unit will be overhauled and the common equipment, such as the switchgear, starting and control/protection equipment will be replaced.

All PCB contaminated equipment, such as the capacitor units and the auxiliary transformers will be replaced. These will be kept in safe storage, temporarily, and subsequently disposed off outside DRC through incineration under the services of an internationally experienced firm.

b. The other contract financed under this sub-component is the Rehabilitation and Reinforcement of Extension 220 kV Substations at Fungurume, Panda, and Karavia, and Installation of Modern SCADA System at Likasi Control Center, entirely financed by the EIB.

The rehabilitation of the existing 220 kV substations on the axis between the Kolwezi converter station and the Zambian border will enable the reinstatement and the reinforcement of the HV highway for the electrical energy exchange with Zambia and SAPP countries. The project scope comprises the replacement of the unreliable equipment, such as the circuit breakers, current transformers, but also the replacement of the technologically antiquated control system and unreliable protection relays.

At the Karavia substation near Lubumbashi inductive power compensation equipment shall be installed to improve the unfavorable reactive power balance and improve the system stability of the HVAC network. To enhance efficiency of operation and management of the transmission system, the existing SCADA facility at Likasi will be upgraded.

Sub-component 2: Rehabilitation of the HVDC and the HVAC Overhead Lines from Inga through Kolwezi to Kasumbalesa (Financing Agreement, Schedule 1, Part B3) and Construction of the new 220 kV Overhead Lines from Fungurume to Kasumbalesa (Financing Agreement,Schedule 1, Part B2).

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6. This sub-component includes two major contracts:

a. The rehabilitation of the existing overhead transmission lines from Inga through Kolwezi to Kasumbalesa at the border with Zambia. The works will include the HVDC as well as the HVAC lines, and the transmission towers The rehabilitation work includes replacement of all broken or missing parts such as the earthing wire, broken insulators, replacement of sections of the main conductors, both DC and AC as may be needed, improvement of some erosion zones, and to strengthen tower foundations, repair of broken bridges, and reclamation of parts of the rights-of-way. The preparatory works for this contract included the detailed aerial diagnostic study of the transmission line, including condition assessment of the 11,200 towers in order to secure the optimum requirements for satisfactory completion of the rehabilitation.

The existing overhead lines will be reinforced by the construction of the new links between Fungurume, over Panda and Karavia, up to the Zambian border at Kasumbalesa. The existing line has limited capacity, which leads to frequent power supply interruptions to Zambia. This will be eliminated with the construction of this new line.

b. A single circuit 220kVoverhead line will be built from Fungurume to Panda, and to Karavia, and a double circuit line from Karavia to Kasumbalesa at the border with Zambia. This contract also includes the supply and installation of a medium voltage line from Shituru to Likasi for the operations of the upgraded Control Center.

Sub-component 3: Telecommunication System (Financing Agreement, Schedule 1, Part B4)

7. This component will finance a set of three activities, which are mutually dependent. It involves the supply and installation of a modern OPGW fiber cable over a distance of about 2,300 km and associated electronic communication equipment to be installed over the high voltage transmission line from Kinshasa through Inga and Kolwezi to Kasumbalesa at the border with Zambia to link with telecommunication system of Zambia and the Southern African Power Pool.

8. The complete system will replace the existing inoperable technologically antiquated PLC system on the HVDC line, which has been out-of-service for several years. The new telecommunication system will allow SNEL the connection and communication between the new network centers in Kinshasa and Likasi and of course enable the proper operation of the rehabilitated converter and inverter stations at Inga and Kolwezi, the entire high voltage transmission system, improved communications with the rest of the Southern African Power Pool, and enhance the speed of transactions. It includes:

a. Supply and delivery of the optical fiber cable (OPGW cable);

b. Installation of the OPGW on the high voltage transmission towers; and,

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c. Supply and installation of the telecommunication electronic repeater equipment.

9. Beside the utilization of this fiber optic cable for SNEL internal communications and controls, a large excess telecommunication transmission capacity beyond the needs of SNEL will be commercialized by internationally experienced operator under Open Access regime.

Sub-component 4: Advisory Services

10. This component will finance the following technical studies and advisory services:

a. Services of an experienced transmission engineering firm to undertake and provide a comprehensive technical audit of the state of the existing HVDC and HVAC transmission lines from Inga to the border with Zambia (2,000 km), including the transmission towers, to establish requirements for rehabilitation of the transmission lines under to be rehabilitated under Component 2. The study was carried out and concluded in 2009.(Financing Agreement, Schedule 1, Part B6)

b. Contract for the Engineering and construction supervision has been signedwith an international engineering consulting firm. The services include assistance to SNEL in preparation of bidding documents, follow-on procurement processes to conclusion of contracts with selected bidders, project management and supervision of implementation. (Financing Agreement, Schedule 1, Part B5)

c. Technical assistance for the design of the Operation and Maintenance Contract, through the procurement, and engagement of an O&MContractor. It will also assist in establishing the demarcation of the high voltage transmission assets of SNEL. The component also finances the mobilization of the O&M operator and the essential tools and equipment, including the two specialized heavy duty helicopters needed for the task. The selected O&M Contractor must have operating experience in the operation and maintenance of long-distance high voltage DC and AC transmission system. The O&M contract will start following the completion of the rehabilitation and reinforcement of the existing transmission corridor from Inga to the border with Zambia, and will run for a period of about five years. The main objective of this component is to train and transfer know-how to the staff of SNEL in modern methods and techniques of all aspects of operation and maintenance of the SNEL high voltage transmission system. (Financing Agreement, Schedule 1, Part B7)

d. Services of an international specialized consultant to (i) design the technical, contractual (shareholders’ agreement, transactions agreement), and business/economic aspects of the commercialization contract of the excess capacity, (ii) assist SNEL to recruit an internationally private world class private operator for the commercialization of the telecommunication excess capacity under Open Access regime, and (iii) drafting the necessary

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interconnection legal and regulatory as well as the commercial arrangements to support Open Access. (Financing Agreement, Schedule 1, Part B11)

e. Services of an international consulting firm to assess the needs to increase the transit capacity of the line HVDC and the HVAC Overhead Lines, from Inga through Kolwezi to Kasumbalesa, from 500 MW to 1000 MW.(Financing Agreement, Schedule 1, Part B6)

f. Procurement of assistance of BCECO to PIU. It will finance the salaries of assigned BCECO staff (excluding civil servants), contribution to payment of office space for BCECO staff, publication of procurement notices, procurement of office equipment, and other related expenses in the provision of the services to PIU. (Financing Agreement, Schedule 1, Part B10)

g. Audits of the project accounts.

h. Foreign consultancy services to assist SNEL in export contract negotiations.

Sub-component 5: Community Development (Financing Agreement, Schedule 1, Part B9)

11. The component comprises the provision of social infrastructure for a population of about 700 families in seven villages – Ngubu, Mutaka, Kapemba, Bungu-bungu, Nsatumbe, Ntumbwe, and Nshinga – along the high voltage transmission corridor in the Katanga Province. It will cover the construction of schools and the provision of basic school furniture, construction clinics and the supply of basic medical equipment, including beds, and six months supply of basic medicines, water supply and sanitation systems, and electricity supply. The envisaged activities include:

a. Construction of the schools and medical centers in the villages.

b. Construction of the water wells for the seven villages and the separate external water supply for the schools and clinics to be constructed under sub-component 1.

c. Supply and delivery of medical equipment and furnishing for the new medical centers.

d. Supply and Delivery of the furnishing for the schools.

e. Supply and installation of low voltage distribution lines for electrification of the seven villages.

f. Supply and delivery of six months stock basic medicines, certified by the appropriate governmental authority, to the medical centers in the seven villages.

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g. This sub-component will also finance a HIV/Aids Awareness Campaign to educate the Project Affected Population and the communities along the length of the high voltage transmission system about the prevention, including the distribution of condoms, and information on where infected persons can go for counseling support and treatment. The activity will be linked with already established systems at state, provincial and local levels for the continuation of educating, counseling, and treatment for infected persons.

Sub-component 6: Environmental and Social Safeguards (Financing Agreement, Schedule 1, Part B8)

12. This subcomponent includes:

a. an update of the earlier Environmental and Social Impacts Assessment study completed in 2002 for the original project to assess any additional changes on the ground that would warrant further mitigation measures under the Project to be undertaken. The update is to cover also the Resettlement Action Plan (RAP), and the Compensation Action Plan (CP) for the project affected population in DRC. The study has been completed in 2010.

b. the implementation of RAP and the CP for the construction of housing and related social infrastructure for the population to be relocated from the rights-of-way of the new transmission lines to be constructed in DRC, as well as the payments of compensation for crops, land and other movable property in the rights-of-way acquired by SNEL (However, cash compensation, land acquisition and other resettlement aid paid in cash will not be financed by IDA).

c. financing for the Monitoring and Oversight of Implementation of Environmental and Social Mitigation Measures for the services of an international NGO will be also provided to assist in the supervision and provide oversight of implementation of the RAP and the CP to ensure success of implementation of the RAP and the CP.

d. financing of a beneficiary assessment to confirm the sustainability and cultural appropriateness of the investments completed under the community development component and other related studies.

Sub-component 7: Institutional Strengthening and Capacity Building (Financing Agreement, Schedule 1, Part B10)

13. This subcomponent is aimed at strengthening the capability and capacity of PIU in the areas of procurement, project implementation supervision and management for the successful execution of the Project. It will provide overseas training as well as on the job training with the support of the engineering consultant, participation in inspections and factory acceptance tests of

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equipment for the Project at manufacturers’ premises. It will also provide tools and equipment, including vehicles, office furniture, computers and communication equipment, and a modern management information system, and will also cover the operating cost of PIU. The activities include:

a. Installation of a modern management information system;

b. Supply of equipment, tools, vehicles and logistics;

c. Training, including participation in inspections and factory acceptance tests of equipments for the project in manufacturers’ factories overseas.

d. Operating cost of PIU

Sub-component 8: Establishment of Letters of Credit (Financing Agreement, Schedule 1, Part B12)

14. Component 2 will also provide financing for the Establishment of Letters of Credit (US$10 million) to cover commercial bank charges and associated costs for the establishment of Letters of Credit on behalf of the Contractors for the supply of imported equipment and materials for the project.

Sub-component 9: Provision for replacement of additional physical components which may compromise the effectiveness and achievement of the project objectives (Unallocated funds to be used accordingly to the Financing Agreement provision)

15. This component will cover the rehabilitation and/or substitution of possible components on the existing installations which could fail between now and project commissioning, based on a detailed review of the existing installation by SNEL’s consulting engineer.

Component 3 – Transmission Link between Luano and Kasumbalesa (US$18 million)

16. This component comprises the construction of a new double circuit 220 kV from Luano substation in Zambia to the border with DRC to link the DRC transmission system. It is to reinforce the existing single circuit 220 kV, which has been unable to cope with the power transfers from DRC into SAPP, and to enable power transfer capability of 500 MW. The existing line with the associated substation is owned and operated by the Copperbelt Energy Corporation (CEC) of Zambia, a private bulk transmission company that purchases power in bulk mainly from ZESCO of Zambia and supplies to the individual mining companies in the copperbelt of Zambia. Luano substation is the off-take point for ESKOM of power delivered by DRC to its customers in the SAPP.

Component 4 – Feasibility and preliminary design study of an interconnector between Zambia and Tanzania that would connect the SAPP to the market that would be formed by interconnecting Tanzania, Uganda and Kenya (US$1 million)

17. This component has been successfully completed already by the original project completion date of December 31, 2007, before the first additional financing.

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Attachment 1: Detailed analysis of proposed additional financing and basis for revised estimated costs

Introduction: Better factoring risks and contingencies

1. Cost underestimations, overruns, and larger than expected rehabilitation works are endemic issues for energy projects in DRC, and are affecting the overall portfolio. However, the factors presented below provide reassurance that proper mitigating measures are in place for the preparation and implementation of the AF2.

2. The main reason justifying the request of the AF2 is the change of scope in the rehabilitation works of the long-distance high voltage (HV) transmission corridor connecting Inga with Kasumbalesa at the Zambia border (Contract 4), and the AF is needed to complement the available financing to meet the cost of rehabilitation of the long-distance transmission line and associated 11,200 towers.

3. However, other contracts in the scope of the SAPMP also require additional financial resources, as a consequence of events, occurred during its execution, that were impossible to foresee at the time they were signed. At this stage, all major rehabilitation contracts have been signed and all base costs associated with the contracts are known with certitude (see Attachment 2 for details). The new project cost estimates are based on a quantitative detailed cost and risk analysis carried out by SNEL, the owner engineer and closely discussed with the task team.

4. The methodology used to assess the revised project costs, benefits from the experience and lessons learned from cost escalation in PMEDE and SAPMP AF1. In the past, contingencies and base costs were benchmarked against worldwide market prices taken at face value, without considering the specific market reality and technical challenges associated with the different characteristics of each contract. In addition, close interdependency between contracts was underestimated and cost overruns associated with delays in implementation of deemed not significant.

5. In the case of the proposed AF2, a systematic analysis of risks has been carried out and tailored to the nature, implementation status and detailed technical characteristics of each contract. A series of risk have been identified, including exogenous factors which may compromise the effectiveness of the investments (such as faults in electrical equipments not covered under a specific contract but whose availability is essentials for the sustainability of the project).

6. Each risk category has been priced and contingency appropriately added to the project costs to avoid future costs overruns. The detailed analysis is presented below. For each contract, in addition to the base cost, physical and price contingencies are presented (including price, exchange rate fluctuations and administrative charges linked with delays in implementation). Change orders are still possible, given the nature of the rehabilitations, but they are deemed to be fully covered by the identified contingencies. Any further increase in costs beyond identified contingencies is not likely to be associated with technical reasons but only due to force majeureevents.

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Detailed costs risk analysis contract by contract

Component 1: Support to the SAPP Co-ordination Center

7. Component 1 has been successfully completed already by the original project completion date of December 31, 2007, before the first additional financing. A continuation of the technicalassistance program for the SAPP Coordination Center is under discussion under another Bank’s operation. The activities under this component were entirely financed by USAID and NORAD.

Component 2: Rehabilitation and reinforcement of the high voltage transmission corridor from Inga to Kasumbalesa at the border with Zambia. With the first additional financing, this component was split into subcomponents and new essential ones were added to ensure that the output of the project can be achieved and be sustained.

Sub-component 1.a. (Contract 1): Rehabilitation and reinforcement of converter station at Inga and inverter station at Kolvezi, installation of synchronous compensator at Kolwezi, and rehabilitation of high voltage alternating current substation at Kolwezi.

8. The contract is on schedule. Its scope includes the rehabilitation (repair) of one of three synchronous condensers installed at the Kolwezi substation, which are needed to achieve minimum reliability in the operation of the Inga-Kolwezi DC transmission line.

9. Repair works showed to be more complicated and expensive than expected by the contractor (who had to assume this risk under the contract). Besides, while this machine was being repaired, a second condenser failed, creating a compromised service condition. The situation was discussed during pre-appraisal with SNEL and its consulting engineer, and several options were analyzed. Taking into account the large logistic costs to execute works in the isolated Kolwezi region, it was concluded that the best technical and financial option was to agree with the contractor on a reasonable price to replace the two units not included in the original scope of the contract by new ones meeting the same service conditions. SNEL’s consulting engineer has recently reported that the contractor presented a proposal for the supply and installation of two synchronous condensers for US$8.16 million. This price seems acceptable, considering the scope of works and the above mentioned logistic constraints. Other minor additional works under Contract 1 were also identified (replacement of a DC reactor, supply and installation of devices to enable operation at reduced voltage, increase installed capacity of the emergency diesel generator, supply and installation of additional metering transformers). The base contract price of about US$ 118.5 million is therefore increased by about US$ 10.6 million.

10. Different additional risks have been identified for this contract: (i) exchange rate fluctuations (as the contract will be mainly paid in SEK (Swedish krona), (ii) due to delays in contract 4, commissioning tests will be also delayed and additional costs may occur for re-mobilizing manufacturer’s teams and extending the warranty technical. SNEL’s consulting engineer proposed to add an administrative contingency of US$ 5,500,000.

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Available financing

Contract signed including addendum

Technical contingencies

Administrative contingencies

Total financing required

US$142.1 million

US$118.5 million US$10.6 million US$5.5 million US$134.6 million

Sub-component 1.b. (Contract 2): Rehabilitation and Reinforcement of Extension 220kV Substations at Fugurume, Panda, and Karavia and Installation of Modern SCADA System at Likasi Control Center.

11. Financed by the European Investment Bank (EIB), the contract and the credit are in the same currency. The base contract price is about 27.3 million Euros and an addendum of about 0.93 million euros has already been negotiated. As the contract is only at its early stage of implementation, SNEL’s consulting engineer proposed to consider for physical contingencies an amount of about 15% of the contract. In addition, due to delays in the telecommunication contract (Contract 5.2) additional costs may occur for re-mobilizing manufacturer’s teams for the commissioning tests an amount of 0.25 million Euros should be considered. The EIB credit has a 12.8 million Euros envelope available that may cover these technical and administrative contingencies.

Sub-component 2.a. (Contract 4): Rehabilitation of the high voltage direct current overhead line and the high voltage alternating current overhead lines.

12. The rehabilitation activities have significantly changed from their original design and scope as appraised in 2003. Based on the reports provided by SNEL at the time of the original appraisal, the initial scope was to repair parts of the tower structures by replacing broken steel angles and members, replacement of a few known broken insulators, repairs to known damaged parts of electrical cables, and strengthening the foundations of some of the towers known to be weak. As such, the cost of the rehabilitation covering the items mentioned above was estimated at US$4.7 million. However, a shallow appraisal was conducted given the country context at that time and an element that was highly underestimated at that stage was the unknown operating state of the thousands of insulators on the transmission towers.

13. During the appraisal of the AF1 in March 2009, based on additional information that became available from SNEL and the engineering consultant on further deterioration of the transmission since 2003, and the prevailing international market prices of steel and other inputs, the scope of the rehabilitation works was reassessed and the cost updated to US$23.3 million. However, as mentioned in the Project Paper of AF1, the activities envisaged under this component still included only the rehabilitation of broken or missing parts, including part of the insulator known to be broken. Only about 2,000 insulators were known to be broken. This was because insulators, a key component of high voltage transmission lines, by industry standards have a normal operating life of 40-50 years after installation. By then, the ones on the towers of the long-distance transmission lines had been in service for only 20/25 years, and, therefore, their

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replacement was not envisaged. Although contingency were considered, they were only proportional to the estimated cost and scope of the envisaged rehabilitation work.

14. Before the first AF, the bidding for Contract 4 failed due to inadequate technical information in the bidding documents, resulting in non-responsiveness of the single bid received. For this reason, SNEL engaged a qualified and experienced transmission engineering services firm to undertake a detailed technical audit of both the High Voltage Direct Current (HVDC) and High Voltage Alternating Current (HVAC) parts of the transmission lines and associated towers to fully establish the requirements for the rehabilitation of the long-distance transmission line and ascertain the cost estimate.

15. The “Flycom” study. In the late 2009, this study, carried out by a company called “Flycom”, included high definition pictures of each element of the transmission system and thermal analysis of the structure to assess structural integrity of each of the 11,000 towers. Based on the detailed assessment, cost estimates for the contract were readjusted to about US$80 million – based on the need to change only 70% of the total number of insulators and a specific set of rehabilitation works as identified by the high resolution pictures taken during the line inspection. The detailed conclusions from the Flycom study were used in the revised bidding documents (mid 2010).

Figure 3: Images from the Flycom Study

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16. The laboratory tests on insulators. As mentioned above, the ensuing aerial survey and inspection, which took place between June and December 2009, concluded that a larger than expected number of insulators could be faulty. Given the dilapidated status of the insulators it was also decided by SNEL and the project team that a representative sample of insulators from both the HVDC and HVAC towers be tested in an independent foreign laboratory17 in France. The test concluded that in fact 100% or the totality of insulators should have been replaced.

Figure 4: Images from the laboratory tests on insulators.

17 A statistically significant sample was selected by the transmission engineering firm to be representative of the status of the overall T-line.

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17. In March 2010, the tests conducted in a laboratory in France (see pictures above) concluded that all the 720,000 insulators were likely to be faulty and had reached their terminal operating life, contrary to the previous expectation, and would need to be replaced for the transmission line to attain the required operating level of reliability after rehabilitation.

18. To conclude on insulators, most of the cost overruns and the need for the AF2 come from the unexpected need to replace all the insulators on the line, which the Bank team could not foresee as a likely risk in June 2009. At that time, the appraisal relied on the opinion of expertsfrom the Owner Engineer and SNEL, who were more familiar with the conditions of the transmission line. Only the subsequent field work and laboratory tests offered the explanation for the short life span of the insulators, especially on the HVDC part (90%). The dielectric material used in the manufacture of the insulators, which were supplied in the 1970’s, when HVDC technology was still in early stages of development, was not specifically adapted to application where DC currents are involved, and, therefore, the shorter life time. The new insulators to be provided for the rehabilitation works that were specified in the bidding documents are the most modern and up to date ones made of high resistivity dielectric materials to prevent degradation over time.

19. The current Contract 4 is a bill of quantity contract covering the substitutions of all insulators and access to towers supply and replacement of all the HVDC insulators on the transmission lines and access to towers, while for the other aspects of the rehabilitation it is still based on the defects identified during the Flycom study. The lowest responsive evaluated offer received from the international competitive bidding for the contract is US$ 182 million. As mentioned above, 82% of this amount, about US$ 150 million, is due to replacement of all the insulators in both DC lines. The remaining covers the rest of the rehabilitation work as envisaged during appraisal in 2009 and a 20-30% price mark-up by contractors to hedge against perceived high risk of implementation delays and potential failure (a common factor in DRC). During pre-appraisal, a thoughtful analysis of this contract was carried out and it was concluded that the prices of the three technically qualified proposals received for Contract 4 are actually high compared to those in “regular” markets. In fact, all the bidders are asking for high margins to contemplate both the challenges inherent to the rehabilitation works and the complexities of doing business in the DRC.

20. It is worth mentioning that the original aerial study was not conceived initially to investigate the performance state and remaining operating life of the insulators. The aim was to find out the requirements for rehabilitating the physical tower structures, the foundations, and the electrical cable itself, as well as identify additional insulators that were physically damaged/broken due to vandalism, wear and tear, and access conditions to the extent possible. The electrical performance of the insulator was not supposed to be investigated. However, during the aerial survey it was noticed that their electrical performance and life expectancy could be suspect. That was what prompted the need for further investigation through the laboratory tests.

21. As mentioned above, Contract 4 is a bill of quantity contract covering the substitutions of all insulators and access to towers, while for the other aspects of the rehabilitation it is still based on the defects identified during the Flycom study. Those other elements include towers (steel),

87

foundations, conductors, clamps and small accessories. In this regard, change orders are still possible (to be assessed based on unit costs as quoted by the bidder), given the nature of the rehabilitations. To cover this risk, identified technical contingencies will be added. To assess those contingencies, the team worked with the Owner’s Engineer to provide details on what was included in the current contract (unit price and quantity) and what is expected before project closing, given that the Flycom study was carried out in 2009. Contingencies were reviewed item by item and have been conservatively at US$15 million which represents 30% of the cost of the contract excluding insulators and access which are fully covered by the contract.

22. Also, to minimize risks in term of unnecessary additional works and prevent potential corruptive practices, access to site for the supervision consultant is essential. The physical, geographical and security characteristics of the construction sites for the HVDC line is the major constraint in monitoring the quality and type of work performed by the contractor. One approach applied by the supervision consultant could be to replicate the visual fly-over monitoring as done during the detailed review of the scope of the project. The supervision consultant and SNEL, as well as the Bank team have the high resolution photographs and close up photographs of each of the tower which allows the team to adequately assess the condition of the towers and lines. All these files are GPS stamped as well uniquely identified. The contractor should be required to submit pre- and post rehabilitation pictures of the lines as well as the insulators. These will be matched against the existing files to assess the improvements. Once these are cleared, the supervision consultant will sign off on the various segments. Finally, the contractor should provide transport and access for the supervision consultant to the worksite from publicly accessible points. These site visits will take place at the beginning and end of each section as well as random access during the contract implementation. Further details on the proposed enhanced supervision of contract 4 are outlined in Annex 9.

23. As detailed above, the contract was negotiated at about US$180.9 million. Because this is a bill of quantity contract covering the substitutions of all insulators and access to towers, while the other aspects of the rehabilitation are still based on the defects identified during the Flycom study, a US$ 15 million technical contingencies will be added to cover possible unexpected additional change in the scope of work (namely in towers (steel), foundations, conductors, clamps and small accessories). In addition, some reserve for administrative contingencies have been considered for exceptional events, such as work stoppage, civil unrest, etc. An amount of US$5.0 million has been considered.

Available financing




Total financingrequired

US$22.31 million US$180.9 million US$15.0 million US$5.0 million US$200.9 million

88

Sub-component 2.b. (Contract 3): Supply and installation of new 220 kilovolts overhead transmission lines from Fugurume to Panda, and to Karavia and to Kasumbalesa.

24. This contract is currently being executed and expected to be completed in December 2012. The base contract price is about US$67.5 million. The corridor of the line has been completely cleared, and erection of towers has begun. Some changes in amount of works considered in the base price are due to the need to adapt the number of tower foundations of each type to actual soil conditions in each area. Besides, the layout of the line had to be deviated to avoid passing over the Kimafia village (this was not detected by the SNEL’s team at the time the bidding documents were prepared). Additional works represent an increase of about US$11.7 million in contract price, which could be considered acceptable, taking into account the poor quality of base information available at the time of the call for bids. The addendum of about US$11.7 million is under preparation. Despite no additional change in the scope of work is expected, technical contingencies of about 5% of the initial contract amount have been considered.

25. A formula for price adjustment is prescribed in the contract to take into account changes in prices of aluminum, steel, diesel and labor over the course of the contract; SNEL’s consulting engineer estimates the adjustment at the end of the contract at about US$3.5 million. No additional administrative contingencies are considered for this contract.

Available financing






Sub-component 3.a. (Contract 5.1): Supply and delivery of a modern optical fiber telecommunication cable.

26. This contract was completed and all costs are well known. The based contract price including addendum is about US$9.4 million.

Available financing





US$15.29 million US$9.4 million 0.0 0.0 US$9.4 million

Sub-component 3.b. (Contract 5.2): Installation of optical fiber cables as guard wire conductors in the high voltage DC lines over a distance of 2,300 km.

27. Base contract price is US$ 41.2million as negotiated with the selected bidder. Physical contingencies are unlikely to happen, however, technical contingencies of about 10% of the signed contract have been considered; a reserve for administrative contingencies of only 2% of the contract appears enough.

89

Available financing






Sub-component 3.c. (Contract 5.3): Supply and installation of associated telecommunication electronic equipment.

28. This contract is well advanced with most of the equipment already manufactured and waiting for transportation. Therefore no major contingencies are expected. However, with the delays in Contract 5.2 the commissioning will be delayed and some minor technical modification may occur, an amount of US$0.8 million for physical contingencies may be useful. The exchange rate risk is also low but a US$0.2 million is also considered as administrative contingencies.

Available financing






Sub-component 4 – Provision of advisory services

Sub-component 4.a.: Study of the state of the existing high voltage direct current and the high voltage alternating current transmission lines.

29. The main contract was the study undertaken by Flycom and which concluded that all HVDC insulators must be replaced; its cost was US$1.3 million. Only one sub-component, the post rehabilitation inspection of the transmission lines, remains to be done. No major contingencies are expected.

Available financing





US$3.09 million -- -- -- US$3.09 million

Sub-component 4.b. (Contract 8): Engineering and construction supervision services.

30. This contract of SNEL’s consulting engineer has been amended in November 2011. The price of the contract is now of about US$16 million. Due to delays in the implementation of the project, the contract of SNEL’s consulting engineer will need to be extended. An amount equal to 16 men-months will be considered (US$0.3 million). Also to take into account the price adjustment formula, an amount of US$0.4 million will be considered.

90

Available financing





US$17.51 million US$22.4 million -- US$1.0 million US$23.4 million

Sub-component 4.c.: Operation and maintenance of the transmission assets, including: (i) engineering studies for the O&M Contract; (ii) supply of goods; and (iii) start up costs for the O&M Contract:

31. This activity has not yet started, only the terms of reference for the recruitment of the consultant who will be in charge of preparing the O&M contract have been finalized and reviewed by IDA. The current envelopes are as follow: (i) US$1.0 million for Consultancy services; (ii) US$3.0 million for Start-up Costs; and (iii) US$25.0 million for equipment and tools. A 10% reserve for physical contingencies is considered for this sub-component.

Available financing





US$29.0 million -- US$2.9 million -- US$31.9 million

Sub-component 4.d. – Services of international specialized consultants for: (i) the preparation of a contract for the management, maintenance, operation and commercialization of the excess capacity of the telecommunication system; (ii) assistance to SNEL to recruit an internationally private world class operator; and, (iii) drafting the necessary legal and regulatory, as well as commercial arrangements. Sub-component 4.e – Services of an international consulting firm to assess the needs to increase the transit capacity of the line HVDC and the HVAC Overhead Lines, from Inga through Kolwezi to Kasumbalesa, from 500 MW to 1000 MW. Sub-component 4.f. – Assistance of BCECO to UCP for procurement and financial management activities. Sub-component 4.g. – Audits of the Project accounts. Sub-component 4.h. – Foreign consultancy services to assist SNEL in the negotiations of the export contract

32. For these sub-components: (4.d) the recruitment of the consultant is ongoing, BCECO is now doing the financial evaluation of the proposals received; activities (4.f) and (4.g) are ongoing; and, activities (4.e) (4.h) has not yet been carried out. No change in financing requirements has been identified during project the preparation of this AF2. A 10% reserve for physical contingencies is considered for this sub-component.

Available financing





US$5.55 million -- US$0.56 million -- US$6.11 million

Sub-component 5. Community development in seven villages in the Borrower’s portion of the transmission corridor in the Katanga Province

91

Sub-component 5.a. (Contract 6.1): Construction of schools and medical centers.

33. This activity is divided in two lots. Contract 6.1.1 price is about US$1.9 million and Contract 6.1.2 is about US$0.99 million. Both contracts are based on unit prices (fixed over the entire duration of the contract) and invoices will be based on the exact quantities completed. The Ministries of Education and Health have already requested for modification and additional requirements, these requirements are estimated at about US$1.7 million. No additional administrative contingencies are expected as the contracts are in US dollar.

Available financing





US$2.9 million US$2.9 million US$1.7 million -- US$4.6 million

Sub-component 5.b. (Contract 6.2): Construction of water wells and separate external water supply.

34. This activity is under implementation and base contract price is about US$1.1 million. The contract is based on unit prices (fixed over the entire duration of the contract) and invoices will be based on the exact quantities completed, however the scope of this contract still needs to be confirmed by the Ministry in charge. Therefore a provisional envelope of about US$0.35 million is considered. No additional administrative contingencies are expected as the contracts are in US dollar.

Available financing





US$1.1 million US$1.1 million US$0.4 million 0.0 US$1.5 million

Sub-component 5.c. (Contract 6.3): Supply and delivery of medical equipment to, and furnishing of, new medical centers.

35. This activity has not yet been procured, the bidding documents still need to be amended. It already appears clearly that the available financing is largely insufficient and it is proposed an envelope of about US$0.8 million for this activity.

Available financing






Sub-component 5.d (Contract 6.4): Furnishing of schools.

36. This activity has not yet been procured, the amended bidding documents have been cleared, but the bidding process has still not been launched. Based on the new scope of activities the budget required is more likely to reach US$0.7 million.

92

Available financing






Sub-component 5.e. (Contract 6.5): Supply and installation of low voltage distribution lines for the electrification of villages.

37. This activity has not yet been procured; the bidding document needs to be updated. Based on SNEL’s consulting engineer, the budget required is more likely to reach US$0.9 million.

Available financing






Sub-component 5.f. (Contract 6.6): Supply and delivery of drugs in the medical centers in villages.

38. This activity has not yet been procured; the bidding document needs to be updated. The Ministry of Health estimates the required financing for this activity at US$1.5 million.

Available financing






Sub-component 6: Environmental and Social Safeguards

39. Social and environmental support includes: (a) updating of the 2003 Environmental and Social Impacts Assessment Study; (b) implementation of an HIV/AIDS awareness campaign; and (c) monitoring and oversight of the implementation of the environmental and social mitigation measures: (a) This activity was completed for a cost of about CAD0.46 million (US$0.45 million). (b) HIV/Aids Awareness Campaign to educate the Project Affected Population and the communities along the length of the high voltage transmission system about the prevention, including the distribution of condoms, and information on where infected persons can go for counseling support and treatment. The activity will be linked with already established systems at state, provincial and local levels for the continuation of educating, counseling, and treatment for infected persons. (c) This activity was completed for a cost of about US$0.13 million. A 10% reserve for physical contingencies is considered for this sub-component. (d) In addition, it was decided to finance a beneficiary assessment to confirm the sustainability and cultural appropriateness of the investment completed under the community development component and other additional related studies. An additional amount of US$0.6 million is considered for this activity.

93

Available financing





US$3.42 million US$0.6 million US$0.4 million -- US$4.42 millionSub-component 7: Institutional Strengthening and Capacity Building

40. The strengthening and capacity building of the Project Management Unit sub-component includes: (a) upgrading of the management information system; (b) provision of equipment, tools, vehicles and logistics required for the purpose; (c) provision of Training for staff of the Project Management Unit, including participation in inspections and factory acceptance tests of equipment for the Project; and (d) for the operation of the PMU: Activities (c) and (d) are ongoing; activities (a) and (b) have not yet started. The current envelopes are as follow: (a) US$1.5 million for the MIS for PMU; (b) US$1.65 million for reinforcement of PMU; (c) US$1.3 million for training of PMU staff; and (d) US$3.45 for PMU operating cost. A 10% reserve for physical contingencies is considered for this sub-component.

Available financing





US$7.9 million -- 0.79 -- US$8.69 million

Sub-component 8 – Establishment of Letters of Credit

41. This sub-component provides financing for the establishment of Letters of Credit to cover commercial bank charges and associated costs for the establishment of Letters of Credit on behalf of the Contractors for the supply of imported equipment and materials. This activity is now completed and the amount of all transactions is US$3.0 million.

Available financing






Sub-component 9: Provision for replacement of additional physical components which may compromise the effectiveness and achievement of the project objectives

42. Based on a detailed review of the existing installation by SNEL’s consulting engineer, possible components on the existing installations which could fail between now and project commissioning have been identified, most of the possible fail will be covered by the local O&M funds. However, for contract 1 (main risk is the failure of transformers) and contract 2 (main risk is the failure of breakers and instrument transformers) have been identified as possible risk which may compromise the effectiveness and achievement of the project objectives. A reserve of US$6.5 million for contract 1 and of 4 million Euros for contract 2 is considered.

94

Available financing





-- -- -- -- US$12 million

Component 3: Construction of a double circuit 220 kV line by CEC from Luano substation in Zambia to link the DRC transmission system at Kasumbalesa. (Sub-component 7 (in the AF1 Project Paper – Annex 3))

43. This component is financed by CEC. The project provides for the construction of new high voltage transmission lines in Zambia to link with the new transmission lines being built in DRC and the extension of existing substations to connect the new lines with the Zambian transmission grid. The contract for the construction of the new transmission lines has been signed whereas that for the extension of the substations has been awarded but has not yet been signed. The two contracts would be completed within 12-14 months and before the commissioning of the new high voltage lines in DRC.

Component 4: A feasibility and preliminary design study of an interconnector between Zambia and Tanzania that would connect the SAPP to the market that would be formed by interconnecting Tanzania, Uganda and Kenya

44. Component 4 has been successfully completed already by the original project completion date of December 31, 2007, before the first additional financing.

95

Attachment 2: Key contracts under the project

Contract 1: Rehabilitation and reinfor-cement of converter station at Inga and inverter station at Kolvezi, instaDation o f synchronous compensator at Kokve:zi,. and rehabilitation oftligh vohage ahernating current substation at Kokve:ri

Contract 2: Rehabilitation and Reinforcement o f Extension 220kV Substations at Fugurume,. Panda, and Kar-avia and InstaDation of Modern

SCADA System at Likasi Control Center

Contract 3: Supply and insta.D.ation of new 220 kilovohs overhead transmission lines from Fugurume to Panda. and to Kar-avia and to Kasum.balesa

Contract 4: Rehabilitation of the high vohage dir-ect current overhead tine and the high vohage ahem.ating current over-head tines•

Contract 5 _l: Supply and delivery of a modern optical fibertelecommunication cable

Contract 5 _2.: InstaDation of optical fiber cables as guard ~vire conductocs in the high vohage DC lines over a distance of2.300 km

Contract 5_3: Supply and instaDation of associated t elecommunication electronic equipment

Contract 7: Engineering and construction supervision services

Community D evelopment Sub-Component

Operation & Mailnenance of the transmission assets Sub-Component

Environmental and Social Safeguards activities

Services of international specialized consuhants

Institutional Strengthening and Capacity Builing activities

Establishment ofleners of Credit

Signed

YES/NO

YES

YES

YES

YES

YES

YES

YES

YES

No

No

Yes

Some

Some

YES

• Contract 4 """""ill only become effective once the s econd additional fmancing is effective.

Amotmt including '"sned addendum

(in USS nUllioo)

1185

192

9A

4 L2

22A

8.0

29.0

3A

6.0

1.9

3.0

C umulative IDA commitment (excluding contingencies)

(US$ nUllioo)

1185

EIB

4292

4373

459.7

463.1

465.1

468.1

47 Ll

Cumulative Percentage of IDA financing (Disbursed and

Undisbursed)

31%

52%

101%

103%

114%

116%

122%

123%

123%

125%

96

Attachment 3: Revised Estimate of Project Costs

US$ million

Component

Component 1

Component 2

Sub-component l.a

Sub-component l.b*

Sub-component 2. a

Sub-component 2.b

Sub-component 3.a

Sub-component 3. b

Sub-component 3.c

Sub-component 4. a

Sub-component 4. b

Sub-component 4. c

Sub-component 4.d - 4.e - 4.f- 4.g

Sub-component 5. a

Sub-component 5. b

Sub-component 5.c

Sub-component 5.d

Sub-component 5. e

Sub-component 5. f

Sulrcomponeut 6.a - 6.b - 6.c

Sub-component 7.a - 7.b - 7.c - 7.d

Sub-component 8

Sub-component 9

Component 3

Component 4

TOTAL

* EIB: 110 million Euros Credit

SAP MP: 30.7 million Euros

PMEDE: 66.49 million Euros

Available: 12.8 million Euros

Initial Cost {including IDA)

3.36 (0.0)

186.11

(177.46)

186.11

{177.46)

0.0

0.0

9.70

(0.00)

1.02

( 1.02)

200.19 (178.48)

Available financing

after AF1 {including IDA)

Completed and

closed

412.00

(3 58.12)

142.08

{141.38)

47.02

(000)

23.31

(22.50) 75.78

(75.02)

40.88

(40.22)

3.00

(3 00)

17.61

( 17.34)

29.0 (28.57)

5.55 (5.55)

6.45

(6.11)

3.42

( 1.55) 7.9

(6.88) 10.0

( 10.0)

0.0

18.00

(0.00)

Completed and

dosed

430.0 (358.12)

Re>;sed Cost

Completed and

closed

581.0

118.5

47.0

180.9

79.2

9.4

41.2

8.1

3.1

22.4

29.0

5.6

2.9

1.1

0.8

0.7

0.9

1.5

5.8

7.9

3.0

12.0

18.0

Completed and

dosed

Physical contingencies

Completed and

closed

41.2

10.6

15.0

4.0

0.0

4.0

0.8

0.0

0.0

2.9

0.6

1.7

0.4

0.0

0.0

0.0

0.0

0.4

0.8

0.0

--

Completed and

d osed

Administrathre

Contingencies

Completed and

closed

16.2

5.5

5.0

3.5

0.0

1.0

0.2

0.0

1.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

--

Completed and

d osed

Total Financing required

C ompleted and closed

638.3

134.6

47.0

200.9

86.7

9.4

46.2

9.1

3.1

23.4

31.9

6.1

4.6

1.5

0.8

0.7

0.9

1.5

6.2

8.7

3.0

12.0

18.0

1.0

657.3

97

Attachment 4: Financing Plan

U S$ million

Total

Component Total F inancing

IDA financing S,._"EL EI B CEC required

required

Component! C ompleted and

closed

Component2 63 8.3 577.0 9.4 51.8 0.0

Sub-component l.a 134.6 133.8 0.8

Sub-component l.b• 47.0 0.0 47.0

Sub-component 2.a 200.9 200.2 0 .7

Sub-component 2.b 86.7 83.7 3.0

Sub-component 3.a 9 .4 92

Sub-component 3. b 46.2 46.2 0.2

Sub-component 3.c 9.1 9. 1

Sub-component 4.a 3.1 3.1

Sub-component 4.b 23.4 22.9 0 .5

Sub-component 4.c 31.9 31.9

Sub-component 4.d - 4.e - 4 .f- 4.g 6.1 6.1

Sub-component 5.a 4.6 4.0

Sub-component 5.b 1.5 1.5

Sub-component S.c 0 .8 0.8 0.6

Sub-component 5.d 0 .7 0.7

Sub-component 5. e 0 .9 0.9

Sub-component 5 .f 1.5 1.5

Sub-component 6.a - 6.b - 6.c 6.2 2.6 3.6

Sub-component 7.a - 7.b - 7.c - 7.d 8.7 8.7

Sub-component 8 3.0 3.0

Sub-component 9 12.0 7.2 4.8

Compooeot 3 18.0 0.0 0.0 0.0 18 .0

Compooeot 4 1.0 1.0 0.0 0.0 0 .0

TOTAL 657.3 578.1 5.8 (+ 3.6)** 51.8 18.0

• EIB: II 0 million Euros Credit SAPMP: 30.7 million Euros ** Compensationlindemnisation in Katanga PMEDE: 66.49 million Euros Available: 12.8 million Euros

98

Attachment 5: Required Additional Financing and Original and revised financing plan

Required Additional Financing

In US$ million

Total IDA Financing required: 578.1

Disbursement to date (May 2012): 149,3

Undisbursed: 227.3

To be disbursed including contingencies: 460.5

Additional IDA Financing requirements: 201.5

Note: Conservative exchange rate SDR/US$ of 1.50 based on the analysis below

SDR vs US$ from May 2003 to February 2012

Original and revised financing plan

InstitutionsOriginal contributi

on

Contribution after AF1Revised contribution after

AF2Initial

Revised contributio

n due to exchange

rate savings

IDA 177.5 358.1(177.5+18

0.6)

376.6(192.8+182.8)

578.1(376.6+201.5)

SNEL 8.5 6.9 6.9 9.4

CEC 9.6 18.0 18.0 18.00

EIB 0.0 47.0 47.0 51.8

Total 195.6 430.0 455.5 657.3

99

Attachment 6: SAPMP – Progress and Actions taken since AF1

Comprehensive procurement and implementation program by contract, including allowance for unexpected delays.

This comprehensive procurement and implementation program, agreed with GoDRC and SNEL during appraisal of the AF1, is updated regularly and shared with the Bank team. It has been improved since and serves also as instrument to forecast disbursements on a quarterly basis.

The time required for processing bidding documents and evaluating offers was underestimated during the AF1, which in turn delayed considerably the project implementation. The process for all major rehabilitation contracts is now concluded. However, in order to capture any potential future implementation delays, the revised timeline under AF2 includes a conservative 9-month slack period.

Staffing and organizational arrangements for the Project Management Unit

PIU of SAPMP merged with PIU of PMEDE project to manage and supervise the implementation of all SNEL’s development projects financed by external donors, including the Bank. However, the process took longer than expected, causing some delays in project implementation.

Bank assistance to provide the right expertise, necessary tools and training is provided through the PMEDE.

Owner’s engineer (including site staff dispersed in the various work sites)

Since SNEL has never implemented a rehabilitation project of such complexity, an international engineering consultant has been put in place before AF1. The international engineering consultant is directing activities on behalf of SNEL.

Numerous deficiencies have been noticed in the international engineering consultant’s performance, including insufficient presence in the various sites and with SNEL. This in turn has also caused delays in the procurement process and slower than expected project implementation and disbursement.

To correct this situation, GoDRC and SNEL have requested the Consultant to provide explanations on the numerous noted deficiencies and more importantly to propose

100

improvement measures, before a full discussion with SNEL. An audit of the Consultant’scontract and numerous amendments (under both the PMEDE and SAPMP projects) will be conducted to verify whether amounts paid match actual levels of effort and whether all contractual services were performed to satisfaction, and to define corrective measures to be agreed upon between SNEL and the Consultant.

Procurement and financial management support from BCECO

The procurement agent BCECO has significantly improved its support to the program through additional procurement staff assigned to the Projects (PMEDE and SAPMP).

A 12-18 month action plan to upgrade various controls, establishing a proper management accounting system, and improving the accountability of the management steering committee was agreed during appraisal of the AF1 and was fully implemented since.

Fiduciary responsibilities will be transferred to PIU/SNEL starting from October 1, 2012.

Strengthening the Bank supervision team The team has been strengthened to take into account of the complexity and multi-sector nature of the project.

To reinforce the Bank’s Implementation Support for the program, the supervision arrangements/strategy on the Bank’s side currently includes currently dual TTL-ship in Washington, with the support of two GH level staff (based in Dakar and Kinshasa), a strongteam of experts including procurement, engineering, economics, financial management, environmental and social safeguards. In addition, the team is complemented by a senior hydro specialist, a senior financial analyst, an ICT specialist, and expertise in community capacity development, public health for the HIV/Aids, regulatory and commercial aspects. A new field based energy specialist should be recruited as soon as possible. The project and all other related energy operations in DRC and regionally associated also benefit from very close managerial oversight at level of Sector Manager and Sustainable Development department Senior Manager as well as strong

101

support by the Country Director.

Sustainability of the Project output and development impact

The team and SNEL have agreed that an operation and maintenance contract (O&M contract) for the SNEL’s high voltage transmission assets would be entered into between SNEL and an experienced entity.

The Expression of Interest has been published and the Request for Proposal (RfP) has been finalized before appraisal for the recruitment of the consultant to prepare the bidding documents for the recruitment of the O&M operator for SNEL’s HV transmission lines SNEL.

Counterpart funding During appraisal of the SAPMP AF1, an agreement has been reached with SNEL on the amounts and timing of contribution into the Counterpart Fund Account. Despite delays in the timing of contribution, to date, SNEL provided the agreed Counterpart amount(condition for negotiations).

Joint Implementation Team A joint Implementation Team has been established by SNEL and CEC under the Infrastructure Agreement between them to coordinate and monitor implementation activities and progress of the construction of the new transmission lines in DRC and the interconnector to be built by CEC.

The joint Implementation team continues to properly operate, although some commercial issues have delayed the construction of the line in Zambia. Those issues have been resolved by the signing of the amendment to the PPA between SNEL and CEC (condition of negotiations for the SAPMP AF2).

ESIAs and RAPs both in DRC and Zambia and Counterpart Funds for the RAP and CP

The updates of the ESIAs and RAPs, conducted before appraisal of the SAPMP AF1, both in DRC and Zambia include the revision of the compensation levels and other measures to ensure that all the mitigation measures and the resettlement of affected population have been addressed and fully comply with the World Bank guidelines.

A dedicated team has been established since 2003. Additional staff comprising two social scientists and two environmental specialists has

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been assigned to the project. An NGO with expertise acceptable to the Bank has also been recruited and additional support is provided by the supervision engineer.

In DRC, however, a series of shortcoming were observed in the process during the Bank’s supervision missions. A resettlement audit has been conducted recently and an action plan (including a follow up system) has been prepared to address the remaining issues raised by the audit (remedial actions to be concluded by October 2012 as per legal covenant).

Those outstanding issues have considerably delayed the project implementation in DRC (in particular Contract 3).

Counterpart funds have been provided to cover for the original and additional compensation.

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Attachment 7: Revised Implementation Schedule~··

I 'I l • l IT

p • I I

I ~ I I

I ~ [~ ~

[ ~

I I I

L J I

I

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Attachment 8: Compliance with Legal Covenants

No Covenant Compliance(Yes/No)

Comments

A. Original CreditA.1 Effectiveness ConditionsA.1.1 The Project Agreement duly authorized or ratified by SNEL and legally

binding upon SNEL in accordance with its termsYes

A.1.2 The Subsidiary Loan Agreement between the Government of DRC and SNEL duly authorized or ratified by the Borrower and SNEL, and legally binding upon the Borrower and SNEL in accordance with its terms.

Yes

A.1.3 BCECO employs an accountant, two procurement experts, and support staff under terms and conditions satisfactory to IDA.

Yes

A.2 OtherA.2.1 The project accounts for each of the implementing agencies shall be audited

by auditors acceptable to IDA, and shall be submitted to IDA within 6 months of the end of each fiscal year.

Yes

A.2.2 The implementing agencies shall retain Project Management Units with professional staff for the duration of the project.

Yes

A.2.3 The implementing agencies shall implement the project in accordance with the agreed Implementation Plan (including the Environmental and Management Plan and the Resettlement Action Plan for the DRC component).

Yes

B. First Additional FinancingB.1 Effectiveness ConditionsB.1.1 Execution of the Subsidiary Agreement YesB.1.2 Effectiveness and availability of funds under the EIB Co-financing

Agreement in form and substance satisfactory to IDA.Yes

B.1.3 Recruitment or designation by SNEL of two environmental specialists and two social scientists with qualifications acceptable to IDA.

Yes

B.1.4 Recruitment of an entity for the purpose of providing additional oversight in the implementation of the Resettlement Action Plan (RAP) and the Compensation Plan (CP).

Yes

B.1.5 Opening up of the Project accounts with terms and conditions acceptable to Yes

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IDA.B.1.6 Signed amendment to the Protocol d’Accord between SNEL and BCECO. YesB.1.7 Revision of the Project Implementation Manual by SNEL satisfactory to the

Association.Yes

B.1.8 The Amendment to the Zambia DCA signed between the Republic of Zambia and the Association.

Yes

B.2 Additional Dated CovenantsB.2.1 SNEL must appoint a consultant for the design of operation and maintenance

services for SNEL’s transmission assets before April 30, 2010No See Para. 85 to 88 main text

B.2.2 Provisioning of the project accounts as per schedule agreed upon between DRC, SNEL and IDA

Yes The projects accounts have been provisioned as part of the Conditions of negotiations for the proposed second additional financing as per amounts agreed between DRC, SNEL and IDA.

B.2.3 SNEL should recruit a Consultant before December 31, 2009 to assist in commercializing the excess capacity of the telecommunication system and the Recipient shall before September 30 2010 identify all measures to select an operator for the same system

No See Para. 85 to 88 main text

B.2.4 No later than September 30 2010, the Recipient shall furnish to the Association a Completion report on the implementation of the RAP, including the Compensation Plan.

Yes

B.2.5 No later than September 30, 2009, the conditions of effectiveness of the CEC commitment to IDA and SNEL will have been satisfied.

Yes

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Attachment 9: Estimated Revised Disbursement of Total IDA Financing (US$million)

Fiscal Year (FY) Cum.2003-2008 2009 2010 2011 2012 2013 2014 2015

Estimated disbursement Credit and Additional

Financing 1

Annual 6.2 58 90 112 55.92 36.00

Cumul. 64.2 154.2 266.2 322.12 358.12Current disbursementCredit and Additional

Financing 1

Annual 6.2 0.4 49.6 10.1 83

Cumul. 6.6 56.2 66.3 149.3*Estimated disbursementCredit and Additional

Financing 1 & 2

Annual 112.8 107.7 104.7 103.6

Cumul. 262.1 369.8 474.5 578.1

*Disbursement in May 2012

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Annex 5: Description of the Regional Context and Southern African Power Market Program


SAPP Regional Context

1. The Southern Africa Power Pool connects the power systems of twelve countries, including ten countries of the Southern Africa sub-region (Angola, Botswana, Lesotho, Malawi, Mozambique, Namibia, South Africa, Swaziland, Zambia, Zimbabwe) and Tanzania and DRC. Nine of these are operating members, namely linked to the interconnected grid that carriesaround 97 percent of the energy produced in SAPP. The non-operating members – which are yet to construct transmission links to the regional grid – are Angola, Malawi and Tanzania.

2. The SAPP region spans over a vast geographical area of nearly 9.09 million sq. km, which is home to over 250 million people. Overall, the economic geography of the region is challenging. Of the 12 member countries, 6 are landlocked, 6 have populations below 15 million people, 5 have economies smaller than $10 billion per annum, and several rely on transnational river basins for their water resources. Nevertheless, the region as a whole has experienced strong economic growth in the last decade until the onset of the global financial and economic crisis. Growth has also rebounded after crisis and is expected to remain steady in the foreseeable future. Regional GDP and average GDP per capita are predicted to increase by 6 and 4 percent per annum respectively from 2010 to 2016 (table 1).

Table 10: GDP growth in the SAPP region

Source: International Monetary Fund, World Economic Outlook Database, September 2011

3. There are two bands of intense economic activity in the region. The first and more intense band runs from Durban in South Africa northward up through Lesotho, Gauteng, Zimbabwe, and into the Zambian copper belt. The second (less intense) band runs from northern Angola across southern DRC and all the way through Tanzania. South Africa constitutes the economic anchor

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of the region, driving demand and market opportunities in Southern Africa and beyond. But there are at least six other countries that are large or potentially large economies, including Angola, the DRC, Mozambique, Tanzania, Zambia, and Zimbabwe. Knitting these emerging economies more closely together and linking them to markets in South Africa would help to create a larger market and greater economic opportunities in the region.

SAPP Current Power Supply-Demand Balance

4. The total combined installed capacity of the SAPP is 56,321MW; however available capacity stands just above 50,000MW (table 2). South Africa, through its national electricity utility Eskom, is the overwhelmingly dominant player of the regional electricity market, accounting for 81 percent of the entire available capacity. With an installed capacity of 2,442 MW, DCR should be the second largest interconnected member. In reality, the available capacity is less than half of what is installed. The second ranking country is therefore Mozambique, whose capacity account for 4 percent of the SAPP total.

Table 11: SAPP Installed & Available Capacity, Peak Demand and Reserve MarginCountry Utility Total Installed

Capacity (MW) as of Apr 2011

Total AvailableCapacity (MW) as of Apr 2011

2010 Peak Demand (MW)

Capacity Required (MW) 10.2% Reserve

Surplus/ Deficit

Angola ENE 1,399 1,202 1,100Botswana BCP 202 190 553DRC SNEL 2,442 1,330 1,081Lesotho LEC 72 72 121Malawi ESCOM 300 300 300Mozambique EDM+HCB 2,308 2,249 560Namibia NamPower 393 360 564South Africa Eskom 44,170 41,074 36,705Swaziland SEC 70 41,70 204Tanzania TANESCO 1008 880 833Zambia ZESCO 1812 1,215 1,640Zimbabwe ZESA 2,045 1,320 2,100

TOTAL SAPP (MW) 56,321 50,262 45,761 50,429 -167

Source: SAPP Statistics, 2010 Annual Report

5. The bulk of power (74 percent) is generated from coal due to the presence of large, low-cost coal deposits concentrated in South Africa’s Northern provinces, but also in eastern Botswana, and western Zimbabwe. South Africa also has a nuclear power plant in the Western Cape, which accounts for 4 percent of the overall SAPP installed generation capacity. Diesel and gas account for an additional 1.6 percent. Most of the diesel power plants serve small isolated rural networks. Generation in the rest of SAPP countries is predominantly hydro-based. Hydropower accounts for 20 percent of the region’s installed generation capacity, with power stations being located in DRC on the Congo River; in the Zambezi Basin countries of Zambia, Zimbabwe, Mozambique and Malawi; in central Angola, Northern Namibia and also in Tanzania. The DRC has a potential hydropower output estimated at 774 TWh/year. Further

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south, the Zambezi, Cunene and Kwanza river basins have another 100 TWh/year of economically exploitable hydropower potential.

6. The SAPP electricity market has experienced steady growth until the onset of the global economic and financial crisis (figure 1). Historical figures show that regional demand has increased at an average rate of nearly 3 percent between 1998 and 2005, reaching up to 4-5percent between 2005 and 2008. Demand has also rebounded after crisis, increasing by 4.3 percent in 2010.

Figure 5: Evolution of electricity demand in the SAPP regionFigure 5.a: Net Peak System Demand (MW) Figure 5.b: System Demand (GWH)

Source: SAPP Statistics, Annual Reports

7. Demand growth has been largely driven by the mining and manufacturing sectors in South Africa and the BLNS countries (Botswana, Lesotho, Namibia and Swaziland) as well as in DRC, Zambia and Zimbabwe. However, population growth, rural electrification and improved economic performance have also resulted in a steady increase in residential demand. The electrification rate in the region has significantly grown overtime, from less than 20 percent in 1999 to nearly 26 percent in 2010 (table 3), with the total number of electricity customers of the combined national interconnected systems increasing to 66 million. Total peak demand has reached 45,761 MW in 2010, with South Africa accounting for about 80 percent of the regional consumption.

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Table 12: Electricity Access Rate in the SAPP Region1999 (% pop.) 2010 (% pop.) 2010 (ml. people)

Angola 8 17 3.24Botswana 15 30 0.55DRC 4 8.7 6.13Lesotho 3 6 0.15Malawi 3 5 0.79Mozambique 6 10.2 2.20Namibia 26 35 0.74South Africa 65 75 37.49Swaziland 21 28 0.33Tanzania 5 10.5 4.34Zambia 12 35 4.64Zimbabwe 20 40 5.03

SAPP 26.1 65.64Source: SAPP Statistics, Annual Reports

8. Conversely, excess capacity – which had been an enduring feature of the region’s electricity sector over two decades – has been shrinking since 2007, when the SAPP began to face serious supply deficits. Regional demand growth, deferral of major generation investments and retirement of aging plants have all contributed to this outcome. In 2007–2008 South Africa experienced severe supply shortages leading to power cuts and load shedding seriously affecting industrial and residential consumption alike. Historically, South Africa had exported electricity to many SAPP countries including Botswana, Lesotho, Namibia and Swaziland, which were relying on South Africa for a significant proportion of their energy supply. Faced with domestic supply constraints, South Africa started curtailing electricity exports. All SAPP countries, with the exception of Mozambique and Tanzania, are now short of generation capacity to meet their domestic demand.

SAPP Governance, Operational and Regulation Framework

9. The Southern Africa Power Pool was created in 1995 through an Inter-Governmental Memorandum of Understanding signed by the Energy Ministers of the Southern African Development Community (SADC) with the primary objective to facilitate the development of a competitive electricity market in the Southern African region and ensure reliable, efficient and sustainable supply to all its members.

10. The SAPP governance structure includes an Executive Committee, which acts as the Board of the SAPP, and a Management Committee, which is responsible for overall administration of the Pool. A Planning, an Environmental and an Operating Subcommittees supervise technical issues under the direction of the Management Committee. In 2002, a Coordination Centre was established in Harare, Zimbabwe as an arm of the Operating Subcommittee to monitor operations and transactions within the Pool, including controlling dispatching operations and serving as trading center for electricity auctions.

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11. In 2002, the SADC Energy Ministers created the Regional Electricity Regulators Association of Southern Africa (RERA), a formal association of electricity regulators with the objective to ensure a consistent and harmonized regulatory framework in the energy sector within the SADC region. A major accomplishment of RERA in facilitating more harmonized regulatory frameworks in the region was achieved in 2010, with the approval by SADC Energy Ministers of RERA’s proposed Cross-Border Regulatory Guidelines. The effort was supported by the World Bank through dedicated technical assistance.

12. The Bank is currently preparing a new technical assistance operation providing critical institution and capacity building to the SAPP and the RERA. In particular, support to the SAPP will entail upgrading of the inter-utility communications system to a fiber optic system, which will provide a stronger, real time communications network for cross border power transactions. Support to the RERA will consist of follow up assistance to facilitate ground level implementation of the Cross-Border Regulatory Guidelines, including: (i) definition of clear policies concerning pricing of transmission services, ancillary services and third-party access; (ii)definition of technical and commercial standard to ensure security of supply; and (iii)identification of future regional regulatory frameworks.

13. Established as a loose pool with a market dominated by bilateral trade, the SAPP has made strides to move towards a tighter structure and facilitate short-term trade. A Short-Term Energy Market (STEM) was introduced in 2001 with access restricted to power utilities, to trade the surplus power not covered by bilateral contracts. Bids and offers were made via an Internet platform. The market was operated by the Coordination Centre, which checked the capacity of the transmission lines and matched offer and demand at the seller’s price. In 2009 the STEM has been replaced by the Day-Ahead Market (DAM), a fully competitive auction market open to utilities, independent power producers, transmitters and distributors. Under the DAM, the SAPP Coordination Centre matches total bids and offers to establish a market-clearing price that is used to settle all transactions.

14. Although STEM and DAM constitute notable innovations, the SAPP market continues to be dominated by bilateral trade. STEM accounted for only 5-10 percent of the energy traded in the region, DAM currently accounts for no more than 1 percent. With the imminent depletion of surplus capacity into SAPP and all member countries exposed to concerns of supply security, although to different degrees, the share of short-term power trading is poised to decrease even further. In a pool with little surplus generation, there is a considerable risk of a utility falling short of its energy requirements. As result, utilities may increasingly resort to PPAs for the bulk of their demand requirements and use the DAM for ‘top-up’ requirements. Also, new PPAs are likely to be shorter and based on long run marginal costs resulting in a two to three-fold increase in prices.

Prospects for SAPP’s Future Development: the SAPP Regional Transmission and Expansion Plan Study

15. A primary challenge for the Southern Africa region is the expansion of power generation and transmission capacity in order to improve security and reliability of supply and cater for future economic and social growth. It is estimated that the region may be losing up to 4 percent

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of GDP annually as a result of unmet power demand18 reducing economic investment, productivity and employment. Integration of physical infrastructure and regional power trade are vital steps to address supply constraints. Integration allows centers of high demand in the south, which are or close to become energy constrained and have traditionally relied on very expensive, thermal generation, to import more cost-efficient electricity, and markedly hydropower, from centers of supply in the north. Large hydropower projects that may not be economically viable for one country alone become highly valuable when they accommodate demand from multiple countries. Security and reliability of supply can be greatly improved by taking advantage of different resources and different peak demand times across the SAPP region and by sharing generation reserve margins among several utilities or countries. All these considerations are at the basis of the creation of the SAPP.

16. The SAPP Regional Transmission and Expansion Plan Study (SAPP Pool Plan), prepared in 2001 and revised in 200919 identifies the coordinated generation and transmission investments that allow accommodating fast increasing electricity demand in the region at the least cost over the period from 2006 to 2025. The Plan considers two scenarios: a ‘base-case’ that is an aggregation of individual national plans; and a ‘recommended case’ envisaging a generation and transmission expansion program optimized on a regional rather than national basis. Both scenarios are further varied using different load forecasts or introducing constraints such as carbon dioxide emission reductions or compulsory use of defined technologies such as nuclear power generation.

17. The Plan considers two regional demand projections. The first assumes total system and peak demand to increase by an average rate of nearly 3 percent per year (table 3). The second assumes regional peak and system demand to grow at over 4 percent per year, reflecting South Africa’s updated load forecast that was released while the Plan was under preparation. Indeed, the Integrated Resource Plan (IRP2) recently completed for South Africa has again revised the country’s load forecast. According to the IRP2, peak demand in the country should reach just above 60,000MW by 2025, as opposed to the previously estimated 93,565 MW20. Thus, a realistic prediction of system and peak electricity demand for the SAPP region as a whole lies somewhere in between the two demand scenarios defined above. Nevertheless, it is evident that the trend of steady growth observed along the past years will continue into the future. In addition to projected economic growth in the region, a renewed focus at country level on significantly increasing household electricity access will also drive electricity demand.

18 SAPP Pool Plan 200919 The SAPP Pool Plan 2009 has been commissioned by the SAPP Coordination center and prepared by Nexant (an American consulting firm) with World Bank support. The Plan constitutes a revision of the original integrated generation and transmission expansion plan commissioned by the SAPP Planning Sub-Committee in 2001 and prepared by the Purdue University with USAID support. 20 This is the ‘moderate demand’ scenario used in the IRP as base case. Electricity demand during the period from 2010 to 2035 is estimated as a function of the projected average GDP growth rate for the next 20 years. In particular, the moderate demand scenario is based on an assumed GDP growth rate of 4.5 percent per annum. A ‘high demand’ (assuming annual GDP growth at 5.5 percent) and a ‘low demand’ scenario’ (assuming annual GDP growth at 3.5 percent) are also considered. Under none of the three scenarios, peak demand is ever expected to exceed 70,000 MW by 2025.

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Table 13: SAPP Demand ForecastScenario 1: Demand growth @ 3%/year 2011 2015 2020 2021 2025SAPP Peak Load (MW) 52,066 58,278 65,167 66,549 71,523SAPP System Demand (GWh) 345,839 386,654 430,868 439,680 470,971Scenario 2: Demand growth @ 4%/year 2011 2015 2020 2021 2025SAPP Peak Load (MW) 53,874 63,530 77,576 80,673 93,565 SAPP System Demand (GWh) 345,744 403,294 488,254 507,843 586,904

Source: SAPP Pool Plan 2009

18. Regardless the load forecast considered, the impact of regional cooperation is evident from the differences in costs between the ‘base-case’ and the ‘recommended’ scenarios. The possibility to complement domestic supply with imports in the recommended scenario enables more efficient generation and supply of electricity, including a reduction of excess capacity above reserve requirements across the region. The investment program identified under this scenario and assuming regional demand growth at 3 percent per year envisages 36,000MW of new generation capacity to be built between 2006 and 2025, 2,700 less than what is envisaged under the base-case scenario. As result the SAPP region would save US$4.8 billion (in net present value) in investment costs over the 20 year period. Assuming regional demand growth at 4 percent per year, the generation investments identified under the recommended scenario total some 57,000 MW, which would lead to doubling the present regional generating capacity. Yet, this is still 4,700 MW less than the base-case scenario. Cost savings in this case would range from US$5.2 billion to US$8.7 billion (in net present value), depending on whether or not South Africa postpone plans for nuclear development in favor of less costly alternatives21.

19. The diversification of energy sources at power pool level would also contribute to put the Southern Africa region on a less carbon intensive path. The SAPP Pool Plan envisages thatcleaner and more competitive energy resources are added to the regional system, with hydro and peaking units replacing conventional coal to a significant extent. The share of hydro into the overall generation mix is projected to increase from the current 20 percent to 25-30 percent, while the weight of coal would decrease to 55-70 percent, depending on the load forecast scenario considered and on Eskom’s plans concerning nuclear energy development.

The Role of DRC in the Regional Power Market: Current and Potential Exports

20. The SAPP is currently the most active power pool in terms of power trading even tough actual traded volumes are not large. SAPP statistics based on the existing power purchase agreements and DAM transactions indicate that total net exports should have reached 15 TWh in 2010, with South Africa still being the primary exporter in the region followed by DRC, Mozambique and Namibia (Table 14).

21 While the SAPP Pool Plan was under preparation, South Africa announced a plan of developing 18,700 MW of nuclear energy. However, the IRP2 has curtailed planned nuclear additions by nearly half. The new nuclear strategy is expected to commence in 2023 and to contribute no more than 9,600MW by 2030.

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Table 14: Current Power Trade in the SAPP

Current trade (2010)

Net imports (GWh)

Net exports(GWh)

Angola 27 -Botswana 2,945 -DRC 38 871Lesotho 49 7.4Malawi - -Mozambique 2,326 309Namibia 2,462 294South Africa 10,156 13,754Swaziland 909.4 -Tanzania 52 -Zambia - 65.6Zimbabwe 710 -Total SAPP 19,674.4 15,301Source: SAPP Statistics, 2010 Annual Report

21. Trade opportunities have firmed up significantly in DRC’s favor over the last decade, as demonstrated by the various sale agreements finalized or negotiated by SNEL in recent years. However, due to supply shortages in DRC and poor transmission capacity both within DRC and partner countries, trade has largely stalled.

22. Two Power Purchase Agreements are currently operational for total trade of 100MW of firm power, which may increase to a maximum of 150 MW if surplus of supply becomes available within DRC (table 6). The first is a six-year PPA entered in December 2009 with the Copperbelt Energy Corporation (CEC) for the supply of 50 MW of firm continuous power at 100 percent load, to be re-sold by CEC to the Botswana Power Corporation (BPC). Due to the difficulties encountered by CEC in securing transmission access from the Zambian power utility (ZESCO), the parties have later agreed that SNEL directly sells power to BPC and that CEC is compensated through a revenue sharing arrangement also defining wheeling charges to be paid to ZESCO and the Zimbabwean power utility (ZESA) for transmission access. This arrangement is intended for three years, after which the original arrangement between SNEL and CEC will be restored. Revenues from the PPA are expected to allow CEC to recover its investment in the reinforcement of the transmission link between DRC and Zambia power systems, which constitutes Component 3 of the SAPMP. However, due to supply shortages and poor transmission capacity in DRC as well as wheeling constraints in Zambia and Zimbabwe, less than 18 percent of the contracted volume has been actually exported and sold in the first two years of implementation of the PPA. As a result, CEC has invocated the revision of the current PPA as a condition to start the construction works under Component 3 of the SAPMP. In January 2012, SNEL and CEC have agreed on an amendment of the PPA entailing a two-year extension of the contract (up to December 2017) and the definition of the schedule and spread of energy

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supply on a monthly basis. An amendment to the PPA was signed in March 30. The second PPA in operation has been entered with ZESA in March 2011 and entails supply of 50 MW of continuous firm power at 100-percent load factor for two years, which can be scaled to 100MW based on availability of power within DRC. However, supply has been recently suspended due to ZESA’s failure to settle outstanding arrears to SNEL.

Table 15: PPA currently operation

PPA Contract duration Committed firm amount Optional amountCEC-BPC 6 years 50 MW ZESA 2 years 50 MW 50MW

Total (committed + optional) 100MW + 50MWSource: SNEL

23. A term-sheet for supply of 50MW of continuous firm power at 100 percent load factor for seven years had been also negotiated with the Namibia Power Corporation (NamPower) but never become operational due to transmission bottlenecks. The recently commissioned Caprivi Link Interconnector, a 350 kV HVDC line connecting electricity grids in Namibia and Zambia, is expected to provide a solution soon. According to SNEL, a Power Purchase agreement for 100MW of firm power is expected to be finalized by July 2012 and sales to start in 2013. A PPA with Eskom expired in December 2008 and has not been re-negotiated.

24. Consultations with SNEL and analyses conducted during preparation of PMEDE-AF1 and SAPMP-AF2 indicate that overall exports may grow already to 150MW, while the reinforcement of the Inga-Zambia Interconnection is being completed, and reach 300MW afterwards, when the line will allow larger power transfers to the SAPP region. NamPower alone has indicated overall import needs of 250MW during power sales negotiations with DRC. These prospects appear rather modest compared to expectations. The Pool Plan calls for 26,000 GWh of exports of firm electricity from DRC each year from 2020 onwards. Nevertheless, a conservative approach to exports is more advisable so as to ensure that domestic demand is adequately accommodated until new generation and transmission capacity becomes available.

25. In the future, there is tremendous potential for trade to develop much further. The SAPP Pool Plan estimates that cumulative exports from 2006 to 2025 could total nearly 720 TWh (table 7). Power trade should increase overtime and become substantial later in this period. By 2025, exports could reach 62 TWh, a four times increase compared to 2010, and accommodate between 11 and 13 percent of total system demand. South Africa would cease to be energy exporter not later than 2017, and even as early as 2012-2013 depending on the assumed regional demand. However, if the country pursues the announced plan of developing 18,700 MW of nuclear energy, its imports needs would be significantly lower. As result, overall exports in the region would not exceed 521 TWh over the 20 year period.

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Table 16: Potential Power Trade in the SAPP

Forecasted trade (cumulative, 2006-2025)No nuclear expansion

in South AfricaWith nuclear expansion

in South AfricaImports (GWh) Exports (GWh) Imports (GWh) Exports (GWh)

Angola 93,558 - 94,782 -Botswana 70,271 10,673 64,809 -DRC - 191,864 - 176,414Lesotho 4,279 - 6,545 -Malawi 3,200 21,615 10,872 1,798Mozambique - 222,941 - 75,783Namibia 25,582 11,061 31,754 596South Africa 277,436 207,813 11,721 253,366Swaziland 26,515 - 26,517 -Tanzania 38,634 - 40,209 1,818Zambia 36,318 38,289 57,747 10,932Zimbabwe 111,334 14,852 161,357 -Total SAPP 687,127 719,108 506,313 520,707SAPP average per year

34,356 35,955 25,316 26,035

Total SAPP, year 2025 only

59,947 62,067 37,894 39,510

Note: The difference between imports and exports is due to system lossesSource: SAPP Pool Plan 2009

26. In the long run, DRC is poised to become a primary power exporter to SAPP, taking at least in part the space given out by South Africa. DRC’s Inga site constitutes a prime target for hydro development in the region, with the rehabilitation of Inga 1&2 as well as development of Inga 3 identified as key components of the least-cost power development program articulated by the SAPP Pool Plan. Given the fast growing demand in the region, the SAPP market can absorb as much electricity as DRC will be able to export once new power generation and transmission capacity comes on stream. Suitable export destinations will be Zambia, Namibia, Botswana, and Angola in the medium- to long-term and ultimately South Africa. The IPR2 envisages hydropower imports to rebound in the foreseeable future. Imports are expected to start in 2020 and total 3349MW by 2023, a significant share of which may be supplied by DRC once Inga 3 comes into service. Exports to Zimbabwe may prove difficult until transmission bottlenecks within this country are removed and in general given its fragile political context.

27. In the long-term, South Africa also constitutes a natural, reliable market for Grand Inga,which, once commissioned, will be the largest hydropower plant in the world. Full development of Inga could turn DRC into Africa’s largest exporter of hydropower, with annual exports growing to more than 50 TWh. On November 12, 2011, the South African and the DRC government signed a Memorandum of Understanding (MoU) establishing a partnership between the two countries for the phased development of the Inga site. Although the MoU is probably largely politically driven, it signals the renewed interest of South Africa for the development of

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the Inga site, which is a notable departure from South Africa’s traditional reservations in considering DRC as a reliable supplier.

The Inga-Zambia Interconnection as a Key Transmission Link of the SAPP Backbone

28. Deepening power trade in the SAPP region requires the completion of the key transmission links needed to facilitate large power transfers. Priority transmission investments have been identified as part of the least-cost power development program articulated by the SAPP Pool Plan. These involve the acceleration of the interconnection of non-operating members and the strengthening of the central transmission corridor between DRC, through Zambia, Zimbabwe, Mozambique and Botswana to South Africa. Altogether, these interconnections would form the backbone of SAPP and ideally move power from Inga to South Africa and to Luanda (see maps at the end of the Project Paper).

29. The Inga-Zambia Interconnection is recognized as a key component of the SAPP transmission backbone and its reinforcement has been identified as a priority project by the SAPP Pool Plan as well as by various regional analyses and strategies completed afterwards.Currently, this corridor is the only linkage between the Inga site and the SAPP. An alternative route was to be provided by the WESTCOR project, entailing development of Inga 3 and the construction of a 3,000-km long transmission network capable of dispersing 3 GW of hydropower from DRC to South Africa through Angola and Zambia. The project was established in 2004 through MoUs signed between the five governments and power utilities of Angola, Botswana, DRC, Namibia and South Africa. However, DRC’s departure from the project in 2007, mainly due to the desire to raise its control on Inga 3 development and increase the use of energy from Inga for national demand, ultimately led to the disbanding of WESTCOR.

30. The Inga-Zambia Interconnection constitutes a transformative opportunity for the Southern Africa region. Although power exports through the line may remain limited until supply capacity from Inga 3 comes on stream, the injection of DRC’s greener and cost-effective hydropower will lead to an overall reduction in the average cost of electricity within the SAPP, with beneficial effects on industrial competitiveness and growth in the Southern Africa region. The Africa Infrastructure Country Diagnostic Study (AICD) recently undertaken by the World Bank estimates that full expansion of regional power trade in the SAPP22 hinges upon the development of 7,640 megawatts of hydropower in DRC. The displacement of thermal generation in the southern part of the SAPP with cost-effective hydropower from DRC could save to the region $1.1 billion annually in power costs and reduce the long run marginal cost of power from $0.07 to $0.06 per kilowatt-hour or 5 percent overall. The largest benefits would be felt by small countries with thermal-based systems, which could save as much as $0.05 per kilowatt-hour or more than 40 percent of power costs overall. The investments associated to additional generation capacity and regional interconnections needed to enable power trade would be recouped in less than a year and yield a return of 167 percent to the region as a whole. The shift to cleaner energy would reduce regional carbon emissions by a significant 41millionannually.

22 The AICD analysis covers the period from 2005 to 2015 and takes regional power trade to its fullest economic potential, assuming that there are no restrictions to cross-border exchange and that the necessary infrastructure can be built wherever it is required.

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31. On the domestic scene, exports constitute an important and reliable source of revenues to help SNEL meet its operating costs. Full development of DRC’s hydropower potential at Inga would guarantee to the country a more stable and significant stream of income than the exports of physical resources, with large effects on the country overall macro-economic situation.

32. The reinforcement of the Inga-Zambia Interconnection also holds great signaling potential and is critical to DRC’s long term regional trade aspirations. South Africa’s power crisis and general concerns of power supply security have contributed to raise reservations towards power imports among SAPP countries. However, shrinking excess capacity at regional level and efficiency considerations will inevitably lead to favor integration over self-sufficiency.Hydropower imports may significantly contribute to strengthen base-load capacity in several countries, avoiding them brownouts or blackouts that mean big losses to their economies. The cost of un-served energy is extremely high among SAPP countries, reaching up to 300 US cents/kWh in South Africa23. There is great momentum for DRC’s greater participation in the regional power market. But to gain the confidence of SAPP members and be able to secure long-term agreements at attractive prices, DRC needs to be perceived as a reliable supplier. This mainly hinges upon its ability to adequately expand generation capacity and build a capable and reliable transmission system that would allows power to be delivered into the SAPP.

33. Finally, transmission linkages need to be already in place by the time generation capacity becomes available. The existence of a viable interconnection to the SAPP provides grounding and justification for further developments at the Inga site, including Inga 3 and most notably Grand Inga. A project of the size of Grand Inga makes sense only in a regional perspective, but this requires that power is timely transferred at the same time that is produced. Reinforcement of the Interconnection between Inga and the SAPP cannot be put on hold until enough power supply for exports is available, but should rather anticipate it.

Transmission Constraints along the SAPP Backbone and Alternative Solutions

34. In addition to strengthening the Inga-Zambia interconnection, completing the SAPP backbone and allowing power to flow from Inga to South Africa will require addressing key transmission bottlenecks along the central corridor of the SAPP high voltage transmission grid. Most of these are to be found in Zimbabwe. In 2004, power transmission constraints began to develop from the Kariba South power station in Zambia to Sherwood in Zimbabwe due to several years of lack of maintenance by ZESA. By 2006, the constraints had developed to such an extent that power flows between the northern and southern parts of the SAPP had virtually ceased, especially during periods of system peak demand. Due to the poor maintenance of the network in Zimbabwe, normal manageable disturbances in the transmission system have evolved into uncontrollable situations resulting in system wide transmission failures and region-wide black-outs. This situation may now largely improve as result of recent developments on key transmission projects.

35. The upgrading of the 330kV transmission line between Zambia and Namibia (Kafue –Muzuma – Victoria Falls Regional Transmission Line Reinforcement Project) with support by

23 Based on estimates by the South Africa’s 10th Integrated Strategic Electricity Plan.

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the World Bank and the European Investment Bank (EIB) will connect the northern and southern power markets of the SAPP bypassing Zimbabwe bottlenecks. The line constitutes a critical link to enable power exports through the Inga-Zambia interconnection to reach further south. Its 450MW capacity is sufficient to accommodate export volumes from DRC as agreed under the existing PPAs including with Botswana and Zimbabwe, as well as increasing exports in the short- to medium-term, such as to Namibia. SNEL, NamPower (Namibia) and ZESCO (Zambia) are already negotiating the wheeling of 416 GWh per annum from DRC to Namibia through Zambia24. The Kafue – Muzuma – Victoria Falls Regional transmission line constitutes an alternative to the ZIZABONA project, a 400 kV line that was intended to link Zimbabwe, Zambia, Botswana and Namibia. Due to political reasons and the associated difficulty in raising the financing for the Zimbabwe portion, the ZIZABONA project has not gone beyond the concept and study stage and prospects for its development in the foreseeable future appear remote. The Kafue – Muzuma – Victoria Falls Regional Transmission Line Reinforcement Project has been recently approved by the World Bank Board of Executive Directors. EIB’sBoard has also approved their co-financing of the project.

36. In the medium- to long-term, a more permanent solution to the transmission bottlenecks in Zimbabwe will need to be put in place. The Central Transmission Corridor Project recently proposed by the SAPP Coordination Center could contribute to this extent. The Project entails construction of three additional 330 kV transmission lines, including Alaska-Sherwood, Bindura-Mtorashanga and Insukamini-Marvel, which altogether will reinforce the Zimbabwe backbone, increasing transfer capability for local requirements as well as for wheeling up to 500MW. Feasibility studies are currently in place for all project components.

24 Exports to Namibia will further flow through the Caprivi Link Interconnector.

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Annex 6: The Regional and Domestic Power Markets Development Project (PMEDE): Links with the SAPMP project. Implementation Status and Update since June 2011


Linkages between the PMEDE and SAPMP Projects

1. The PMEDE and SAPMP Projects are closely linked and interdependent. The transmission system to be rehabilitated and reinforced by the SAPMP is needed to convey the power produced by the generating units rehabilitated under the PMEDE from 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. The power transported by the transmission system will also supply export markets in the Southern African Power Pool (SAPP). The decision of the Government, supported by the Bank, to proceed first with SAPMP ahead of PMEDE was a rational one because the SAPMP would need to be fully completed and operational ahead of the completion of the PMEDE.

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. In order to enter into secure, longer term agreements at attractive prices; DRC would need to demonstrate reliable availability of power supported by a capable and reliable transmission system that SAPMP would provide. 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 population.

The PMEDE Project

3. On June 28, 2011, the Board approved an additional financing grant of US$ 283 million for the PMEDE Project to complement the existing grant of US$ 296.7 million, approved in May 2007 for the Project. This brought the total IDA contribution to US$ 579.7 million towards the financing of the total revised estimated project cost of US$ 882.9 million. At same time the Board approved a further 3 years extension of the Project Closing Date to June 30, 2016. The additional financing grant became effective on October 25, 2011.

4. The objective of the PMEDE 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. To achieve its objective, the PMEDE consists of the following:

Component 1: Generation: Improvement of the installations at Inga, including civil works on the intake canal to improve water flow through the plant; rehabilitation of turbines to increase the capacity and reliability of the Inga 1 and 2 power stations from the current maximum of around 750 MW to about 1,300 MW of reliable production; provision of dam safety equipment; as well as the design and implementation of an effective maintenance program for the facilities.

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Component 2: Transmission: Construction of a 400 kV Inga-Kinshasa transmission line to complement the existing 220 kV transmission line, which is presently saturated, thereby increasing the amount and reliability of power that can be delivered to Kinshasa.

Component 3: Distribution: Expansion and strengthening the distribution system in Kinshasa and implementation of an energy efficiency and load management program through the acquisition of low voltage cables and transformers; the extension of the grid into currently un-electrified areas of Kinshasa; the connection in these areas of a total of 35,000 new customers; distribution of around 2 million compact fluorescent lamps or light emitting diodes for the systematic replacement of traditional bulbs; as well as the installation of around 70,000 classic meters and around 32,000 prepaid meters.

Component 4: Capacity Building and Governance: 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 through the transformation of SNEL into a limited liability company, signing of a performance contract between the Government and SNEL, and technical assistance to SNEL to be provided by an experienced operator.

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, including Project preparatory activities: Effective implementation of the Project works, in an environmentally and socially sound manner, including the appointment of supervisory engineering consultants, environmental/social consultants and the PFM Agent as well as the implementation of a communication program.

Implementation Status of PMEDE and Progress since June 2011(approval of the Additional Financing)

5. The additional financing became effective on October 25, 2011. To reach effectiveness, the Project Implementing Entity has revised and disclosed the Inga Emergency Preparedness Plan, addressing a major outstanding action under the original project. The table below summarizes the status of dated covenants and actions taken to date.

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Table 17: Status of dated covenants and actions taken to date

Description of Condition Date Due Status as of February 2012Amendment of the existing Subsidiary Agreement between SNEL and the GoDRC

Effectiveness Completed (before the 90 days limit)

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.

Effectiveness Completed (before the 90 days limit)

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

Not later than three months following effectiveness

Completed.

SNEL’s new Board is appointed

December 31, 2011 Completed in advance (see below)

Signature of SNEL performance contract between SNEL and the State

March 31, 2012 Completed in advance (see below)

Opening and provisioning of dedicated account for Inga O&M

December 31, 2011 Completed (as conditions of negotiations of the SAPMP AF2)

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


Completed.

Revision of ToR of external auditors of project accounts to include the additional financing


Completed.

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The Project Implementing Entity shall employ a consultant for the design of operation and maintenance services at the Inga hydropower plants, including the determination, on a quarterly basis, of the funding requirements.

October 31, 2011 Completed early 2012

Appointment of two internal auditors (technical and financial) of the SNEL internal audit department to the PMEDE Project


Completed.

Signing of SNEL’s TA services contract

March 31, 2012 RfP launched for the recruitment of the consultant for the technical assistance service contract (completed as condition of Appraisal for SAPMP AF2). Contract signing expected by December2012.

6. On the procurement side, contracts for the generation, transmission and distribution components are at various stages of implementation.

Generation. Work on four of the generating units to be rehabilitated is progressing (G12, G14, G15 and G16). The first unit (G12) will be completed in the second quarter of 2012. The partial rehabilitation G16 will be completed in June 2013, while the G14, financed by AfDB, will be concluded in January 2014. The contract for two more units (G21 and G22) has been awarded, and the tender for two other units is currently ongoing (G11 and full rehabilitation of G15). The bidding documents for the remaining two units are under preparation (G27 and G28) and scheduled to be ready in February 2013. The launching of the contract for the dredging of the intake channel is waiting for the completion of studies that will determine the optimum dredging method. All other 14 contracts under the emergency rehabilitation are progressing smoothly and on schedule.

Transmission. The construction of the second line Inga-Kinshasa has commenced in June 2011. In addition, works at the Kimbanseke substation and associated transmission line has started in February 2012. The procurement process for the contract aiming at the reinforcement of transmission sub-stations in Kinshasa up to US$ 39 million is ongoing.

Distribution. Out of the eighteen contracts for the distribution component, thirteen have been signed and are being executed. Works for the electrification of Kimbanseke and other areasin Kinshasa providing access to about 280,000 people (35,000 new connections) have started

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in February 2012. The procurement of meters is ongoing, while procurement of CFL lamps is scheduled for September 2012. All contracts are on target for completion before the end of June 2016.

7. Disbursement. Disbursements on the IDA financing, cumulatively, stand at US$ 63 million as of March, 2012 and it is forecasted to reach US$ 93 million at the end of June 2012. With the signing of the contract for the rehabilitation of G21 and G22, the amount committed on signed contracts that are being financed by IDA stands at around US$ 472 million. Disbursement is expected to reach US$ 200 million by the end of 2012.

8. The PMEDE project is supporting SNEL to improve its governance, as well as its technical and commercial performance. Good progress have been made since the additional financing of PMEDE and both the Government and SNEL has demonstrated commitment to this path as evidenced by the following key steps taken (this is noteworthy given the recent election turmoil):

Appointment of SNEL’s new Board and Senior Management. A new Board of SNEL was appointed in September 2011 (before the scheduled date of 31/12/2011 as targeted under the PMEDE project). The Chairman of the Board of Directors has significant management experience from the private sector and a clear vision on the effort needed on corporate culture, performance incentives, corporate governance, and the autonomy and accountability of SNEL. The new CEO has conducted a performance evaluation on the basis of technical skills for the senior positions before confirmations of new appointments.

Signing of the Performance Contract between SNEL and the Government. COPIREP (Comité de Pilotage de la Réforme des Entreprises Publiques), in consultation with the Government and SNEL, has finalized, with the assistance of its consultants, the proposed performance contract between the Government and SNEL. The contract was signed on February 27, one month ahead of March 31, 2012, targeted deadline. The document contains all the principles appropriate to the performance improvement and corporate governance of SNEL, in terms of roles and commitments of the parties, targets and indicators, and monitoring and evaluation mechanism. SNEL is also recruiting a consultant to develop the business plan required to achieve the outcomes specified in the performance contract.

Finalization of the Terms of Reference for SNEL’s TA Services Agreement. COPIREP has prepared draft Term of References for the technical assistance service contract and draft terms of reference for the independent audit of the performance contract. The notice of expressions of interest for technical assistance services to SNEL was published in October 2011 and the request for proposals launched in March 2012. The contract is expected to be signed by December 2012.

Arrangements for appropriate O&M of SNEL’s transmission and hydropower facilities.Under a multi-party agreement between SNEL, EIB, the WB and a private bank (the so-called “Accord de mécanisme de paiement”), escrow accounts have been established abroad for appropriate financing of O&M of SNEL’s transmission assets, which are

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automatically provisioned by sales to six large mining customers. SNEL has also opened a dedicated account for O&M of Inga hydropower facilities and recruited a consulting firm to design appropriate O&M costing, procedures and organization for these facilities. The recruitment of the technical audit and design of the private O&M contract for SNEL transmission facilities is underway.

9. Attachment 1 to this Annex provides two tables with further information on actions and progress aimed at enhancing SNEL’s corporate governance and performance and an update onkey indicators for SNEL.

10. The implementation of the capacity building and governance component is also progressing according to schedule. As mentioned in the PMEDE AF project paper, SNEL has recruited three experts for advice on billing, financial management and procurement so as to improve its financial performance. SNEL has also recruited another expert to advise the project implementing unit. Based on the work of three consultants, three action plans were prepared and a number of key actions extracted to be implemented in the short term with the support of thePMEDE. The consultants, in collaboration with SNEL, are currently finalizing these short-term plans and key actions to be implemented are summarized in the box below. The consultants will continue to support SNEL during the implementation of these short-term measures.

Box 6: Key Short-Term Measures in the commercial, procurement and financial and timetable for implementation financed under PMEDE

1. Procurement and Acquisition (about US$ 10 million)

Phase 1 (Jun-Dec 2012): establishment of procurement and acquisition units and training program, review of current procurement procedure (including strategy, vision and procurement policies), implementation of the budget process, implementation of a data management system to monitor current stock in different location (starting with headquarters and central deposit in Kinshasa).

Phase 2 (Jan-Jun 2013): strengthening of the organization, review of the planning and logistics arrangements, training, establishment of accounts for contractors and suppliers. Extension of the data management system to the whole Kinshasa province.

Phase 3 (Jun 2013- Jun 2014): Extension of procurement system to Bas Congo and Katanga and establishment of strategic stocks for generation, transmission and distribution (to be financed by SNEL).

Phase 4 (Jun 2015 – Jun 2015): Extension of procurement system to other provinces.

2. Commercial- Billing and Collection Rate Improvement (about US$ 8 million)

Key actions to be realized over the next 12 to 18 months (in 6 pilot areas to be determined by SNEL and the consultant) include:

Installation of new meters (and substitution of classic meters)Audit and reinforcement of the electronic system for paymentsInformatization of manual methods of paymentOpening and modernization of new Point for Payment and ServiceOther short-term initiatives targeted at specifically fighting non-technical losses and fraud

3 Financial Management (about US$ 2 million)

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Key actions to be carried out over the next 12 months include:

Establishment of an integrated accounting and financial information management system including the implementation of the technical platform to manage budgets, commitments, accounting, treasury and communication system; and

Training and capacity building of staff for the use of the new system.

11. The project paper for the PMEDE Additional Financing included a table (Table 2, p. 16) outlining the Implementation Challenges and Measures taken/envisaged to foster project implementation. Those are important lessons learned for the preparation of the SAPMP AF2 and an update from June 2011 is presented below.

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Table 18: Implementation Challenges and Measures – Update since June 2011

Implementation Challenge

Consequences/Lesson Learnt Mitigations/Changes Made during implementation

Update

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

Shortcomings in project management, procurement and contract management

Multiplicity of implementing agencies spreads further scarce expertise and resources

Additional expert support engaged through the Project at the level of the Ministry and the implementing agencies particularly SNEL PIU

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

Continued

Continued

Continued

SNEL poorly organized and managed

Poor maintenance of assets

Indicators of operational, commercial and financial performance consistently below

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

The local O&M account for Inga has been openedand provisioned.(Provisioning of the account was a Condition of negotiation of the SAPMP AF2.)

O&M arrangements for SAPMP are treated in Annex Attachment 1 and in the main text.

The performance contract, now signed, is

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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

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

expected to produce positive impacts on SNEL performance.

RfP launched for the recruitment of the consultant for the technical service contract was a condition of Appraisal for the SAPMP AF2.

The Project Engineer has strengthened its field presence. An Action Plan has been developed toimprove the owner’s engineer over the next three months.

Supervision missions were carried out as per Implementation Support Plan (a part from during the period of suspension due to election).

Lack of coordination and oversight by the Ministry of Energy

Important decisions on project and related sector issues that impact on the project are not taken in a timely and efficient manner.

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

Continued (CATE is operating properly with an efficient monitoring and coordination role).

Strong guidance and coordination role continuing to be effective

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stakeholders

Closer supervision by the Bank team including frequent video conference meetings with the Minister, SNEL CEO and their teams.

Bi-monthly VC are scheduled with DRC counterparts.

BCECO carries out procurement functions for many projects and lacks sufficient staff capability

Inappropriate discharge of the procurement and financial management functions by BCECO for the Project leads to delays and errors

BCECO strengthened with additional staff assigned to the Project for procurement workBCECO has maintained adequate capacity.

The 2-year extension of the SNEL – BCECO contract financed by the Project, 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

Capacity building activities were delayed mainly due to the turmoil in the country.

The transfer of fiduciary responsibilities from BCECO to SNEL is based on an agreed action plan to achieve proper fiduciary capacity at PIU/SNEL and it will be carried out by end of September, when it is deemed that PIU/SNEL has enough capacity to avoid jeopardizing the project implementation.

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Attachment 1: Enhancing SNEL’s corporate governance and performance

A. SNEL Recovery program

1. As part of the PMEDE project, the Government designed in March 2011 a comprehensive five-year program for the financial and operational recovery of SNEL and to enhance SNEL’s corporate governance. The program is being implemented under the leadership of COPIREP, with guidance from the Ministry of Portfolio and the Ministry of Energy.

2. The program includes five main components described below.

1/ Performance Contract (“Contrat de Plan”) between the State and SNEL

3. The performance contract stipulates the respective roles and obligations of SNEL and the State to achieve sector objectives over time (as measured by timebound indicators/targets), including mainly:

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 electricity service, as a critical contributing factor to economic growth and poverty reduction; and

increased access to electricity from currently low 10%.

4. Actions to reach these objectives include the completion of SNEL transformation into a limited liability company (see below), mechanisms for settling of debt and future payments for electricity consumption by the State and by 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 (“Plan d’Entreprise”) to improve SNEL’s organization, management, investments, monitoring and reporting.

5. The performance contract includes dispositions for the monitoring and audit of the performance of both parties, as well as achievement of performance targets.

2/ Corporate Governance plan

6. The corporate governance plan addresses the following aspects:Board composition and appropriate functioning;Internal control and reporting mechanism ;External audits;Procurement audits;

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Development of suitable internal control systems to allow the audit of SNEL’s accounts following international standards;Strengthening human resource actions and performance incentives;Guidelines for mobilizing private investment and PPPs, and for contract review;Communication strategy; andDisclosure of performance indicators/results.

3/ SNEL institutional and financial restructuring

7. SNEL restructuring started in 2010, with its transformation into a limited liability company as of 01/01/2011. The first phase of SNEL restructuring is designed around SNEL’s current institutional structure, i.e. a vertically and horizontally integrated electric utility. Actions include:

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;

Public and private debt restructuring;

Receivables restructuring (particularly receivables from SOEs);

Design and implementation of SNEL organizational restructuring, including a social plan, staff redeployment and a training program; and

Definition of a strategy for the next phase of SNEL restructuring and for increased private participation in the electricity sector

8. SNEL will establish a Register of Asset and 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.

9. Based on the reconciliation of the debts of SOEs to SNEL (to be confirmed and suitably documented), a repayment schedule will be agreed and 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.

10. 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

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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.

11. 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 for 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 re-deployment of administrative staff in operational positions.

12. The first phase of SNEL restructuring will also include the preparation of a strategy for the further restructuring of SNEL, possibly including vertical unbundling (i.e. separation of Inga generation, separate transmission company, etc) and horizontal unbundling (i.e. subnational distribution utilities), as well as for increased private participation in sector financing and operations, as may be justified.

4/ Technical Assistance Services Agreement

13. A three year TA Services Agreement is to be entered into with a reputable operator or management consulting firm. Permanent technical assistance in counterpart management positions will be provided on key operational aspects (such as commercial, financial, accounting, procurement, etc). Short term technical assistance will also be provided on specialized aspects(such as improving billing system, preparation of maintenance plans by function, management of network extension, management of metering installations, etc), and to support installation of and associated training for improved commercial and financial systems.

14. Special emphasis will be placed on 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 revenues). 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 areasof Kinshasa).

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5/ Institutional and financing arrangements for appropriate O&M of SNEL’s transmission facilities, as well as Inga hydropower plants.

15. Appropriate O&M of transmission and generation assets financed under the SAPMP and PMEDE projects is an essential element to achieve the sustainability and normal lifespan of these assets. The gradual improvement of SNEL’s financial position through the above described actions will ensure in the medium term sufficient resources to finance O&M activities as required. In the short to medium term, specific institutional and financing arrangements have been agreed upon with SNEL to ensure appropriate O&M of transmission and Inga hydropower assets.

16. Improvement of transmission facilities operation and maintenance includes the following aspects:

Establishment of dedicated escrow accounts for O&M financing, automatically provisioned by identified mining customersTechnical audit of transmission O&M, to define appropriate O&M costs and organizationRecruitment of a private contractor for O&M of SNEL high voltage transmission assets

17. Improvement of Inga facilities operation and maintenance includes the following aspects:Restructuring and strengthening of SNEL’s Inga O&M organization, staffing and proceduresCosting/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&MReview 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, with opportunity of combination with Inga 3 development)

B. Progress on SNEL’s recovery program (as of March 1, 2012)

18. Significant progress has been made on all five components of SNEL’s recovery program, as presented below.

1/ Performance contract between the State and SNEL

19. SNEL performance contract was signed on February 27, 2012 by SNEL and all five Ministries that have an interaction with SNEL or the electricity sector, i.e. Portfolio (ownership), Energy (policy), Finance (debt), Economy (tariff), and Budget (public receivables).

20. COPIREP has prepared a draft RfP for the recruitment of:the technical audit of the performance contract by an independent firm; and support to the preparation of SNEL business plan (“Plan d’Entreprise”).

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2/ SNEL corporate governance plan

21. A new Board for SNEL was appointed in September 2011 (i.e. before PMEDE AF’s dated covenant). The new Chairman of the Board has experience in management of private companies and clear ideas on necessary efforts to improve the enterprise culture, performance incentives, corporate governance, and autonomy and accountability of SNEL. The new general manger (“Administrateur Délégué”) and member of the Board made an assessment of SNEL’s management positions and proceeded with important reshuffling and new nominations with competent managers.

22. A external audit of a representative random sample of procurement activities conducted by SNEL in 2008/09/10 (other than activities financed by IDA under the SAPMP and PMEDE projects) was completed in 2011. The audit did not find any severely wrong practices but made detailed recommendations for improvement of procurement practices at SNEL, which were taken into account in the recommendations made by SNEL’s external advisor on procurement (see below).

23. SNEL’ external advisor ob financial/accounting aspects made recommendations for the development of suitable internal control systems to allow the audit of SNEL’s accounts following international standards.

24. Disclosure of SNEL performance indicators/results will be made under the performance contract (see Appendix 1 with SNEL’s past performance regarding key operational and financial indicators).

3/ SNEL institutional and financial restructuring

25. Only limited progress was made on this front due to the complexity of issues surrounding property of assets and valuation of these assets, as well as actual settlement of cross-debts with the State and SOEs (particularly GECAMINES and REGIDESO).

26. COPIREP has prepared TOR for consulting services to support in resolving the above issues.

27. The PMEDE project includes financing to support the definition of a strategy for the next phase of SNEL restructuring and for increased private participation in the electricity sector.

4/ Technical Assistance Services Agreement

28. COPIREP has prepared a draft RfP for the recruitment of SNEL’s TA Services agreement, which has been extensively discussed with SNEL, and the Ministries of Portfolio and Energy, and has received Bank’s comments. The call for proposals should be issued as a condition for appraisal of SAPMP second additional financing. The TA Services Agreement is expected to be signed by December 31, 2012.

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29. In the meantime, technical assistance by individual experts in commercial, financial/accounting and procurement aspects will be continued. Three experts are in place since March 2011 and have made detailed recommendations to improve SNEL performance in their respective fields, as well as regarding specifications of the corresponding management systems and equipment to be acquired by SNEL. On that basis, SNEL will formulate a detailed action plan for 2012, including immediate measures to improve commercial, financial and procurement performance, and the acquisition of related systems and equipment by end 2012.

5/ Institutional and financing arrangements for appropriate O&M of SNEL’s transmission facilities, as well as Inga hydropower plants.

30. A five party agreement between IDA, EIB, the Government of DRC, SNEL and a domiciliary bank in Luxemburg (the Accord de Mécanisme de Paiement, AMP) was signed in February 2010 for the creation of a secured mechanism for the provisioning of operation and maintenance funds for SNEL transmission assets and for the servicing of EIB debt related to the SAPMP and PMEDE projects (Euros 110M).

31. The AMP includes a Collect Account that is provisioned by electricity payments from six large mining companies. The domiciliary bank automatically proceeds to cascade payments in an O&M Account A (for SNEL high voltage transmission facilities) and a Debt Service Account, as per amounts and frequency established in the AMP. Since its creation the AMP has been functioning as planned.

32. The AMP also includes the creation of an O&M local account B (for the maintenance of SNEL high voltage transmission assets until the full provisioning of the O&M Account A in 2014), also as per amounts and frequency established in the side letter between IDA and the DRC. The local O&M account has not been provisioned to the amounts stipulated in the side letter for 2011 and 2012 ($5 million each year). However, while only $0.9 million were provisioned in 2012, SNEL spent $2.1 million and 3.1 million for transmission maintenance expenditure in 2011 and 2012 respectively. It should also be noted that the above annual amount of $5 million was a rough estimate, which should be revised on the basis of the technical audit of transmission assets. The O&M account B has been provisioned before negotiations of the AF2 up to the amount agreed with IDA.

33. SNEL and BCECO are preparing and EOI and RfP for the recruitment of the consulting firm that will conduct the technical audit of SNEL transmission assets and design the bidding documents for the recruitment of the private contractor for the O&M of SNEL’s high voltage transmission assets. The RfP was submitted to IDA to meet the conditions for appraisal of SAPMP second additional financing.

34. Regarding Inga O&M, good progress has been made on the recruitment of the consulting firm that will design and cost appropriate O&M arrangements for Inga hydropower facilities. SNEL has opened a dedicated account for Inga O&M, which has been provisioned on the basis of SNEL’s existing O&M program as a condition for negotiations of SAPMP second additional financing.

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C. Expected impact of the SNEL Recovery Program35. Performance targets at the end of the five-year performance contract are rather ambitious and include mainly: losses 16%; bill collection 95%; clients per employee 175; Government and SOEs’ collection 100%; Inga availability 75%; clients with meters 100%; reduced Government electricity consumption; actual yearly review & adjustment of electricity tariff.

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Table 19: SNEL’s Performance Indicators

(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) State, public institutions, city halls, etc

Indicators 2005 2006 2007 2008 2009 2010 20111. Hydroelectric and thermal power plants total installed capacity

(MW) 2,442 2,442 2,442 2,442 2,442 2,442 2,442

2. Hydroelectric power plants total available capacity (MW) 1,262 1,309 1,301 1,287 1,275 1,250 1,2503. Available capacity Inga 1&2 (%) 57 57 57 57 43 43 434. Total energy produced (GWh) 7,171 7,229 7,582 7,246 7,641 7,409 7,1895. Gross energy produced Inga I and II (GWh) 4,746 4,981 4,822 4,541 4,858 4,815 4,2046. Exported energy (GWh) 1,768 1,323 1,508 915 887 916 1927. Unavailability T-line Inga-Kinshasa (hours per year) 60.85 74.87 22.33 18.63 8.66 2.328. Unavailability T-line Inga-Kolwezi ( hours per year ) 630.39 474.88 994.52 781.09 467.1 975.70 9159. Distribution losses (%) - - - (3) - (3) - (3) - (3) - (3)10. Non distributed energy (%) - - - (3) - (3) - (3) - (3) - (3)11. Total collection rate with arrears (%) 43.8 54.3 57.7 60.1 64.7 69.4 78.512. Collection rate with governmental entities (5) (%) 0 0 52.32 34.2 3.813. Collection rate SOEs (%) 29,6 37,1 32,6 32.4 14.9 23.0 26.714. Collection rate exports with arrears (%) 68 61,6 71,4 93 354,315. Billed energy (GWh) 5,742 5,697 6,131 5,837 6,323 6,697 6,80516. Total number of client 433,947 422,254 417,965 428,297 426,232 440,777 483,71917. Number of client – residential 388,485 393,897 392,172 401,284 440,75018. Number of employees SNEL 5,742 5,697 6,131 5,837 6,323 6,697 6,80519. Ratio clients/employees SNEL 70.65 68.42 66.82 69.38 59.87 61.36 66.8920. Average tariff ($/kWh) 0.030 0.031 0.039 0.048 0.045 0.046 0.04621. Average residential tariff ($/kWh) 0.0095 0.0095 0.009522. Collected revenues per kWh generated ($/kWh) 0.010 0.013 0.018 0.023 0.024 0.029 0.03423. Collected revenues per kWh billed ($/kWh)) 0.013 0.017 0.022 0.028 0.029 0.032 0.03524. Total sales ($ millions) 174,850 180,408 240,594 280,773 287,239 310,632 310,59125. Total collection ($ millions) 76,577 97,912 138,755 168,770 185,932 215,692 243,66826. Personnel costs (US$ millions) 45.635 49.701 49.965 51.506 67.168 73.66127. Actual expenditure on generation maintenance ($ millions) 4.1 4.5 3.7 3.9 1.528. Actual expenditure T&D ($ millions) 5.6 7.9 4.1 2.05 3.0229. Number of metered customers (%) - - - (2) - (2) - (2) - (2)

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Table 20: Progress and targets - SNEL performance improvementGovernance Area

Action 2012 2013 2014 2015

Corporate governance and financial viability

Electricity Law Law expected to be adopted once the new Government and Assembly return to session

SNEL conversion to commercial status

SNEL transformed into limited liability company as of 1 January 2011Appointment of independent Board concluded in 2011

Internal management system

Design of management systems Selection of Experts March 2012

Implementation of management systems Auditable Accounting system

New management systems in place

Advisors to ADG on key management aspects (commercial, finance/accounting, purchases)

In place since 2011,and until TA services agreement is recruited.

Clean financial Audits

Clean opening balance sheet and inventory of assets

Auditable balance sheet (by 2014)

Settlement and rescheduling of Government and SOEs debts

Negotiations and rescheduling schedule

Conclusion of negotiations and rescheduling schedule

Payment of rescheduled debts First payment Last payment

Design of procedures for bill collection from Government and SOEs

Proposal of detailed mechanisms for reconciliation and collection of fresh electricity bills under discussion

Mechanisms operational

Continued implementation and monitoring

Collection procedures in place Continued monitoring of implementation

Disclosure of performance indicators

SNEL to disclose operational information to the public on its website (Recurrent covenant of the SAPMP AF2)

Ongoing implementation

Data available on a regular basis

Cost reflective tariff

Tariff decree with phased adjustment schedule (in 4 stages) already adopted in 2009

Third adjustment Fourth adjustment

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Management efficiency and transparency

Performance contract

Performance contract already signed in February 2012

TA services three-year agreement TA servicescompany recruited

TA Services activities implemented

Independent audit of Performance Contract (recurrent covenant for the SAPMP AF2)

Audit recruited Audit performed

Billing and collection plan

Part of the action plan to improve SNEL performance in the medium term (see above)

Implementation

Staff redeployment Based on completed studies on SNEL human resource training and redeployment strategy and action plan

Formal adoption of staff training and redeployment strategy and action plan by SNEL board

Implementation

Restructuring Phase 1

Financially sustainable management of Inga

Increased managerial and organizational autonomy for Inga’s operation, together withsystematic measuring of performance for accountability

Fully separate management system (procedures, budgeting, management indicators) is established

Clarification of Inga’s asset legal ownership Condition for establishing opening balance sheet

Adequate and ring-fenced funding for Inga’s O&M

Dedicated maintenance account opened

Transfer of fund as per agreed annual O&M budget (recurrent covenants SAPMP AF2)Audit of the appropriate use of funds

Evaluation of technically sound O&M needs Study of maintenance requirements by external consultant (consultant recruitedin March 2012)

Adoption of annual maintenance budget

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 Energy Efficiency plan still to be done

Preparation Finalization and approval -Implementation

Implementation

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Annex 7: Economic and Financial Project Re-evaluation


Project Economic Re-evaluation

1. During the appraisal of AF1, it was firmly established that the project is economic viable and the least-cost means for DRC of serving the two principal power markets – the customers in the Katanga Province, including mining and associated industrial complexes, and the export market in the Southern Africa Power Pool (SAPP). The project’s economics was robust, with an economic internal rate of return (EIRR) estimated at 31%, and sensitivity analyses confirming the robustness of the profitability/economic returns on the project.

2. An economic re-evaluation of the Project is required to assess the impact of cost overruns on the economic justification of the Project. This re-evaluation also needs to take into account change in assumptions for other significant parameters, including the revision of the project implementation schedule, higher cost estimates for injected energy in the transmission system, and a revised (more conservative) scenario for incremental energy transferred on the transmission lines.

3. Methodology and main assumptions. The economic rate of return on the investment in the Project is re-evaluated following the same approach used under the AF1, but reflecting the regional analysis presented in Annex 5 and revised assumptions as stated below.

4. Project Costs. Revised Project costs include:

Capital cost of the Project – estimated at US$ 659 million. Overall project costs reflect the revised cost estimates for the full rehabilitation and reinforcement of the HVDC and HVAC systems from Inga to the border with Zambia, including the associated telecommunication system, the institutional aspect for implementation, the engineering and procurement services, as well the environmental and social mitigation measures to be implemented as part of the Project. For the purpose of the analysis, the funds already disbursed to date have been considered as part of the project costs and not discounted over time.

Annual Fixed Operation and Maintenance Cost: O&M costs are assumed at about 2% of the overall investment costs (above standard industry practice for large transmission systems given a more challenging operating environment in DRC) and amount to US$ 12 million per year on average.

Energy cost into the transmission system: As mentioned in the regional analysis, the rehabilitation of Inga 1&2 as well as the development of Inga 3 have been identified as key components of the least-cost power development program articulated by the SAPP Plan. For this reason, for the purpose of AF 1 economic analysis, the cost of energy into the transmission system was based on the cost of Inga 3 as a proxy for the marginal cost of generation in DRC. At that time, the long run incremental marginal cost of generation from

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Inga 3 was estimated at US$0.02/kWh. Inga 3 is indeed the next in-line candidate project in the least-cost generation expansion program of DRC, which is entirely hydro-based. Inga 3 is expected to be the main source of electricity supply to meet the incremental demand and its development should start by no later than 2016 for first units installed and operational in by 2021, and full completion to about 4,000 MW realized by 2025. However, before Inga 3 comes online, the output of the rehabilitated Inga 1 and 2 would constitute the main source of additional generation in DRC. For this reason, the economic reevaluation values the energy injected in the transmission line on the basis of the cost of Inga 2 rehabilitation until 2020, and on the basis of Inga 3 afterwards.

Inga 2. The estimated cost of incremental energy from Inga 2 is based on the value of signed contracts for the rehabilitation of two turbines, and of the total expected cost of the reprofiling of Inga 2 intake canal.

Inga 2 rehabilitation – assumptions Unit ValueCapital costs

Investment costs rehabilitation MUSD

130contingencies on rehabilitation % 10%

Intake Canal reprofiling MUSD

70contingencies on reprofiling % 40%Other technical and economic parameters

Construction time years

4Annual O&M (% of initial investment) % 2.0%Provision for renewal (% of initial investment) % 3.0%Economic real discount rate % 10.0%

Total Rehabilitated generation capacity MW

300load factor after rehabilitation MW 70%Inga 2 rehabilitation – Results Unit Value

Overnight capital costs incl. contingencies MUSD

241

Interests during construction MUSD

52

Net annual generation GWh

1,840

Levelized cost per kWH – Inga 2 US$c/kWh 2.39

Inga 3. The incremental energy costs from Inga 3 have been derived from a recent pre-feasibility study of Inga 3 (in a design that would allow a phased development of Grand Inga). It is assumed that total project costs would be US$ 9,016 million, based overnightinvestments costs of US$ 6,400 million in the feasibility study. The difference between the two estimates corresponds to contingencies and interests during construction.

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Inga 3 - assumptions Unit ValueCapital costs

Investment costs MUSD

6,400 Contingencies % 10%Other technical and economic parametersConstruction time years 5Annual O&M (% of initial investment) % 2.0%Economic real discount rate % 10.0%

Total additional generation capacity MW

3,968 Average net load factor MW 81%Inga 3 – Results Unit Value

Overnight capital costs incl. contingencies MUSD

7,040

Interests during construction MUSD

1,976

Net annual generation GWh 28,136 Levelized cost per kWH – Inga 3 US$c/kWh 3.85

5. Transmission losses: The level of transmission losses has been reassessed at 9.0% (against an assumption of 6.0% in AF1) based on the most recent available statistics on the operation of the line by SNEL (2011 and first quarter of 2012) and hold constant over time. This represents a conservative estimate, considering that rehabilitation of the line may reduce losses over time.

6. Benefits: The main Project benefits comprise the economic values associated with the incremental energy transfers from the western to the southern system and exports, namely to the Katanga Province and to the SAPP, and cost savings associated with the use of less costly DRC electricity generation assets compared to SAPP.

7. Three main scenarios of electricity demand and supply balances and underlying assumptions, were prepared with SNEL during the preparation of the PMEDE Additional Financing approved in June 2011, 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 (see Annex 6 of the PMEDE Additional Financing Project Paper). Those balances remain overall valid and strongly highlight the fact that until additional generation becomes available (e.g., Inga 3 is commissioned) the demand/supply balance will remain tight and would require a series of actions on the three fronts identified during the processing of the PMEDE AF to ensure that the rehabilitated SAPMP transmission line is fully utilized (namely, enhancing energy efficiency and demand-side management, managing carefully the additional capacity delivered by SNEL to the mining sector and ensuring timely financing and completion of projects to increase generation capacity).

8. As clearly shown as part of the regional analysis in Annex 5, in the long run, DRC is poised to become a primary energy exporter to SAPP. Given the fast growing demand in the region, the SAPP market can absorb as much electricity as DRC will be able to export once new

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power generation and transmission capacity comes on stream. In particular, in order to be able to reap the full economic benefits of Inga 3, the power transfer capability of the existing transmission system would need to be augmented from 500 to 1,000 MW by end-2021 to complement the transmission development associated with Inga 3. The additional cost of this upgrading of the line is estimated at about US$200 million. Neither the additional benefits arising from such expansion nor its costs have been considered in the economic analysis of the Project. It is however clear that doubling the capacity of the line at a cost equivalent to about 1/3rd of the first rehabilitation would significantly improve the overall economic return of the Project.

9. However, for the purpose of this analysis, a more conservative approach to exports is advisable so as to ensure that domestic demand is adequately accommodated until new generation and transmission capacity becomes available. This analysis therefore assumes a more conservative scenario as presented in the table below.

Table 21 –Net Energy Transfers to Katanga Province and into SAPP 2014- 2040 (Capacity and Energy)

10. The analysis, in its base case, assumes a 80.5% utilization of the line capacity of 560 MW (domestic mining demand is envisaged to use any additional capacity in addition to exports). Also, benefits will only materialize once the line is completed in 2015. It is then assumed that the full energy flow on the line would be incremental, since it is likely that without the project the line may stop operating altogether by then due to lack of maintenance and rehabilitation investments.

11. In order to meet the export and mining demand and fully utilize the transmission line capacity, trade-offs may materialize with regards to demand in Kinshasa, which is likely to remain suppressed. Similarly to PMEDE AF and SAPMP AF1 assumptions, this suppressed demand is eliminated when Inga 3 comes into service. This is also consistent with the time that will be required to rehabilitate and expand the distribution system in Kinshasa in order to remove the supply constraint and enable normal demand growth in Kinshasa. In addition, a slower growth in demand in the Katanga Province, including, especially the mining sector, is projected taking account of actual and expected situation in the mining sector, and expectations of the immediate future evolution of the international metal markets.

12. Valuation of benefits: As in the SAPMP AF1, the Willingness –to –Pay (WTP) is used as the basis of determining the value of a unit of electricity consumed in the mining sector and

Base ScenarioCapacity [MW] 2014 2015 2016 2017 2018 2019 2020 2025 2030 2035 2040TL CAPACITY TO SOUTHERN SYSTEM 500 500 500 500 500 500 500 500 500 500 500Going to Kinshasa 0 0 0 0 0 0 0 0 0 0 0Transfers into Katanga ProvinceTransfers into SAPP 0 300 300 300 300 300 300 300 300 300 300Transfers into SAPP and Katanga Total 0 300 300 300 300 300 300 500 300 300 300Annual transfers [GWh]Injected in HVDC line 3942 3942 3942 3942 3942 3942 3942 3942 3942 3942Technical losses 0 237 237 237 237 237 237 237 237 237 237Transfers into Katanga Province 0 1077 1077 1077 1077 1077 1077 1077 1077 1077 1077Transfers into SAPP 0 2628 2628 2628 2628 2628 2628 2628 2628 2628 2628Transfers into SAPP and Katanga Total 0 3705 3705 3705 3705 3705 3705 3705 3705 3705 3705

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exported from DRC into SAPP. This WTP is derived from the estimate for the Long Run Average Incremental Cost (LRAIC) in SAPP. The opportunity cost of generating electricity in the SAPP is based on the cost of the alternative source of supply in-lieu of imports from DRC. This is estimated as the average incremental cost (AIC) of supply derived from the long-term least-cost generation expansion program of SAPP. The expansion program comprises a mix of hydro, coal, nuclear plants for base load and mid-range duty, and pump-storage, oil and gas plants for peaking duty. The estimate for LRAIC used in AF1 (8.7 US$c/kWh gross, and 7.0 US$c/kWh netback value after transmission costs related to exports) has been conserved.

13. Contrary to AF1, for the energy which would remain in Katanga, the economic re-evaluation uses the gross LRAIC instead of the netback value. From a logical standpoint, applying exports transmission costs to energy flows that would remain in DRC is not justified.

14. Assessment of the economic benefits from the telecom component: The primary technical justification of the telecom component of the project is to allow more efficient operation of SNEL’s transmission network. SNEL will also be able to resale excess broadband capacity (about 80%) of the total to telecom operators. This excess telecommunication capacity will be made available for all the various forms of communication and information for private and public business, and household applications. It will provide the first broad-band telecommunication back-bone infrastructure for DRC, and is expected to reduce the cost of telecommunication services by about two-thirds.

15. The estimate of the benefits prepared for the period 2014-2025 is based on available data regarding the size of the DRC telecom market, its growth in volumes, as well as price trends. Only the international traffic resulting from connecting Kinshasa and other cities to southern Africa is considered in the analysis (no consideration of the domestic traffic). While the volume of traffic is expected to increase significantly over the period considered (above +25% per year) starting from a very low base, unit prices are expected to fall constantly (15.5% per year) resulting in sustained but moderate increase in the annual revenue accruing to SNEL, from US$ 1.5 million in 2014 to 3.6 million in 2025. On this basis, the net present value of the revenues to be perceived from 2014 to 2025 would be US$ 11.0 million.

16. From a methodological point of view, this constitutes a very conservative estimate of (i) growth in traffic for broadband Services in DRC, (ii) market share of SNEL and (iii) excess capacity share. In addition, it does not consider any benefits which would accrue to end-users as consumer surplus and which are likely to be considerable given the absence of comparable alternative telecom infrastructure in DRC. The 2010 Africa Infrastructure Country Diagnostic (AICD) study estimates that improvements in information and communication technologies (ICT) linked to sector reforms have added as much as 1 percentage point to Africa’s per capita growth rate, accounting for over half of Africa’s improved growth performance and more than any other sector. At the microeconomic level, ICT provides farmers, workers and entrepreneurs opportunities to reduce transaction costs (increase revenues of local population), increase market coverage and improve competitiveness.

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17. Results. On this basis, the revised EIRR for the project is 17.5% and the NPV US$ 324 million.

18. Sensitivity Analyses. The robustness of the economic justification has been assessed by adopting more pessimistic assumptions for the major economic and technical parameters. This includes: increased project costs (5%), reduction in transmitted volumes of energy (to 400 MW on average equivalent 71% of the line technical transfer capacity of 560 MW), increase in 20% in the cost of energy injected in the line.

Table 22: Economic analysis – Revision in assumptions and results

2009analysis

2012 base scenario

2012pessimistic

scenarioAssumptionsTotal Project costs MUSD 394.0 659.0 692.0

Annual O&M costsMUSD

%12

3%13

1.9%13

1.8%Annual Energy injected GWh 5,880 3,942 3,504 Losses % 6% 9% 9%Net annual energy transferred GWh 5,521 3,587 3,189 Unit cost of energy injected (until 2020) US$c/kWh 2.0 2.4 2.9Unit cost of energy injected (after 2020) US$c/kWh 2.0 3.8 4.6Unit value of energy transferred US$c/kWh 7.0 7.5 7.3ResultsEconomic Rate of Return % 31.0% 17.5% 9.2%Net Present Value MUSD 817 324 (30)

Additional Telecom benefits 2014 2016 2020 2022 2025Total Traffic forecast Mb/s/month 173.5 295 701.5 1076 2024SAPMP Traffic Mb/s/month 74 125.5 298.5 457.5 860Price trends USD/ Mb/s /month 1750 1312.5 738.5 554 356Total extra annual revenue MUSD 1.48 1.91 2.56 2.95 3.67

Project Economic Costs and Benefits (US$Million)2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2030 2040

Costsa. Investments Transmission 112.0 151.6 131.8 131.8 131.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.01. Project costs (in Mns USD) Mns USD MUSD 112.0 151.6 131.8 131.8 131.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02. Op. and Maintenance (in Mns USD) Mns USD MUSD 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0Energy injected on TL (GWh) 0 0 0 0 3942 3942 3942 3942 3942 3942 3942 3942 39423. Energy cost into the transmission system in (Mns USD) 0.023912932 0.0384513 0.0 0.0 0.0 0.0 94.3 94.3 94.3 94.3 94.3 94.3 151.6 151.6 151.6Total Incremental Costs (Mns) Mns USD 112.0 151.6 131.8 131.8 239.1 107.3 107.3 107.3 107.3 107.3 164.6 164.6 164.6

HVDC transmission losses (GWh) 355 355 355 355 355 355 355 355 355 Injected in SAPMP and Katanga Province (net of transm. losses) (GWh) 3587 3587 3587 3587 3587 3587 3587 3587 3587of which Exports (GWh) 2628 2628 2628 2628 2628 2628 2628 2628 2628of which Katanga sales (GWh) 959 959 959 959 959 959 959 959 959

a. Total Revenues Katanga Province 0.0869 MUSD 83 83 83 83 83 83 83 83 83b. Total Revenues exports SAPP 0.07 MUSD 184 184 184 184 184 184 184 184 184Total Revenues Mns USD 267 267 267 267 267 267 267 267 267Total Incremental Revenues (in Mns USD) 267.3 267.3 267.3 267.3 267.3 267.3 267.3 267.3 267.3

Net Benefits/costs (Mns USD) -112.0 -151.6 -131.8 -131.8 28.3 160.1 160.1 160.1 160.1 160.1 102.7 102.7 102.7

NPV electricity (US$ million) 315.3 EIRR elec 17.3%Telecom net additional benefits 1.5 1.7 1.9 2.1 2.2 2.4 2.6 2.7 0.0 0.0Net Benefits/costs with telco (Mns USD) -112.0 -151.6 -131.8 -130.3 30.0 162.0 162.1 162.3 162.4 162.6 105.5 102.7 102.7

NPV telco (US$ million) 11.0

NPV electricity + telco (US$ million) 323.6 EIRR elec+telco 17.5%

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19. As indicated in the above table, in this modified “pessimistic “scenario, the project EIRR would be 9.2% and therefore the Net present Value of the project assessed with a discount rate of 10% would be slightly negative.. Even in this pessimistic scenario however, the project NPV would remain largely positive if the benefits from carbon reduction emission by substitution in the SAPP of thermal generation by hydroelectricity are considered.

20. Switching values: The project NPV would become negative in case the modeling parameters reach the following values:

The average transfers on the line would fall below an average of 326 MW (58.3% of the 560 MW transit capacity);

The cost of energy injected into the system increases by 42% compared to the base case (this would appear unlikely, especially for Inga 2 for which the estimate is based on signed rehabilitation contracts plus contingencies); and

Total project costs increase by more than 65% above the baseline (corresponding to US$1,087 million). This would appear extremely unlikely now, given that project costs estimates are derived from received bids and conservative contingencies have been included in revised project costs.

21. Other Benefits. Similarly to SAPMP AF1, other benefits of the Project not considered in the above analysis include:

Provision of social infrastructure to the communities along the transmission line corridor under the Project, comprising water supply and sanitation systems, construction of schools and clinics and the implementation of HIV/Aids awareness campaign will bring added improvement in the quality of life of the communities, and generate more economic activity in the communities;

The catalytic effect of the Project in attracting private investments into the rehabilitation of Inga 1&2, as well as of Inga 3 because of the access it will provide to the power markets in the Katanga Province and in the SAPP.

22. Additional economic benefits of the Project may be achieved by upgrading the power transfer capability of the existing transmission system to 1,000 MW at an additional cost of about US$200 million25 by 2020 to complement the transmission development associated with Inga 3. Although those investments are outside the scope of the project, if realized, they will s increase the economic viability of the SAPMP, producing a EIRR of about 20.9% and corresponding to a NPV of US$ 6761 million. The same share of exports and domestic consumption has been assumed in this positive scenario and the results are reported in the tables below.

25 The proposed additional financing will support SNEL by financing the services of an international consulting firm to assess the needs to increase the transit capacity of the transmission system from Inga through Kolwezi to Kasumbalesa and associated detailed costs. See Annex 4 for details.

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Project Financial Analysis

23. Assumptions. The financial analysis shares key technical and project costs assumptions with the economic analysis (without the activities in Zambia). However, only the project financial benefits accruing directly to SNEL are considered, and the project benefits are assumed to be immune from corporate tax.

24. Evaluation of benefits - Destination of incremental sales - The value of additional sales due to the project are evaluated through the SNEL present and projected revenues collected, based on average tariff after deduction of the T&D and generation costs as appropriate. It is estimated that additional energy sales would go towards exports (60%), HV in Katanga (20%), MV in Katanga (15%) and LV (5%).

25. Evaluation of benefits – incremental revenue under current conditions with current tariffs and collection rates, the average incremental revenue collected per kWh would be 3.8 US$c (corresponding to a price of 4.4 US$c/kWH and 88% collection).

Table 23: Additional revenue - Current prices and collection ratesprice share of incr. collection collection

US$c/kWh generation rate US$c/kWh LV 2.7 5.0% 50.0% 1.4 MV 8.4 15.0% 70.0% 5.9 HV 4.7 20.0% 75.0% 3.5 Exports 3.5 60.0% 100.0% 3.5 Weighted average 4.4 88.0% 3.8

26. Results. Under this condition The Project Financial Internal Rate of Return (FIRR) would be negative. The switching value for a FIRR above 0% is around 4.7 US$c/kWh (revenue

Project Economic Costs and Benefits Doubling of line capacity from 2020 (US$Million)2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2030 2040

Costsa. Investments Transmission 112.0 151.6 131.8 131.8 131.8 0.0 60.8 60.8 81.0 0.0 0.0 0.0 0.01. Project costs (in Mns USD) Mns USD MUSD 112.0 151.6 131.8 131.8 131.8 0.0 60.8 60.8 81.0 0.0 0.0 0.0 0.02. Op. and Maintenance (in Mns USD) Mns USD MUSD 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0Energy injected on TL (GWh) 0 0 0 0 3942 3942 3942 3942 3942 7884 7884 7884 78843. Energy cost into the transmission system in (Mns USD) 0.023912932 0.0384513 0.0 0.0 0.0 0.0 94.3 94.3 94.3 94.3 94.3 188.5 303.1 303.1 303.1Total Incremental Costs (Mns) Mns USD 112.0 151.6 131.8 131.8 239.1 107.3 168.0 168.0 188.3 201.5 316.1 316.1 316.1

HVDC transmission losses (GWh) 355 355 355 355 355 710 710 710 710 Injected in SAPMP and Katanga Province (net of transm. losses) (GWh) 3587 3587 3587 3587 3587 7174 7174 7174 7174of which Exports (GWh) 2628 2628 2628 2628 2628 5256 5256 5256 5256of which Katanga sales (GWh) 959 959 959 959 959 1918 1918 1918 1918

a. Total Revenues Katanga Province 0.0869 MUSD 83 83 83 83 83 167 167 167 167b. Total Revenues exports SAPP 0.07 MUSD 184 184 184 184 184 368 368 368 368Total Revenues Mns USD 267 267 267 267 267 535 535 535 535Total Incremental Revenues (in Mns USD) 267.3 267.3 267.3 267.3 267.3 534.6 534.6 534.6 534.6

Net Benefits/costs (Mns USD) -112.0 -151.6 -131.8 -131.8 28.3 160.1 99.3 99.3 79.1 333.1 218.5 218.5 218.5

NPV electricity (US$ million) 668.1 EIRR elec 20.7%Telecom net additional benefits 1.5 1.7 1.9 2.1 2.2 2.4 2.6 2.7 0.0 0.0Net Benefits/costs with telco (Mns USD) -112.0 -151.6 -131.8 -130.3 30.0 162.0 101.4 101.5 81.4 335.7 221.2 218.5 218.5

NPV telco (US$ million) 11.0

NPV electricity + telco (US$ million) 676.3 EIRR elec+telco 20.9%

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collected). The minimum which should be expected is for SNEL to achieve a FIRR equivalent to the project financing costs, i.e. the 5.0 percent on-lending rate to SNEL on the IDA Grant. This would imply achieving a revenue collected of 5.0 US$c/kWh.

27. Financial break-even would be achievable with adequate commitment – A break-even scenario has been identified, corresponding to a weighted incremental revenue collected of 5.0 US$c/kWh. This scenario involves only modest price and tariff adjustments and an enforcement of payment discipline for HV and MV domestic sales. No change is assumed for LV sales, which is pessimistic, but stems from a recognition that improvement in commercial performance for residential users will be more difficult to achieve and require more time and investments. In fact, the break-even scenario represents objectives which should be achievable within a relatively short term time frame (3 to 4 years), and only requires following up on a phased tariff adjustment process which is already ongoing. On a longer timeframe, the logic would be to progressively align exports prices and HV/MV tariffs with long run development costs, since increasing electricity supply beyond Inga 1 and 2 rehabilitations will require the construction of new power plants and transmission lines.

Table 24: Tariffs and collection - breakeven scenarioprice share of incr. collection collection

US$c/kWh generation rate US$c/kWh LV 2.7 5.0% 50.0% 1.4 MV 8.4 15.0% 95.0% 8.0 HV 5.5 20.0% 95.0% 5.2 Exports 4.5 60.0% 100.0% 4.5 Weighted average 5.2 95.8% 5.0

28. These results could not be compared with the SAPMP AF 1 since no project financial analysis was carried out during the appraisal of the first additional financing. This is likely linked with the fact that the main benefits for the SAPMP project come from its regional nature and overall economic benefits and not from its financial profitability to SNEL (despite the project should be financially sustainable).

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Annex 8: Financial Analysis of SNEL


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 for regulatory and taxation purposes, but at this point, 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 GoDRC). 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. This has been followed by legal, and accounting due diligences to produce a reliable opening balance for the transformed SNEL, some of which are still ongoing (asset valuation, asset ownership, debt and receivables restructuring, exhaustivity of passives). In parallel, as part of the PMEDE project, the Bank is supporting activities and hands-on technical assistance that

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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. SNEL emerged from several years of armed conflicts in DRC with extremely degraded infrastructure which had not received even the most basic maintenance. Barely half of the installed generation capacity is currently in operation. This functioning capacity is not operating reliably, and will need to be taken out of service for heavy maintenance/rehabilitation when additional generation comes on line. Also as a result of the conflict, payment discipline for electricity tariffs largely broke down, while electricity tariffs for domestic users shrunk in real terms alongside the depreciation of the Congolese Franc. As a result of the above, SNEL’s volume of generation is greatly reduced and this energy is sold at low average tariffs, with poor collection rates. This in turn constrains SNEL’s ability to finance maintenance, asset renewals and other investments.

5. Despite this challenging context, from 2006 to 2011, the annual revenue collected by SNEL has increased year after year and gone from 115 to 251 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 3.8 US cents per kWh sold, thanks to improved collection rates combined with a limited increase in the average price per kWh. SNEL is now in a position to finance its operating costs and basic maintenance with itsown resources, but its free cash-flow remains insufficient in comparison with the major investments needed to rehabilitate existing infrastructure.

6. Average electricity tariffs in DRC remain very far from the long run average incremental costs (LRAIC). The process of phased tariff adjustment needs to be pursued in order for the power sector to generate sufficient resources to increase supply and expand coverage to a larger share of the population, from its low existing base. In spite of the adjustments since 2009, domestic electricity tariffs remain significantly distorted in favor of the minority of residential users with access to electricity. Progress has also taken place with regard to collection rates, but the potential for further improvement remains large. While restoring payment discipline for residential users will require significant investments in metering and billing and be a lengthy process, much quicker gains would be possible with parastatals.

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Table 25: SNEL – Summary Cash flow statement and performance indicators

SNEL – Cash Flow Statement 2008 2009 2010 2011 Total Generation GWh 7,246 7,641 7,850 7,856 Energy sold GWh 5,823 6,323 6,597 6,599

Revenue collected MUSD 161.4 187.2 216.5 251.4

Personnel MUSD -54.3 -54.2 -66.9 -70.3

Other operating costs MUSD -73.0 -73.2 -83.4 -91.8

Taxes MUSD -10.6 -17.8 -20.2 -23.4

Current Operating expenses MUSD 138.0 145.1 170.5 185.5

Cash flow from current operations 23.4 42.1 46.0 65.9

as a % of revenue 15% 22% 21% 26%

Investments from internal funds MUSD -19.6 -28.3 -24.9 -35.0

Investments from external funds MUSD 112.8 127.2 -79.6 235.2

Total Investments MUSD 132.4 155.5 104.5 270.2

Debt service MUSD -5.1 -10.6 -25.8 -27.6

Debt drawdown MUSD 112.8 127.2 79.6 235.2

Total – financing activities MUSD 107.7 116.6 53.8 207.6

Change in cash balance MUSD -1.2 3.3 -4.6 3.3

Closing Cash Balance MUSD 6.5 9.8 5.2 8.5

Transmission and distribut. Losses % 19.6% 17.2% 16.0% 16.0%

Revenue collected per kWh sold US$c/kWh 0.028 0.030 0.033 0.038

Self-financing ratio % 14% 20% 19% 14%

Financial Forecast (2012-2019)

Assumptions

7. 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.

8. 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. From its current level of 3.8, it would reach 5.0 US cents per kWh in 2016, and 6.0 US cents per kWh in 2019.

9. Available data on SNEL balance sheet remains unreliable. 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, the forecast assumes no repayment of arrears to SNEL by other SOEs. It does not take into account potential liabilities for SNEL related to the debt held by foreign investment funds. Otherwise, SNEL would assume the debt service for recent investments financed by mining companies as well as for ongoing donor-financed projects. The onlending terms for donor-financed investment would be the following: 5 percent

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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.

Results and discussion

10. 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 and of 2018. 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 before the end of the decade appears achievable.

Table 26: SNEL – Summary Cash flow forecast

SNEL – Cash Flow Statement 2012 2013 2014 2015 2016 2017 2018 2019 Total Generation GWh

9,490 9,949 9,902 12,02

2 13,41

4 11,55

2 11,99

3 15,45

6 Energy sold GWh

7,981 8,387 8,367 10,17

1 11,34

8 9,773 10,14

6 13,07

6

Revenue collected MUSD 328.4 372.7 394.2 507.9 595.0 538.0 586.5 786.1

Personnel MUSD -77.3 -82.7 -86.8 -91.2 -95.7 -100.5 -105.6 -110.8

Other operating costs MUSD -109.0 -118.9 -123.7 -147.1 -164.5 -153.5 -163.1 -200.5

Taxes MUSD -30.0 -33.3 -34.5 -43.6 -50.1 -44.4 -47.4 -62.2

Current Operating expenses MUSD -216.3 -234.9 -245.1 -281.9 -310.3 -298.4 -316.0 -373.6

Cash flow from current operations 112.2 137.9 149.1 226.0 284.7 239.6 270.5 412.5

as a % of revenue 34% 37% 38% 44% 48% 45% 46% 52%

Investments from internal funds MUSD -38.5 -42.4 -46.6 -53.6 -61.6 -70.8 -81.5 -93.7

Investments from external funds MUSD -403.1 -332.8 -281.3 -194.2 -172.0 -135.0 -135.0 -135.0

Total Investments MUSD -441.6 -375.1 -327.9 -247.8 -233.6 -205.8 -216.5 -228.7

Debt service MUSD -60.2 -83.2 -104.6 -120.4 -138.8 -163.6 -201.8 -231.5

Debt drawdown MUSD 403.1 332.8 281.3 194.2 172.0 135.0 135.0 135.0

Total – financing activities MUSD 342.9 249.6 176.7 73.8 33.2 -28.6 -66.8 -96.5

Change in cash balance MUSD 13.5 12.3 -2.1 52.0 84.2 5.2 -12.8 87.3

Closing Cash Balance MUSD 22.0 34.3 32.2 84.2 168.5 173.6 160.8 248.1

Transmission and distribut. Losses % 15.9% 15.7% 15.5% 15.4% 15.4% 15.4% 15.4% 15.4%

Revenue collected per kWh sold US$c/kW

h 0.041 0.044 0.047 0.050 0.052 0.055 0.058 0.060

Self-financing ratio % 12% 15% 14% 43% 62% 37% 32% 79%

DSCR 1.9 1.7 1.4 1.9 2.1 1.5 1.3 1.8

11. Continued financial fragility. However, the forecast also illustrates that SNEL financial position would remain fragile. For instance, the reduction in generation expected in 2014 and 2018 (resulting from the rehabilitation of turbines 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

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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.

12. 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).

13. 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. The procedures and internal controls for managing the additional revenue remain inadequate. These issues are being addressed as part of the PMEDE Project through the implementation of the corporate governance plan and targeted technical assistance

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Annex 9: Implementation Support Plan


1. Similarly to PMEDE, a detailed Implementation Support Plan has been designed to ensure timely and effective implementation of the Project. With few different factors, the team will follow the same principles and carry out implementation support actions jointly with PMEDE. The aim of the plan is to align the implementation support required to the Project’s expected risks and results. The Plan will be updated every six months, in line with the progress made by the Project.

2. To reinforce the Bank’s Implementation Support for the program, the supervision arrangements/strategy on the Bank’s side currently includes dual TTL-ship in Washington, with the support of two senior level staff (based in Dakar and Kinshasa), a strong team of experts (including a senior hydro specialist and a senior financial analyst). A new field based energy specialist should be recruited as soon as possible. The project and all other related energy operations in DRC and regionally associated also benefit from very close managerial oversight at level of Sector Manager and Sustainable Development department Senior Manager as well as strong support by the Country Director.

3. Deficiencies were also noted in the owner’s engineer performances, including insufficient presence and decision-making process in the field, causing delays in procurement and implementation. SNEL and its owner’s engineer have agreed to resolve those performance issues identifying key actions to be taken over the next three months. Those actions include: (i) recruitment of a general project engineer coordinator to be based in Kinshasa (with proper seniority to be able to improve the decision-making process); (ii) increased field presence at the Inga site and other project sites in the context of the SAPMP and PMEDE; (iii) strengthened mechanisms for coordination and collaboration. At the end of this period, SNEL will carry out a performance audit of the owner’s engineer performances and conclude whether the actions were satisfactorily implemented.

4. The Plan was followed for PMEDE and two implementation support missions were carried out since the Board Approval of the PMEDE Additional Financing, in addition to the daily supervision by the senior energy staff based in Kinshasa (until February 2012). Given the turmoil in the country, missions were suspended between October 28, 2011 and January 31, 2012, and the Country Office relocated all staff outside DRC starting from December 3, 2011 until January 16, 2012. This limited the amount of implementation support possible during this period. Mid-term review has been carried out in May 2012.

5. Similarly to PMEDE, the Plan includes a presentation of implementation risks, strategies and actions aimed to mitigate those risks (as presented in Table 27), a detailed schedule summarizing the required supervision missions, field visits, and other meetings (Table 28), and the required effort and resource commitment in terms of implementation support to ensure successful implementation of the Project (Table 29).

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6. Due to the complex governance challenges and risks the Project implementation is facing, as part of the implementation support plan, a series of project governance issues have been identified to address such challenges in a systematic way and therefore ultimately minimize potential project overruns, increase transparency, prevent corruptive practices, and allow the Project to achieve its overall development objectives.

7. The team has been closely working with the Bank’s Integrity Vice-Presidency (INT),whose staff has been involved in the pre-appraisal mission for the project preparation and provided support to the team. The team will also look into involving “Contract Watch” type organization for the monitoring of project implementation going forward. Some specific area of concern for SAPMP and mitigating measures are included below:

Price and volume variation for smaller works: there are several items with a large variation in price for the same activity and the team was suggested to closely supervise those small items, usually easily superficially reviewed given the small scale.

Fraudulent Claims of Work and Goods provided: To limit the risk of overbilling through reduced or substandard delivery of goods and works, the project should ensure field presence of the supervision consultants. The consultant should be instructed to be in the field periodically based on a combination of risk analysis and random inspections.

Access to site for supervision consultant: The physical, geographical and security characteristics of the construction sites for the HVDC line is the major constraint in monitoring the quality and type of work performed by the contractor. One approach applied by the supervision consultant could be to replicate the visual fly-over monitoring as done during the detailed review of the scope of the project. The supervision consultantand SNEL, as well as the Bank team have the high resolution photographs and close up photographs of each of the tower which allows the team to adequately assess the condition of the towers and lines. All these files are GPS stamped as well uniquely identified. The contractor should be required to submit pre- and post rehabilitation pictures of the lines as well as the insulators. These will be matched against the existing files to assess the improvements. Once these are cleared, the supervision consultant will sign off on the various segments. Finally, the contractor should provide transport and access for the supervision consultant to the worksite from publicly accessible points. These site visits will take place at the beginning and end of each section as well as random access during the contract implementation.

8. A capacity building program on contract management will be implemented and carried out by the team with the support of INT staff during the supervision mission in the last quarter of 2012 or as soon after effectiveness of Contract 4. The program is schedule to last at least 5 working days and target staff in the PIU/SNEL and owner’s engineer responsible for verification of physical work, invoice processing and disbursement (from October 1st 2012, all those activities should be transferred from BCECO to PIU/SNEL).

9. Before the program, the team will develop with the support of INT a platform to monitor work performed against the bill of quantities (BoQ) included in Contract 4, segment by segment

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(in fact possibly tower by tower for each segment). This is possible due to the high level resolution pictures provided as part of the study on the integrity of the transmission line. Once a change of order request is received by the contractor, PIU/SNEL staff will be able to assess the magnitude and relative unit cost compared with original BoQ before any payment authorization is given. Change of order thresholds will be identified and alerts rose beyond those limits. If that happens, a series of measures will be identified to verify the validity of the claim, which may include: (i) GPS stamped pictures before and after change order; (ii) specific visit to the site by the supervision and project unit; and (iii) monitoring of disposed equipment (the latter will be integrated in the routines activities already performed and monitored in accordance with the Environmental and Social Management Plans under the supervision of the owner's engineer and SNEL, avoiding duplication).

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Table 27: Implementation and Governance Risks, Strategies and Proposed Actions

Implementation Risk Implementation Support Strategy ActionsProject 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.

To reinforce the Bank’s Implementation Support for the program, the supervision arrangements/strategy on the Bank’s side currently includes dual TTL-ship in Washington, with the support of two senior level staff (based in Dakar and Kinshasa), a strong team of experts (including a senior hydro specialist and a senior financial analyst). A new field based energy specialist should be recruited as soon as possible. The project and all other related energy operations in DRC and regionally associated also benefit from very close managerial oversight at level of Sector Manager and Sustainable Development department Senior Manager as well as strong support by the Country Director.

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 (see Table 29 below).

Adhering to mission schedule as outlined in the Implementation Support Plan (see Table 28 below).

Monitoring appropriate capacity of Implementing Agencies.

World Bank Task Team to annually update capacity assessment of implementing agencies.

Monitoring of the Project indicators as included in the Project Result Framework and Monitoring (Annex 1).

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.

Governance SNEL corporate governance plan properly implemented Close monitoring of SNEL Performance Indicators

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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 and FM management.

(jointly with PMEDE) (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 procurement and financial management by BCECO.

Work towards timely transfer of procurement and FM responsibilities from BCECO to SNEL PIU.

Task team to continue close supervision of procurement actions and contract 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 project governance structure and oversightmechanisms.

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 to ensure transfer of fiduciary responsibility to SNEL PIU.

Safeguard

Risk associated with environmental and social potential negative impacts from Project activities.

Close monitoring of safeguards to avoid potential negative impacts associated with the project.

Close supervision of project activities by the Sr. Environmental Specialist and the Sr. Social Specialist, including RAPs and ESMPs implementation.

Financing and Sustainability

Operation and Maintenance plan not properly funded, compromising sustainability of project

Monitoring of contract management. Conservative physical and price contingencies were considered for additional financing project cost estimates and all contracts are signed. However, very closed supervision will be needed to ensure that contractors carry out activities as scheduled and transparently, with the INT support, as outlined in this Annex.

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investments.

SNEL financial condition worsening and inability to ensure service for Project on-lending.

Close dialogue and collaboration with the co-financiers (CEC).

Live contacts with co-financiers will be maintained on common issues of interest.

Increasing resource commitment to ensure sustainability of Project activities.

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 during the processing of SAPMP AF2.

Implementation of the strategy to improve SNEL corporate governance and performance under PMEDE

As mentioned, the task team will closely support the 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. RfP launched for the recruitment of the consultant for the technical assistance service contract was a condition for appraisal of SAPMP AF2, together with the Action Plan of SNEL for the implementation of the recommendations on the three areas (financial, commercial, procurement) being currently supported by consultants financed under PMEDE.

Project Stakeholders

Inadequate or ineffective stakeholder participation and capacity could undermine success or sustainability of project activities.

NGOs and civil society opposition to the project.

Continuous engagement and dialogue with the Government and SNEL to agree on corrective measures and critical decisions needed.

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.

Continuous engagement and dialogue with civil society and communities.

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.

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.

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Transparency and Anti-Corruption Risks

Mitigation Actions and Controls Detection

1) SECTOR LEVEL - POLICY FORMULATION AND IMPLEMENTATION – SECTOR GOVERNANCE

Risks Prevention / Deterrence Transparency and monitoring Alert Lack of organizational/ institutional setup to gather, maintain and update information.

Non-traceability of revenue collection (including exports)

Project financed TA to put in place Integrated management system

SNEL Performance contract signed and RfP launched for the recruitment of the consultant for the technical assistance service contract (completed as condition of appraisal for the SAPMP AF 2) aimed at increasing transparency.

Action Plan of SNEL for the implementation of the recommendations on the three areas (financial, commercial, procurement) being currently supported by consultants financed under PMEDE (also completed as condition for appraisal for the AF2) aimed at increased coordination and transparency.

Periodic public disclosure by SNEL of key technical and financial information (covenant):- energy balance- revenue collection broken down by category of customers

Public disclosure of annual financial statements and annual report.

Regular update of SNEL website for mandatory disclosure as well as information of the public.

Non-compliance with dated covenants related to disclosure of information

Short term choices in allocation of resources (e.g. inadequate maintenance)

Assess maintenance requirement for Inga (Project financed study) and approve annual maintenance budget.

Establish dedicated account for Inga maintenance and transfer funds as per approved annual budget (completed as condition for negotiations of AF2)

SNEL auditors to prepare periodically and communicate to the Bank report on the use of dedicated maintenance account funds.

Findings of irregularities /red flags by the Internal Auditor and the Task Team supervising the Project.

Lack of planning leading to insufficient investments and risk of arbitrariness in the choice of project and developers

Project-financed Electricity Masterplan study.

Assistance to CATE for putting in place adequate framework for

Broad dissemination of Masterplan

Disclosure of contract with private operators (original PMEDE covenants)

Non-compliance with covenant regarding disclosure of contracts

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assessment, selection, negotiation and monitoring of IPPs (ongoing under PMEDE)

2) UTILITY (SNEL) LEVEL See SNEL Governance enhancement plan including measures to address critical areas (financial systems and reporting, internal and external audit, commercial, procurement) as well as corporate governance. Technical assistance contracts.3) PROJECT LEVEL – FINANCIAL MANAGEMENT – PROCUREMENT – IMPLEMENTATION

Risks Prevention / Deterrence Transparency and monitoring Alert Inadequate enabling framework for a project of this size and scope –multiplicity of implementing agencies –Shortcomings in project management

Strengthened staffing and organizational arrangements for the PIU following merger of the PIUs of two projects (PMEDE and SAPMP) under one structure,

Improved coordination and collaboration between implementation actors as per procedures and arrangements in the revised implementation manual

Additional expert support engaged through the project at the level of the Ministry and the implementing agencies particularly SNEL PIU

Delays in Project implementation.

Delays in contract implementation.

Unclear and inefficient procedures and cycle

Insufficient FM oversight

Ongoing revision of project procedure Manual

Effective use of Project Manual

Audit of Project by SNEL internal auditor (SNEL internal audit function to be outsourced to international consultant). Tight Project supervision by Bank team of FM aspects

Deviation from procedures set in Manual

Findings of irregularities /red flags by the Internal Auditor and the Task Team supervising the Project.

Collusion/fraud during contract implementation

Ensure proper supervision and access to site for supervision consultant to ensure proper contract implementation and correct billing.

The contractor will be required to provide evidence for change orders for Contract 4. These will be matched against the existing files to assess the improvements. Only once these are cleared, the supervision consultant will sign off on the various segments.

Findings of irregularities /red flags by the Internal Auditor, supervision engineer and the Task Team supervising the Project.

Lack of experience and capacity in safeguards may reduce monitoring and control ability

Capacity-building activities targeting the environmental social unit within SNEL (UGES)

Dissemination of Environmental Assessments, Mitigation Measures, Social Assessment, and Resettlement Framework and Action Plan.

Satisfactory execution of proposed safeguard mitigation plans as assessed by the World Bank specialists.

162

10. The implementation plan 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 developed under PMEDE. Also, most project specific measures are in fact measures already agreed and already implemented or being implemented to improve key aspects of project performance, such as financial management, procurement or implementation arrangements. In addition to formalizing in one document these measures, this plan adds detection and transparency mechanisms and alert indicators that will guide the supervision of the project governance aspects, including in the case of failure to remedy to issues raised by Bank team with the client, the recourse to INT. The Box below outlines the various level of activities, from preventive and deterrence to monitoring and transparency measures, as well as the decision making process in terms of project governance.

Box 7: Measures and Decision-Making Process for Enhanced Transparency of Project Activities

Preventive and deterrence measures are specific to project cycle and processes addressing areas of identified weaknesses. All measures are presented as mitigation measures and incentives. The deterrence measures will include control mechanisms and sanctions. Sanctions will be applied in the case of proven corruptive practices, and consequently will require actionable proof. To this end, investigative tools, skills and teams are needed to analyze actions that have taken place. Such investigations are not part of Bank’s Task team mandate and are the full responsibility of INT under its own procedures.

The monitoring and transparency measures are aimed at enhancing mitigation and increasing accountability. They will include two phases and corresponding indicators: (i) indicators of potential inefficiencies – “alerts”; (ii) indicators of potential fraud – “red flags”. Research and analytical work regarding indicators of suspicion of corruptive practices has produced a certain number of indicators that have been denominated commonly as “red flags” and that are supposed to alert of possible corruption or fraud. These indicators may only be a potential indication of fraud. They are usually at least evidence of inefficiency, and as such their monitoring is justified for the sake of effective project implementation alone. The Box below outlines the main Fraud Indicators or Red Flags.

Decision- Making Process and Escalation of Issues

The project implementation unit (PIU), will coordinate that all services involved in the project are providing the identified indicators of the Plan, through follow-up of task completion. Together with the SNEL services involved in the project, the PIU will maintain the relevant monitoring indicators. In addition, the SNEL internal auditor (function outsourced to an external international consultant), will as part as its mandate, prepare a periodic report on the basis of indicators kept and monitored and send it to the Energy Minister and the Bank Task Team.

When any indicator reaches an Alert level, the Task Team will seek explanations from the relevant project counterparts, who will present a written response. If the answer is satisfactory to the Task Team – the alert will be lifted. If not, the Task Team will conduct an enhanced supervision.

The scope of the enhanced supervision will be defined by the Task Team according to the Alert indicators and levels detected. The enhanced supervision team will include the fiduciary team (Financial Management and Procurement Specialist) and whatever additional skill mix is warranted according to the Alerts detected.

During the enhanced supervision, the Task Team will endeavor to analyze the issues and look out for the “Red Flags”. If no red flags are detected as a result of the enhanced supervision, the Task Team will update the risk assessment of the project and propose project implementation improvement measures.

163

If Red Flags are found, the team will seek written explanations from the implementing agencies and discuss corrective measures to be taken. If the Red Flags remains, the task team would seek advice from Bank management and subsequently report the matter to INT.

If proof of corruption is found the Bank will officially ask the GoDrC to take the measures that the existing legal framework allow with regard to: (i) the legal proceedings against individuals; and (ii) the black listing of firms.

Reporting

The reporting requirements will include a semi-annual report produced by SNEL Internal Auditor, on the Alert Indicators established outlined below. This procedure will be mainstreamed into the regular cycle of supervision missions. The relevant client counterpart will be asked to provide written explanations by Task Team requests when Alert Indicators require explanations.

11. In order to implement the actions contained in the Implementation Support Plan, close supervision of Project activities is needed. Table 28 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 2012 and first two quarters of 2013. Bi-monthly VC and meeting carried out between the World Bank team in HQ, 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. 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.

12. Bi-monthly meetings by VC will be carried out between the TTL and the Project implementing agencies. 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 18: Timeline – Implementation Support Missions

13. A significant staff effort is envisaged to meet the implementation challenges characterizing this Project. The Team shows the appropriate skills mix and experience,

164

including staff both from the Country Office in Kinshasa and in Headquarters in Washington,required to successfully implement the Plan. Table 29 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$ 250,000.

Table 29: Implementation Support Team

Name Title Unit Staff Weeks (per year)

Travel(US$

Thousand)Eustache Ouayoro

Country Director (Kinshasa) AFCC2 1

Lucio Monari Sector Manager AFTEG 2Jean-Christophe Carret

Sector Leader (Kinshasa) AFTSN 8

Philippe Durand Program Coordinator AFTEG 8 4x8Manuel Berlengiero

Energy Specialist AFTEG 8 4x15

Stephan Garnier Senior Energy Specialist (TTL for SAPMP and PMEDE)

AFTEG 8 4x15

Frederic Louis Sr. Hydropower Specialist AFTEG 4 2x15Jerome Bezzina Sr. Regulatory Economist TWICT 4 2x8Fily Sissoko Lead Financial Management

SpecialistAFTFM 2

Bella Lelouma Diallo

Sr. Financial Management Specialist AFTFM 6

Elvira Morella Energy Specialist AFTEG 4Fabrice Bertholet Sr. Financial Analyst AFTEG 3 2x15Bourama Diaite Senior Procurement Specialist

(Kinshasa)AFTPC 4

Paul Martin Sr. Environmental Specialist AFTEN 4Antoine Lema Sr. Social Specialist (Kinshasa) AFTCS 5Alexandra Bezeredi

Regional Safeguards Advisor AFTOS 1

Louise Mekonda Engulu

Sr. Communication Officer (Kinshasa)

AFRSC 4

Leonce Kazumba Team Assistant (Kinshasa) AFCC2 4Augustine Wright Team Assistant (Washington) AFTEG 4INT Staff 2 1x15Evariste Niyonkuru

Governance Specialist Consultant AFTPR 1 1x15

(Carine Karitini Doganis)

Sr. Public Sector Management Specialist (Kinshasa)

AFTPR 1

Christophe Rockmore

M&E Specialist (Kinshasa) AFTDE 1

165

Annex 10: Project Preparation and Appraisal Team Members


Name Title UnitPhilippe Durand Program Coordinator AFTEGManuel Berlengiero Energy Specialist and TTL AFTEGStephan Garnier Senior Energy Specialist AFTEGFrederic Louis Sr. Hydropower Specialist AFTEGElvira Morella Energy Specialist AFTEGJean-Charles Kra Sr. Financial Management Specialist AFTFMFily Sissoko Lead Financial Management Specialist AFTFMFabrice Bertholet Sr. Financial Analyst AFTEGJerome Bezzina Sr. Regulatory Economist TWICTBourama Diaite Senior Procurement Specialist AFTPCJean-Christophe Carret Sector Leader AFTSNPedro Antmann Senior Energy Specialist SEGENPhilippe Mahele Sr. Procurement Specialist AFTPCPaul Martin Sr. Environmental Specialist AFTENAntoine Lema Sr. Social Specialist AFTCSLouise Mekonda Engulu Sr. Communication Officer AFRSCDaria Goldstein Sr. Counsel LEGAFRaima Naomi Oyeneyin Language Program Assistant AFTEGLeonce Kazumba Team Assistant AFCC2Augustine Wright Program Assistant AFTEG

LUBILANJI

TSHELA

LUKULALEMBA

MOANDA

INGA

KINSHASA

ZONGO

SANGA

GBADO-LITEMOBAYI

TSHOPO

MWEKA

DEMBA

MANI

TSHALA

KANIAMA

KILUBI

KIBU

KARAWA

BELIA

AMBWE

KAMPEN

LUILINGU

NYABIONDORUTSHURU

MOKOTOS

RUZUZI I&IIMUNGOMBE

MANGEMBE

KYIMBI

PIANA-MWANGA

MITWAB

DIKOLONGO

KONI

KASENGA

KISANGAMWADINGUSHA

KALULEN’SEKE

N’ZILO

LUTSHURUKURU

Boma Mbanza-Ngungu

Tshikapa

Mwene-Ditu

Aketi

Boende

Buna

BetambaYumbi

Faradje

Kamina

Kikwit

Feshi

Idiofa Kongolo

Kutu

Likasi

Lubudi

Kilwa

Lodja

Lusambo

Watsa

Kenge

Bulungu

Mangai

Lisala

Lubutu

Lowa

KabaloKabinda

Kapanga

Sandoa

Bafwasende

Banalia

Butembo

Moba

Sakania

Dilolo

Pweto

Basankusu

Bongandanga

Akula

Bikoro

Inongo

Gemena

Imese

Zongo

LibengeBusinga

Bondo

ButaTitule

Bumba

Kolwezi

Kasongo

Uvira

Lulimba

Wanie Rakula

Yangambi

Bunia

Beni

Isiro

WambaMongbwalu

Manono

Kalemie

Ilebo

Ikela

Kalima

Kama

Malela

Matadi

Bukavu

Goma

Kindu

Mbandaka

Kananga

Kisangani

Mbuji-Mayi

Bandundu

Lubumbashi

KINSHASA

S U D -K I V U

N O R DK I V U

MANIEMA

B A N D U N D U

K ATA N G A

E Q U AT E U R

O R I E N TA L E

K A S A IO R I E N TA L

KASAI

OCCIDENTALBAS-CONGO

KINSHASA

CONGO

CAMEROON

GABON

CENTRAL AFR ICAN REPUBL IC

TANZAN IA

UGANDA

S O U T H S U D A N

Z A M B I A

ZAMBIA

A N G O L A

BURUNDI

RWANDA

MAL

AWI

CABINDA (ANGOLA)

Tshuapa

Lomela

Kasai

Kwango

Lualaba

Congo

Luvua

Ulindi

Aruwimi

Kibali

Uele

Ubangi

Oub

angu

i

Lulua

Lualaba

Lopori

Lomami

Lukuga

Congo

Luilaka

Salonga

Sankuru

Lukenie

Kasai Lulua

Lufira

Loma

mi

Lueo

Lualaba

Kwilu

Lulonga

LakeTanganyika

LakeEdward

Lake Kivu

LakeAlbert

LakeMweru

Lake Malawi

A T L A N T I C

O C E A N

Lake

Victoria

To Bangui

To Kembe

To Bangasso

To Juba

To Pakwach

To Kibuye

To Ruhengeri

To Bujumbura

To Kitwe

To Luwingu

To Lucano

To Damba

To Pointe-Noire

5°N

0°

5°S

10°S10°S

30°E25°E

30°E25°E15°E10°E

5°N

0°

5°S

5°E

5°E

10°E 15°E

DEM. REP.OF CONGO

Th is map was produced by the Map Des ign Uni t o f The Wor ld Bank. The boundar ies , co lo rs , denominat ions and any other in format ionshown on th is map do not imply, on the par t o f The Wor ld BankGroup, any judgment on the lega l s ta tus of any te r r i to r y, o r anyendorsement or acceptance of such boundar ies .

0 100 200 300

0 100 200 Miles

400 Kilometers

IBRD 39346

MAY 2012

MAIN CITIES AND TOWNS

PROVINCE CAPITALS

RIVERS

MAIN ROADS

RAILROADS

PROVINCE BOUNDARIES

INTERNATIONAL BOUNDARIES

EXISTING POWER NETWORK:

POWER DISTRIBUTION

HYDRO POWER PLANTS (PUBLIC)

HYDRO POWER PLANTS (PRIVATE)

THERMAL POWER PLANTS

HVDC TRANSMISSION LINE (INGA-KOLWEZI)

220kV TRANSMISSION LINES

110-132kV TRANSMISSION LINES

30-50-70kV TRANSMISSION LINES

PROJECT WORKS:

INGA-KINSHASA PROJECT TRANSMISSION LINE

INGA HYDRO POWER PLANT REHABILITATION

KINSHASA DISTRIBUTION REHABILITATION AND EXPANSION


SOUTHERN AFRICAN POWER MARKET PROJECT

LüderitzLüderitz

Walvis BayWalvis Bay

ArushaArusha

IringaIringa

DodomaDodomaSingidaSingida

TaboreTabore

KitweKitwe

KimberleyKimberley

East LondonEast London

BloemfonteinBloemfontein

LikasiLikasi

Owen FallsOwen Falls

MwanzaMwanza

MusomaMusoma

KasamaKasama

LichingaLichingaCuambaCuamba

NacalaNacala

PembaPemba

NampulaNampulaAlto MolocueAlto Molocue

BeiraBeira

CaiaCaia

BulawayoBulawayo

InhambaneInhambane

Temane Gas FieldsTemane Gas FieldsPande Gas FieldsPande Gas Fields

Xai-XaiXai-Xai

Louis TrichardtLouis TrichardtSeruleSerule

DurbanDurban

Richards BayRichards Bay

Port ElizabethPort ElizabethMosselbaaiMosselbaai

JohannesburgJohannesburg MBABANEMBABANE

GABORONEGABORONE

WINDHOEKWINDHOEK

MASERUMASERU

KIGALIKIGALI

KAMPALAKAMPALA

BUJUMBURABUJUMBURA

LILONGWELILONGWE

DAR ESDAR ESSALAAMSALAAM

HARAREHARARE

PRETORIAPRETORIA

KINSHASAKINSHASA

LUANDALUANDA

LUSAKALUSAKA

CAPE TOWNCAPE TOWN

MAPUTOMAPUTO

NAIROBINAIROBI

PhombeyaPhombeyaMatamboMatambo

KaraviaKaravia

LuanoLuano

Nzelo &Nzelo &NsekeNseke

MwadingushaMwadingusha& Koni& Koni

SolweziSolwezi

KolweziKolwezi

Kafue LowerKafue Lower

IngaInga

CapandaCapanda

CambambeCambambe

MatalaMatala

LomaumLomaum

RuacanaRuacana

Kudu CCGTKudu CCGT

KokerboomKokerboom

EhuhaEhuha

KoebergKoeberg

AggensisAggensisAriesAries

GriepGriep

DrakensbergDrakensberg

CamdenCamden

Edwaleni IIEdwaleni II

MuellaMuella

Van DerVan DerKloofKloof

PalmietPalmiet

MerapiMerapi

MatimbaMatimba

PhokojePhokoje

MarvelMarvelInsukaminiInsukamini

SpitskopSpitskopApolloApollo

ArnotArnot

FrancistownFrancistown

KomatipoortKomatipoortCorumanaCorumana

MorupuleMorupule

HwangeHwange

BatokaBatoka

KapichiraKapichira

Cahora BassaCahora BassaMepandaMepandaUncuaUncua Nkula A&BNkula A&B

Alto MalemaAlto Malema

Gokwe NGokwe NBinduraBindura

Kariba S&NKariba S&N

VictoriaVictoriaFallsFalls

PensuloPensulo

KidatuKidatu

PanganiPangani

UbungoUbungo

HaleHale

MteraMtera

KihansiKihansiMwakibeteMwakibete

500 kV DC

500 kV DC

220 kV220 kV

220 kV220 kV

220 kV220 kV

220 kV220 kV

220 kV220 kV

330 kV330 kV

400 kV400 kV

400 kV400 kV

400 kV400 kV

400 kV400 kV

275 kV275 kV

220 kV220 kV

330 kV330 kV

330 kV330 kV

330

kV33

0 kV

330

kV33

0 kV

330 kV330 kV

220

kV22

0 kV

220 kV220 kV

132 kV132 kV

132 kV132 kV

132 kV Cable132 kV Cableto Zanzibarto Zanzibar

110 kV110 kV

220 kV220 kV

220 kV220 kV

400

kV40

0 kV

132 kV132 kV

220

kV22

0 kV

110 kV110 kV

HVDC

or H

VAC

HVDC

or H

VAC

Tran

smiss

ion

Syste

m

Tran

smiss

ion

Syste

m

533

kV D

C

533

kV D

C

U G A N D AU G A N D A

S U D A NS U D A N E T H I O P I AE T H I O P I A

G A B O NG A B O N C O N G OC O N G O

EQ.EQ.GUINEAGUINEA

D E M . R E P.D E M . R E P.O F C O N G OO F C O N G O

A N G O L AA N G O L A

N A M I B I AN A M I B I A

Z A M B I AZ A M B I A

MALAWIMALAWI

B O T S W A N AB O T S W A N A

S O U T HS O U T HA F R I C AA F R I C A

LESOTHOLESOTHO

SWAZILANDSWAZILAND

Z IMBABWEZ IMBABWE

CAMEROONCAMEROON

T A N Z A N I AT A N Z A N I A

BURUNDIBURUNDI

RWANDARWANDA

K E N YAK E N YA

Lüderitz

Walvis Bay

Arusha

Iringa

DodomaSingida

Tabore

Kitwe

Kimberley

East London

Bloemfontein

Likasi

Owen Falls

Mwanza

Musoma

Kasama

LichingaCuamba

Nacala

Pemba

NampulaAlto Molocue

Beira

Caia

Bulawayo

Inhambane

Temane Gas FieldsPande Gas Fields

Xai-Xai

Louis TrichardtSerule

Durban

Richards Bay

Port ElizabethMosselbaai

Johannesburg MBABANE

GABORONE

WINDHOEK

MASERU

KIGALI

KAMPALA

BUJUMBURA

LILONGWE

DAR ESSALAAM

HARARE

PRETORIA

KINSHASA

LUANDA

LUSAKA

CAPE TOWN

MAPUTO

NAIROBI

PhombeyaMatambo

Karavia

Luano

Nzelo &Nseke

Mwadingusha& Koni

Solwezi

Kolwezi

Kafue Lower

Inga

Capanda

Cambambe

Matala

Lomaum

Ruacana

Kudu CCGT

Kokerboom

Ehuha

Koeberg

AggensisAries

Griep

Drakensberg

Camden

Edwaleni II

Muella

Van DerKloof

Palmiet

Merapi

Matimba

Phokoje

MarvelInsukamini

SpitskopApollo

Arnot

Francistown

KomatipoortCorumana

Morupule

Hwange

Batoka

Kapichira

Cahora BassaMepandaUncua Nkula A&B

Alto Malema

Gokwe NBindura

Kariba S&N

VictoriaFalls

Pensulo

Kidatu

Pangani

Ubungo

Hale

Mtera

KihansiMwakibete

500 kV DC

220 kV

220 kV

220 kV220 kV

220 kV

330 kV

400 kV400 kV

400 kV

400 kV

275 kV

220 kV

330 kV

330 kV

330

kV

330

kV

330 kV

220

kV

220 kV

132 kV

132 kV

132 kV Cableto Zanzibar

110 kV

220 kV

220 kV

400

kV

132 kV

220

kV

110 kV

HVDC

or H

VAC

Tran

smiss

ion

Syste

m

533

kV D

C

PMD Project RehabilitationPMD Project Rehabilitationof Inga Hydropower Plantof Inga Hydropower Plant

PMD Project Rehabilitationof Inga Hydropower Plant

T

TS

S

S

S

S

S

S

S

S

S

S

S

S

S

SS

S

S

S

S

S

S

SS

S

S

SS

S

S

S

S

S

S

S

S

S

T T

T TT

T

T

T

T

U G A N D A

S O U T H S U D A N E T H I O P I A

G A B O N C O N G O

EQ.GUINEA

D E M . R E P.O F C O N G O

A N G O L A

N A M I B I A

Z A M B I A

MALAWI

B O T S W A N A

S O U T HA F R I C A

LESOTHO

SWAZILAND

Z IMBABWE

CAMEROON

T A N Z A N I A

BURUNDI

RWANDA

K E N YA

LakeTurkana

Lake AlbertCongo

Kasai

Lake

Victoria

Lake Tanganyika

Lake

Malawi

LakeKariba

Zambezi

LakeMweru

Ubangi

Orange

Limpopo

Orange

AT L A N T I C

O C E A N

I N D I A N

O C E A N

Con

go

20°

30°

10°

0°

30°

20°

10°

0°

20°10°

20°10°

30°

40°

30° 40°

IBRD 39347

MAY 2012

MAIN CITIES

INTERNATIONALBOUNDARIES


SOUTHERN AFRICANPOWER MARKET PROJECT

POWER LINES

EXISTING HVDC & HVAC TRANSMISSIONLINES UNDER REHAB. (SAPMP PROJECT)

SUBSTATIONS

HYDRO POWER PLANTS

THERMAL POWER PLANTS

NUCLEAR POWER PLANTS

SAPP COORDINATION CENTER

S

TT

S

EXISTINGPOSSIBLEFUTURE

0

0 100 200 300 Miles

100 200 300 400 Kilometers

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