Document of The World Bank
FOR OFFICIAL USE ONLY Public Disclosure Authorized
Report No: 39645 - ZR
PROJECT APPRAISAL DOCUMENT
ON A
Public Disclosure Authorized PROPOSED GRANT
IN THE AMOUNT OF SDR 196.1 MILLION (US$296.7 MILLION EQUIVALENT)
TO THE
DEMOCRATIC REPUBLIC OF CONGO
FOR A
REGIONAL AND DOMESTIC POWER MARKETS DEVELOPMENT PROJECT
Public Disclosure Authorized IN SUPPORT OF THE
SOUTHERN AFRICAN POWER MARKET PROGRAM (PHASE AF'L-lb)
May 2,2007
This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. Public Disclosure Authorized CURRENCY EQUIVALENTS
Currency Unit = Franc Congolais (FC) US$1 = 555 FC (as ofApril 30,2007) US$1.513 = SDR 1
FISCAL YEAR January 1 - December 31
ABBREVIATIONS AND ACRONYMS AAFM Administrative, Accounting and Financial Manual AfDB Afncan Development Bank APL Adaptable Program Loan BCECO 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 CATE Cellule d 'appui technique a I 'tlectricit&, the unit within MoE responsible for providing guidance on sectoral strategies and MoE support on SNEL related activities CFAA Country Financial Accountability Assessment CQS Selection based on Consultant Qualifications DRC Democratic Republic of Congo ED3 European Investment Bank EIRR Economic Internal Rate ofReturn EMW The Emergency Multisector Reconstruction and Rehabilitation Project, approved by the Association's Board ESR Plan Environmental, Social and Resettlement Plan: the seven documents, dated December 2006, relating to environmental, social and resettlements aspects ofthe Project, namely: (i) the ESIA, (ii)ESMP, (iii)the ESMF, (iv) the RPF, (v) the MCHF, (vi) the ESIA Executive Summary (French), and (vii) the ESIA Executive Summary (English), as supplemented by (viii) the PMP. ESIA Etude d 'Impact Environnemental et Social (the Environmental and Social Impact Assessment), dated December 2006, prepared for the Project ESMF Cadre de Gestion Environnementale et Sociale (the Environmental and Social Management Framework), dated December 2006, prepared for the Project. ESMP Plan de Gestion Environnementale et Sociale (Environmental and Social Management Plan), dated December 2006, prepared for the Project. ESMU SNEL's Environmental and Social Management Unit FIRR Financial Internal Rate of Return FM Financial Management FMR Financial Management Reports GoDRC Government ofDRC GWh Gigawatt hours (of energy) HV High Voltage HVDC High voltage, direct current transmission line IDA International Development Association IFC International Finance Corporation Inga 1 and 2 The two existing power plants located at the Inga site Inga 3 The proposed new hydroelectric plant at the Inga site IEM Inga Entomological Mission FOR OFFICIAL USE ONLY
IRR Internal Rate ofReturn LV Low Voltage MCHF Cadre de Gestion du Patrimoine Culture1 (the Management of Cultural Heritage Framework), dated December 2006, prepared for the Project. MIGA Multilateral Investment Guarantee Agency MoE Ministry ofEnergy ofDRC MoE Project Component ofthe Project to be carried out by MoE, namely Component 4(b) ofthe Project Components MV Medium Voltage MW Megawatt NEPAD New Partnership for Africa's Development N-PV Net Present Value PCB Polychlorinated Biphenyl PCG Project Coordination Unit, which includes the PCT PCT-SNEL SNEL's Project Coordination Team PCU Project Coordination Unit PFM Agent The procurement and financial management agent to be employed by MoEto assist with procurement and financial management actions under the Project PMP Plan de Gestion des Nuisances et Pesticides (Pest Management Plan), dated March 2007, related to the control ofblack flies in the Inga area QBS Quality Based Selection RPF Cadre de Reinstallation Involontaire (Resettlement Policy Framework), dated December 2006, prepared for the Project SADC Southern Afncan Development Community SAPMP The Southern Afncan Power Market Program, approved by the Association's Board SAPP Southern African Power Pool, comprised ofthe following Operating and Non-Operating members: DRC, Botswana, South Ahca, Namibia, Mozambique, Malawi, Lesotho, Swaziland, Angola, Zambia, Zimbabwe and Tanzania SBD Standard Bidding Documents SNEL Socie'te! Nationale d 'Electricite!, DRC's national power utility SNEL Project The Components of the Project to be carried out by SNEL, namely all the Components of Components the Project other than Component 4(b), which relates to MoE activities SOE Statement ofExpenditures sss Single Source Selection Westcor A joint-venture among the utilities ofDRC, Botswana, Angola, Namibia and South Afnca for the construction of a transmission line in southwestern Africa emanating from Inga 3 WHO World Health Organization WTP Willingness to pay
Vice President: Obiageli K. Ezekwesili Country Managermirector: Mark Tomlinson, Pedro Alba Sector Manager: S. Vijay Iyer Task Team Leader: Philime Benoit
This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not be otherwise disclosed without World Bank authorization.
DEMOCRATIC REPUBLIC OF CONGO
REGIONAL AND DOMESTIC POWER MARKETS DEVELOPMENT PROJECT (SOUTHERN AFRICAN POWER MARKET PROGRAM, APL-lb)
PROJECT APPRAISAL DOCUMENT
AFRICA
AFTEG
Date: May 2,2007 Team Leader: Philippe Charles Benoit Country Director: Mark Tomlinson, Pedro Alba Sectors: Power (100%) Sector Managermirector: S. Vijay Iyer Themes: Infrastructure services for private sector development (P) Project ID: PO97201 Environmentalscreening category: B - Partial Assessment Lending Instrument: Adaptable Program Lending -
[ ] Loan [ ] Credit [XI Grant [ ] Guarantee [ ] Other:
For Loans/Credits/Others: Total Bank financing (US$ million): 296.7
Retroactive Financing: In accordance with OP12.10, the Project will be able to charge up to US$20 million of the grant amount for expenditures occurring on or after April 1,2007. Borrower: DEMOCRATIC REPUBLIC OF CONGO
Responsible Agencies: SociCtC Nationale d’ElectricitC 283 1 Avenue de la Justice, La Gombe, Kinshasa, BP 500 KinshasdGombe, Tel: + 243 81 607 6254 Fax: +243 81 301 0382 E-mail: [email protected]
Ministry of Energy - Cellule d’Appui Technique Energie (CATE) Immeuble Regideso, 15 Ctage, 5963 Bd du 30 Juin, La Gombe, Kinshasa Tel: + 243 81 810 2300 FY 2008 2009 2010 2011 2012 2013 Annual 5.0 40.0 80.0 80.0 70.0 21.7 Cumulative 5 .O 45.0 125.0 205 .O 275.0 296.7
Project development objective Re$ PAD B.3, Technical Annex 3 The development objectives ofthe Project are to improve operational efficiency in the electricity sector and expand generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration. Project description Re$ PAD B.2 and B.4, Technical Annex 4 The Project would have five components: (a) rehabilitation ofgeneration capacities at the Inga 1 and 2 power plants to provide power to DRC, as well as to the Southern Afhcan Power Pool and to Central Afhca, (b) construction of a transmission line from Inga to Kinshasa (also serving the Republic ofCongo), (c) expansion and rehabilitation ofthe distribution network in Kinshasa, including powering ofun-electrified areas and 50,000 new connections, (d) strengthening the capacities of SNEL (notably via a program to enhance governance, including the reduction of losses in commercial operations) and ofthe Ministry ofEnergy, and (e) support to execution ofthe Project, including on engineering and environmental/social aspects. The project will support the Southern African Power Market Program APL series, and notably complements Phase 1 which involves the rehabilitation of the transmission line from Inga to the border of the Republic ofZambia. Which safeguard policies are triggered, if any? Re$ PAD 0.6, Technical Annex 10 The Environmental Assessment (OP/BP/GP 4.0 l),Involuntary Resettlement (OP/BP 4.12), Pest Management (OP 4.09), Dam Safety (OP/BP 4-37), International Waterways (OP/BP 7.50), and Cultural Properties (OP 4.1 1) safeguard policies are triggered under the Project.
Significant, non-standard conditions, if any, for: Re$ PAD C.6 The main conditions of effectiveness are:
Execution of a GoDRC/SNEL subsidiary loan agreement, in form and substance satisfactory to the Association.
0 Establishment ofthe PCU and a financial management system for the Project, acceptable to the Association, including: (a) recruitment of a PFM Agent (including adoption of an accounting software); (b) adoption by the PCU of a manual of accounting and financial procedures; (c) recruitment ofan internal auditor; (d) recruitment of an external auditor; and (e) adoption ofan anti-corruption action plan for the Project.
0 Establishment within SNEL of an Environmental and Social Management Unit (ESMU), under terms of reference and with staffing acceptable to the Association.
The main Grant covenants are:
0 The ESR Plan will be implemented in a manner satisfactory to the Association.
GoDRC shall employ the PFM Agent (the procurement and financial management agent) throughout Project implementation.
0 The ESMU within SNEL will be operated under terms ofreference and with staffing acceptable to the Bank.
0 SNEL shall: (i)not later than October 3 1 of each year, adopt a maintenance program for the facilities under the Project and a related budget for the succeeding fiscal year, acceptable to the Association, (ii)thereafter implement such program, modified as necessary to properly maintain the facilities, and (iii)not later than October 3 1 ofeach year, report on the implementation ofthe such year’s maintenance program.
SNEL (i)shall only enter into agreements relating to the financing of rehabilitation or other works, or any concessioning or other similar arrangements, regarding the Project facilities under terms that protect the development interests of DRC in a financially and technically sound and equitable manner, and (ii)shall consult with the Association prior to entering into any such agreement.
0 SNEL shall ensure that all financiers of activities or operators at the Project facilities will co-ordinate their activities with those financed by the Association in a manner acceptable to the Association, and shall require such activities to be carried out in conformity with the ESR Plan.
SNEL shall employ a supervisory engineer during Project implementation, under terms of reference satisfactory to the Association.
0 SNEL shall adopt a dam emergency preparedness plan by December 3 1,2007 that reflects the comments of the Association.
0 GoDRC and SNEL shall implement their undertalungs to enhance governance in the electricity sector, including with respect to the publication of audits and contracts.
AFRICA REGIONAL AND DOMESTIC POWER MARKETS DEVELOPMENT PROJECT (SOUTHERN AFRICAN POWER MARKET PROGRAM. APL-lb)
CONTENTS
Page
A . STRATEGIC CONTEXT AND RATIONALE ...... 1 1. Regional. Country and Sector Context ...... 1 2 . Rationale for Bank involvement ...... 7 3 . Higher level objectives to which the Project contributes ...... 8 B. PROJECT DESCRIPTION ...... 9 1. Lending instrument ...... 9 2 . Program objective and Phases ...... 9 3 . Project development objective and key indicators ...... 10 4 . Project components ...... 10 5 . Lessons learned and reflected in the Project design ...... 11 6 . Alternatives considered and reasons for rejection ...... 12 C . IMPLEMENTATION ...... 14 1. Partnership arrangements ...... 14 2 . Institutional and implementation arrangements ...... 14 3 . Monitoring and evaluation ofoutcomeshesults ...... 15 ... 4 . Sustainability ...... 15 5 . Critical risks and possible controversial aspects ...... 16 .. 6 . Loadgrant conditions and covenants ...... 17 D . APPRAISAL SUMMARY ...... 19 1. Economic and Financial Analyses ...... 19 2 . Technical ...... 22 3 . Fiduciary ...... 22 4 . Social ...... 23 5 . Environment...... 23 6 . Safeguard policies ...... 23 7 . Policy Exceptions and Readiness...... 24
Annex 1: Regional. Country and Sector Background...... 26 Annex 2: Major Related Projects Financed by the Bank and/or other Agencies ...... 41 Annex 3: Results Framework and Monitoring ...... 42 Annex 4: Detailed Project Description...... 44 Annex 5: Project Costs ...... 58 Annex 6: Implementation Arrangements ...... 60 Annex 7: Financial Management and Disbursement Arrangements ...... 66 Annex 8: Procurement Arrangements ...... 77 Annex 9: Economic and Financial Analysis ...... 83 Annex 10: Safeguard Policy Issues ...... 98 Annex 11: Project Preparation and Supervision ...... 103 Annex 12: Documents in the Project File ...... 104 Annex 13: Statement of Loans and Credits ...... 105 Annex 14: Country at a Glance ...... 106 Annex 15: IBRD 35198, 35356 ...... 108
A. STRATEGIC CONTEXT AND RATIONALE
1. Regional, Country and Sector Context
A. Regional Context
Southern African Power Pool
1.1. Southern Afhca exhibits substantial variations in energy resource endowments, degrees of industrial development, levels and patterns ofpower consumption and power costs. These differences present opportunities for coordinated development of the regional power sector to: (i)generate savings through aggregation of loads with different load profiles, (ii)achieve efficient use of energy resources by exploiting large scale power generation schemes that are viable only on the basis of large multi-counhy markets, and (iii)manage the risks of climate-related power shortages in hydro- dependent countries. In recognition of the potential benefits, in August 1995, SADC member countries created the Southern Ahcan Power Pool (SAPP) by concluding an Intergovernmental Memorandum of Understanding and related agreements which together govern the operation of the power pool. The utilities of 12 southern African countries are members ofthe SAPP.
1.2. SAPP started as a cooperative pool, that is, a pool under which members would seek to maximize economic and system reliability benefits through trade, while retaining maximum autonomy for individual members. However, in the longer term the SAPP aims to facilitate the development of a competitive electricity market in the SADC region. Currently there are two market mechanisms used in SAPP energy exchanges: medium-to-long term bilateral power purchase agreements and the Short Term Energy Market. An update ofthe long-term least-cost generation and transmission expansion study (the ‘Pool Investment Plan’) for the SAPP was started midSeptember 2006, and is expected to be completed before end-2007.
1.3. DRC has enormous hydropower potential, estimated at about 100,000 MW - or 13 percent ofglobal hydropower potential. Much ofthis potential is located in a single site, the Inga dam site on the Congo River, located 125 miles downriver from Kinshasa, with a potential capacity estimated at about 45,000 MW. With energy resources on this scale, DRC has the potential to play a pivotal role in meeting not only its domestic energy needs, but also the energy needs of neighboring countries and beyond. Today, the Inga site provides power both southward (notably to the Southern African Power Pool - the SAPP) and northward (to the Central Afhcan Power Pool - the CAPP). Power supplied from DRC will be a critical enabling factor for the development of a competitive power market in both sub-regions, with reliable, low-cost power supporting industrial competitiveness, private sector investment and regional growth and development. As a consequence, DRC generally and the Inga specifically are currently central to most discussions in southern and central Africa to developing hydropower resources on a regional basis.
1.4. The New Partnership for Africa’s Development (NEPAD) has designated the development ofthe Inga site as a priority under the regional development programs. As such, NEPAD, the Ahcan Development Bank (AfDB) and other institutions are supporting the development of Inga’s power potential in three distinct but interrelated stages: (i)in the short-term, the rehabilitation of the existing facilities, which operate at less than 40 percent of installed capacity; (ii)in the medium-term, the development of a new hydro-power facility, with about 3,500 MW of capacity (likely the Inga I11 site or, possibly, an initial phase of the Grand Inga project); and (iii)in the longer-term, the full development of the additional 40,000 MW potential ofthe site (the “Grand Inga” Project).
1 1.5. Reflecting its geographic position and the centrality of the Inga site, DRC is a member of both the SAPP and the CAPP. Currently, DRC's state electricity utility, Socie'tP Nationale d 'Electricit& (SNEL), has long-term bilateral contracts for power exports to South Africa and Zimbabwe (about 100 MW each). These sales generate valuable foreign exchange revenues for DRC. For its regional neighbors to the south, DRC's hydro-power (from Inga and other sites) provides benefits that include a low-cost and low-carbon alternative to thermal generation capacity (especially for those countries, such as Zimbabwe, that have no low-cost, indigenous sources of electricity) and a diversified source of power for countries extensively reliant on domestic hydropower. Discussions are currently underway about linlung Zambia to Tanzania, thereby providing a route for DRC's power to also supply countries in eastern Ahca. It is anticipated that the incremental hydro-production from Inga will substitute for carbon intensive fossil generation and so may be eligible under the Clean Development Mechanism.
1.6. DRC's hydropower potential (and specifically the resources available at Inga) is anticipated to play an increasingly central role in the further development of the SAPP. SAPP members have drawn up a list of high priority projects, backed by both SADC and NEPAD. Electricity supplied by DRC will be pivotal to some of these projects. These projects will allow Inga to supply significantly more power to the SAPP member countries, both through increased sales to existing customers and to new off-takers.
1.7. There are, however, several constraints preventing this demand from being met via the existing infrastructure. They include the transfer capacity of a part of the regional interconnection between DRC and Zambia; capacity and performance restrictions of the AC power system in the Katanga region in DRC; capacity and operational status of the High Voltage Direct Current (HVDC) link between Inga and Katanga; and the need to refurbish the generating plants in the DRC, notably at Inga.
1.8. The Projects in the Southern African Power Market Program (SAPMP) APL series currently in preparation or being implemented will remove some of these constraints. Zambia and the DRC are to upgrade their current 220-KV regional transmission corridor to a much higher specification to allow other SAPP counties to tap Inga's energy supplies. To this end, Zambia's Copperbelt Energy Corporation (CEC) and SNEL are discussing a project to construct a new 220-KV line running in parallel to the existing interconnection between Chingola in Zambia and Karavia near the southern DRC city of Lubumbashi. In addition to the new transmission line, the two countries will also repair the existing 220-KV line. More details on the SAPMP are provided in section C below.
1.9. DRC's hydro resources are also viewed as central to the development of the CAPP. SNEL currently exports about 50-80 MW from Inga north to Brazzaville (Republic ofCongo) along a 220- hlovolt (KV) connection. SNEL has had discussions about supplying industrial clients in Pointe Noire (Republic of Congo), possibly via a transmission line through the Cabinda region of Angola, which would simultaneously allow power off-take in Cabinda. The CAPP has initiated donor-funded studies of this and other prospective regional inter-connection projects. It is expected that exports in the medium term to Brazzaville will decrease as power plants being commissioned in the Republic of Congo, including the hydro plant at Imboulou, come on line. However, the Inga supply will remain an important source of supply security for Brazzaville. Loolung further afield, there is also potential for electricity generated at Inga to supply the West Afica Power Pool.
1.10. Towards the east ofthe country, the focus of the regional collaboration in the energy sector in the Great Lakes region is la Socidtd Internationale d 'Energie des Grands Lacs, a joint company wholly-owned by Burundi, Rwanda and DRC and established in 1984, with the support ofthe World Bank, to build and manage a group ofjoint energy sector operations in the Great Lakes region. The
2 company’s main operation is the Ruzizi I1hydropower plant at Mumosho in the DRC, which supplies power to all three countries. The company has faced extensive financial and operating difficulties (in part the legacy of the years of conflict in the sub-region); the World Bank, building on security improvements in the area, is currently supporting efforts to help the utility strengthen its operations and financial position. However, even as these efforts go forward, other challenges emerge, including the recent drops in the water level in Lake Kivu that reduce Ruzizi 11’s output potential.
1.11. In summary, DRC generally, and Inga specifically, lie in many respects at the center of gravity of discussions on regional power in sub-Saharan Africa. DRC, however, has not yet managed to capitalize on this opportunity. A range of projects currently under commission or consideration will allow DRC and its neighbors, near and far, to tap the country’s extraordinary hydropower potential, in particular from the Inga site. These efforts, however, necessarily hinge on the rehabilitation of the existing Inga site in two distinct ways: first, rehabilitating Inga provides incremental power to supply the SAPP and the CAPP countries; second, larger scale development of the Inga site (such as Inga 3, which will require over US$4 billion in investment) depends on DRC demonstrating the ability to assure the sound operation of the existing Inga 1 and 2 facilities.
B. Country Context
1.12. The size of DRC’s promise has, unfortunately, been undermined by its challenges. It is potentially one of Afhca’s richest economies, with extensive mineral, energy and natural resources. It is a potential dynamo for regional growth, with its large labor force and potential market size, extensive navigable inland waterways and land links to nine states. Yet hopes of tapping this rich potential have been repeatedly thwarted. Successive governments have failed to translate the country’s assets into improved standards of living for the Congolese people. The level of physical and social devastation caused by decades of mismanagement, starting in the colonial era, worsening during the regime of Mobuto Sese Seko and compounded by extended periods of conflict since 1997, has been great.
1.13. Today, the country is embarking on systematic efforts to overcome the legacy of mismanagement and conflict. The recent elections mark an important moment in Congolese history when the government, parliament and local authorities have assumed power through a democratic process. With a new cabinet appointed in early February 2007, the post-election period provides a rare opportunity to push forward with much-needed reforms. These efforts, however, will face a complex array offactors: the delicate democratic transition currently underway, the legacy ofconflict, ongoing regional tensions, economic and social collapse, and the weight of a legacy of corruption.
C. Sector Issues
1.14. Despite the country’s enormous power potential, DRC has managed neither to capitalize on the opportunity of significantly higher electricity exports across Afnca nor to provide adequate energy services for the vast majority of its own population. Household access is now less than before the war, at 6.5 percent ofhouseholds, compared to the SSA average of 20 percent, leaving the country in the bottom 15 of SSA nations. Frequent blackouts hit even high priority parts of the network. Electricity consumption per head was 9lkWh in 2002, down from 161 kWh in 1980. Traditional biomass fuel is now estimated to account for 86 percent of total energy use in the country, with diesevoil at 8 percent, electricity shrinking to 4 percent and coal accounting for the remaining 2 percent.
1.15. The proximate cause of these very low energy access rates is the state of DRC’s electricity infrastructure. All parts ofthe network deteriorated extensively in the 1990s, as a result of extensive
3 theft (both of physical components and via financial embezzlement) as the security situation worsened, direct conflict damage and a lack ofmaintenance (including a dearth ofreplacement parts). Underlying all these factors is a weakening of the institutional capacity to maintain the system. In particular, SNEL, the vertically-integrated parastatal power utility that dominates electricity generation, transmission and distribution in DRC, faces wide-ranging financial, management, governance and operational challenges. Improving the quality and quantity of electricity service in DRC will require significant improvements in SNEL’s operations and maintenance program. SNEL will, as a covenant of the Project Grant: (i) not later than October 31 of each year, adopt a maintenance program for the facilities under the Project and a related budget for the succeeding $seal year, acceptable to the Association, (ii) thereafter implement such program, modiJied as necessary to properly maintain the facilities, and (iii) not later than October 31 of each year, report on the implementation of the such year’s maintenance program.
1.16. Looking forward, the government has identified several priority objectives for revitalizing the electricity sector: (a) supporting local business needs and satisfying unmet domestic demand, thereby supporting economic recovery and growth; (b) stemming losses that negatively impact the financial position of the sector; and (c) exporting electricity to generate foreign exchange and improve the strategic positioning of DRC within a regional context.
1.17. Demand. Total demand (as represented by sales) in 2005 was about 5700 GWh, with low voltage power accounting for about 50 percent. Demand is projected to increase annually by about 7 percent in the coming five years, but could increase significantly more as the electricity infrastructure expands.
1.18. Generation. Only a small fraction of DRC’s vast energy resources has been exploited. Despite having potential production capacity estimated at about 100,000 MW from hydro power alone, the country’s total installed capacity is approximately 2,400 MW, or less than 3 percent ofthat potential. Ofthis, hydropower accounts for nearly 99 percent, with the remaining supplied by about 60 small and isolated solid-fuel thermal plants. A handful of large industrial enterprises maintain their own production capacity. The two hydro plants at Inga between them account for 1775 MW of installed capacity (351 MW at Inga I,1424 MW at Inga 2), or roughly 70 percent of the country’s total.
1.19. Even this limited installed capacity runs significantly below potential. Some of the electricity generation infrastructure dates back to the colonial era - the oldest installed facility was constructed in 1929 - and has not been systematically maintained, overhauled or updated. Rehabilitation has tended to be on an ad hoc, emergency basis, resulting in outdated and unreliable machinery. As a result, only 48 percent of installed capacity is actually available. Total annual electricity production in 2005 was about 7,100 GWh, or slightly less than 50 percent of what the installed capacity could potentially generate. With some of the smaller hydro-facilities wholly inoperative and only about one third of the small thermal plants functioning, some urban centers in more remote regions have had their grid electricity supply completely cut off.
1.20. The state of the Inga plants epitomizes the state of the country’s generation capacity. Currently, available capacity at Inga 1 and 2 totals about 700 MW out of 1775 MW of installed capacity. Both plants need urgent repairs as well as extensive rehabilitation for longer-term viability, in addition to extensive re-shaping, dredging and clearance ofthe heavily-silted canals that supply the turbines. Given Inga’s role as the backbone of DRC’s generation capacity, the Government of DRC (GoDRC) views rehabilitation of the two plants as a high priority in order to improve the reliability and quantity ofsupply of electricity from Inga for both domestic and export markets.
4 1.21. Transmission. The transmission system in DRC consists of several unconnected electricity sub-networks. There are three principal components that together span 5547 km (3447 miles): a high voltage line (500kV) that runs 1740 km (1081 miles) from Inga to the Katanga region, and three large sub-networks, composed of high-voltage lines varying between 50kV and 220kV (Western network, Southern network, and an Eastern network). In addition, there is a variety ofindependent mini-grids, organized around smaller urban and industrial centers across the country, powered by small power plants.
1.22. Distribution. The distribution system is structured around four principal networks that between them account for 90 percent of total electricity consumption in the DRC and approximately 400,000 connections. This includes about: (i)290,000 connections in the Kinshasa region; (ii) 35,000 connections in the Bas Congo region; (iii)54,000 connections in the Katanga region; and (iv) about 32,000 connections in the Kivu region. The distribution system includes roughly 1920 miles of medium voltage (6.6 to 30kV) lines and 7239 miles of low voltage (0.4kV) lines. As with the generation and transmission facilities, maintenance of the distribution system has primarily been on an emergency repair basis, with virtually no systematic rehabilitation. A litany of shortcomings has rendered the entire system highly unreliable, including saturated lines and transformers, and dilapidated poles.
1.23. Kinshasa is dependent on Inga for virtually all of its power, with a small amount provided from the Zongo plant. Maintenance issues at Inga and limited capacity on the existing 220kV Inga- Kinshasa transmission line restricts supplies to the capital to about 400 MW. There is an estimated additional 200 MW of unmet demand. In addition, limitations in the current distribution system and lack of connections further constrain consumption. The result is that the 290,000 connections in Kinshasa (representing an access rate ofroughly 35 percent) experience frequent load shedding.
1.24. The SNEL network is characterized by significant losses at all stages of generation, transmission and distribution. Overall distribution losses are estimated at around 25 percent, but it is difficult to determine given weaknesses in the controls systems. In Kinshasa, the difference between energy delivered to the domestic network and total collections, which represents technical, non- technical and collection losses, amounts to over 60 per cent.
1.25. An understanding of the poor state of DRC’s energy infrastructure starts with the national electricity utility. SNEL manages the main components of the generation, transmission and distribution networks described above, including the isolated mini-grids that power some outlying towns, delivering 95 percent of all electricity produced in DRC. The company currently employs 6,500 staff. SNEL’s technical and operational abilities appear to be sufficient to run the Inga facilities and the related transmission systems, but in overall terms remain weak as a result of a funds, lack of slulls upgrading and the loss of qualified personnel during the conflict. SNEL’s weak financial position, and internal governance and management weaknesses further undermine its efficacy. For example, SNEL’s turnover in 2005 was US$174.3 million (Le. total consumption billed), but only about 55 percent of moneys owed to SNEL for that year were paid, with domestic consumers and notably government agencies and parastatals the least likely to pay. SNEL’s turnover (gross sales) in 2005 was equivalent to US cents 3.0kWh sold. For the same year, given the combined effect of network losses (technical and non-technical) and non payment, the revenue collected per kwh generated was equivalent to only US cents 1.5/kWh.
1.26. These weaknesses and failures have helped to severely weaken SNEL’s financial position and its ability to deliver key power services. The GoDRC has recognized that making progress on any of these fronts will require thorough reform at SNEL. The GoDRC and SNEL, currently
5 operating under new management, have stated their joint commitment to increasing the quality and transparency of SNEL’s financial management (see discussion on governance below).
1.27. SNEL’s tariff structure is divided into three key categories: high, medium and low voltage. Electricity for commercial customers in all three categories is priced in US dollars to reduce the financial impact of Congolese Franc inflation. Residential customers in the low voltage category are billed in Congolese Francs. High voltage industrial customers are small in number - there are currently about 20, including export customers - but account for about 45 percent of sales. The average tariff in 2005 was about US cents 2.8kWh. Some ofthe customers in this group, particularly other parastatals, have had large payment arrears but, for political reasons, continue to be supplied. Medium voltage clients number approximately 1,300 and account for approximately 15 percent of sales; the tariff in 2005 was about US cents 7.3kWh. Low voltage customers, comprising residential, commercial and ‘public facilities’, have increased rapidly in recent years and there are now approximately 400,000 connections, accounting for approximately 40 percent of sales. Tariffs for commercial low-voltage customers average about US cents 11.6kWh.
1.28. Low-voltage tariffs for residential customers are much lower because they are denominated in Congolese Francs and had not been adjusted for several years to compensate for the depreciation of the national currency. In addition to low tariffs, the large majority (80-90 percent) of residential customers are not equipped with meters and are billed through a lump-sum tariff system. In 2005, the average residential tariff was equivalent to US cents 1.2 kWh. Given the combination of low collection rates and the lump-sum tariff system, the average collected revenue was slightly below US cents 0.4 kwh. SNEL’s tariffs, particularly for residential customers, are low and do not reflect the full marginal cost of service provided. The utility increased tariffs for residential customers early in 2007 by about 50% as an initial step which should bring average tariffs for this category to about US cents 1.7kWh. GoDRC has commissioned a tariff study to help it to further evaluate options. However, it was felt that a reform sequence that tackled major pricing changes before improving service quality would be inappropriate at this juncture.
1.29. Corporate Governance Structure. The corporate governance mechanisms under which SNEL operates include the Board ofDirectors and a Management Committee. Externally, SNEL is under the joint supervision of the Ministries of Portefeuille and Energy, with the former ministry supervising administrative and financial aspects of SNEL’s activities and the latter exercising technical supervision across the energy sector; both ministries have representation on SNEL’s Board of Directors. There are some areas where supervision overlaps between the two ministries, including when SNEL establishes external partnerships. There is currently no electricity regulator, although discussions are underway to evaluate this option.
1.30. Private Sector Participation. Private sector involvement in the electricity sector in DRC has primarily been limited to private investment in generation, notably in connection with extractive industry operations in the Katanga region. The Government and SNEL have also been working to develop partnerships with the private sector in generation, transmission and distribution (including efforts at Inga 1 and 2). To date, however, SNEL and other Government efforts to engage the private sector have been ad hoc and have lacked consistency and transparency. Efforts are now underway to institute a more systematic approach in this area. Recognizing the importance of creating a sound framework for attracting private sector partners on conditions that best protect the development interests ofDRC, the Government and SNEL are exploring how to institutionalize stronger processes for partnering with the private sector (see discussion below on electricity sector governance program).
1.31. One potential area for large private investment is the development of Inga 3, a new hydroelectric plant at the same site with a generation capacity of about 3,500 MW. A consortium -
6 named the Western Power Corridor Project, or ‘Westcor’ - was launched in 2004 as a collaborative effort between the electricity supply companies of DRC, Angola, Botswana, South Afiica and Namibia to develop the Inga 3 plant with a view to exporting power to southern Africa along a western corridor. Total costs are estimated at about US$5 billion, including well over US$1 billion in related transmission investments to connect to SADC customers. This effort will require extensive private sector financing to be financially viable. The Bank is helping the Ministry of Energy (MoE) to strengthen its capacity to evaluate and promote private sector involvement in the further development ofthe Inga site.
D. Governance Challenges in the Electricity Sector
1.32. GoDRC has sought to prioritize reliable power provision as a driver of economic development. While allowing for private participation in the sector, the GoDRC recognizes that SNEL remains a key operator in the sector and that improvements in the sector will depend to a large extent on improving SNEL’s efficacy. SNEL, however, has historically faced significant governance weaknesses and failures. These have undermined the utility’s ability to operate efficiently, weakening its financial position and preventing it from delivering key power services to the people of DRC. At the same time, there is need to improve governance within the sector beyond SNEL, notably by reducing non-payment by power consumers and establishing a transparent, equitable and sound framework for attracting private sector partners to the sector who are viewed by the authorities as vital to the further development ofthe sector.
1.33. The governance failings can be distinguished into two basic types: those relating to strategic decision-making and the second to financial aspects at the level of everyday operations. These failings encompass SNEL’s internal management and operations, as well as external parties, including the Government, contractors and customers. Recognizing the centrality of the power sector to DRC’s development, GoDRC and the management of SNEL have been developing a program to improve both sector and utility governance. Initial steps by SNEL and GoDRC have included (i) commissioning from an external firm a diagnostic of SNEL’s financial control systems (financed as part of project preparation), (ii)commissioning an external audit of SNEL’s financial statement after a hiatus ofseveral years, and (iii)commissioning an external review ofSNEL’s corporate governance mechanisms. In order to deepen and solidify these actions, a series of actions to enhance governance in the electricity sector has been developed (see Attachment 1 to Annex 4 below). The implementation of key actions to enhance governance in the electricity sector is a covenant under the Project’s Legal Agreements.
2. Rationale for Bank involvement
2.1. Improving the quantity and quality of electricity services, both for domestic and export markets, is a priority activity for GoDRC. The proposed Project is consistent both: (a) on a national level, with the Transitional Support Strategy for DRC (January 26, 2004) and the proposed new CAS (which will soon be discussed), notably the strategic element ofinfrastructure reconstruction, as well as increasing government revenues and improving living conditions in the critical Kinshasa urban area, and (b) on a regional level, with efforts ofNEPAD and other organizations to promote low-cost regional power development. Notwithstanding Bank support to the sector to date, DRC continues to require assistance to better exploit the potential at Inga 1 and 2, and to better meet domestic demand, including in the Kinshasa urban center. Bank support can help the Government to better develop this resource to serve the dual benefits ofincreased domestic consumption and increased export revenues, while also improving the capacity ofthe system to transmit and distribute this power for the benefit of consumers. The Bank’s involvement will also underpin reforms of SNEL designed to improve the
7 financial sustainability and transparency of the sector. Bank support should also provide a more solid foundation for the Government to engage constructively with potential private sector investors. The scope ofthe Bank’s support can also be adjusted during Project implementation to promote synergies with private sector interests that mature into sound investments.
2.2. The Bank is, through the APL series for the Southern African Power Market Program (SAPMP), providing long term support to both SADC and NEPAD initiatives that aim to increase the availability and reliability of low cost, environmentally-friendlyelectric energy in southern Africa. The Program consists of a series of inter-related phases that will increase both the inter-connectivity of national power systems in the SAPP and the capacity available in the power pool. The original APL series supporting the SAPMP was designed with three phases. APL-1 finances rehabilitation of the HVDC line which runs from Inga to the Katanga region close to the Zambian border. In the three years since APL-1 was approved, extra rehabilitation needs have emerged at Inga and demand for power both within the SAPP and the DRC has grown, necessitating the elaboration of a new and separate effort to support the rehabilitation of Inga within the APL series. In this context, the proposed Project, SAPMP APL-lb, will generate incremental power at the Inga site, a portion of which will be exported via the HVDC line being rehabilitated under SAPMP APL-1. This Project has been formulated as a new phase of the APL series because the further investment at the Inga hydroelectric plant directly underpins APL-1. Rolling this Project into the existing APL series also reflects the view within the SAPP that the Inga component is an integral part of the SAPMP regional vision. The SAPMP is described in more detail in Section B below.
3. Higher level objectives to which the Project contributes
3.1. The Project will provide more electricity to more people in DRC, including over 350,000 additional people in Kinshasa, as well as improve the quality of service to the more than 1.5 million people in Kinshasa currently with access. Improving the quantity and quality of electricity to urban and peri-urban areas is consistent with the Transitional Support Strategy for DRC and the proposed CAS, and is an important pillar of the country’s development strategy. Moreover, incremental power exports generated as a result of the Project will represent a sustainable source of foreign exchange earnings for the GoDRC, helping to improve the balance of payments and support the government’s budget position.
3.2. By rehabilitating the Inga power plants, a pillar ofregional power trade, the Project will also provide benefits on a regional basis. The Project will notably increase access of consumers to cheaper and more reliable power than would otherwise be available in the various SAPP and CAPP countries receiving exports from DRC. Equally important, the Project will also provide an important touchstone for expanding regional power trade and regional-oriented investments in generation and transmission, which are keys to reducing costs and improving energy security for the interconnected members of these power pools. The proposed Project is also in line with relevant broad-based regional strategies, including the Regional Integration Assistance Strategy (US) for southern Ahca (2003), the Strategic Framework for IDA’SAssistance to Ahca (SFIA) (IDNSecM2003-0406) of 2003, and the Southern Africa Sub-Regional Strategy Paper (SecM98-272), which placed regional cooperation high on the policy agenda ofthe counties in southern Ahca, and the Ahca Action Plan reviewed by the Board in 2005.
8 B. PROJECT DESCRIPTION
1. Lending instrument
1.1. The proposed Project, APL-lb, constitutes a new fourth phase of the SAPMP APL series (see description below). This Project has been included in the SAPMP APL series because it provides important support to the success ofthe APL-1 phase, and prospectively the APL-3 phase, of the series by generating the incremental power to be transported by the transmission infrastructure financed by these phases. Given the particularly close links of the proposed Project with the existing APL-1 (which finances upgrading of the transmission line emanating from Inga for export to the SAPP -- see section 2 below for more details), this proposed Project is presented as APL-lb. The first phase of the SAPMP APL, APL-1, was approved by the Board on January 24, 2004 and became effective on May 17,2004; APL-2 is scheduled for Board presentation in mid-2007.
1.2. At the same time, the APL instrument allows the simultaneous financing of the domestically-oriented components ofthe Project alongside the regionally-oriented components, in an integrated fashion. The domestic components include the rehabilitation and expansion of the distribution network in Kinshasa. The second line from Inga to Kinshasa will primarily serve Kinshasa customers (and will also transport some power from Inga to the Republic of Congo). In addition, the various capacity building components will help SNEL and MoE to better serve the growing domestic demand. Since the project has a regional scope, regional IDA funding has been mobilized.
2. Program objective and Phases
2.1. The overall program objective of the SAPMP (as set out in the APL-1 PAD) is to increase the availability and reliability of low cost, environmentally-friendly electric energy in the southern Africa region, thereby increasing competitiveness of industry and fostering economic growth. The Program comprises the highest priority projects identified in the ‘Pool Investment Plan’ prepared by the SAPP.
a. APL-1 (P069258): The first phase finances investments to strengthen and increase the capacity of DRC to export power to the SAPP countries, notably from Inga, primarily by rehabilitating and upgrading the HVDC transmission line from Inga to Kolwezi in the Katanga region and the rehabilitation and upgrading of the AC network that extends from there to Zambia. The first phase is currently under implementation, but has faced significant delays. These delays were due in part to initial delays in finalizing the technical designs and in establishing familiarity with Bank processes; as a result ofthese delays, APL-1 is well behind schedule, resulting in a current overall Implementation Status rating of ‘Moderately Unsatisfactory’. In addition, there have been significant cost overruns as a result of various factors, such as the increase in the price of metals and other electrical materials, depreciation ofthe US dollar relative to the currencies in which the major contracts are expected to be denominated, and further deterioration of the assets. The design issues have recently been resolved and the procurement for major contractors is now well underway; the possibility of a supplement to the original credit is being considered to meet the anticipated cost overruns. The proposed Project will support the achievement of the APL-1’s objectives both by increasing the generation capacity at Inga, a priority for the SAPP, and by strengthening SNEL’s capacity.
9 b. APL-2 (P084404). This phase will finance the transmission interconnection of the Malawi national electricity gnd to the SAPP transmission grid via a transmission line to Mozambique. The interconnection will allow Malawi to sell excess energy into the SAPP, as well as facilitate power purchase in drought years. The APL 2 will be accompanied by complementary investments in the domestic power sector. The project is scheduled for presentation to the Association’s Board in mid-2007.
c. APL-3: This phase will connect Zambia to Tanzania, facilitating the connection of Uganda and Kenya to the SAPP in the future, hence significantly expanding the size of the pool and bringing new trading opportunities to all members.
2.2. The proposed Project constitutes a supplement to the SAPMP APL series. As described in the previous section, this Project is closely linked in particular with the APL-1 project, as it would enhance the quantity and reliability of power generated at Inga to be exported along the SAPP transmission network that is being upgraded under the APL-1 project; accordingly, this proposed Project has been given the appellation “APL-lb.” The addition ofthis phase APL-lb does not affect phases APL-2 or APL-3, including the triggers for those phases. In addition, while the implementation of the rehabilitation and upgrading activities under APL-1 will support the APL-lb Project objectives (see below) by increasing the amount and reliability of DRC exports to the SAPP countries, the adverse impact of further significant delays in implementing the APL-1 project will likely be mitigated by SNEL by dispatching the available power at Inga to other prospective clients (notably to Kinshasa or, assuming some rehabilitation ofthe HVDC line, to Katanga customers).
3. Project development objective and key indicators
3.1. The development objectives of the Project are to improve operational efficiency in the electricity sector and expand generation, transmission and distribution capacity in order to better serve domestic power demand and to support regional power market integration.
3.2. Key indicators for the Project’s intended final outcomes will be the increase in GWhs of energy delivered from Inga to Kinshasa and for export to the SAPP and commercial clients in the Katanga region. Intermediate outcome indicators will be: (i)rehabilitated generation capacity at the Inga Iand 2 plants; (ii)kilometers ofthe second transmission line strung between Inga and Kinshasa; (iii)GWhs delivered to the Kinshasa distribution network from Inga site; (iv) GWhs delivered from Inga to the SAPP countries and to industrial customers in the Katanga region; (v) SNEL’s rate of collection of accounts receivables from low voltage customers in Kinshasa; (vi) revenues collected per kWh delivered to the Kinshasa distribution network; (vii) number of additional households connected in Kinshasa; (viii) number of qualifications to the external audits of SNEL’s financial accounts; and (ix) publication of public/private partnership agreements for the electricity sector. These indicators will be measured by SNEL.
4. Project components
4.1. The Project consists offive components as follows:
ComDonent 1: Generation (US$ 226.7 million): Rehabilitation ofthe hydroelectric facilities at Inga, including civil works on the intake canal to improve the water flow through the plant and rehabilitation of turbines and other facilities to increase the operational capacity and reliability of the Inga plant (1 and 2) from its current level of about 700 MW to about 1300 MW of reliable production.
10 0 Component 2: Transmission (US$ 93.8 million): Construction of a 400 KV transmission line from Inga to Kinshasa. The second line will complement the existing 220 KV IngaKinshasa transmission line, which both increases the amount of power that can be delivered to Kinshasa and improves the security oftransport ofpower from Inga to Kinshasa.
0 Component 3: Distribution (US$ 88.5 million): Strengthening and expanding the distribution system in Kinshasa, including (a) the acquisition of low voltage cables and transformers, and (b) the extension of the grid into currently un-electrified areas of Kinshasa and the connection in these areas of 50,000 new customers.
0 Component 4: Capacity Building and Governance (US$ 41.2 million): The component comprises two subcomponents:
o Subcomponent A: Strengthening SNEL’s operational capabilities, notably in billing/collection activities, planning and maintenance. The component will also finance capacity building activities (in finance and other areas) designed to enhance governance within the utility specifically and in the sector generally. o Subcomponent B: strengthening the Ministry of Energy’s (MoE) capacity to develop sector reform and to support further development ofthe Inga site.
Comuonent 5: Proiect Execution (US$ 48.8 million): The component will support the effective implementation of the Project’s works, including the appointment of a supervisory engineering consultant and of the Procurement and Financial Management Agent (PFM Agent).
4.2. The following table summarizes tentative costs and proposed sources of financing (figures include price and physical contingencies).
5. Lessons learned and reflected in the Project design
5.1. The major lessons from the Bank’s prior experience are as follows:
(a) The need to strengthen internal financial controls and revenue collection mechanisms to ensure that incremental revenues are generated from additional power generation and that these additional moneys are used to sustain the sector. Accordingly, the Project includes a
These figures include taxes on consulting services estimated at about 18%. hid. Also includes refinancing ofPPF in the amount ofUS$3 million. Goods and works will not be subject to import duties or other taxes. Accordingly, no taxes are included, except as noted above for consulting services for Components 4: Capacity Building, and 5: Project Execution.
11 series of governance enhancement actions to improve SNEL’s financial management practices. In addition, the appointment of the PFM Agent will serve to strengthen procurement and financial management with respect to the Project specifically.
(b) The importance of complementing physical investment with strengthened managerial actions, in particular targeted at reducing the non-technical and collection losses, which can deprive utilities of the revenues needed to maintain the facilities financed under a project. Accordingly, the physical components are complemented by a component designed to improve revenue collection.
(c) Given the institutional weaknesses resulting in part from the conflict and post-conflict period, the need to limit the scope of actions in challenging post-conflict context. Accordingly, the Project attempts to focus on a limited set of discrete physical actions under a limited sector approach (construction of a transmission line, rehabilitation of the Inga site and rehabilitation of the Kinshasa distribution system, all of which lie along the IngalKinshasa corridor), rather than a broader more geographically dispersed set of actions.
(d) The need to balance power development that addresses export and large industrial clients with actions that benefit smaller domestic customers and households. Accordingly, the Project is designed to address both types of complementary activities.
(e) The importance ofpromoting ownership of activities, promoting sustainability through the use of existing structures, while also ensuring adequate technical management of capital investments. Accordingly, the Project design relies upon and empowers SNEL’s existing technical divisions rather than on the creation of a special implementation unit, while providing for strategic support (e.g., through the financing of a supervisory engineering firm to support SNEL).
(f) The importance of strengthening the capacities of GoDRC and SNEiL in soliciting and engaging with potential private sector partners. The Association is financing financial and legal advisors, as well as assisting the GoDRC in evaluating options for private sector involvement. Similarly, the Project provides funding for financial and legal advisors in respect ofthe development of Inga 3, which will involve commercial partners.
5.2. The Project will rely on implementation arrangements that build on SNEL’s technical capacities and role in the sector. However, given SNEiL’s weaknesses in procurement and financial management, the design also takes into account the success of other Bank-financed projects with alternative procurement and other fiduciary arrangements that compensate for Weaknesses in these areas through the use of the PFM Agent. In addition, the Association has experience to date in working with SNEL on the generation, transmission and distribution systems targeted under the Project, namely: (i)the Inga power plants (under the EMRRP Project); (ii)on the transmission system linking Inga with both Kinshasa (under the EMRRP Project) and southward to the SADC countries (under SAPMP APL-1 project); and (iii)on the distribution system in Kinshasa (under the EMRRP Project). The implementation ofthe Project should benefit fkom these earlier experiences.
6. Alternatives considered and reasons for rejection
6.1. Various alternatives were considered, both in terms of the overall scope of the Project and its components.
12 One alternative Project configuration considered (Component 1) was the rehabilitation of power plants located in Katanga. While these plants also help to serve the export market and industrial customers in Katanga, this activity was not ultimately included in the Project scope as it involved an activity that was geographically and operationally distant from the core activities within the Project, and so did not meet the benefits of relative simplicity in Project design that are gained by focusing on the IngaKinshasa corridor.
There were various alternatives considered with respect to the routing ofthe transmission line and to its sizing (Component 2). The route selected was viewed as the preferred option takmg into account environmental and social aspects (see discussion in the environmental/social section below). In addition, 220 kV and 400 kV linehbstation configurations were considered. The former was rejected as it was not viewed as being cost effective over the long run, given that it would not meet Kinshasa’s anticipated growing demand and would potentially require the eventual construction of a third separate line. The latter was rejected as premature, since the growth in demand over the next several years would not require a full 400 kV line and substations. Instead, an intermediate solution was selected in which the line would be constructed with a 400 kV configuration (building the towers and stinging the line itself is costly, and so it is efficient to make the pre-investment in stringing 400 rather than 220 kV lines), while the construction ofthe substations to operate the line at 400 kV was postponed to a later date.
0 Different configurations were considered for expanding the distribution network in Kinshasa (Component 3). Ultimately, the largest areas ofKinshasa that do not currently have electricity were chosen to be targeted under the Project. Other alternatives that were considered were electrifying a greater number of areas, but the remaining areas were relatively smaller and dispersing the electrification activity among too many areas was less cost-effective.
Consideration was also given to expanding the geographic scope of the areas to be targeted under the Project, including under the generation, transmission and distribution components. Given the operational and managerial challenges facing SNEL, there were numerous advantages from limiting the scope of the Project to a geographically discrete area. For example, Kinshasa was selected for the distribution component in part because it is directly related to the Inga production and transmission components and also because it is relatively cost effective to extend the grid to its urban and peri-urban areas.
0 Avenues for greater private sector participation in the short-term were also considered, but there were concerns regarding the benefits for DRC, in particular given the current context where the deteriorated nature of the sector might result in an unsustainable cost of capital or result in the mortgaging of the sector’s productive assets, thereby preventing these assets in the near term from servicing DRC’s domestic and other needs. Recognizing the importance ofprivate investment for the growth of the sector, the Project supports DRC and SNEL in developing a sound framework for attracting and developing sound public/private partnerships.
13 C. IMPLEMENTATION
1. Partnership arrangements
1.1. The Project involves co-financing. The AfDB is expected to provide about US$lOO million, principally for some works at Inga and for rehabilitation and expansion of the Kinshasa distribution network. GoDRC has approached the European Investment Bank (EIB) regarding financing for the second transmission line; GoDRC is also exploring funding from sources from the People’s Republic of China for the transmission line as well as for expansion of its distribution network. The co- financing agreements are to become effective no later than June 2008, with engmeering design and procurement beginning well before then (using in part engineering support to be financed with the IDA grant). In addition, the Agence Franqaise de De‘veloppement is exploring the possibility of providing support to strengthen SNEL’s commercial activities. Within the Bank Group, both IFC and MIGA are exploring opportunities for investing in the sector. The GoDRC and SNEL are also exploring financing for the sector (including the Project facilities) from other financiers (both public and private). GoDRC and SNEL recognize the need to ensure that such arrangements protect the development interests of DRC. SNEL has agreed under the Project legal agreements: (9 only to enter into agreements relating to thefinancing of rehabilitation or other works, or any concessioning or other similar arrangements regarding the Project facilities, under terms that protect the development interests of DRC in a financially and technically sound and equitable manner, and (il, to consult with the Association prior to entering into any such agreement. In addition, it is important to ensure that activities of other financiers and operators regarding the Project facilities are coordinated and that they comply with the Environmental, Social and Resettlement (ESR) Plan. Under the Project, SNEL has undertaken to ensure that all financiers of activities or operators at the Project facilities will co-ordinate their activities with those financed by the Association in a manner acceptable to the Association, and shall require such activities to be carried out in conformity with the ESR Plan.
1.2. In addition, various donors are actively exploring the further development of the Inga site. The AfDB is planning to finance a series of extensive feasibility studies for Inga 3 and Grand Inga. The Canadian International Development Agency has provided financing for a study of Inga 3 focused initially on environmental issues.
2. Institutional and implementation arrangements
2.1. The Project will primarily rehabilitate and expand the integrated power grid owned and operated by SNEL. Accordingly, the Project will principally be implemented by SNEL. Project implementation will rely on existing departments within SNEL’s Operations and Support groupings, which include separate departments dedicated to the following functions: (i)the facilities at Inga; (ii) the transmission system linking Inga to Kinshasa; (iii)the distribution network in Kinshasa; and (iv) commercial operations for the Kinshasa area. In addition, MoE will be responsible for its own capacity building activities (under Component 4(b) ofthe Project).
2.2. MoE and SNEL have created a project coordination grouping (to be formalized as part ofa Project Coordination Unit - the “PCU’ - as a condition of efectiveness) responsible for coordinating implementation of the Project. The PCU will be headed by a project co-coordinator appointed by the MoE. The PCU comprises staff from both SNEL and MoE, and includes two key subunits:
(a) SNEL’s project coordination team, established within SNEL to provide coordination under the Project among the various SNEL departments and to ensure proper execution ofthe various administrative and other tasks associated with implementation of a donor-financed
14 operation (including support on procurement issues and ensuring coordination with and among the various Project co-financiers), and
(b) the MoE unit, which draws from the MoE’s CATE team and is responsible for executing the capacity building components directed at MoE and for supporting MoE in providing overall strategic direction of the Project.
Each team has a designated leader, who will report to the PCU coordinator.
2.3. While SNEL possesses a moderate amount ofprocurement experience, its internal controls for financial management and procurement are considered too weak to confide these functions entirely to SNEL for a Project of this size and complexity. To address thefiduciary risks, a PFM Agent, operating under terms of reference acceptable to the Association, will be engaged by MoE during Project implementation to carry out the procurement andJinancia1 management function for the Project; the PFMAgent will be employed as a condition of effectiveness of the grant.
3. Monitoring and evaluation of outcomes/results
3.1. SNEL will monitor physical implementation of the SNEL Project Components through its traditional monitoring and control systems, supplemented by support from the PCU. SNEL currently measures through its power flow and financial monitoring systems the electricity generated and distributed through its system, as well as revenues. This monitoring system will provide the basis for measuring the outcomes and results. In addition, while it is currently difficult for SNEL to effectively measure the level of technical and non-technical losses in the Kinshasa distribution system, the Project will strengthen SNEL’s capacity to determine these levels, which will be monitored under the Project. The financial audits of SNEL will supplement this monitoring system. The Environmental and Social Management Unit (ESMU), supported by specialized technical assistance, will supervise implementation of the ESR Plan. The PCU will monitor implementation of the MoE Project Components and be responsible for overall project monitoring.
3.2. In addition, reviews will be carried out at least twice a year by the Bank, together with the PCU, to assess progress in implementing the agreed activities. The reviews will be coordinated with other donors financing the Project. The PCU will be responsible: (i)for preparation of the necessary documentation for the reviews; (ii)planning ofreview meetings and (iii)planning site visits.
3.3. A midterm review will be carried out 18 months after effectiveness of the Association’s grant to assess progress under the Project, achievement of overall objectives, and the contributions of the various partners. The PCU will be responsible: (i)for preparation of the necessary documentation for the reviews and (ii)for planning the midterm review meeting. The review will evaluate progress in reaching Project objectives, compliance with Project undertakings, including implementation of the ESR Plan, and identify measures needed to reach objectives.
4. Sustainability
4.1. Several factors should support the sustainability ofthe Project.
0 First, the nature of the physical investments requires limited subsequent ongoing operating costs (i.e., hydropower production entails limited variable costs as compared to diesel or other similar fuel generation).
15 Second, gains in revenue from the billinglcollection activities under the Project should support the effectiveness and sustainability of SNEL’s overall capacity building activities. SNEL’s actions with respect to governance enhancement should also help.
Third, the Project is expected to generate increased financial resources for SNEL, which should enable it to improve its maintenance operations.
Fourth, there appears to be increased demand within DRC for reliable power services, thereby creating both constructive pressure on the utility, but also support within Government, to improve SNEL’s performance.
Fifth, the SAPP is likely, in aggregate, to be in a net power deficit by the time of Project completion, thereby ensuring a reliable source of demand and hence export revenues from the incremental generation capacity to be financed by the Project.
5. Critical risks and possible controversial aspects
5.1. The Project presents several critical risks and possible controversial aspects. Controversial aspects include SNEL’s historical poor governance, an area to be addressed through the governance enhancement actions under the Project.
Table 2: Principal Risks, Ratings and Mitigation Measures H-High; S-Substantial; M-Moderate; L-Low Mitigation
S 0 Government actions to increase socio-political dialogue and to generate tangible economic gains, which build on the marked improvement over the last several years in the overall political context. The successful implementation ofthe recent elections. The recent successful installation of a new government should further support these efforts. S 0 Targeted preparation ofbidding documents during Project capacity, and delays in preparation phase implementing the Project 0 Existing studies on Inga and transmission system 0 Use ofa PFMAgent to manage procurement under the project 0 BorrowerEiank experience with similar bid packages Institutional support to Ministry and SNEL; building off project management units used in other DRC Projects S 0 Reliance on feasibility reports and experience under other Bank costs for the physical projects in the power sector in DRC components 0 The Project has been designed in a modular approach that permits resizing ofindividual components and sub-components to accommodate the possibility ofcost overruns SNEL governance issues S Development ofthe SNEL governance enhancement program and uncertain commitment Inclusion ofcapacity building component to governance reforms Clear understandings with SNEL management and Government regarding expectations Use ofa PFM Agent to assist on procurement and financial management aspects under the Project
16 Risks Risk Mitigation Rating Uncertainties regarding M Strong Government commitment to construction ofthe project sources of funding, facilities including donor and private Strong interest from donors and other sources sector involvement Undertaking from Government that activities financed by third parties to be carried out in compliance with the ESR Plan Clarify with Government/SNEL nature of co-financing arrangements SNEL to require coordination of all activities with IDA-financed activities Assist government in developing strategy for engaging private sector Technical hurdles L Upfront Project engineering Use ofexternal technical support, notably detailed design and supervisory engineering firm
5.2. Conclusion: Overall, the Project risk is Substantial
6. Loadgrant conditions and covenants
6.1. The conditions ofeffectiveness are:
0 Execution of a GoDRC/SNEL subsidiary loan agreement, in form and substance satisfactory to the Association.
Establishment ofthe PCU and a financial management system for the Project, acceptable to the Association, including: (a) recruitment of a PFM Agent (including adoption ofan accounting software); (b) adoption by the PCU of a manual ofaccounting and financial procedures; (c) recruitment of an internal auditor; (d) recruitment ofan external auditor; and (e) adoption ofan anti-corruption action plan for the Project.
0 Establishment within SNEL of an Environmental and Social Management Unit (ESMU), under terms ofreference and with staffing acceptable to the Association.
6.2. The main Grant covenants are:
0 The ESR Plan will be implemented in a manner satisfactory to the Association.
0 GoDRC shall employ the PFM Agent (the procurement and financial management agent) throughout Project implementation.
0 The ESMU within SNEL will be operated under terms of reference and with staffing acceptable to the Bank.
0 SNEL shall: (i)not later than October 3 1 of each year, adopt a maintenance program for the facilities under the Project and a related budget for the succeeding fiscal year, acceptable to the Association, (ii)thereafter implement such program, modified as necessary to properly maintain the facilities, and (iii)not later than October 31 of each year, report on the implementation ofthe such year’s maintenance program.
17 0 SNEL (i)shall only enter into agreements relating to the financing of rehabilitation or other works, or any concessioning or other similar arrangements, regarding the Project facilities under terms that protect the development interests of DRC in a financially and technically sound and equitable manner, and (ii)shall consult with the Association prior to entering into any such agreement.
0 SNEL shall ensure that all financiers ofactivities or operators at the Project facilities will co- ordinate their activities with those financed by the Association in a manner acceptable to the Association, and shall require such activities to be carried out in conformity with the ESR Plan.
SNEL shall employ a supervisory engineer during Project implementation, under terms of reference satisfactory to the Association.
0 SNEL shall adopt a dam emergency preparedness plan by December 3 1,2007 that reflects the comments ofthe Association.
0 GoDRC and SNEL shall implement their respective following undertakings regarding enhancing governance in the electricity sector:
a. SNEL shall have its financial statements audited annually, which shall be published in its annual report by the third trimester of each subsequent fiscal year;
b. GoDRC shall strengthen the oversight effectiveness of SNEL’s Board of Directors by providing for the designation: (i)of one external director responsible for overseeing audit issues, (ii)a second external director responsible for overseeing procurement issues, and (iii)a third external director responsible for strengthening the flow of information between SNEL and the Board;
c. SNEL shall undertake an evaluation ofits public/private partnership agreements;
d. GoDRC and SNEL shall promptly and regularly publish all contracts entered into after March 1, 2007, relating to sale, concessioning, joint-venturing or other arrangements with the private sector;
e. GoDRC and SNEL shall adopt a process for public/private partnerships that provides for sound and equitable financial and technical partnerships, ensures transparency and favors competition;
f. GoDRC and SNEL shall implement conflict of interest and financial disclosure requirements for SNEL’s Board Directors and SNEL’s senior executives; and
g. SNEL shall implement the capacity building activities under the Project designed to improve its governance, including strengthening its financial control and procurement systems.
18 D. APPRAISAL SUMMARY
1. Economic and Financial Analyses
1.1. The economic and financial analyses are based on a set oflargely common factors:
a. Inga Rehabilitation - Increase in MW. The rehabilitation of the generation facilities is expected to increase production capacity at the site by about 600 MW, from about 700 MW to about 1300 MW. The increase will be incremental, averaging about 150 MW per year beginning end 2009 through end 2012. From a purely technical perspective, given the run-of-river quality of the Inga site and the hydrological conditions, the plant load factor could be 85 percent or higher. However, given that there is not expected to be a demand for the totality of the potential output of Inga during off-peak hours, the analysis ofthe benefits ofthe Project is based on an assumption ofa 70 percent load factor. Thus each incremental MW of capacity can be expected to generate 6,132 MWper year.
b. Second InmKinshasa Transmission line. The second transmission line from Inga to Kinshasa is anticipated to be commissioned in 2010 and is expected to increase the capacity to deliver power to Kinshasa from the current 450 MW (along the oversaturated existing 220 KV line) to well over 700 MW.
c. Markets for Incremental Power. The incremental power generated at Inga is anticipated to be destined for three distinct markets: (a) domestic consumption in Kinshasa, and to a lesser extent in Bas Congo, (b) exports, primarily to the SAPP and potentially to the CAPP countries (notably for Brazzaville in the Republic of Congo, where demand for power from Inga is expected to diminish as its own hydropower site comes on line), and (c) consumption by mining and other large industrial consumers in the Katanga and other areas.
d. Kinshasa Distribution. Currently, the Kinshasa distribution system is oversaturated, with transformers operating at precariously high levels of capacity, which result in localized loss ofpower and contribute to high technical losses. The Project will alleviate this stress on the system by financing rehabilitation of the existing system. In addition, the Project will also electrify several areas in Kinshasa not currently served where nearly 2,000,000 people live. The Project will fund 50,000 new connections in these areas, and, by providing the distribution backbone, will provide the basis for further connections at a relatively lower cost per connection.
e. Losses (including Auxiliaw Use ofPower). The following system losses and other uses are assumed for purposes of the economic and financial analysis: (1) for generation at the Inga site: auxiliary systems are assumed to consume 0.3 percent of generation; (2) for transmission losses: (i)10 percent for the HVDC line from Inga to Katanga, including transmission and conversion for HV and MV clients, and (ii)2.5 percent for the 220 kV AC line from Inga to Kinshasa, with in addition 0.5 percent in step-down losses; and (3) for the distribution system in Kinshasa: initially 15 percent technical losses and 10 percent non-technical losses, with technical losses gradually reducing from 15 to 12 percent as a result ofthe capital improvements financed under the Project. In addition, SNEL faces significant collection losses of about 50 percent for sales into the Kinshasa system (65 percent for smaller residential customers), but only marginal losses for sales to exports (which figures have been applied also to mining customers for purposes of this analysis).
19 f. Benefits and Revenues. The economic benefits are distinguishable into two major types: (a) the economic benefit from selling to domestic consumers, which has been evaluated based on a willingness-to-pay analysis; and (b) the economic benefit from the export of power, which has been evaluated as a function of the sales price at export. For simplicity, the sale of power to domestic mining customers has been evaluated in the same manner as exports, namely the sales price. By comparison, the bases for the financial analysis for exports and sales to mining customers is identical to the economic analysis, but differs from the economic analysis for domestic customers in Kinshasa in two respects. First, while the economic analysis incorporates the benefits of power delivered to customers (i.e., net of technical losses only), the financial analysis is based on actual revenues collected (i.e., net of technical, non-technical and collection losses). Second, the actual tariff charged by SNEL, rather than the willingness-to-pay, is used for the financial analysis.
A. Economic Analysis
1.2. The benefits of the Project would include increased availability and improved quality of power supply for domestic use and exports, and resource savings from the reduction ofsystem losses. Further, the Project would assist SNEL’s institutional development through technical assistance to upgrade the technical, financial and managerial capabilities of SNEL’s staff and systems. The institutional support is expected to bring about sustained improvement in SNEL’s operational efficiency and financial performance.
1.3. The Project’s distribution component is an integral part of the best solution to address current inefficiencies and problems with the distribution system, while the transmission investment constitutes a part of the least-cost transmission investment to transmit additional power from existing and future generating power plants to the Kinshasa load center. The analysis conducted by SNEL for each component of the Project has been reviewed and found to be satisfactory. The Project constitutes a major part of SNEL’s least-cost investment activities. The Project has been analyzed over the period 2008-2030. The capital costs as well as operating and maintenance costs associated with the Project are shown in Annex 9. A minimum measure of economic benefits associated with the Project is represented by incremental sales. These in turn are divided between sales on the domestic market and exports. Sales to the mining sector and for exports are valued at the latest contractual price level negotiated ofUS cents 2.5kWh which could increase up to US cents 3.9kWh in 2015. Incremental sales on the domestic market are valued at the average willingness to pay for electricity supply which has been estimated at US cents 6.15 kWh. Details of the analysis are shown in Annex 9. The current average domestic tariff is, by its nature, more a measure of the adequacy of tariffs than of the true economic merit ofthe project, and is evaluated as part of the financial analysis below.
1.4. The results of the economic analysis show that under these assumptions, the net present value ofthe Project is US$501 million and the internal rate ofreturn is 29 percent. Consumers are the biggest beneficiaries of the Project, followed by SNEL. The results of the sensitivity analysis demonstrate that the Project is robust to significant variations in its main variables (i.e. capital cost and sales revenues):
20 25%
1.5. The alternative configurations for meeting the Project’s objectives are limited. One alternative would be the construction of a new hydropower plant; however, a new construction is estimated to be costlier (US$1 million or more per installed MW) than the rehabilitation of the existing Inga plant (estimated at US$0.3 million per installed MW); the new construction would also take longer than rehabilitating the existing turbines. Another alternative is the construction and operation of a thermal power plant near Kinshasa to supply the main domestic load center. The investment costs alone would be at least about two to three times the cost of rehabilitating the Inga hydropower plant or about US$400-600 million for generation alone (excluding fuel costs, a major item in a thermal power plant). This would eliminate the need for a large part of the transmission line, but would necessitate either the construction of a fuel pipeline (estimated at over 250hfrom Matadi, DRC’s main port, which itself is in need of extensive rehabilitation), or ferrying the fuel through a variety of means (barges along the Congo river and then by truck), which presents major logistical issues and reliability concerns. In addition, DRC would have to pay on an ongoing basis, the costs for fuel that is hampering thermal power plants in many other countries. The least cost option to supply the needed energy for the domestic and export markets is the rehabilitation of the Inga hydropower plant and the construction of the second transmission line from Inga to serve Kinshasa. The no-project alternative would deprive DRC of the needed improvements in the power sector and the anticipated US$501 million ofnet economic benefits (as calculated on an NPV basis).
1.6. Regional Dimension of the Project. The Project has additional economic benefits at a regional level that have not been directly quantified. First, the increases in the available capacity in DRC and in the energy flows between DRC and the other SAPP countries are essential steps to deepen the short and long term markets for power trading in the region. By decreasing the total reserve capacity in the southern Africa region, important savings in investment capital can be made. Furthermore, the Project increases the security ofpower supply in the southern Africa region. Based on historical data, the probability of occurrence of a major drought in the SAPP countries every 10 years is high. One exception is DRC, which benefits from the very large catchment area of the Congo River spread on both sides ofthe equator. Thus, the Project will enable the use of DRC’s generating plants as a backup to mitigate the impact of a possible drought on electricity production in the rest of the SAPP countries. Finally, the increase of cheap hydro electricity supply will substitute for thermal plant generation and contribute to the reduction of fossil fuel emissions.
B. Financial analysis
1.7. The entirety of the investment and operating costs associated with the Project will be borne by SNEL. However, in part because of low electricity tariffs and poor revenue collection in Kinshasa, the financial returns for SNEL are significantly lower than the economic returns. In the Base Case, the NPV is US$293 million and the financial rate ofreturn is 20 percent (as compared to US$501 million and 29 percent for the economic analysis). The NPV of the Project for SNEL remains positive under the various scenarios considered.
21 Financial Internal Rate ofReturn ofthe Proiect Financial Analysis - Sensitivity NPV FIRR(%) Base Case 293 20.4% (1) 20% increase in investment costs 216 17.4% (2) 20% reduction in revenues in Kinshasa 254 19.3% (3) 20% reduction in revenues from mining and exports 198 17.8% Low case: (1) + (2) + (3) 81 14.1%
1.8. From a cashflow perspective, the Project should improve SNEL’s financial position, even taking into account the on-lending terms. Even in the least favorable scenario studied, the FIRR of 14.1 percent is significantly above the 5 percent on-lending interest rate. Also, the payment schedule (with its 5 year grace period) would ensure that the first principal repayments take place only after the investments are completed and have started to generate additional cashflow for SNEL.
2. Technical
2.1. The technical design ofthe Project is considered to be sound. The physical components of the Project are based on comprehensive feasibility studies. These feasibility studies have been approved by the Government and have been reviewed by the Association. International consultants will be employed under the Project to assist SNEL in engineering design, bid documents and project management.
2.2. Generation and distribution rehabilitation components were selected based on a technical assessment of options ranging from no rehabilitation, to repairinglrenewing the system or replacing the system entirely. The generation rehabilitation work is expected to improve plant performance and performance parameters will be guaranteed by the rehabilitation contractor.
2.3. The new transmission line involves standard technology for high voltage transmission line and substation construction. Specifications for equipment are consistent with the design and structure of the existing network and include all appropriate safety measures. The design outlined in the feasibility study has been approved by SNEL. The company proposes to engage a single contractor for the detailed design, supply and installation of the transmission line. SNEL will also use a single design firm and supervisory engineer for the generation, transmission and distribution components, which will ensure accountability and facilitate Project management.
2.4. The Project will employ modem technological practice in rehabilitating the distribution networks including: (a) utilizing underground cabling technology to replace rundown overhead electric lines in urban areas; (b) replacing old equipment with more efficient and standard equipment; and (c) continuing the phasing out of non-standard medium voltages to provide more reliable and efficient operation of the distribution system and to minimize the costs ofnetwork maintenance and expansion.
3. Fiduciary
3.1. As noted above (under Institutional and implementation arrangements), while SNEL possesses a limited amount ofprocurement experience, its internal controls for financial management and procurement are considered too weak to confide these functions entirely to SNEL for a Project of this size and complexity. To substantially reduce the fiduciary risks, a Procurement and Financial Management Agent (PFM Agent) will be engaged by MoE to carry out the procurement and financial management functions for the Project. Payments for contractual services under all components will be jointly authorized by the PFM Agent and SNEL, except: (i)for subcomponent 4(b) executed by
22 MoE, which will be managed by the PFM and MoE, and (ii)for the PFM Agent contract itself, which will be authorized by the PCU. See also the discussion in Annex 7 (Financial Management) and Annex 8 (Procurement) for related analysis.
4. Social
4.1. Social, environmental and resettlement issues are addressed in the context of the Project’s ESR Plan. SNEL’s concession at the Inga 1 and Inga 2 hydroelectric power stations consists of 21,000 hectares. This concession includes the future sites for Inga 3 and Grand Inga. The ESR Plan’s review concluded that the population who had the land use rights at the time of the construction of Inga 1 and Inga 2 had been adequately compensated. Most of these people live outside the concession.
4.2. The rehabilitation of the Inga 1 and Inga 2 hydropower plants does not involve any land acquisition or resettlement. The routing for the second transmission line from Inga to Kinshasa ending at the Kingatoko substation has not yet been finalized. Land acquisition will be required. The Project’s resettlement framework (RPF) and framework for managing cultural properties (MCHF) were disclosed in-country and were subsequently disclosed in the Infoshop in Washington on January 18,2007.
5. Environment
5.1. The site of the Inga 1 and Inga 2 hydroelectric power stations is located approximately 150 km from the mouth of the Congo River. The area is sparsely populated and consists mostly of savanna with gallery forests in the valleys. The construction of Inga 1 was finished in 1972 and Inga 2 in 198 1. The Inga 1 and Inga 2 hydropower stations use the same 9 km long canal for their water supply. Only a fraction of the water from the huge Congo River has been diverted into this canal for hydropower production. The environmental impacts of the construction and operation of the Inga 1 and Inga 2 Hydropower Plants were and still are moderate and manageable, and there are no legacy issues to consider. The transmission line from Inga to the Kingatoko substation in Kinshasa passes mostly through agricultural land. A sensitive forest area near the Inga hydropower station has been avoided. The transmission lines pose manageable environmental impacts which will be mitigated by the actions described in the Environmental and Social Management Plan (ESMP). The Environmental and Social Impact Assessment (ESIA) and related documentation were disclosed in- country and were subsequently disclosed in the Infoshop on January 18,2007.
6. Safeguard policies
6.1. The project has been classified as a Category B project. The anticipated environmental impacts of the rehabilitation of the Inga 1 and Inga 2 hydropower plants are moderate and manageable. There will be almost no change in the hydrological regime of the Congo hver. Dredging and re-profiling of the 9 km canal will be needed to bring the capacity closer to the design capacity. The dredging sludge will be tested for chemical pollution. Based on the test results, a safe disposal place will be identified. There are macrophytes and likely PCB problems which need to be managed. Water quality monitoring will be strengthened in order to optimize reservoir management. HIV/AIDS will be managed during construction. The ESMF and other documents within the ESR Plan describe environmental and social aspects of the Project that will need to be managed, at the level of individual components, including applicable environmental and social regulations. The present Project has been categorized as a Category B project, as a result of the expected moderate impacts. An Environmental and Social Management Unit will be established within SNEL (as a condition ofeffectiveness) to assist in implementing the ESR Plan. The contractors will prepare their
23 own environmental and social management plans, which will be based on the ESMP prepared for the project. The Project poses a moderate potential reputational risk for the World Bank.
6.2. Dam Safety. Consistent with OP 4.37, and according to TORSdeveloped in consultation with the relevant Bank specialist, a consultant dam safety engineering firm has completed for SNEiL a review of the hydroelectric facilities at the Inga site. No significant concerns were identified, and a strengthened program ofmaintenance was recommended. Under the grant, SNEL has agreed that it shall adopt a dam emergency preparedness plan by December 31, 2007, that reflects the comments of the Association. SNEL has employed a consultant to assist it in the preparation of the plan. SNEL has also agreed, as a covenant of the Grant, to submit to the Association, by October 3lstof every year, a facilities and network maintenance plan and associated budget for the forthcoming financial year for Inga and the other Project facilities, and to report on implementation of the plan.
6.3. International Waterwavs. OP 7.50 applies to projects that involve the use of international waterways. The Inga rehabilitation component (Component 1) will involve the use of the Congo River, an international waterway that DRC shares with 8 counties and, as such, OP 7.50 applies. However, the Inga dam is a "run of the river" plant, and the proposed activities (rehabilitation of the dam, dredging and reprofiling of the intake canal) will not modify the water volume. On this basis, and as set out in paragraph 7(a) of OP 7.50, this Project is exempt from the requirement to notify other riparian states about the Project, as the activities will alter neither the quality nor the quantity of the water flowing to other riparian states, nor will the Project be adversely affected by the other riparians' possible water use.
6.4. Pest Management. The vector control program for black flies at the Inga site will involve the use of the pesticide Permethrin, which will be effected in accordance with the Pest Management Plan (PMP), which has been approved by the Bank. Disclosure ofthe PMP in-country and in the Infoshop was made in April 2007.
6.5. Cultural Propertv. The MCHF (framework for managing cultural properties) has been prepared, was approved by the Bank and was released in-country and filed in the Infoshop in January 2007. Sensitive sites include caves in the targeted project area.
Safeguard Policies Triggered by the Project Yes No Environmental Assessment (OPBP 4.0 1) [XI [I Natural Habitats (OPiBP 4.04) [I [XI Pest Management (OP 4.09) [XI [I Cultural Property (OPN 11.03, being revised as OP 4.1 1) [XI [I Involuntary Resettlement (OP/BP 4.12) [XI [I Indigenous Peoples (OPiBP 4.10) [I [XI Forests (OPBP 4.36) 11 [XI Safety ofDams (OPiBP 4.37) [XI 11 Projects in Disputed Areas (OPiBP 7.60)' [I [XI Projects on International Waterways (OPiBP 7.50) [XI [I
7. Policy Exceptions and Readiness
7.1. The Project complies with all World Bank applicable policies and no exceptions are required. The Project is ready for presentation given:
24 a. the procurement plan for the first two years has been established; b. the RFP for the detailed engineering firm has been issued, and the technical proposals are being evaluated, c. the request for expressions ofinterest for the PFM Agent has been launched; d. the request for expressions ofinterest for the firm to strengthen SNEL’s financial systems has been launched; and e. the SNEL and MoE project coordination teams are operational, and the PCU structure has been delineated.
25 Annex 1: Regional, Country and Sector Background AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb)
A. Regional Context
Southern African Power Pool
1. Southern Africa exhibits substantial variations in energy resource endowments, degrees of industrial development, levels and patterns ofpower consumption and power costs. These differences present opportunities for coordinated development of the regional power sector to: (i)generate savings through aggregation of loads with different load profiles, (ii)achieve efficient use of energy resources by exploiting large scale power generation schemes that are viable only on the basis oflarge multi-country markets, and (iii)manage the risks ofclimate- related power shortages in hydro-dependent countries. In recognition of the potential benefits, in August 1995, SADC member countries created the Southem Ahcan Power Pool (SAPP) by concluding an Intergovernmental Memorandum of Understanding and related agreements which together govern the operation of the power pool. The utilities of 12 southern Ahcan countries are members ofthe SAPP.4
2. SAPP started as a cooperative pool, that is, a pool under which members would seek to maximize economic and system reliability benefits through trade, while retaining maximum autonomy for individual members. However, in the longer term the SAPP aims to facilitate the development of a competitive electricity market in the SADC region. Currently there are two market mechanisms used in SAPP energy exchanges: medium-to-long term bilateral power purchase agreements and the Short Term Energy Market. An update ofthe long-term least-cost generation and transmission expansion study (the ‘Pool Investment Plan’) for the SAPP was started mid-September 2006, and is expected to be completed before end-2007.
DRC Hydro Resources in a Regional Context
3. DRC has enormous hydropower potential, estimated at about 100,000 MW - or 13 percent of global hydropower potential. Much of this potential is located in a single site, the Inga dam site on the Congo River, located 125 miles downriver from Kinshasa, with a potential capacity estimated at about 45,000 MW. With energy resources on this scale, DRC has the potential to play a pivotal role in meeting not only its domestic energy needs, but also the energy needs of neighboring counties and beyond. Today, the Inga site provides power both southward (notably to the Southern African Power Pool - the SAPP) and northward (to the Central African Power Pool - the CAPP). Power supplied from DRC will be a critical enabling factor for the development of a competitive power market in both sub-regions, with reliable, low-cost power supporting industrial competitiveness, private sector investment and regional growth and development. As a consequence, DRC generally and the Inga specifically are currently central to most discussions in southern and central Africa to developing hydropower resources on a regional basis.
4 Inter-connections among the main grid systems of Botswana, DRC, Lesotho, Mozambique, Namibia, South Africa, Swaziland, Zambia, and Zimbabwe form the basis ofthe regional network. Angola, Malawi and Tanzania are not yet connected.
26 4. NEPAD has designated the development of the Inga site as a priority under the regional development programs. As such, NEPAD, the AfDB and other institutions are actively supporting the development of Inga’s power potential in three distinct but interrelated stages: (i)in the short-term, the rehabilitation of the existing facilities, which operate at less than 40 percent of installed capacity; (ii)in the medium-term, the development of a new hydro- power facility, with about 3,500 MW of capacity (likely the Inga I11 site or, possibly, an initial phase of the Grand Inga project); and (iii)in the longer-term, the full development of the additional 40,000 MW potential of the site (the “Grand Inga” Project).
5. Reflecting its geographic position and the centrality ofthe Inga site, DRC is a member of both the SAPP and the CAPP. Currently, DRC’s state electricity utility, Sociit6 Nationale d ’Electricit6 (SNEL), has long-term bilateral contracts for power exports to South Africa and Zimbabwe (about 100 MW each). These sales generate valuable foreign exchange revenues for DRC. For its regional neighbors to the south, DRC’s hydro-power (from Inga and other sites) provides benefits that include a low-cost and low-carbon alternative to thermal generation capacity (especially for those countries, such as Zimbabwe, that have no low-cost, indigenous sources of electricity) and a diversified source ofpower for countries extensively reliant on domestic hydropower. Discussions are currently underway about linkmg Zambia to Tanzania, thereby providing a route for DRC’s power to also supply countries in eastern Africa. It is anticipated that the incremental hydro-production from Inga will substitute for carbon intensive fossil generation and so may be eligible under the Clean Development Mechanism.
6. With excess generation capacity in the region forecast to diminish, DRC’s hydropower potential (and specifically the resources available at Inga) will play an increasingly central role in the successful further development of the SAPP. SAPP members have drawn up a list of high priority projects, backed by both SADC and NEPAD. Electricity supplied by DRC will be pivotal to some of these Projects. These projects will allow Inga to supply significantly more power to the SAPP member countries, both through increased sales to existing customers and to new off-takers.
7. There are, however, several constraints preventing this demand from being met via the existing infrastructure. They include the transfer capacity of a part of the regional interconnection between DRC and Zambia; capacity and performance restrictions of the AC power system in the Katanga region in DRC; capacity and operational status of the High Voltage Direct Current (HVDC) link between Inga and Katanga; and the need to refurbish the generating plants in the DRC, notably at Inga.
8. The Projects in the Southern Afkican Power Market Program (SAPMP) APL series currently in preparation or being implemented will remove some of these constraints. Zambia and the DRC are to upgrade their current 220-KV regional transmission corridor to a much higher specification to allow other SAPP countries to tap Inga’s energy supplies. To this end, Zambia’s Copperbelt Energy Corporation (CEC) and SNEL are discussing a project to construct a new 220-KV line running in parallel to the existing interconnection between Chingola in Zambia and Karavia near the southern DRC city of Lubumbashi. In addition to the new transmission line, the two countries will also repair the existing 220-KV line. More details on the SAPMP are provided in section C below.
9. DRC’s hydro resources are also viewed as central to the development of the CAPP. SNEL currently exports about 50-80 MW from Inga north to Brazzaville (Republic of Congo) along a 220-kilovolt (KV) connection. SNEL has had discussions about supplying industrial
27 clients in Pointe Noire (Republic of Congo), possibly via a transmission line through the Cabinda region of Angola, which would simultaneously allow power off-take in Cabinda. The CAPP has initiated donor-funded studies of this and other prospective regional inter- connection projects. It is expected that exports in the medium term to Brazzaville will decrease as power plants being commissioned in the Republic of Congo, including the hydro plant at Imboulou, come on line. However, the Inga supply will remain an important source of supply security for Brazzaville. Looking further afield, there is also potential for electricity generated at Inga to supply the West AhcaPower Pool.
10. Towards the east of the country, the focus of the regional collaboration in the energy sector in the Great Lakes region is la Sociktk Internationale d’Energie des Grands Lacs, a joint company wholly-owned by Burundi, Rwanda and DRC and established in 1984, with the support ofthe World Bank, to build and manage a group ofjoint energy sector operations in the Great Lakes region. The company’s main operation is the Ruzizi I1hydropower plant at Mumosho in the DRC, which supplies power to all three countries. The company has faced extensive financial and operating difficulties (in part the legacy of the years of conflict in the sub-region); the World Bank, building on security improvements in the area, is currently supporting efforts to help the utility strengthen its operations and financial position. However, even as these efforts go forward, other challenges emerge, including the recent drops in the water level in Lake Kivu that reduce Ruzizi 11’s output potential.
11. In summary, DRC generally, and Inga specifically, lie in many respects at the center of gravity of discussions on regional power in sub-Saharan Ahca. DRC, however, has not yet managed to capitalize on this opportunity. A range ofprojects currently under commission or consideration will allow DRC and its neighbors, near and far, to tap the country’s extraordinary hydropower potential, in particular from the Inga site. These efforts, however, necessarily hinge on the rehabilitation of the existing Inga site in two distinct ways: first, rehabilitating Inga provides incremental power to supply the SAPP and the CAPP countries; second, larger scale development of the Inga site (such as Inga 3, which will require over US$4 billion in investment) depends on DRC demonstrating the ability to assure the sound operation of the existing Inga 1 and 2 facilities.
B. Country Context
12. The size of DRC’s promise has, unfortunately, been undermined by its challenges. It is potentially one of Africa’s richest economies, with extensive mineral, energy and natural resources. It is a potential dynamo for regional growth, with its large labor force and potential market size, extensive navigable inland waterways and land links to nine states. Yet hopes of tapping this rich potential have been repeatedly thwarted. Successive governments have failed to translate the country’s assets into improved standards of living for the Congolese people. The level of physical and social devastation caused by decades of mismanagement, starting in the colonial era, worsening during the regime of Mobuto Sese Seko and compounded by extended periods ofconflict since 1997, has been great.
13. Today, the country is embarking on systematic efforts to overcome the legacy of mismanagement and conflict. The recent elections mark an important moment in Congolese history when the government, parliament and local authorities have assumed power through a democratic process. With a new cabinet appointed in early February 2007, the post-election period provides a rare opportunity to push forward with much-needed reforms. These efforts, however, will face a complex array of factors: the delicate democratic transition currently
28 underway, the legacy of conflict, ongoing regional tensions, economic and social collapse, and the weight of a legacy of corruption.
B 1. Political backdrop
14. The recently concluded presidential elections, won by incumbent President Joseph Kabila, mark a new chapter in DRC’s turbulent recent political history. The second run-off vote passed off remarkably smoothly. The elections come after a forty-year history of political instability and conflict. Decades of misrule under Mobutu saw DRC entering the 1990s in a state of economic and political collapse. The institutional mechanisms associated with an effective state - legislative, judicial, regulatory and others - became increasingly hollowed out from within, leading to recurring political instability and increasing levels of violence throughout the decade. The civil war that erupted in 1997 pitted a variety of Congolese rebel movements and quickly became a complex regional conflict, involving several neighboring countries. After several false dawns, a durable peace process was instigated in 2001 leading to the withdrawal of foreign troops and the formation in 2003 of a transitional government of national unity with representation of all key armed groups, opposition groups and civil society. In December 2005, a new constitution was approved by popular referendum, leading directly to the recent elections for a directly elected government.
15. The elections mark the culmination of extended efforts to put in place a sustainable peace and reconciliation process. The international community has provided intensive support, notably through the deployment of a 16,500 strong UN peacekeeping force (MONUC). The mediation ofthe United Nations and the Afncan Union, as well as the support ofkey bilateral partners has also been critical. With the successful holding of elections, DRC is entering a new phase ofits post-conflict recovery.
16. The elections are an achievement not to be under-estimated, marlung the first time in Congolese history that the government, parliament and local authorities have assumed power through a largely free and fair democratic process. With a new cabinet appointed in early February, the post-election period will be a rare opportunity to push forward with much- needed reforms. At the same time, the political context is likely to remain turbulent. While widespread violence - with the exception of localized fighting in the north and east of the country - has subsided since 2003, the political transition was marked by disunity. Ongoing challenges face the government, as reflected in the instability in Kinshasa in March 2007.
17. President Kabila and his new government face several immediate challenges. First, a fragile majority in parliament may stymie stabilization and reform efforts. Second, significant opposition - both political and popular - remains in Kinshasa itself following the election. Third, disaffection in several regions will likely pose a challenge to central government authority. The way in which these risks are handled will be critical for the viability and sustainability of external interventions in DRC.
B2. Economic & Social Backdrop
18. The legacy of conflict, mismanagement and political paralysis over the past forty years has been a near-collapse ofDRC’s economy. Per capita income has declined from US$380 in 1960 to US$120 in 2004. Between 1997 and 2002, disease, deprivation and casualties in the civil conflict caused more than 3.3 million deaths.
29 19. During the Mobutu era, the Congolese economy was dominated by export-oriented extractive industries. These provided little by way of jobs or other income-generating opportunities, with the vast majority of the population remaining in subsistence-level agriculture and informal activities. The war intensified the economic hardship. Investment slumped, bringing the export-oriented industries to the verge of collapse. Conflict destroyed livelihoods and stripped millions of people of livestock, property, tools and other productive assets. Physical infrastructure deteriorated. Intangible infrastructure - particularly the . machinery of government and state institutions - also withered.
20. Since 2001, a degree of economic stability has returned. Inflation fell to below 10 percent in 200 1. Price liberalization has increased food availability in urban areas. Improved public expenditure management has grown public revenues, and structural reforms in the public and financial sectors have been launched. As a result, economic growth turned positive in 2002 and has remained above 5 percent since. These efforts have been rewarded by a strong private sector response, with US$2.7 billion in new investments in a range of sectors - including telecom, construction, agro-business and extractive industries - registered since 2003. Investment at this scale provides a hint of the country’s enormous economic potential. For now, though, improvements in state institutions and the economy have not reached all regions ofthe country.
2 1. Despite this nascent economic recovery, human development indicators for DRC’s people remain poor. The logistical challenges in DRC remain formidable. Many provincial capitals are difficult to reach by road. It has been estimated that 3.5 million people remain internally displaced. 75 percent of the population lives on less than a dollar a day. While detailed statistical information is lackmg, available indicators point to declining life expectancy and increasing childhood mortality. Most of the MDGs are likely to be missed. The challenges are formidable.
B3. Governance backdror,
22. The Mobutu regime was synonymous with extensive corruption, embedding the expectation of significant and rapid private gain from public office. The conflict and political transition allowed these governance failures to continue, in part through a lack of effective sanctions mechanisms. As a result, corruption remained endemic, with DRC ranked 144 out of 158 countries by Transparency International. State institutions and parastatals are key sectors that have been particularly badly affected.
C. Sector Issues
C1 Overview, Access and Demand
23. Despite the country’s enormous power potential, DRC has managed neither to capitalize on the opportunity of significantly higher electricity exports across Ahca nor to provide adequate energy services for the vast majority of its own population. Household access is about 6.5 percent ofhouseholds, compared to the average for sub-Saharan Ahca (exclusive of South Africa) of 20 percent, leaving the country in the bottom 15 of sub-Saharan Africa. Frequent blackouts hit even high priority parts of the network. Electricity consumption per head was 9lkWh in 2002, down from 161 kWh in 1980. Traditional biomass fuel is now estimated to account for 86 percent of total energy use in the country, with diesel/oil at 8 percent, electricity shrinking to 4 percent and coal accounting for the remaining 2 percent.
30 24. The proximate cause of these very low energy access rates is the state of DRC’s electricity infrastructure. All parts of the network deteriorated extensively in the 1990s as a result of extensive theft (both of physical components and via financial embezzlement) as the security situation worsened, from direct conflict damage and, most importantly, from a lack of maintenance and a dearth of replacement parts. Underlying all these factors was the weakening of the institutional capacity to maintain the system. SNEL, the vertically- integrated parastatal power utility that dominates the generation, transmission and distribution ofelectricity in DRC, faces wide-ranging financial, management, governance and operational challenges. Improving the quality and quantity of electricity service in DRC will require significant improvements in SNEL’s maintenance and upkeep program. SNEL has agreed, as a covenant under the Grant Legal Agreements, to submit to the Association, by October 31st of every year: (9 a facilities and network maintenance plan and associated budget for the forthcoming financial year, and (ii) a report on maintenance expenditures incurred to date in the currentfinancial year.
25. Total demand (as represented by sales) in 2005 was about 5700 GWh, with low voltage power accounting for about 50 percent. Demand is projected to increase annually by about 7 percent in the coming five years, but could increase significantly more as the electricity infrastructure expands.
26. Loolung forward, the Government has identified several priority objectives for revitalizing the electricity sector: (a) meeting local business needs and satisfying unmet domestic demand, thereby supporting economic recovery and growth; (b) stemming losses that negatively impact the sector’s financial integnty; and (c) exporting electricity, to generate foreign exchange and improve the strategic positioning of DRC within a regional context.
C 1. The Network
27. DRC’s entire electricity network is under severe strain. The combination of the saturated transmission system, limited generation capacity and technical operating constraints (that include high loss rates and poorly maintained equipment) combine to produce an electricity supply system with a very small capacity margin and inadequate levels ofredundancy in the system to avoid or mitigate frequent breakdowns. The problems are exacerbated by a weak institutional framework.
Generation
28. Only a small fraction ofDRC’s vast energy resources has been exploited. Despite having potential production capacity estimated at about 100,000 MW from hydro power alone, the country’s total installed capacity is approximately 2,400 MW, or less than 3 percent of that potential. Of this, hydropower accounts for nearly 99 percent, with the remaining supplied by about 60 small and isolated solid-fuel thermal plants. A handful of large industrial enterprises maintain their own production capacity. The two hydro plants at Inga between them account for 1775 MW of installed capacity (351 MW at Inga I,1424 MW at Inga 2), or roughly 70 percent of the country’s total.
29. Even this limited installed capacity runs significantly below potential. Some of the electricity generation infrastructure dates back to the colonial era - the oldest installed facility was constructed in 1929 - and has not been systematically maintained, overhauled or updated. Rehabilitation has tended to be on an ad hoc, emergency basis, resulting in outdated
31 and unreliable machinery. As a result, only 48 percent of installed capacity is actually available. Total annual electricity production in 2005 was around 7,100 GWh, or slightly less than 50 percent of what the installed capacity could potentially generate. With some of the smaller hydro-facilities wholly inoperative and only about one third of the small thermal plants functioning, some urban centers in more remote regions have had their gnd electricity supply completely cut off.
Power Station Number of Turbines Capacity (MW) Installed Operational Installed Available Western Region 27 7 1864 722
L Southern Region 20 14 476 365 Eastern Region 6 6 58 58 Other 10 6 48 25 2,446 1,170
30. The state of the Inga plants epitomizes the state of the country’s generation capacity. Currently, available capacity at Inga 1 and 2 totals about 700 MW out of 1775 MW of installed capacity. Both plants need urgent repairs as well as extensive rehabilitation for longer-term viability, in addition to extensive re-shaping, dredging and clearance of the heavily-silted water intake canals that supply the turbines. Given Inga’s role as the backbone of DRC’s generation capacity, the GoDRC views rehabilitation of the two plants as a high priority in order to improve the reliability and quantity of supply of electricity from Inga for both domestic and export markets.
3 1. GoDRC is also prioritizing other generation projects, including (a) targeted rehabilitation of existing plants in Katanga to support exports and supply prospective mining customers; and (b) electrification (and in some cases re-electrification) of major urban centers.
Transmission
32. The transmission system in DRC consists of several unconnected electricity sub- networks. There are three principal components that together span 5547 km (3447 miles):
A high voltage direct current line (500kV) that runs 1740 km (1081 miles) from Inga to the Katanga region; Three large sub-networks, composed ofhigh-voltage lines varying between 50kV and 220kV:
- The Western network, connecting Inga, Kinshasa and Lubumbashi, with further regional inter-connections for export ofelectricity to the Republic of Congo; - A Southern network in the Katanga region, receiving power from Inga and inter- connected with Zambia; - An Eastern network interconnected with Burundi and Rwanda.
A variety of independent mini-grids organized around smaller urban centers and industrial centers across the country, powered by small power plants.
32 33. The transmission system is under significant strain. Equipment is outdated, maintenance levels have been insufficient and new investment minimal. The system also has inadequate capacity to meet demand. In particular, lines connecting to Kinshasa and in the capital are heavily overloaded and operating beyond their design limits. The 220kV line connecting Inga and Kinshasa is oversaturated. The very high voltage line that connects Inga to the Katanga region currently carries only about one quarter of its design capacity.
Distribution
34. The distribution system is structured around four principal networks that between them account for 90 percent of total electricity consumption in the DRC and approximately 400,000 connections. The distribution system includes roughly 1920 miles of medium voltage (6.6 to 30kV) lines and 7239 miles oflow voltage (0.4kV) lines:
Distribution Network Connections Bas Congo 35,000 connections Kinshasa 290,000 connections Katanga 55,000 connections North & South Kivu 3 2,000 connections Other Isolated Systems 21,000 connections
As with the generation and transmission facilities, maintenance of the distribution system has primarily been on an emergency repair basis, with virtually no systematic rehabilitation. A litany of shortcomings has rendered the entire system highly unreliable, including saturated lines and transfonners and dilapidated poles.
35. Kinshasa is dependent on Inga for virtually all ofits power. Maintenance issues at Inga and limited capacity on the existing 220kV Inga-Kinshasa transmission line restricts supplies to the capital to about 450MW. There is an estimated additional 200 MW of unmet demand. Limitations in the current distribution system and lack of connections further constrain consumption. The result is that the approximately 290,000 connections in Kinshasa (representing an access rate of roughly 35 percent) experience frequent load shedding. Moreover, insufficient capacity, growing demand and a dilapidated network has resulted in significant voltage drops in the system in Kinshasa; in order to prevent further drops and greater instability in the network, SNEL is severely limiting new connections.
System Losses
36. The SNEL network is characterized by significant losses, at all stages of generation, transmission and distribution. The capital’s dilapidated distribution network and overloaded transformers result in heavy losses in Kinshasa. Distribution losses have been estimated at around 25 percent; according to gross estimates, these are split between 15 percent for technical losses and 10 percent for non-technical losses. In addition, ofthe total consumption billed in Kinshasa, only about 50 percent is actually collected.
C2. SNEL - The Vertically Integrated Parastatal Power Utility
37. An understanding ofthe poor state ofDRC’s energy infrastructure starts with the national electricity utility. SNEL manages the main components of the generation, transmission and distribution networks described above, including the isolated mini-gnds that power some
33 outlying towns, delivering 95 percent of all electricity produced in DRC. The company currently employs 6,500 staff. Details of SNEL’s organizational structure are provided in Attachment 1 to Annex 6.
38. SNEL’s technical and operational abilities appear to be sufficient to run the Inga facilities and the related transmission systems, but in overall terms remain weak as a result of a lack of skills upgrading and the loss of qualified personnel during the conflict. Of fundamental concern to the viability of SNEL’s operations are its financial position, internal governance and management weaknesses, and a poorly calibrated tariff regime. Taken together, they have caused SNEL to struggle to improve electricity services in the country.
39. The electricity sector in DRC has only been managed in an integrated fashion since the establishment of SNEL in 1970 from six private regional companies. As a result, the electricity system that SNEL inherited had not been built to consistent technical standards, being instead composed of different technical, equipment and planning standards (such as differing specifications for transformers or varying voltage levels in transmission lines). The lack of inter-operability between components represents an engineering challenge and entails higher maintenance costs, for both components and training.
40. During the war, SNEL was divided into three distinct entities, with very limited links between them. While the company has since been re-unified, management remains weak. The majority of decisions are made at the corporate level, but because reporting lines to the regional divisions remain weak, implementation is patchy. A chronic lack of institutional support - such as vehicles, equipment and up-to-date IT resources - considerably weakens management capacity. The company was recently re-organized into three main groupings. The Corporate Grouping runs the strategic functions that define long-term objectives, plans implementation and monitors performance. The Operations Grouping undertakes the principal activities of the company, including generation, transmission, distribution and marketing functions. The Support Services Grouping provides the human and financial resources for the activities of the other two groups. SNEL is in parallel undertaking a corporate revitalization plan, including efforts to improve management of its finances and operations. A more detailed description of SIWL is provided in Annex 6.
41. SNEL faces significant challenges in running the commercial aspects of its business. Collection ofrevenue for power provided is weak. For example, SNEL’s turnover in 2005 was US$174.3 million (i.e. total consumption billed), but only about 55 percent of moneys owed to SNEL were paid, with government agencies and parastatals the least likely to pay.
Collection Rates
42. These weaknesses and failures have helped to severely weaken SNEL’s financial position, and have helped to constrain the utility’s ability to deliver key power services. The
34 GoDRC has recognized that making progress on any of these fronts will require thorough reform at SNEL. The GoDRC and SNEL, currently operating under new management, have stated their joint commitment to increasing the quality and transparency of SNEL’s management. As the table above illustrates, improving billing and collection is vital and is a priority of SNEL management. Improving internal financial control systems is also key to any financial recovery effort. Organizational and financial evaluations audits have already been launched.
C3. Tariffs
43. SNEL’s tariff structure is divided into three key categories: high, medium and low voltage. Electricity for commercial customers in all three categories is priced in US dollars in order to reduce the financial impact of Congolese Franc inflation. Residential customers in the low voltage category are billed in Congolese Francs, which has resulted in a reduction in tariffs in dollar terms.
0 High voltage industrial customers are small in number - there are currently about 20 -but account for about 45 percent of sales. The average tariff in 2005 was about US cents 2.8kWh. Some of the customers in this group, particularly other parastatals, have had large payment arrears but, for political reasons, continue to be supplied.
0 Medium voltage clients number approximately 1,300 and account for approximately 15 percent of sales; the tariff in 2005 was about US cents 7.3kWh.
0 Low voltage customers, comprising residential, commercial and ‘public facilities’, have increased rapidly in recent years and there are now approximately 400,000 connections, accounting for approximately 40 percent of sales. Tariffs for commercial low-voltage customers average about US cents 11.6kWh. The large majority (80-90 percent) of residential customers, by contrast, lacks a functioning meter and instead pay for electricity services via a lump-sum system. Customers are grouped into five categories. While the system specifies a nominal upper limit of consumption, the lack of meters or consumption audits means that most customers are actually billed irrespective ofactual consumption. SNEL recognizes that this is a major source of non-technical losses and is exploring ways to address this issue (including implementing a trial system in which meters will be placed further upstream in low and medium voltage supply boxes, allowing exact consumption of all downstream residential connections to be measured). Tariffs for low voltage customers were increased in early 2007 by about 50 percent in an effort to compensate for the reduction in tariffs relative to their original dollar equivalency.
35 L ump-Su m Monthly Actual Actual Monthly Nominal Categories consumption Monthly Billing (US$)* Unit Charge (US (kWh) Billing (FC) cents IkWh) ** ‘Social’ Level 2: Neighborhoods of I 400 1440 3.00 0.75 Medium Staiding Neighborhoods Level 4: Outlying 900 5116.5 10.66 1.18 Neighborhoods 44. The tariff adjustment framework in DRC involves several government actors. Tariff changes are proposed by SNEL and brought to the tariff-setting committee (Comitk de Suivi de Tarzj) for discussion. The committee comprises representatives from five ministries (Energy, Finance, Economy, Planning, and the MinistBre du Portefeuille) and the National Energy Commission, as well as SNEL, but the shape of the final proposal is decided by the Ministry ofthe Economy, which then transmits it to the full Cabinet. 45. In summary, the tariff system in DRC has wide-ranging shortcomings. First, high levels of non-payment of bills from many customers, combined with a lump-sum system for residential customers that acts to decouple electricity consumption from billing, results in total revenues that do not cover SNEL’s operating and maintenance costs. Second, the combination of residential customer billing in Congolese Francs and high inflation in the intervening period has meant that residential tariffs have decreased in real terms. Third, the payment burden is unequally distributed, with certain classes of customers accounting for a disproportionately high share of total consumption charges. While significant changes to the tariff structure and levels may be appropriate (the Government has commissioned a tariff study which will provide input to this analysis), significant changes in this area will likely await improvements in service quality. C4. SNEL Comorate Governance 46. SNEL was created, as a legal entity, by ‘ordonnance-loi’ no. 70-033, of May 16, 1970. Building on this, law no. 78-196 of May 5, 1978 sets out in detail the charter and the legal basis on which the company operates, including its objectives, corporate structure and financial arrangements. As set out in Attachment 1 to Annex 6, law no. 78-196 stipulates the corporate governance mechanisms for SNEL, including the Board of Directors, the Management Committee and the CollBge des Commissaires aux Comptes (see description in Attachment 1 to Annex 6). In addition, the law stipulates that SNEL is under the joint supervision of the Ministries of Energy and of Portefeuille. The former ministry exercises technical supervision, with competency to oversee the organization of SNEL’s internal services, its operations, staff remuneration and the annual report. The latter ministry supervises administrative and financial aspects of SNEL’s activities, including actions that affect SNEL’s financial position (including external loans), budgetary and financial plans and real estate transactions. There are also areas where supervision overlaps between the two ministries, including when SNEL establishes external partnerships. 36 47. As set out in the relevant law, the supervisory ministries exercise their authority via three means, namely: 0 Ex-ante authorization, required for certain acquisitions, works or goods that exceed a certain threshold (about US$500,000 for certain transactions), loans with a tenor exceeding one year and the acquisition or sale of external financial interests. 0 ‘Passive approval’, where approval is deemed to have been granted when the relevant ministry does not intervene within the space of a month; these activities include the internal organization of SNEL’s departments, personnel issues, budgets and financial forecasts, and year-end activity and financial reports. 0 ‘Opposition’, whereby the supervisory ministry blocks a decision of the Board within five days of the notification having been received (which implies that any Board decisions are not deemed to have been executed until five days after their receipt at the relevant ministry). 48. Despite this legal framework for SNEL’s corporate activities, the company faces numerous corporate reporting and management issues. Reporting and management lines between the Government and SNEL are somewhat unclear in practice. SNEL’s Board of Directors, composed of the four-person ‘internal’ Management Committee plus five ‘external’ directors (all of whom are appointed by the President of the Republic), plus a representative from each supervisory ministry, does not have an explicit framework of goals and objectives guiding the company’s activities. The infomation flow between SNEL and the Board has at times been inadequate, undermining the ability of the Board to exercise oversight. Recognizing these weaknesses, the Government and SNEL are taking actions to strengthen corporate governance (see discussion on governance in Attachment 1 to Annex 4). There is currently no statutory electricity regulator, although discussions are underway to evaluate this option. C5 Rural Electrification 49. A Rural Electrification Unit was established within SNEL in 2005 to implement the rural electrification initiative launched by the Government the previous year. The Government has recently commissioned a strategic, regulatory and implementation study for this area. A draft is currently being reviewed by the Government and SNEL. In general, electrifying the country (including the currently un-electrified large urban centers) is a priority of the government. C6. Private Sector Participation 50. Private sector involvement in the electricity sector in DRC has primarily been limited to private investment in generation, notably in connection with extractive industry operations in the Katanga region. The Government and SNEL have also been working to develop partnerships with the private sector in generation, transmission and distribution (including efforts at Inga 1 and 2). To date, however, SNEL and other Government efforts to engage the private sector have been ad hoc and have lacked consistency and transparency. Recognizing the importance of creating a sound framework for attracting private sector partners on conditions that best protect the development interests ofDRC, the Government and SNEL are exploring how to institutionalize a more systematic and stronger process for partnering with the private sector (see discussion below on electricity sector governance program). 37 51. One potential area for large private investment is the development of Inga 3, a new hydroelectric plant at the same site with a generation capacity of about 3,500 MW. A consortium - named the Western Power Corridor Project, or ‘Westcor’ - was launched in 2004 as a collaborative effort between the electricity supply companies of DRC, Angola, Botswana, South Africa and Namibia to develop the Inga 3 plant with a view to exporting power to southern Africa along a western corridor. Total costs are estimated at about US$5 billion, including well over US$l billion in related transmission investments to connect to SADC customers. This effort will require extensive private sector financing. The Bank is helping MoE to strengthen its capacity to evaluate and promote private sector involvement in the further development ofthe Inga site. C7. Bank Group Support to the Electricitv Sector 52. IDA. To date, IDA has, in addition to the SAPMP APL-1 project described above, provided funding to the sector in DRC through three Projects: (i)the Emergency Multisector Rehabilitation and Reconstruction Project (“EMRRP”, Cr. 3703-DRC), (ii)the Emergency Economic and Social Reunification Support Project (“EESRSP”, Cr. 3824-DRC) and (iii)the Emergency Living Conditions Improvement Support Project (“ELCISP”, Cr. H-164-DRC): 0 The EMRPP has provided US$90 million equivalent in support for a range of upgrading Projects, including: (a) about US$15 million for limited repair and maintenance works at the Inga 1 and 2 facilities; (b) strengthening the reliability of the existing 220 KV line from Inga to the capital; (c) upgrading the distribution network in Kinshasa and other main towns; and (d) rehabilitation of small thermal and hydro facilities in Katanga and other towns. All the contracts for these works under the EMRPP were signed last year and the contractors have remobilized following the electoral period. 0 The EESRSP Project has allocated about US$3 million for the rehabilitation of the existing Ruzizi plant, as well as US$990,000 of small investments in the rehabilitation ofthe network in Kindu. 0 The ELCISP Project has allocated US$5 million for the rehabilitation and strengthening of the urban distribution networks in six large towns across the country. 53. IDA has also financed a range of capacity building and technical assistance activities: (a) logistical support to SNEL, including for project procurement and supervision, (b) sectoral studies directed at tariffs and rural electrification, and (c) institutional support to SNEL/Government in negotiating export trade arrangements. 54. IFC and MIGA: IFC and MIGA are exploring potential operations in the electricity sector, including support to the further development ofthe Inga site. D. Governance Challenges in the Electricity Sector 55. GoDRC has sought to prioritize reliable provision of electricity as a driver of economic development. While allowing for private participation in the sector, the GoDRC recognizes that SNEL remains a key operator in the sector and that improvements in the sector will 38 depend to a large extent on improving SNEL’s efficacy. SNEL, however, has historically faced significant governance weaknesses and failures. These have undermined the utility’s ability to operate efficiently, weakened it financially, and prevented it from delivering key power services to the people of DRC. At the same time, there is need to improve governance within the sector beyond SNEL, notably by reducing non-payment by power consumers and establishing a transparent, equitable and sound framework for attracting private sector partners to the sector who are viewed by the authorities as vital to the further development of the sector. The governance failings in the sector encompass SNEL’s internal operations, as well as external parties, such as the Government, contractors and customers. 56. These failings can be distinguished into two basic types: those relating to strategic decision-making and the second to financial aspects at the level of everyday operations. Examples ofeach are given belpw. Strategic Decision-Making 0 Investment and Staffing Decisions. Historically, decision-making within SNEL was driven at times by privileged stakeholders, rather than corporate objectives. While recognizing that any power company, and in particular a state-owned company, must respond to a variety of constituencies and dnvers in making strategic decisions, there was excessive influence that led the company to largely ignore its non-industrial customers. Perhaps more importantly, this dynamic arguably created an environment of weak governance - which in turn allowed secondary strategic decisions (such as smaller level service decisions) to be made to support similar private rather than corporate objectives. Secondly, a perception was created that decisions were driven excessively by non-corporate criteria, which undermined staff morale. 0 Joint-Venture Contracting. There is currently a lack of clarity regarding the joint venture contracting practices of SNEL and other Government entities, which appear to be handled in an ad hoc manner. In addition to potentially leading to disadvantageous contracts for the public sector, it leads to a perception ofweak governance. Financial Aspects at Operational Level 0 Financial Operating Issues. The major governance issues facing SNEL relate to financial weaknesses, including (a) misappropriation of corporate funds; and (b) misprocurement, including inappropriate selection of suppliers/contractors, and uncertain receipt and fraudulent invoicing ofgoods. 0 Failure to Pay for Power by Consumers. An important financial drain for SNEL are the consumers (both public and private) who tap into the power lines illegally or refuse to pay their bills, consuming power without ever paying for the electricity they consume. It is currently estimated that these forms of misappropriation of power represent an important part of SNEL’s non-technical and collection losses. 57. Given that these failings encompass SNEL’s internal management and operations, as well as external parties, the mechanisms to improve governance must be tailored to address a 39 spectrum of governance challenges, both in and outside the utility and at senior management and operational levels. Recognizing the centrality of the power sector to DRC’s development, GoDRC and the management of SNEL have been developing, with Bank support, a program to improve both sector and utility governance. Initial steps by SNEL and GoDRC have included (i)commissioning from an external firm a diagnostic of SNEL’s financial and procurement control systems, (ii)the systematic publication of annual reports to improve communication and transparency, (iii)commissioning and publication of an external audit of SNEL’s financial statements, and (iv) commissioning an external review of SNEL’s corporate governance mechanisms. In order to deepen and solidify these actions, a program ofactions to improve governance in the sector and within SNEL has been developed, within a broader context of public enterprise reform generally. The details of the program are set out in Attachment 1 to Annex 4 below. The implementation by GoDRC and SNEL of key actions to promote governance in the electricity sector is a covenant under the Project, 40 Annex 2: Major Related Projects Financed by the Bank and/or other Agencies AFRICA: Regional and Domestic Power Markets Development Project (Southern Afncan Power Market Program, APL-lb) 1. As set out in Annex 1 section C above, IDA has, in addition to the SAPMP APL-1 project, provided financing to the energy sector through three projects: the Emergency Multisector Rehabilitation and Reconstruction Project (“EMRRP”, Cr. 3703-DRC), the Emergency Economic and Social Reunification Support Project (“EESRSP”, Cr. 3824-DRC) and the Emergency Living Conditions Improvement Support Project (“ELCISP”, Cr. H-164- DRC) . Title I Project ID I Latest DO I Latest IP Emergency Multisector Rehabilitation and I PO57296 1s 1s Reconstruction Project (“EMRRP”), FY03 Emergency Economic and Social PO8 1850 S S Reunification Support Project (“EESRSP”), FY04 Southern Afi-ica Project Management Plan MU Mu Emergency Living Conditions PO88619 MS MS Improvement Support Project (“ELCISP”), FY05 41 Annex 3: Results Framework and Monitoring AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) Results Framework PDO Project Outcome Indicators Use of Project Outcome Information To improve operational efficiency in Increase in GWhs of energy delivered To measure overall progress the electricity sector and expand to Kinshasa and to SAPP and Katanga towards meeting the Project’s generation, transmission and region clients. development objectives. distribution capacity in order to better serve domestic power demand and to support regional power market integration. Intermediate Outcome Indicators Use of Intermediate Outcome Monitoring Increased reliable generation at Inga 1 Aggregate rehabilitated generation To monitor progress against and 2 plants capacity at the Inga 1 and 2 plants engineering timelines and ensure appropriate rehabilitation sequencing. Increased power delivery capacity to Kilometers of second transmission To measure status of second Kinshasa from Inga site line strung transmission line construction and identify possible obstacles Improved operating efficiency of GWhs ofenergy delivered to Kinshasa To monitor and manage ‘weak transmission and sub-transmission distribution network from Inga links’ in delivering energy to system Kinshasa Increased power delivery from Inga for Incremental GWhs delivered to SAPP To assess trade prospects and export to SAPP countries and to countries and Katanga region hurdles with SAPP and demand Katanga industrial and other customers customers from Inga and delivery on the HVDC line to Katanga Improved financial efficiency of SNEL Revenues collected in Kinshasa per To gauge impact of efforts to kwh delivered to Kinshasa improve collection rates and SNEL’s overall management Improved commercial efficiency of Percent of accounts receivable To gauge impact ofefforts to SNEL collected by SNEL in Kinshasa improve collection rates and SNEL’s overall management Increased connection in Kinshasa and Number of additional households To track pace ofelectrification electrification ofpreviously un- connected in Kinshasa and identify any implementation electrified areas obstacles Strengthened SNEL financial reporting Number ofqualifications to external To identify weaknesses in audits financial control systems Improved transparency in SNEL’s Publication ofpublic/private Ensure full disclosure ofexternal external partnerships partnership agreements for electricity partnerships with SNEL sector 42 4 c) Y w 3 z 0 0 e 8 .[ v, * r 0 E 0 c : d8 I: L m 0 d 6 0 +U 0- 0 ! m fe C I I I i Annex 4: Detailed Project Description AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, AF'L-lb) A. SUMMARY OF PROJECT COMPONENTS 1. The Project consists offive components as follows: Component 1: Generation (US$226.7 million): Rehabilitation of the hydroelectric facilities at Inga, including civil works on the intake canal to improve the water flow through the plant and rehabilitation of turbines to increase the operational capacity and reliability of the Inga plant (1 and 2) from its current maximum of about 700 MW to about 1300 MW ofreliable production. 0 Component 2: Transmission (US$93.8 million): Construction of a 400 KV Inga- Kinshasa transmission line. The second line will complement the existing 220 kV IngaiKinshasa transmission line, relieving the current saturation of the existing line and thereby improving the security of transport of power from Inga to Kinshasa, as well as increasing the amount ofpower that can be delivered to Kinshasa. 0 Component 3: Distribution (US$88.5 million): Expansion and strengthening the distribution system in Kinshasa, including the acquisition of low voltage cables and transformers, the extension ofthe grid into currently un-electrified areas ofKinshasa and the connection in these areas of a total of50,000 new customers. Component 4: Capacitv Building and Governance (uS$41.2 million): The component comprises two subcomponents: o Subcomponent (a): Strengthening SNEL's operational capabilities, notably in commercial activities, planning, dam safety and technical training. The component will also support actions to enhance governance within the utility specifically and in the sector generally. o Subcomponent (b): Strengthening the Ministry of Energy's capacity to develop sector reform and to support the further development ofthe Inga site. Component 5 : Proiect Execution WS$48.8 million), including Project preparatory activities): Effective implementation of the Project works, in an environmentally and socially sound manner, including appointment of supervisory engineering consultants, environmentalhocial consultants and the PFM Agent. Each of these components is described in further detail below. B. DETAILED PROJECT COMPORTNTS Project Component 1: Generation (US$226.7 million, of which US$198.3 will be flnanced by IDA and US$28.4flnanced by other sources) 2. There are 6 turbines at Inga 1, with nameplate capacities of 55 MW each, and maximum capacities of 58.5 MW (total max. capacity at Inga 1 is 351 MW) and there are 8 turbines at the Inga 2 plant (separated into two groups of four, entitled 2A and 2B), each with nameplate 44 capacities of 162 and maximum capacities of 178 MW (total max. capacity at Inga 2 is 1,424). The total nameplate capacity at the two plants is 1626 MW and the total maximum capacity is 1775 MW. The plant today is operating nearer to 700 MW, as a result of poor maintenance and some questionable design choices, with significant intermittent reductions as a result of low reliability. Production capacity at the Inga plant is limited by turbines that no longer function, and other factors such as siltation and rock formations that limit the water flow through the intake canal. 3. In order to address these issues, the Project will rehabilitate the turbines and other installations at the Inga 1 and 2 plants to make available about 1300 MW ofreliable production. In addition, SNEL is exploring the option of redesigning two ofthe units which require the most extensive rehabilitation to increase the unit output (potentially at Inga 2B). To this end, a study will be carried out as part of the work of the firm selected to handle the rehabilitation, and will be overseen by the Supervisory Engineer. In addition, in order to achieve a production capacity of about 1300 MW, the canal needs to be re-profiled and dredging undertaken. The Association will finance rehabilitation works for the turbines and related facilities at Inga 1, for the turbines and related facilities at Inga 2A and the canal dredging and reprofiling. Donors and other partners will provide financing for the other facilities, and SNEL will ensure that these other activities are coordinated with thosefinanced by the Association. 4. The rehabilitation work and canal re-profiling is expected to increase production capacity at the site by about 600 MW, from about 700 MW to about 1300 MW, and to improve its reliability. The increase will be incremental, averaging about 150 MW per year beginning end 2009 through end 2012. Given the run-of-river quality of the Inga site and the hydrological conditions, each incremental MW can be expected to generate 6132 Mwh, assuming a 70 percent plant load factor. Project Component 2: Transmission (US$93.8 million,Jinanced by other sources) 5. There are currently three transport networks emanating from Inga. The first is the eastward HVDC KinshasaKolwezi (Katanga) line, which transports power to the SAF'P and to Katanga mining and other customers. The second is the northern IngaKinshasa corridor, which transports power to Kinshasa and to Brazzaville. The third is the IngaBas Congo line, a smaller transmission system to provide power to the city of Matadi and other areas in Bas Congo (located to the west of Inga). A fourth corridor under consideration (as part ofthe CAF'P) would transport power northwest to Cabinda, Angola and onward to Pointe Noire, Republic ofCongo. The second transmission line from Inga to Kinshasa to be erected under Component 2 of the Project is expected to increase the capacity to deliver power to Kinshasa from the current 450 MW (along the oversaturated existing 220 KV line) to well over 700 MW. This second line will also provide increased security of supply to Republic of Congo through this corridor. 6. This second line from Inga to Kinshasa will enhance the security of supply of power available for Kinshasa, as well as Brazzaville. The line would be about 260 Km in length and would be configured as a 400 kV line, but initially operated in 220 kV until demand in Kinshasa would justify the additional investments needed to operate the line at 400 kV (e.g., in substations at the Inga and Kinshasa ends of the line). It is anticipated that the new line would largely follow the route of the existing 220 kV line that follows the Inga-Kwilu-Kimwenza axis. 7. The component would include: (a) construction of a double circuit 400 kV line from Inga (Camp Kin location) to Kingantoko, with a fibre optic line, (b) construction ofa 220 KV double circuit line from the dispersion substation at Inga to Camp-Kin (at the Inga site) with a fibre optic line, (c) construction of a 220 kV double circuit line from Kingantoko to the end point of 45 the Kimwenza-Lingwala line (single circuit) - i.e., in the Kinshasa area, with a fibre optic line, and (d) construction of a 220 kV line from the end point of the Kimwenza-Maluku line to the Kimbanseke end point (see discussion under distribution component). Project Component 3: Distribution (US$SS.5 million, of which US$26.2 million financed by IDA and US$62.3 million financed by other sources) 8. Currently, the Kinshasa distribution system is oversaturated, with transformers operating at precariously high levels of capacity, resulting in localized loss of power and increased levels of technical losses. The Project will alleviate this stress on the system by financing rehabilitation of the existing system, thus improving the quality of service and reducing system losses (cost estimated at about US$50 million). One objective is to progressively shift customers from the antiquated 6.6 kV distribution network to the 20 kV distribution network. The Project will also finance rehabilitation activities at three key substations serving Kinshasa, namely the 30 kV substations located at Liminga and Lingwala and the 20 kV Utexco substation (estimated cost US$3 million), and increase 220 KV transformer capacity in the system. These activities will complement the rehabilitation activities being carried out under the IDA-financed EMRRP Project. 9. In addition, the Project will also electrify new areas within greater Kinshasa that do not currently receive power, notably the Kimbanseke area located to the east of the city (the largest un-electrified area within greater Kinshasa), with a population estimated at above 1.2 million. Electrification ofKimbanseke will require the erection ofa new substation (estimated cost US$6 million). In addition, the Project will electrify the Kinseso, Mpasa 1/2/3 and Malweka areas which are, other than Kimbanseke, the largest remaining un-electrified areas in Kinshasa, with populations estimated each in the 250,000-350,000 range. 10. The Project will also finance 30,000 new connections in Kimbanseke, and 20,000 new connections in the other three areas. As the Project will, in essence, be providing for a distribution backbone in these areas to be electrified, further connections over and above the project-financed 50,000 are anticipated. In addition, the addition of these newly constructed distribution networks to the Kinshasa grid should help to reduce overall technical loss rates. Project Component 4: Capacity Building and Governance - SNEL and MoE (US$41.2 million, of which US$34.7 million financed by IDA, US$1.5 million financed by SNEL, and US$5.0 million financed by other sources) 11. This component includes a capacity building sub-component to benefit SNEL and a separate sub-component to benefit the Ministry of Energy. Subcomponent 4(a) - SNEL (US$36.7 million, of which US$30.2 million financed by IDA, US$1.5 million financed by SNEL, and US$S.O million financed by other sources): 12. The Project will strengthen the capacity of SNEL in four principal ways: (a) support to strengthen SNEL’s commercial management and operations, (b) support for improved planning and maintenance, (c) improved training ofSNEL staff, and (d) improved governance. 13. Improved Commercial ODerations. SNEL’s capacity to conduct commercial operations (namely billing and collections) will be strengthened through such actions as improved client databases, improved billing and collection systems, and other support. A consultant will be employed by SNEL to conduct a diagnostic of the weaknesses in its billing and collection 46 systems and to develop a program to strengthen operations in this area. In addition, the Project will support the acquisition and deployment of about 60,000 meters, including about 50,000 meters for the new customers in the newly electrified areas and about 10,000 pre-payment meters for an established area (such as the Gombe area), and about 300 MV meters for medium voltage clients (the installation of the meters will be funded by SNEL). 14. Improved Planning. Training and Maintenance. The Project will finance consultants to assist SNEL in developing a strategic expansion plan to electrify urban centers and other areas throughout the country. In addition, the Project will finance training for SNEL staff in such areas as planning, strategy and operational areas. The Project will also finance a diagnostic of the maintenance needs, including in training of staff. AfDB would finance follow-up training activities designed to strengthen the maintenance and operating capacity of SNEL staff. The Bank will also strengthen SNEL’s capacity to manage environmental and social aspects of its operations, initially by providing support to the environmental and social unit (ESMU) to be established within SNEL (as a condition ofeffectiveness). 15. Strengthened Dam Safetv. An independent assessment was carried out of the facilities which concluded that there were no major issues, but that SNEL would benefit from a strengthened maintenance program. SNEL will strengthen its capacity to carry out dam safety maintenance activities at the Inga installations, including the preparation of an emergency preparedness plan. 16. Vector Control (Onchocerciasis-related). Black flies (Simulium Damnosium), a vector for onchocerciasis, are prevalent at the Inga site and surrounding health zones (Inga and Seke- Banza, with a total of 160,000 inhabitants). The presence ofthe disease has decreased in the last two years due to mass distribution of Invermectid Mectizan(R), a potent antiparasite drug mixture. This drug is distributed in the region with the support of the African Program for Onchocerciasis Control, which is executed by WHO and funded through a World Bank trust fund. However, the flies still represent a major issue for the population. The nuisance factor is severe and has important socio-economic effects including on school attendance. 17. SNEL and the Ministry of Health have been working to address this issue. The Project activity will focus on addressing the black fly nuisance on the Inga site and surrounding health zones. It will: (i)control black fly larvae by spraying Permethn, an insecticide, in the river six times a year in high season, (ii)strengthen the existing Inga Entomological Mission (EM), which will monitor impacts, (iii)strengthen the spraying team, (iv) provide the necessary equipment (spraying boat) and pesticide. Particular attention will be paid to monitor hydro- biological impact, strengthen capacities for entomological monitoring and evaluation, and ensure sustainability of the interventions. It is anticipated that the WHO/APOC (African Program for Onchocerciasis Control) will be contracted to implement the control activities under the joint supervision of MoH and SNEL, and to strengthen the existing capacity in the EM. A Pest Management Plan (PMP) has been prepared and released in-country and in the Bank’s InfoShop (see discussion in Annex 10). Total estimated cost is US$2.2 million, including about US$ 1.2 million for pesticides, US$ 0.1 million for a pesticide spraying boat and US$ 0.9 million for consulting services. 18. Improved Governance. The Project will support the implementation ofa series ofactions to enhance governance within SNEL and the electricity sector generally. The actions are built around three pillars: strengthening SNEL’ s capacity; improving oversight and transparency; and strengthening partnerships in the sector, notably publidprivate partnerships. The component will include support to strengthen SNEL’s financial and procurement systems, which will draw from the diagnostic study commissioned as part ofproject preparation. It will also include a sub- 47 component to strengthen SNEL’s commercial activities (notably billing and collection), which should improve governance both within SNEL and in its customer base. In addition, the Project will fund annual financial audits and annual procurement audits. SNEL will also systematically produce and disseminate annual reports, which will include the audited financial statements. A fuller description of the governance enhancement activities is set out in attachment 1 to this Annex 4. Subcomponent 4(b) - MoE (US$4.5 million,$nanced by IDA): 19. This component will strengthen the capacity ofMoE: a. to formulate a strategy to further develop the Inga hydropower resources (including the proposed Inga 3 Project and related Western Corridor Project, and opportunities for export into the Central Africa Power Pool), including hiring financial, legal and other advisors, as needed, and b. to develop and analyze structuring options for the sector, including in particular setting a framework for publidprivate partnerships (including the concessioning of power assets and the negotiation ofjoint-venture agreements). 20. The Project will build on the results ofthe tariff, rural electrification and sector studies being executed under the EMRRP. Project Component 5: Project Execution (US$48.8 million, of which US$3 7.5 financed by IDA and US$11.3 million financed by SNEL) 21. The component will strengthen SNEL’s and MoE capacity to carry out the rehabilitation and expansion activities provided for under the Project, including through the acquisition of supervisor engineering services. In addition, a PFM Agent will be hired to manage procurement and financial management aspects relating to Bank and other donor financing to be provided under the Project. This component will also finance the cost of managing and implementing the ESR Plan (see discussion in Annex 10). The component will also provide financing for operating, logistical, training and other support required by SNEL and MoE for Project coordination through the Project Management Units (estimated cost ofUS$3.5 million, ofwhich IDA will finance US$2.5 million - including US$2.0 million for the SNEL PCU team and US$500,000 for the MOE PCU team; the balance of US1.0 million will be provided by SNEL through in-kind support). In addition, SNEL will contribute its staff resources and logistical support to the Project (estimated at no less than US$lO.O million). 48 Attachment 1 to Annex 4 Enhancing Governance in the Electricity Sector 1. Experience in DRC and elsewhere in the world has demonstrated that the types of governance challenges facing the electricity sector generally and SNEL specifically are difficult to overcome, and that a multi-faceted approach is required that addresses aspects both internal to SNEL’s operations and external to the broader context in which it operates. The governance challenges facing the sector (see discussion above in Annex 1) can be distinguished into two basic types: those relating to strategic decision-malung and the second to financial aspects. A series of actions has been delineated by the Government and SNEL to address these challenges. The actions are designed to empower the utility, the Government as shareholder, and current and future consumers (namely the population). The actions can be grouped around three pillars: (a) improving SNEL’s institutional capacity; (b) enhancing the oversight and transparency of SNEL; and (c) strengthening partnerships in the sector. Each of these three pillars is built on a firm foundation, namely a commitment from the highest governmental authorities to address governance weaknesses in the sector so as to put the sector on a sound commercial basis. A. Pillar One: Strengthening SNEL’s Institutional Capacity 2. The actions within the first pillar are designed to strengthen SNEL’s institutional capacity, notably in financial management, procurement and other control systems. An external evaluation commissioned by SNEL (with Bank financing) pointed to various weaknesses in SNEL’s financial management and procurement systems. SNEL also faces weaknesses in its billing and collection systems, its management information systems (including in tracking energy flows through its grid, notably from generation through transmission and distribution to its ultimate customers), and in its personnel functions. SNEL is also looking to improve its communication with stakeholders and needs to strengthen its staffing practices. 3. The first pillar contains the following set ofactions: a. Financial Management Svstems. SNEL is undertakmg various actions to strengthen its financial management systems: i. Conduct an external independent diagnostic of its financial management systems, their weaknesses and identify actions to strengthen these systems (completed end 2006). ii. Employ an external accounting or other similar consulting firm to develop and assist SNEL in implementing strengthened financial management systems, including the implementation of improved control systems, the acquisition ofrelated software and equipment, and training. This action will be financed under the Project. ... 111. Conduct annual external financial audits (see discussion below under oversight‘transparency pillar). b. Procurement Svstems. SNEL is undertaking various actions to strengthen its procurement systems: i. Conduct a summary diagnostic ofits procurement practices (completed end 2006). 49 ii. Employ an external accounting or other specialist consulting firm to strengthen SNEL’s procurement practices. A single firm will be employed to assist with both the strengthening of SNEL’s financial management and procurement systems (financed under the Project). ... iii. Conduct annual procurement audits (see discussion below under oversightltransparency pillar). C. Commercial Business Practices. SNEL is undertaking various actions to reduce billing and collection losses by strengthening its commercial practices in this area. As noted above, SNEL’s losses in collection are estimated at about 45 percent for the Kinshasa region. SNEL is undertaking the following actions: i. Commission a diagnostic review and an action plan to strengthen its commercial practices. This action will be financed under the Project. ii. Employ an external consulting firm to develop and assist SNEL in implementing the action plan, including the development of improved billing and collection practices, the acquisition ofrelated software and equipment, and training. This action will be financed under the Project. ... 111. The acquisition and installation of meters, including 50,000 in an initial phase. d. Management Information Svstems. In connection with enhancing its financial control system, SNEL will also strengthen its management information systems to improve the quality and flow ofinformation within the utility (including fi-om decentralized centers to its headquarters in Kinshasa). As a related aspect, SNEL will improve its ability to track energy flows (including identifying sources of losses) through its system, which underpins the financial and commercial operations of the company. SNEL will undertake the following actions: i. Employ the external consulting firm responsible for strengthening its financial management systems to assist in strengthening its management information systems and its ability to track energy flows. This support will be financed under the Project. ii. Install meters at strategic points in its grid to improve its ability to track energy flows. The installation of meters in the Kinshasa network is being financed under the Project as part ofthe distribution and transmission components of the Project. e. StaffindPersonnel Function. SNEL needs to strengthen its personnel function to support more transparent and effective staffing. i. Managerial Appointment Process. SNEiL will review its recruitment and promotion processes for managers. ii. Staff Recruitmenflerformance ReviewPromotion Process. SNEL will review and reform its recruitment, performance review and promotion processes for staff so as to create a sound incentives framework for staff. f. Strengthened Communication. The management of SNEL has recognized the importance of maintaining a strong culture of communication in order to inform its stakeholders - including staff - and current and prospective partners about its activities and corporate priorities. 50 i. To inform outside stakeholders, SNEL prepared annual reports for 2004 and 2005. SNEL’s management is looking to improve the breadth and depth of these reports, including presenting its financial statements in the report. The Project will support SNEL’s management in this effort by financing the preparation and publication of annual reports for the succeeding four years. ii. A stronger informatiodcommunications culture directed at SNEL staff, its partners and consumers is also a necessary complement to other actions, so as to both raise awareness and to encourage stronger internal actions in support of the governance enhancement effort. g. Strengthened Joint-Venturing Capacity. GoDRC and SNEL will improve their capacity to undertake the legal and financial analyses necessary to develop sound and equitable public/private partnerships and other joint ventures. i. Strengthen SNEL’s Legal Department (support being provided by the Bank) ii. Strengthen SNEL and MoE’s financial evaluation capacity (support being provided by the Bank). B. Pillar Two: Enhancing Oversight and Transparency of SNEL 4. The second pillar addresses issues of oversight and transparency; it is designed to enhance the control of SNEL’s activities by its Board and enhance the participation of other stakeholders in the sector by improving transparency. This pillar contains the follow set of actions: a. External IndeDendent Financial Audits and their Publication. After a three-year hiatus, SNEL commissioned an external audit of its accounts (for 2005, as well as 2004), which was completed in February 2007. SNEL intends to commission these audits annually and to publish them (notably in its annual report). Specific steps include: i. The external audit for FY 2005 was completed in February 2007. 11. SNEL will conduct annual financial audits by an independent auditor. Audits for the next several years will be financed under the Project. The audits will be completed by June 30 of each year (in accordance with the audit requirements for recipients under IDA-financed projects). ... 111. The audit for FY2005 (completed in March 2007) was published in local newspapers in April 2007. Going forward, the audited financial statements will be included in SNEL’s Annual Reports, which will be published by September of each year. b. External Procurement Audits. SNEL will commission annual procurement audits. These audits will feed into the institutional strengthening activities to be carried out under Pillar One. Specific steps include: i. SNEL will conduct annual procurement audits (to be financed under the Project). The audits will be completed by March ofeach year. ii. These procurement audit reports will be published, 51 c. Board of Directors. Prospects to improve SNEL’s management begin at the top of the organization, notably with its Board of Directors. As part of the public enterprise reform effort, the Government is exploring mechanisms to strengthen oversight of its public enterprises and create the mechanisms so that companies such as SNEL can be more commercially oriented in their operations. The Government is considering different mechanisms for promoting effective Board oversight. For example, in the recent past, Board members were vetted by a selection committee. A strengthened appointment process will be developed as part of the public enterprise reform initiative (draft laws in this regard are currently under consideration). One of the constraints which has faced the Board of SNEL has been inadequate information flow, as well as difficulties in traclung key actions such as the preparation of audits and procurement aspects. To strengthen the effectiveness of the Board ofDirectors of SNEL: i. Specific external directors will be given responsibility for audits, procurement issues, and improving information flow to the Board ofDirectors. The designation of specific external directors with these responsibilities should help to enhance the ability ofthe Board to follow these areas by providing for a lead external director. ii. The process and criteria for appointing the ‘external’ directors on the Board will be reviewed, as well as the nature ofthe Board’s oversight of SNEL management, with a view to enhancing oversight, while also fostering an environment that is more commercially oriented. Action in this area is expected within the next several months as part ofthe overall public enterprise reform effort. iii. A review of SNEL’s legal charter to determine whether the above-mentioned proposals require modification ofthe charter. d. Senior Management Amointment Process. The CEO and Senior Management of the utility are central to efforts to strengthen governance within the utility. The appointment (or confirmation) process of the CEO and of the other senior executives who make up the Management Committee is key. Clear criteria are needed for the selection of the CEO and other senior executives that emphasize technical qualifications, while also recognizing other qualities that can provide for strong and effective leadership. In this regard: i. The process and criteria for appointing SNEL’s senior managers will be reviewed by the Government, as part of the public enterprise reform effort, with a view to providing a systemic process designed to foster a more commercially oriented enterprise. e. Conflict/Disclosure re: SNEL Board Directors and Kev Executives. Strong policies for avoiding conflicts of interest and financial disclosure requirements are important tools to improve governance. The Government is currently finalizing a Ministerial order in this area which will govern SNEL and other public enterprises; the order is expected to be issued by May 2007. In this regard: i. The directors and senior executives of SNEL will provide financial disclosure statements and follow financial conflict ofinterest proscriptions. 52 C. Pillar Three: Enhancing Strategic Partnership Arrangements 5. The third pillar targets improving the strategic partnership arrangements entered into with other key actors in the sector, namely prospective private (including public foreign) sector investors and public sector consumers. This third pillar includes the following set ofactions: a. Joint-Venturing and other Partnerships. The Government’s stated policy is to open the sector to greater private sector investment, whether though joint-venture arrangements, concessioning or other forms of public/private partnership. To date, SNEL and other involved ministries have taken an ad hoc approach to these transactions, highlighting the need for a systematic and sound approach to engaging with the private sector. i. MoE will launch, over the next several months, a review of the current partnering practices of SNEL and other government entities and ministries regarding the power sector. ii. GoDRC, under the leadership of the MoE and SNEL, will develop a framework for soliciting, evaluating and negotiating with prospective private sector investors that promotes financially and technically sound investments, ensures transparency and favors competition. ... 111. MoE/SNEL will commission a review of the existing agreements regarding electricity sector assets to establish an inventory and facilitate a deeper understanding ofthe approaches used to date. iv. All public/private partnership agreements signed after March 1, 2007 will be published in the local press and in other media. v. SNEL and GoDRC will strengthen their legal and financial evaluation capacities to support negotiations (see discussion above under Pillar One). To this end, SNEL is obtaining external legal support to conduct a diagnostic of its needs in this area (which is being financed by the Bank). b. Parastatal/Companv Pavments. Numerous public enterprises have systematically failed to pay their electricity bills, which has multiple negative impacts, such as undermining SNEL’s financial position, encouraging over-consumption by the entities, and creating an atmosphere in which failure to pay for electricity becomes accepted. In addition, while the GoDRC has terminated the practice of imposing on SNEL preferential tariffs for certain companies, SNEL continues to have the discretion in this regard - which it is interested in limiting (so as to protect its financial position). To strengthen payments from parastatals and other company clients: i. The Government will organize periodic meetings with SNEL and its public sector debtors (including ministries and parastatal companies) to review the status of payments due to and owed by SNEL with an ultimate view to establishing a system to provide for the payment of these amounts in a timely manner. ii. SNEL will, every six months, review the use ofpreferential tariffs; these reviews should serve to limit the application ofthese preferential tariffs both in terms of the number ofbeneficiaries and their duration. 53 D. Program Summary 6. The program and its timing are summarized in the following table. Pillar Action Timing Institutional Strengthening a. Financial Systems i. Diagnostic of Financial system Completed end 2006 ii.Procurement of ‘turnkey” firm to Initiated Feb. 2007 strengthen financial system (technical (EO0 assistance, software and hardware, Consultancy hired training) Aug 07 Revised systems: end ‘07 Implementation: beginning 2008 iii. Audit of2005 accounts Completed end March 2007 iv. Publication of 2005 accounts Published in local press April 2007 v. Procurement of auditor for 4 year End August, 2007 period (FY 06,07,08,09) v. Audit of2006 accounts End June 2007 vi. Publication of2006 accounts To be included in 2006 Annual Report to be published by Sept. 2007 I (see below) vii. Audits of subsequent fiscal years June 30 of succeeding (’07 on) year viii. Publication ofAudits ’07 onwards As part ofAnnual Reports for that fiscal year (by Sept 30) b Procurement Systems i. Summary diagnostic ofprocurement Completed end 2006 system ii.Procurement offm to strengthen Combined with Financial SNEL’ s procurement system systems support. See above iii. Procurement ofannual procurement End November 2007 auditor for multi-year period (FY 07,08, iv. Annual procurement audits End March ofsucceeding fiscal year v. Procurement by MoE ofProcurement-- Initiated Feb. 2007 Financial Management (PFM) Fiduciary POI) Agent for the Project Contract signature: August 2007 54 Pillar Item Action Timing ICommercial Practices i. Recruitment ofa consultant to conduct Procurement initiated a diagnostic ofCommercial Systems, Mar. 2007 (EOI) develop an action plan and implement Consultancy hired “turnkey” technical support (systems, Nov. 07 equipment, training) to strengthen billing Action plan Mar. and collection and action plan 2008 Implementation: ’08- ‘09 Management Information Systems i. Summary diagnostic ofselected Completed end 2006 management information systems ii.Procurement ofturnkey technical 2008 assistance to strengthen management information svsterns StaffingRersonnel Function i. Appointment ofPersonnel Consulting Mar 2008 Firm I ii.Review by SNEL ofmanagerial and 2008 staff appointment and promotion I arocesses iii. Strengthening the recruitment svstem 2008 Strengthened Communication i. Publication ofAnnual Report for FY Sept 2007 2006 ii. Publication ofAnnual Reports for FY By Sept. 30 ofthe ’07, including Financial Statements for succeeding year the year iii.Delineation ofa Governance Mar. 2008 Communication Campaign (for internal and external stakeholders) iv. Implementation ofthe Governance Beginning early 2008 Communication Campaign onwards Strengthened Joint- Venturing Capacity i. Strengthened SNEL’s Legal Consultant to conduct Department, including training and diagnosis: external negotiations support Procurement initiated Feb ’07 (EOI) Capacity building actions: 2008 ii. Strengthening financial evaluation Finalization of contracts capacities (SNEL and Ministry) for initial financial consultant 55 Pillar Item Action Timing TWO Oversight and Transparency a. Financial Audits and Annual - see above under Financial Mid-year (see above Publication Systems and Annual Reports under financial systems) b Procurement Reviews Publication ofthe annual procurement Publication 2nd trimester audit ofeach year Board of Directors i.Designation of an external director End 2007 responsible for audit issues ii. Designation ofan external director End 2007 responsible for oversight ofprocurement asoects iii. Designation ofan external director End 2007 responsible for improving information flow to the Board ofDirectors iv. Review ofthe mandate of the Board 2007 ofDirectors so as to strengthen SNEL’s business orientation v. Implementation of a strengthened 2007-2008 process for the nomination of directors (including charter changes as necessary) within the context ofthe overall public enterprise reform d SNEL Senior Management i. Implementation ofa strengthened 2007-2008 process for the appointment ofSNEL’s senior executives (members ofits Management Committee), within the context ofthe public enterprise reform (including charter changes as necessary) ii. Implementation ofStrengthened Mid 2008 SNEL Senior Executive Appointment Process (including charter changes as necessary) e. ConflictOlisclosure Processes i. Implementation ofconflict ofinterest Ministerial order to be and financial disclosure requirements for issued by end May 2007 Board Members and SNEL Senior Executives (requirements to be set out in Ministerial Order) THREE Strengthening Partnership Arrangements a. Joint-venturing, Partnering processes i. Launch by MoE of review of current Sept. 2007 publidprivate partnering practices 56 submission to its Board ofa preliminary framework for partnering with the private sector that provides for financially and technically viable ventures, ensures transparency and favors competition iii. Adoption ofa framework for August 2007 partnering with the private sector that provides for financially and technically viable ventures, ensures transparency and favors competition iv. Analysis of the public/private Recruitment of a agreements consultant - May-Aug. 2007 v. Review ofagreements under Beginning May 2007 negotiation vi. Strengthened SNEL/Gov. legal and Beginning second half '07 financial capacities in evaluating- and - See discussion above negotiating publiciprivate partnerships under Pillar One vii. Publication in the local press and Beginning May 2007 other media all hture contracts signed in the electricity sector with or with the participation ofthe Government or SNEL b Payments by public sector consumers i.Trimestrial review, with SNEL, the Beginning June 2007 Portfolio Ministry and the public sector to establish the payment due to SNEL by other parastatals and government ministries and entities ii. Semestrial review ofthe preferential Beginning July 2007 tariff policy 57 Annex 5: Project Costs AFRICA: Regional and Domestic Power Markets Development Project (Southern Ahcan Power Market Program, AF'L-lb) Local Foreign Total Contin- Total Project Cost By Component and/or Activity US$ US$ US$ gencies (w/Taxes million million million & Cont.) 1. Generation: (a) Inga 2A units 17.5 55.5 73.0 13.7 86.7 (b) Inga 1 units and common facilities 10.6 29.5 40.1 8.1 48.2 (c) IngaY 2 - other facilities 5.2 19.2 24.4 4.0 28.4 (d) Inga Short-term works 0.5 3.0 3.5 0.5 4.0 (e) Civil works - Intake canal reprofiling 6.8 10.2 17.0 3.3 20.3 (0 Civil works - Intake canal dredging 8.2 24.7 32.9 6.2 39.1 Sub-total: 48.8 142.1 190.9 35.8 226.1 2. Transmission: New 400 kV transmission line Inga -Kinshasa 13.2 69.4 82.6 11.2 93.8 Sub-total: 13.2 69.4 82.6 11.2 93.8 3. Distribution: (a) Electrification ofKimbanseke 4.8 16.9 21.7 3.4 25.1 (b) Network extension in Kisenso, Mpasa & Malweka 2.2 7.7 9.9 1.6 11.5 areas (c) Rehabilitation ofring substations in Kinshasa and 2.3 12.6 14.9 2.3 17.2 new substation in Kimbanseke, and increased 220 KV transformer capacity (d) Network rehabilitation in Kinshasa (Lot A) 2.5 6.7 9.2 1.5 10.7 (e) Network rehabilitation in Kinshasa (Lot B) 3.4 13.4 16.8 3.2 20.0 (0 Distribution short-term works 0.5 3.0 3.5 0.5 4.0 Sub-total: 15.7 60.3 76.0 12.5 88.5 4. Capacity Building and Governance: A. SNEL (i)Strengthened commercial business (ab Acauisition and Installation ofmeters 5. Project Execution: 58 Note: The figures exclude taxes and duties on goods and works, but includes taxes on consulting services estimated at 18 percent 59 Annex 6: Implementation Arrangements AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) 1. The Project will be implemented primarily by SNEL (notably Components 1, 2, 3, 4(a) and 5) and by MoE (Subcomponent 4(b)). A. SNEL Organization 2. SNEL has about 6500 staff. The company was recently re-organized into three main groupings. The Corporate grouping runs the strategic functions that define long-term objectives, plans implementation and monitors performance. The Operations grouping undertakes the principal operational activities of the company, including generation, transmission, distribution and marketing functions. The Support Services grouping provides the human and financial resources to support the activities of the other two groupings. A more detailed description of SNEL is provided in Attachment 1 to this Annex 6. 3. Project implementation will rely on existing departments within SNEL, primarily within its Operations and Support Services groupings, which include separate departments dedicated to the following functions: (i)the maintenance and operation of the facilities at Inga, (ii)the transmission system, including the IngaKinshasa corridor targeted under the Project; (iii)the maintenance and operation of the distribution network in Kinshasa; and (iv) commercial operations in the Kinshasa area. B. MoE Organization 4. MoE is responsible for developing and implementing the policy of the GoDRC in both the energy and water sectors. The MoE has recently set up a Cellule d’Appui Technique Energie (CATE) to provide technical support to the Minister. A coordinator has been appointed, and CATE’s staff will be strengthened under the Project to improve the ability of the ministry to develop and evaluate strategic and reform initiatives in the electricity sector. A more detailed description ofthe MoEis provided in Attachment 2 to this Annex 6. C. Project Coordination Unit and Sub-units 5. MoE and SNEL have created a project coordination group, which as a condition of effectiveness) will be formalized as a Project Coordination Unit (PCU), responsible for coordinating implementation of the Project. The PCU comprises staff from both SNEL and MoE, and includes two subunits: (a) SNEL’s project coordination unit, created within SNEL to provide coordination among the various SNEL departments under the Project and to ensure proper execution of the various administrative and other tasks associated with implementation of a donor-financed operation (including support on procurement issues), and (b) the MoE unit, which draws from the MoE’s CATE technical assistance team and is responsible for executing the MoE capacity building component under the Project and for supporting the MoE in providing overall strategic direction ofthe Project. 6. The PCU will be headed by a Project Coordinator, representing the MoE. The PCU will also include the PFM Agent, and an internal auditor (see Annex 7), as well as representation from the 60 Ministry of Portefeuille, which has oversight functions over SNEL (see discussion in Annex 1 on SNEL’s corporate governance structure) and from the Ministry ofFinance. D. On-lending Terms for Project Funds provided by GoDRC to SNEL 7. The proceeds of the IDA grant relating to the Project activities to be carried out by SNEL (namely all activities other than ‘Component 4(b): MoE Capacity Building’ and the employment of the PFM Agent) will be provided by GoDRC to SNEL through a subsidiary loan agreement. The funds will be provided for a term of twenty years, with a five year’s grace period, at an interest rate of 5 percent per annum (with the foreign exchange risk borne by SNEL). E. Procurement Implementation Arrangements 8. As described in Annex 8, given the limitations ofSNEL’s existing procurement systems, and the limited procurement experience of the MoE, a procurement agent (the PFM Agent) will be employed by the MoE (under the PCU) to assist with procurement actions to be carried out for the benefit of SNEL and MoE under the Project. The PFM Agent will operate under the following terms and conditions: The PFM Agent will be responsible for carrying out the processing of procurement actions, with SNEL providing all technical input for activities under the SNEL Project Components and with MoE providing technical input for the MoE Project Component. All contracts relating to the SNEL Project Components will be signed by both the PFM Agent (as agent for MoE) and by SNEL and all contracts relating to the MoE Project Component will be signed by the PFM (as agent for MoE). All non-objection requests shall be submitted by the PFM Agent, with the technical approval ofSNEL, in the case ofcontracts under the SNEL Project Components. Disbursement requests will be signed by PFM, with the prior written technical approval of SNEL, for all disbursement requests for contracts under the SNEL Project Components. The external financial audits relating to SNEL will be procured and managed by the PCU through the PFM Agent. 9. The PFM Agent will provide training in procurement matters to SNEL and MoE personnel, notably in connection with procurement actions under the Project. The procurement ofthe PFM Agent itself will be carried out by MoE with the support of a procurement agent acceptable to the Association. F. Financial ManagementDisbursernentsunder the Project 10. The financial management aspects are described in Annex 7. As noted above under the discussion of procurement aspects, all disbursement requests will be submitted by the PFM Agent to the Association, and disbursement requests relating to funding for the SNEL Project Components will require the prior written technical approval ofSNEL. 61 G. Project Monitoring 11. The PCU will be responsible for ensuring overall project monitoring. SNEL will monitor physical implementation of the Project through its traditional monitoring and control systems, supplemented by support from the PCU, and will report at least semi-annually on progress. SNEL currently measures through its power flow and financial monitoring systems the electricity generated, and distributed through its system, as well as revenues. This monitoring system will provide the basis for measuring the outcomes and results. In addition, while it is currently difficult for SNEL to effectively determine the level of technical versus non-technical losses in the Kinshasa distribution system, the Project will strengthen SNEL’s capacity to determine these levels, which will be monitored under the Project. SNEL’s ESMU, supported by specialized technical assistance, will supervise implementation of the ESR Plan. The PCU will monitor implementation of the MoE Project Components, with the support of CATE. In addition, reviews will be carried out at least twice a year by the Bank, together with the PCU, to assess progress in implementing the agreed activities. The reviews will be coordinated with other donors financing the Project. 62 Attachment 1 to Annex 6 SNEL Organizational Structure 1. SNEL was recently reorganized along the following functional groupings: - The Corporate Grouping undertakes the following strategic and advisory functions: defining long-term objectives, planning their implementation and monitoring performance. Units include: (i)research and development; (ii)organization and monitoring; (iii)the general secretariat; (iv) standards; (v) prevention and security; (vi) the legal division; (vii) the advisory office; (viii) the project management unit for the SAPMP APL-1 project. - The Operations Grouping undertakes the principal operational activities ofthe company, including generation, transmission, distribution and marketing. The units include: (i)production and transport; (ii) distribution for the interconnected provinces; (iii)distribution for the Kinshasa region; (iv) supplies and markets; (v) equipment; (vi) the EMRRP project management unit; and (vii) rural electrification. - The Support Services Grouping which provides the human and financial resources for the activities of the other two divisions. The units include: (i)human resources; (ii)finance; and (iii)commercial activities. 2. SNEL’s corporate governance structure includes two principal bodies, the Board of Directors and the Management Committee: The Board of Directors (Conseil d ’Administration) is the principal decision-making and management body of SNEL. It is composed ofnine Directors, including 5 external directors selected by the President of the Republic, including the Chairman of the Board. The appointment of these directors is for five years and is renewable. The remaining four directors are the senior executives of SNEL who serve on the SNEL Management Committee (described below). In addition to these nine directors, the oversight ministries (Energy and Portefeuille) each appoint an additional director. The Management Committee (Conseil de Gestion) is responsible for implementing the decisions of the Board ofDirectors, managing and supervising the company’s activities and preparing the financial statements. It is composed of the same four senior SNEL executives who sit on the Board of Directors, namely the Chief Executive Officer (Administrateur DdlkguC General (ADG)), the Assistant Chief Executive Officer, the Chief Technical Director, and the Chief Financial Officer. The committee also includes a union representative. The ADG chairs the committee. 3. In addition, the corporate governance structure includes a financial oversight body, the Colkge des Commissaires aux Comptes, a unit external to SNEL. The members play a supervision and monitoring role with regard to SNEL’s financial operations and as such are equivalent to an external inspection function. The members are appointed by the President ofthe Republic but are remunerated by SNEL. 63 SNEL Organigram IBOARD OF DIRECTORS I MANAGEMENT COMMITTEE I CHIEF EXECUTIVE OFFICER SECRETARIAT OF ASSISTANT CEO - GENERAL SECRETARIAT ADVISORY OFFICE Accounting General Services Press and External Relations Information and Documentation LEGAL DEPARTMENT I 1 RESEARCHAND DEVELOPMENT DEPARTMENT DEPARTMENT OF STUDIES AND I I STANDARDS Expansion Planning Economic and Financial Analyses External Financing Mobilization CONTROL DEPARTMENT Organization General Monitoring and Control IT 1 CHIEF TECHNICAL OFFICER CHIEF FINANCIAL OFFICER i GENERATION AND DISTRIBUTION INVENTORY AND FINANCE HUMAN TRANSMISSION DEPARTMENT PROCUREMENT DEPARTMENT RESOURCES DPT. DEPARTMENT DEPARTMENT - ~ KINSHASA REGION RURAL ELECTRIFICATION EQUIPMENT DISTRIBUTION DEPT UNIT DEPARTMENT COMMERCIAL ACTIVITIES Attachment 2 to Annex 6 Ministry of Energy Organizational Structure 1. The MoE portfolio comprises the electricity and water sectors. The MoE has formal supervisory authority over SNEL and REGIDESO with respect to technical aspects. Previously, the ministry also handled petroleum issues, but the oil portfolio was recently transferred from MoEto a newly created ministry ofpetroleum. 2. The MoE is responsible for the government’s policy in the electricity and water sectors, including: (a) drawing up the Government’s strategy in these sectors, and designing and managing sector policies; (b) establishing administrative rules and regulations; and (c) technical oversight over SNEL and REGIDESO, the electricity and water public enterprises. 3. The Ministry ofEnergy comprises the following administrative functions: H. E. the Minister and H. E the Vice Minister of Energy; Front Office functions, including a Chief of Staff; Secretary General-Energy and a Secretary General-Water responsible for managing the administration ofthe energy and water portfolios, respectively; the National Energy Commission which advises the MoE on energy policy issues; the CATE (the energy technical support unit, the Cellule d’Appui Technique Energie) established to provide institutional and technical support to MoE, to support the development and implementation of MoE strategies and policies, and to support specified project-related tasks and monitoring of donor funded projects; the Westcor support unit, to assist in the development of the Westcor initiative; and the Energy Sector Unit to assist the Government’s overall general public enterprise reform effort. 65 Annex 7: Financial Management and Disbursement Arrangements AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) A. Executive Summary 1. The financial management arrangements for the Project have been designed with consideration for the country’s post-conflict situation. The arrangements aim to facilitate disbursements and to ensure effective use of Project resources and funds while at the same time using the country’s own systems to the extent possible. To this end, overall coordination ofthe financial management aspects of the Project will be the responsibility of the Project Coordination Unit (PCU), supported by a Procurement and Financial Management agent (PFM Agent). 2. The principal objective of the Project’s financial management system will be to support the Project in the use ofresources to ensure efficiency and effectiveness in delivering the results required to achieve Project objectives. The financial management system must be capable of producing timely, understandable, relevant and reliable financial information that will enable the Project’s management to plan, implement, monitor and assess the Project’s overall progress toward its objectives. 3. The Financial Management team (FM team) of the PCU will be outsourced to a PFM Agent selected on a competitive basis and composed of 3 staff. The PFM Agent will be headed by a qualified and experienced Financial Manager. The FM team will be responsible for: (i)designing and establishing a computerized financial management system; (ii)approving disbursement offunds to services providers, contractors and consultants; (iii)maintaining up-to-date accounting records and ledgers; (iv) recording fiduciary transactions for all activities pertaining to the Project for which the FM team of the PCU is held responsible; (v) fiduciary reporting; (vi) submitting audit reports; and (vii) ensuring that a proper internal control system is in place to achieve accountability at all levels. Such an arrangement will enable the management of the PCU to focus on its main responsibility of coordination and supervision ofProject activities. 4. The team will be further strengthened through the recruitment of an Internal Auditor. The internal audit function will be camed out by a qualified and experienced international (individual) consultant recruited on a competitive basis. The consultant will be located at the PCU and will review the Financial Management Reports (FMR) submitted by the PCU and the Ministry ofEnergy, and will carry out regular internal audit controls. This will include the verification of eligibility of expenditures ex-post as well as physical inspection of works and goods acquired by the Project at central and departmental levels. 5. A Designated Account will be opened in US Dollars in a commercial bank acceptable to the Association. The account will be maintained by the PFM Agent established at the PCU. Disbursement from the IDA Grant will be transaction-based (that is, replenishment and reimbursement). Funds will be disbursed to contractors and providers of services, equipment, and goods, subject to the approval of the Project Coordinator of the PCU, in consultation with the Financial Manager of the PFMAgent. 6. Qualified, experienced and independent external auditors will be appointed on approved terms of reference. The external financial audit, including eligibility of expenditures and physical inspections, will cover all aspects of Project activities and will be carried out on an annual basis. 66 7. An anticorruption action plan will be developed by Grant effectiveness and will include oversight mechanisms such as development ofan effective mechanism to receive complaints and to investigate claims of wrongdoing. Among other anti-corruption measures, the frequency of supervision missions will be increased and at least three missions will be conducted during the first two years of the project implementation (and will benefit from field-based financial management staff). B. Country Financial Management Issues 8. The DRC has experienced a long period of instability, during which the administrative and regulatory institutions in the country seriously deteriorated. Efforts are being made to reestablish these. The recent elections open a new phase in DRC history. After decades of mismanagement, instability, and conflict, the Congolese have selected their leadership through an open and democratic process. 9. The existing capacity to assume financial management responsibility in the ministries and at decentralized administrative levels is weak. World Bank documents, notably the Country Financial Accountability Assessment (CFAA) completed in May 2005, portrays a highly unsatisfactory economic and financial control environment. In-depth structural reforms have been launched in the areas of economic governance, public expenditure management, financial sector and public enterprises to strengthen capacity in public administration. With the support of the international community, the Transitional Government had undertaken reforms in budget preparation and execution, adhesion to Treasury forecasts, preparation of regular budget execution reports, simplification of the national budget classification system, and monitoring and supervision ofpublic enterprises. 10. The relevant conclusions and major recommendations from the 2005 Country Financial Accountability Assessment are laid out in the table below: Key weakness Priority recommendations Outdated and poorly adapted legal and The legal and regulatory framework for public finance regulatory framework management must be completely revamped, in particular the Financial Law (organic law). Inadequate budget preparation cycle Review the budget cycle and establish the budget timetable by law. Non compliance with standard budget execution Strengthen ex ante budgetary controls to ensure adherence to procedures normal budget execution procedures and limit the incidence of exceptional procedures. Inadequate debt management Strengthen coordination between the units involved in public debt I management. Irregular, incomplete, unreliable production of Produce and publish execution reports in a timely manner using reports the computerized public expenditure system database. Lack of an accounting framework that meets Finalize, adopt, and effectively implement a double-entry standard norms accounting framework. Weak management and control of public funds Strengthen the procedures for opening and maintaining bank due to proliferation of bank accounts accounts, ensuring proper reporting of transactions. Weakness ofex post administrative oversight of Reinforce the capacity of the Inspectorate General of Government. expenditure execution Major need for training and human resources Establish strategies and plans to uplift the capacity of staff responsible for the management and tracking of public finances, 67 11. Although there is cause for cautious optimism, it will take a long time for these reforms to yield substantial improvements in the management of public funds. Given the fragility of the fiduciary environment, and the weak governance and risks associated to the Project, the only financial management and disbursement arrangements which provide the fiscal and fiduciary safeguards required for Projects financed by IDA are the arrangements described in the present annex. C. Institutional Arrangements for Financial Management The Project Coordination Unit (PCU) 12. Responsibility for the financial management and operational aspects of the Project will be assigned to the Project Coordination Unit (PCU) set up by the MoE, and consisting of the SNEL Project Coordination Team and of a MoE Team. The PCU will implement and manage the Project activities as well as managing Project funds. 13. The financial management functions that are the responsibility ofthe PCU will be outsourced, on the basis of competitive selection, to an auditing firm acting as PFM Agent for the Project. This FM team will be staffed with three consultants located at the PCU premises, headed by a qualified and experienced Financial Manager. The team will also comprise a Treasurer and an Accountant. This arrangement will enable the management of the PCU to focus on its main responsibility of coordination and supervision ofproject activities. Financial Management Assessment of the Ministry of Energy 14. The capacity assessment conducted during the Project preparation phase through the CFAA exercise revealed several capacity shortages in key ministries with respect to financial management and procurement. These weaknesses include: (i)a lack of sufficiently qualified staff in the areas of financial management; (ii)a lack of a tracking and reporting system and a formal accounting system within the ministries acceptable to the Association; and (iii)non-familiarity of ministry staff with IDA-financed project procedures for reporting requirements, disbursement arrangements and auditing. Therefore, the financial management system in place does not meet the Association’s financial management requirements. Financial Management Assessment of SNEL 15. The review of the SNEL financial management system as well as the audit reports and various external studies reveal significant weaknesses in term of internal control, accounting system and external oversight. SNEL faces a range of financial governance issues. These include weaknesses relating to contracting for goods and services, and shortcomings in the collection of revenues for power provided. The studies suggest that there is a lack of transparency and predictability in SNEL’s resources management, and the accounting system currently in place does not allow proper reporting and management offunds. 16. The overall conclusion of the financial management assessment is that in order to satisfy the World Bank’s minimum financial management requirements, a unit independent ofSNEL using IDA financial management procedures should be established. For this purpose, a PFM Agent will be recruited to lead the financial management function of the PCU, with the team consisting of three consultants (Financial Manager and Treasurer and Accountant). Management of the Designated Account\ will be the responsibility ofthe PFM Agent under the direction ofthe PCU. 68 D. Summary Risk Analysis 17. An effective financial management system will be vital for the Project because of the need to deliver services quickly over a large geographic area to a wide variety of stakeholders. The objectives ofthe Project’s financial management system are: (i)to ensure that Project funds are used only for their intended purposes efficiently and economically; (ii)to enable the rapid disbursement of Project funds to implementing agencies; (iii)to ascertain that funds are properly managed; (iv) to enable the preparation ofaccurate and timely financial reports; (v) to enable project management to monitor the efficient implementation of the Project; and (vi) to safeguard the Project assets and resources. 18. In the context of these objectives, the specific risks and proposed mitigation measures, the latter in the form of a Financial Management Action Plan, are summarized in the table below: Risk Assessment and Mitigation (H-High, S-Substantial, M-Moderate, L-Low) Risk Mitigating Measures Remarks Incorporated into Project Design Inherent risk Country level The Government of DRC is N The CFAA report outlined significant highly committed to a reform PFM weaknesses at government level program that includes the as well as sector ministries level: (i)in strengthening of the budget term of budget formulation and classifications, execution, financial reporting, and implementation of an interim oversight systems, (ii)weak linkage Integrated Financial between agreed policies, budget Management Information planning and execution; (iii)lack of System. A new legal an adequate tracking and reporting framework is being prepared. system and a formal accounting However, there are still system within the ministries; (iv) the weaknesses in capacity and in lack oftransparency and predictability audit & preparation ofthe first in public resource management at set of consolidated accounts. central government and public Efforts are continuing to enterprise levels; (v) insufficiently strengthen accounting and qualified staff in the areas of financial audit capacity. management. Use of IDA FM procedures Entity level Creation of a PCU and use of N The assessment of SNEL revealed IDA FM system requirements. significant internal control The government will adopt an weaknesses and a lack of anti-comption plan and other transparency. SNEL faces governance safeguards by Project issues. effectiveness. Project level Recruitment of PFM Agent Y The Project aims to finance with significant experience infrastructures and equipment in an and an Internal Auditor (Intl) environment that is characterized by on a competitive basis. the lack offiduciary capacity. Control Risk S 69 Risk Mitigating Measures Remarks Incorporated into Project Design Budgeting M Annual work plan and budget N required each year. The Project’s Administrative, Accounting and Financial Manual (AAFM) will define the arrangements for budgeting, budgetary control and the requirements for budgeting revisions. Annual work plan and budget required. Accounting S The Project will adopt Y The accounting system currently used international accounting by SNEL does not support the standards, and accounting Management in making decisions. procedures and policies will be documented in the AAFM. The FM functions will be outsourced to a PFM Agent and installation of a computerized accounting system completed. Training on IDA FM procedures planned. Internal H Manual of accounting and The distribution of responsibilities Control financial procedures required between the SNEL and the MoE before Grant effectiveness and requires clarification. Internal audit recruitment of an internal function exists, but is largely auditor. compliance and transaction oriented and adds little value to the control framework. Funds Flow S (i)Payment requests will be Without these measures, funds, approved by the PFM Agent especially for implementation prior to disbursement of funds agencies and the PCU, may not be to contactors or consultants. used in an efficient and economical (ii)Audits of performance way and exclusively for intended will be conducted and will be purposes. integrated to ensure a close link between physical progress and financial reporting. (iii)An internal auditor will be recruited to carry out regular physical inspection, assess the eligibility of expenditures and review ofthe quarterly FMR. Financial S To reduce delays and ensure a Reporting proper financial reporting system, a computerized accounting system will be put in place and will be under the responsibility of the PFM Agent. 70 Risk Risk Mitigating Measures Conditions Remarks Rating Incorporated into Project for Design Effectiveness (YB)~~ ~~~ M (i)The Project’s institutional Y The auditing profession in DRC is arrangements allow for the still generally weak. International appointment of adequate auditing standards are followed in the external auditors. industry. Audit reports are generally (ii) Annual auditing timely, and management letters arrangements will be put in contain issues that assist management place. to ensure the continuing adequacy of the financial management arrangements. Overall Risk s Rating 19. The Financial Management Action Plan described below has been developed to mitigate the overall FM risks. Financial Management Action Plan Issue Remedial Action Recommended Responsible Due date body Staffing Recruitment ofthe PFM Agent I PCU I Effectiveness Administrative, Adoption ofan Administrative, Accounting and 1 PCU I Effectiveness Accounting and Financial Manual of procedures Financial Manual Internal Auditing Terms ofreference for the selection ofthe PCU Effectiveness internal auditor agreed and expressions ofinterest advertised Selection ofthe internal auditor, as agreed by the Bank External Financial Terms ofReference for the selection ofthe PCU Effectiveness Auditing External Auditors agreed and expressions of interest advertised Selection ofthe External Financial Auditor completed Anti-corruption action Development and adoption of an anti-conuption PCU Effectiveness dan dan E. Financial and Administrative Management 20. Upon Grant effectiveness, the overall coordination of the fiduciary aspects ofthe Project will be under the responsibility ofthe PCU: Overall Responsibilities 2 1. The FM team of the PCU will be responsible for all financial management, accounting and audit aspects of the Project, including: (i)designing and establishing a computerized financial management system; (ii)approving disbursement of funds to services providers, contractors and consultants; (iii)maintaining up-to-date accounting records and ledgers; (iv) recording fiduciary 71 transactions for all activities pertaining to the Project for which the FM team of the PCU is held responsible; (v) fiduciary reporting; (vi) submitting audit reports; and (vii) ensuring that a proper internal control system is in place to achieve accountability at all levels. At least three sets of financial reports will be prepared and consolidated by the FM team of the PCU, namely the annual budget of the Project, the quarterly Financial Monitoring Reports (FMRs), and the Project financial statements. Administrative, Accounting and Financial Manual of Procedures 22. The accounting systems and policies, administrative (including procurement) and financial procedures employed by the Project will be documented in the Project’s Administrative, Accounting and Financial Manual (AAFM). This will be used by (i)the Project staff as a reference manual; (ii) by the Association to assess the acceptability of the Project accounting, reporting and control systems; and (iii)by the auditors to assess Project accounting systems and controls and to design specific Project audit procedures. Specific procedures will be documented for each significant accounting function. They will be written to depict document and transaction flows, and will cover the following aspects: flow of funds; record keeping and maintenance, the chart of accounts, formats of records and books of account; authorization procedures for transactions; planning and budgeting; financial reports (including formats, linkages with the chart of accounts and procedures for reviewing these); and auditing arrangements. The AAFM will also describe the PCU organizational chart and administrative and procurement procedures as agreed in Section I11 of Annex 2 to the Financing Agreement. Planning and Budgeting 23. The PCU will prepare an annual work plan and budget for implementing Project activities talung into account the Project’s objectives. The work plan and budgets will identify the activities to be undertaken and the role ofrespective parties in implementation. Annual work plans and the budgets will be consolidated into a single document by the PCU, which will be submitted to the Ministry of Energy for approval, and thereafter to the Association for no objection no later than November 30 of each year preceding the year in which the work plan is to be implemented. The consolidation will be done after the PCU ensures, through its technical teams, that the plan and budget meet the Project objectives. Stafing: Financial Management Agency 24. The PCU will retain staffing resources that are adequate for the level ofProject operations and activities and are sufficient to maintain accounting records relating to Project-financed transactions, as well as to prepare the Project’s financial reports. The FM team will be responsible for (i) maintaining the Project expenditure accounts (ii)approving payments to service providers, contractors and suppliers of goods; (iii)drafting the Project financial statements (budget, FMR and annual accounts); and (iv) auditing and reporting to the Association. Such an arrangement will enable the management of the PCU to focus on its main responsibility of coordination and supervision of project activities. The PFM Agent will have the overall FM responsibility including for budgeting, accounting, reporting, disbursement and auditing functions. The PFM Agent will also, where required, help build the capacity ofthe staff of SNEL. Record Keeping and Maintenance 25. The FM team of the PCU will be responsible for maintaining the Project’s records related to expenditures incurred by the PCU. All accounting documents of contracted implementing agencies 72 will be kept at their premises and made available upon request during supervision missions and audit missions carried out by internal and external auditors. Financial Reporting 26. Consolidated financial management reports (FMR) will be designed to provide quality and timely information on Project performance to Project management, and relevant stakeholders. Formats ofthe various periodic FMRs to be generated from the financial management system will be developed using the World Bank’s Guidelines for Borrowers on Financial Monitoring Reports. The quarterly FMR includes financial statements (e.g. sources of funds and Projects revenue and uses of funds; statement of expenditures classified by Project component, disbursement category, expenditure types and implementing agent, showing comparisons with budgets; cash forecast; physical progress report; notes to the FMR Special Account activity statements and information on contracts above and below the prior review threshold). In compliance with International Accounting Standards and IDA requirements, the Project will produce annual financial statements. These include: (i)a balance sheet that shows assets and liabilities; (ii)a Statement of Sources and Uses of Funds showing all the sources of Project funds, expenditures analyzed by Project component and Grant category; (iii)a Statement ofCash Receipts and Payments which recognizes all cash receipts, cash payments and cash balances controlled by the Project; (iv) a Special Account Activity Statement; (v) an implementation report containing a narrative summary of the implementation progress of the Project; (vi) a summary of withdrawals using FMR, listing individual withdrawal applications by reference number, date and amount; and (vii) notes related to significant accounting policies and accounting standards adopted by management and underlying the preparation of financial statements. The FMR and financial statements, whose format will be developed by grant effectiveness, will be submitted for audit at the end ofeach semester or other periods to be stated. Integrated Financial Management System 27. For the Project to deliver on its objectives, a computerized financial management system will be developed based on software to be acquired by the PCU (to be performed by grant effectiveness). The system should integrate budgeting, operating and accounting systems to facilitate monitoring and reporting. The formats of periodic reports would be developed and agreed with Project management. F. Audit arrangements Internal Auditing 28. A separate Internal Audit function outsourced to an international (individual) consultant will be established to support the PCU. The consultant will be located at the PCU offices. The role ofthe position will be to ensure that the Project’s fiduciary procedures and regulations are adhered to by all the implementing agencies. The selected consultant will inspect accounting procedures used by the PCU to ensure that they conform to the established procedures. This inspection will cover the verification ofexpenditures including payments ofworks and acquisition of furniture and equipment. The scope of the consultant’s mission will also include review ofthe quarterly FMR as well as any financial statements submitted to the Association by the PCU and other entities. The Administrative, Accounting and Financial Manual, as well as the terms of reference for the selection of the consultant, will contain a description of the roles and responsibilities of the internal audit function and the arrangements that guarantee the necessary level of independence. 73 External Financial Auditing 29. A firm of qualified independent auditors will be contracted by the PCU to carry out the audit of the financial statements of the Project on an annual basis. The selection of the successful firm will be based on a Terms of Reference that sets forth the scope of the audit. The audit firm will also be recruited on terms that meet the Association’s requirements relating to independence, qualifications and experience. The scope of the audit will cover the activities performed by any entity managmg Project funds, mainly SNEL, the PCU, and the Ministry ofEnergy. The audited financial statements, together with the auditor’s report and management letter covering identified internal control and accounting system weaknesses, will be submitted to the Association no later than six months after the end of each accounting period. A single audit opinion will be issued with respect to Project income and expenditures, special accounts and the FMRs. A second audit opinion will be issued on specific controls such as compliance with procurement procedures and FMR requirements and consistency between financial Statements and management reports and field visits. The audit report will thus refer to any incidences of non-compliance and to any ineligible expenditures identified during the audit mission. Closing the Accountability Cycle: Following up on Audit Queries 30. The duties of the management of the PCU will include the review of audited financial statements and internal and external audit findings. The outsourced internal auditing function will require corrective actions to be taken by the PCU and any other implementation agencies as relevant, to address any weaknesses in the fiduciary management system or incidences of non-compliance with procedures. The internal audit function will also use the results of the audits in monitoring the performance of other agencies at national and regional level. This arrangement is intended to ensure the satisfactory follow-up ofaudit findings. G. Conclusion of the Assessment 3 1. The outsourcing ofthe key financial functions to a PFM Agent will enable the establishment ofa financial fiduciary management system for the Project that satisfies the Bank’s minimum requirements under OP/BP 10.02. The financial management arrangements, including the actions intended to strengthen these, will be adequate to provide, with reasonable assurance, accurate and timely information required by the Association on the status of the Project. The actions which are required by effectiveness of the grant to facilitate the establishment of this system are set out in the Financial Management Action Plan described above. H. Supervision Plan 32. Financial management supervision missions will be conducted over the Project’s lifetime, at least on a semi-annual basis (and will benefit from the field presence of a financial management expert). But due to the fiduciary risks associated with this Project, more supervision missions budget will be allocated in order to increase the frequency of controls. It is planned at least three supervision missions during the first year ofthe project implementation (including reliance on field- based staff). The missions’ objectives will be to ensure that adequate and effective financial management systems are maintained for the Project throughout its lifetime. A review will be carried out regularly to ensure that expenditures incurred by the Project remain eligible for IDA funding. The Implementation Status & Results Report (ISR) will include a financial and procurement management rating for the component. 74 I. Disbursement arrangements and flow of funds Disbursement of funds to the Project Coordination Unit 33. The PCU will open a Designated Account in order to manage program expenditures, as follows: 0 Designated Account: To facilitate Project implementation and reduce the volume of withdrawal applications, the PCU will open and maintain a Designated Account in US Dollars in a commercial bank on terms and conditions acceptable to the Association. This account will finance all eligible Project expenditures. 0 The ceiling will be US$300,000 for the Designated Account. The amount has been calculated to represent approximately four months of eligible expenditures. Upon Effectiveness, IDA will deposit US$ 150,000 in the designated account representing 50 percent ofthe ceiling. 34. The Designated Account will be used for all payments inferior to 20 percent of the deposited amount and replenishment applications will be submitted, at least once a month. Additional deposits into the Designated Account will be made against withdrawal applications supported by appropriate documents. The option of disbursing funds thought direct payment on contracts above a pre- determined threshold will also be available. Withdrawal applications for such payments will be accompanied by relevant supporting documents such as copies ofcontract, contractor’s invoices and appropriate certifications. The Designated Account will be audited annually by external auditors acceptable to the Association as part ofthe overall Project audit. 35. Disbursement from the IDA Grant will be transaction-based (that is, on a replenishment and reimbursement basis). The option of disbursing the funds through direct payments on contracts above a pre-determined threshold will also be available. Withdrawal applications for such payments will be accompanied by relevant records such as copies of the contract, contractors’ invoices and appropriate certifications. Disbursement offunds to SNEL by the PFM 36. The PFM will make disbursements to SNEL for operating expenses and other small amounts based on budget transfers, as set out in a Memorandum ofUnderstanding (MoU) agreed between the PFM and SNEL. The MoU is required prior to the transfer of funds from the PFM to SNEL. The MoU will provide 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$50,000. Payments will be made into commercial bank accounts opened by SNEL. The PFM will effect subsequent payments to SNEL upon submission of supporting documentation for the previous payment, as specified in the MoU (FMR, and a Statement ofExpenditures (SOE)). In addition, the PFM will rely on the findings of the internal auditor prior to approval ofthe payments where applicable. The PCU, with the assistance of the PFM Agent and the internal auditor, will reserve the right to verify the expenditures ex-post and refunds might be requested if contractual clauses were not respected. Uses of Statement of Expenditures 37. Disbursements for all expenditures should be made against full documentation except for contracts valued at less than: (i)US$l,OOO,OOO for works; (ii)US$250,000 for goods; (iii) 75 US$lOO,OOO for consulting firms and (iv) US$50,000 for individual consultants as well as operating costs which will be claimed on the basis of SOEs.’ Training and operating costs will also be claimed on the basis of statement of expenditures (SOEs). All supporting documentation for SOEs will be retained at the PCU. They will be kept readily accessible for review by periodic IDA, PCU supervision missions and external auditors. J. Allocation of Grant Proceeds Amount of the Percentage of Grant Allocated Expenditures to be Category in US$ million Financed (1) Works re: Rehabilitation ofInga Plant (Inga 1 ce equipment, transport Plan) 4.1 100 percent (8) Refinancing of PPF 3 .O (9) Unallocated 35.4 Total Amount 296.7 I The proposed thresholds are in line with the procurement PR thresholds indicated in Annex 8, 76 Annex 8: Procurement Arrangements AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) A. General 1. Procurement for the Project for contracts financed in whole or in part by IDA will be carried out in accordance with the World Bank's "Guidelines: Procurement Under BRD Loans and IDA Credits" of May 2004, revised October 2006; the "Guidelines: Selection and Employment of Consultants by World Bank Borrowers'' of May 2004, revised October 2006; and the provisions stipulated in the Legal Agreements. The various items under different expenditure categories are described in general below. For each contract to be financed by the Grant, the different procurement methods or consultant selection methods, the need for pre-qualification, estimated costs, prior review requirements, and time frame are agreed between the Borrower and the Bank in the Procurement Plan. The Procurement Plan will be updated at least annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. 2. Procurement of Works: Works procured under this Project will include: the rehabilitation of the hydroelectric facilities at Inga 1 and 2, the rehabilitation ofturbines at Inga 1 and 2, dredging and re-profiling of the feeder canal at Inga, and rehabilitation and expansion of the power distribution system in Kinshasa. The procurement will be done using the Bank's Standard Bidding Documents (SBD) for all contracts. Works estimated to cost US$1 million per contract and above will be procured through ICB. Works estimated to cost less than US$l million per contract may be procured through NCB. Works may also be procured through Direct Contracting with the prior approval if IDA. A prequalification will be carried out for works contracts estimated to cost US$lO million and above, exceptions to which require the prior approval of the Bank. The construction of a second power transmission line from Inga to Kinshasa will be financed by co-financiers using their own procurement procedures. 3. Procurement of Goods: Goods procured under the Project will include pesticides, a pesticide spraying boat, vehicles, and computers and office equipment. The procurement will be done using the Bank's SBD for all contracts. Goods estimated to cost US$200,000 per contract and above will be procured through ICB. Goods estimated to cost less than US$200,000 per contract may be procured through NCB. Goods estimated to cost less than US$50,000 per contract may be procured through Shopping. Goods may also be procured through LIB and Direct Contracting with the prior approval ofIDA. 4. Procurement of non-consulting services will include onchocerciasis vector control, laboratory analysis ofdredging sludge, training and workshops. 5. Selection of Consultants: Consulting services will consist of feasibility studies, design, preparation and evaluation of bidding documents, and supervision associated with the works listed above; environmental and social impact assessments and associated management plans; strengthening maintenance programs; strengthening procurement and financial management performance; legal financial and technical assistance; and financial and procurement audits. Contracts with consulting firms may also be procured through Quality Based Selection (QBS). Contracts estimated to cost less than US$lOO,OOO may be procured through Selection Based on Consultant Qualifications (CQS). The Single Source Selection (SSS) of firms requires the prior approval of IDA. Individual consultants may be selected in accordance with the provisions of Section V of the Consultant Guidelines. 77 6. Operating Costs: Incremental operating costs associated with the implementation ofthe Project will consist ofvehicle operating costs, other transportation costs, office rental and utilities, stationary and other office consumables, travel allowances, insurances, and production ofreports. B. Assessment of the agency’s capacity to implement procurement 7. Country context. A Country Procurement Assessment Review was carried out in 2002 and found that the existing national regulations are inadequate for use in IDA-assisted Projects. The main problems with the national procurement practices that were identified in this review are: weaknesses of the legal framework and lack of enforcement; inefficient and costly procedures and practices; weak procurement organizations and capacity; weak audit and unit-corruption mechanisms; and payment delays that result in higher contract prices. An action plan to implement the agreed recommendations is being implemented through the IDA-assisted Economic Management Technical Assistance Project. However there has been little progress with the national procurement reforms as other political and development priorities have had to be addressed, following many years of civil war and economic decline. The dialogue with the Government on procurement reform was at a virtual standstill in the period preceding the Presidential elections and was resumed after the appointment ofthe new cabinet. The overall country procurement risk is high. 8. A number of Post Procurement Reviews (PPR) have been carried out in recent years that identified weaknesses in the procurement on projects under implementation and have resulted in some instances in a declaration ofmisprocurement. 9. SNEL and MOE. The procurement capacity ofthe main project implementing agencies, SNEL and MOE, has been assessed and was found to be inadequate for the Project. The key issues and risks that would arise if procurement were entrusted to these agencies include: political interference with the orderly procurement function; insufficient procurement experience of the staff; lack of experience with World-Bank assisted projects; insufficient interest ofthe private sector in competing for the contracts; and costs exceeding the estimates by a wide margin. The procurement risk with entrusting procurement to these agencies would therefore be high. 10. Mitigating measures. To mitigate the high procurement risk, all procurement activities will be carried out by a Procurement and Financial Management (PFM) Agent, who will be selected through competition. The TOR for this assignment and the performance evaluation criteria for the consulting firm will be designed to ensure that the PFM Agent has adequate procurement capacity to implement the Project. The PFM Agent’s employer will be the MOE. The selection of the consultant for the assignment will be done under the direction of MOE, with the support of a procurement agent satisfactory to the Association. To carry out the procurement function, the PFM Agent will be staffed at the minimum with one senior procurement specialist (SPS) and one procurement officer. The SPS should have knowledge and experience - some of it internationally - in (i)the power sector, including generation and distribution, (ii)procurement in general, and (iii)procurement under World Bank policies and procedures. The PFM Agent will be required to deploy additional staff on a part- time basis who are capable ofbacking up the SPS as needed and to carry out an extensive capacity building and training program. 11. Under the coordination of the PCU, SNEL will be responsible for the technical aspects of the planning and execution of the contracts relating to all Project components, except for those in Component 4(b) relating to the MOE, mainly through the involvement of the relevant SNEL departments (see Annex 6). SNEL will also benefit from the support of the engineering firm employed for the detailed engineering and supervision phases. SNEL will sign contracts relating to its components jointly with the PFM Agent and will participate in contract management in the form 78 of a clearance of contractual payments. SNEL will second counterpart staff with procurement knowledge to the PFM Agent to participate in the procurement functions and to gain procurement experience for the ultimate benefit of SNEL. The organizational responsibilities for the different steps in procurement and contract management will be specified in the terms of reference for the PFM Agent. 12. The following additional mitigating measures for the Project will be taken: . Commitment ofMOE to safeguard the procurement process that is the contractual obligation ofthe PFMAgent; . Annual procurement audits; . Capacity building in SNEL and MOE (e.g. improved governance procedures -- see Attachment 1 to Annex 4 -- and training through courses and through secondment to the PFM Agent); . Support for the national procurement reform through other assistance projects; Keeping cost estimates up to date; and . Wide advertising about business opportunities for the private sector. C. Procurement Plan 13. The Borrower developed a procurement plan for project implementation which has assisted in the choice of procurement methods. This plan has been agreed on between the Borrower and the Project Team during negotiations and is available at the offices of SNEL in Kinshasa (with the PCU team). It will also be available in the Project Database at the Bank’s external website. The Procurement Plan will be updated in agreement with IDA annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. D. Frequency of Procurement Supervision 14. In addition to the prior review of procurement decisions submitted by the Borrower that will be carried out at the Bank’s offices, the results ofthe procurement capacity assessment call for one & review of procurement actions per year. 79 E. Details of the Procurement Arrangements Involving International Competition The contracts are financed in whole or in part by IDA. 1. Goods and Works (a) Thresholdsfor Procurement Methods and Prior Review I Procurement Method I Procurement Methods Threshold I Prior Review Threshold 1 I ICB (Goods) I Contracts of US$200,000 and above I All contracts I I LIB(Goods) I None I All contracts I NCB (Goods) Contracts below US$200,000 First 2 contracts ICB (Works) Contracts of US$1 million and above All contracts NCB (Works) Contracts below US$l million First 2 contracts I Shopping (Goods and Works) I Contracts below US$50,000 1 First 2 contracts I Direct contracting (Goods and None All contracts Works) Contracts for works valued at US$lO million or more are procured using prequalification ofbidders, exceptions to which require the prior approval of the Bank. 1 2 3 4 5 6 7 8 No. Estimated Procure- Prequali Review Expected Contract Cost (in ment fication by Bank Bid- Comments Description US$ Method (Yes/No) (Prior / Opening Millions) Post) Date Generation 1.1 Rehabilitation of Inga I1A 86.7 ICB Yes Prior May 08 Consultant units (G21, G22, G23, and selection for G24) design is underway 1.2 Rehabilitation of Inga I 48.2 ICB Yes Prior April 08 Same as above Units and common facilities 1.3 Inga Short-termworks - 2 4.0 ICB No Prior December To be deter- lots 07 minedbythe 11 2 3 4 5 6 7 8 Contract Cost (in ment fication by Bank Bid- Comments Description US% Method (Yes/No) (Prior / Opening Millions) Post) Date 1.4 Inga - Intake Canal 20.3 ICB Yes Prior October Consultant reprofiling 08 selection for design is underway 1.5 Inga - Intake Canal 39.1 ICB Yes Prior April 08 Same as above dredging 2.1 Network rehabilitation (lot 22.2 ICB Yes Prior March 08 Same as above A) & extension in Kinsenso, Mpasa and Malweka 2.2 Emergency works for 4.0 ICB No Prior December To be deter- distribution - 2 lots 07 minedbythe engineering study TOTAL ESTIMATED 224.5 COST 2. Consulting Services (a) Thresholdsfor Procurement Methods and Prior Review Procurement Method Procurement Methods Prior Review Threshold Threshold OCBS and OBS None All contracts ofUS$lOO.OOO and above 1 COS I Contracts below US$lOO,OOO I First 2 contracts I sss None All contracts ICs None All contracts ofUS$50,000 and above Short lists of consultants for services estimated to cost less than US$lOO,OOO equivalent per contract may comprise entirely national consultants in accordance with the provisions of paragraph 2.7 of the Consultant Guidelines. All TORSfor the selection offirms and individual consultants are subject to prior review regardless ofthe estimated value of the contract. 81 (b) List of consulting assignmentsfinanced through the Grant 11 3 I 1 Estimated Ref. Description of Assignment Comments Cost (in No. US$ I Post) 1. SNEL 4.1 Business systems for 10.2 QCBS Prior March 08 Based on collection and billing diagnostic analysis to be completed in Nov. 2007 4.2 Strengthening offiancial 9.0 QCBS Prior October 07 Based on and procurement systems diagnostic analysis completed in Nov. 2006 4.3 Strategic expansion plan 2.5 QCBS Prior June 08 4.4 Dam safety maintenance 1.5 QCBS Prior December 07 program 4.5 Diagnosis of maintenance 2.0 QCBS Prior November 07 structure 4.6 Financial audits, 3 years 0.2 QCBS Prior October 08 4.7 Procurement audits, 4 years 0.3 QCBS Prior February 08 4.8 Preparation of annual reports, 0.5 QCBS Prior February 08 5 vears 2. Ministry of Energy 4.9 Legal and financial Advisory 4.0 QCBS Prior July 08 services 3. Project Execution 4.10 Detailed engineering design 23.6 Prior April 07 and supervision 4.11 Fiduciary agent for 5.9 Prior July 07 procurement and financial management 4.12 Institutional support 0.25 QCBS Prior December 07 (supervisory) to Environment Unit I resettlement plan 4.14 I Audit of implementation of I 0.15 social and environmental action lan TOTAL ESTIMATED COST 82 Annex 9: Economic and Financial Analysis AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) A. Common assumptions 1. The economic and financial analyses are based on a set of largely common factors: A. Inaa Rehabilitation - Increase in MW. The rehabilitation of the generation facilities is expected to increase production capacity at the site by about 600 MW, from about 700 MW to about 1300 MW. The increase will be incremental, averaging about 150 MW per year beginning end 2009 through end 2012. From a purely technical perspective, given the run-of-river quality of the Inga site and the hydrological conditions, the plant load factor could be 85 percent or higher. However, given that there is not expected to be a demand for the totality of the potential output of Inga during off- peak hours, the analysis ofthe benefits ofthe Project is based on an assumption of a 70 percent load factor. Thus each incremental MW ofcapacity can be expected to generate 6,132 MWH per year. B. Second Inaa/Kinshasa Transmission line. The second transmission line from Inga to Kinshasa is anticipated to be commissioned in 2010 and is expected to increase the capacity to deliver power to Kinshasa from the current 450 MW (along the oversaturated existing 220 KV line) to well over 700 MW. This second line will also provide increased security of supply to the Republic of Congo through this corridor. C. Markets for Incremental Power. The incremental power generated at Inga is anticipated to be destined for three distinct markets: (a) domestic consumption in Kinshasa and to a lesser extent in Bas Congo, (b) exports, primarily to the SAPP and potentially to the CAPP countries (notably for Brazzaville in the Republic of Congo, where demand for power from Inga is expected to diminish as its own hydropower site comes on line), and (c) consumption by mining and other large industrial consumers in the Katanga region. The following allocation to these various markets is set out in Table 9.1. Table 9.1 : Markets D. Kinshasa Distribution. Currently, the Kinshasa distribution system is oversaturated, with transformers operating at precariously high levels of capacity, which result in localized loss of power and contribute to high technical losses. The Project will alleviate this stress on the system by financing rehabilitation of the existing system. In addition, the Project will also electrify several areas in Kinshasa not currently served where nearly 2,000,000 people live. The Project will fund 50,000 new connections in these areas and, by providing the distribution backbone, will provide the basis for further connections at a relatively lower cost per connection. E. System Losses and Auxiliaw Use of Power. The following system losses and other uses are assumed for purposes ofthe economic and financial analysis: a. Generation at the Inga site: auxiliary systems are assumed to consume 0.3 percent of generation. 83 b. Transmission losses: i. 10 percent for the HVDC line from Inga to Katanga, including transmission and conversion for HV and MV clients (of which about 1.5 percent relating to the step- down and conversion to AC); and ii. 2.5 percent for the existing 220 kV AC line from Inga to Kinshasa, and by extension 2.5 percent for the proposed second transmission line, with an additional 0.5 percent in step-down losses. c. Distribution system in Kinshasa: (i)initially 15 percent technical losses and 10 percent non-technical losses, with technical losses gradually reducing from 15 to 12 percent as a result ofthe rehabilitation works financed by the Project. F. Collection Losses. In addition, SNEL faces significant collection losses of about 50 percent &e., collections as a percentage ofbilling) for sales into the Kinshasa system (65 percent for residential customers), but only marginal losses for export sales to SAPP countries (as distinguished from other exports) and to high voltage private mining customers. G. Capital Costs and Operation and Maintenance Costs: Anticipated capital expenditures on generation, transmission and distribution, as well as operating and maintenance costs are detailed in Table 9.8 of this annex. Operating and maintenance costs are assumed to be 2.5 percent of investment costs in generation, transmission and distribution. The analysis also assumes that incremental commercial costs (metering, billing and collection) in Kinshasa will amount to 10 percent ofincremental revenues. H. Benefits and Revenues. The economic benefits are distinguishable into two major types: (a) the economic benefit from selling to domestic consumers, which has been evaluated based on a willingness-to-pay analysis; and (b) the economic benefit from the export of power, which has been evaluated as a function of the sales price at export. For simplicity, the sale of power to domestic mining customers has been evaluated in the same manner as exports, namely the sales price. By comparison, the bases for the financial analysis for exports and sales to mining customers are identical to the economic analysis, but differ from the economic analysis for domestic customers in Kinshasa in two respects. First, while the economic analysis incorporates the benefits of power delivered to customers (i.e., net of technical losses), the financial analysis is based on actual revenues collected (i.e., net of technical, non-technical and collection losses). Second, the actual tariff charged by SNEL, rather than the willingness-to-pay, is used for the financial analysis. B. Economic Analysis 2. The proposed Project has been analyzed over the period 2008-2038. The analysis conducted by SNEL for each component of the Project (supported by their external consultants) has been reviewed and found to be satisfactory. The Project constitutes a major part of SNEL’s least-cost investment activities. The Project’s distribution component is an integral part of the best solution to address current inefficiencies and problems with the distribution system, while the transmission investment constitutes a part of the least-cost transmission investment to transmit the additional power to the Kinshasa load center. Economic Benefits 3. Economic benefits associated with incremental electricity sales to consumers are calculated using: (i)the consumers’ willingness to pay as proxies ofbenefits for domestic sales; and (ii)the export tariff for sales to the mining sector and sales outside DRC. Details of the incremental energy sales for the domestic 84 market and for exports are shown in Table 9.7. The projected economic benefit streams are presented in Table 9.8. Willingness to Pay 4. The value of the willingness to pay (WTP) of consumers of electricity has been calculated as a function of the willingness to pay for three separate classes of customers: residential, commercial and industrial consumers. 0 Residential Electricity Consumption. About 10 percent of present total residential electricity use can be considered minimum lighting requirements. In the absence of electricity supply, households would use kerosene lamps. This portion is valued at the economic cost of US cents 37.9kWh. The remainder of consumption is conservatively assumed to be valued at US cents 1.5kWh (the 2006 average domestic tariff revenue) at the margin. This is a conservative assumption because this residential tariff level is very low and does not necessarily reflect the true economic benefit ofpower supply for DRC. 0 Commercial Electricity Consumption. For commercial consumers, the willingness to pay is based on a basket in which 30 percent of consumption is assumed to derive from gasoline fired engines at a cost estimated at US cents 2O.61/kWh7 with the balance provided by SNEL- equivalent sources. 0 Industrial Electricity Consumption. The willingness to pay for industrial customers isbased on a basket in which 40 percent ofindustrial customers are assumed to use diesel engines at a cost estimated at US cents 20.34 kwh, and the balance isprovided by SNEL-equivalent sources. 5. The weighted average WTP for a kWh of incremental electricity supply is derived using the 2005 consumption mix presented in Table 9.2 below. Based on these factors, the Weighted Average WTP for domestic consumption is US cents 6.15kWh. Table 9.2. Willingness to pay Share in 2005 Wilh'IgneSS to pay Weighted Customer group Consumption mix (UScentslkWh) willingness to pay (UScentslkWh) Residential 0.70 5.14 3.60 Commercial 0.20 7.93 1.59 Industrial 0.10 9.64 0.96 Aggregate average 6.1 5 6. Sales to the mining sector and for exports are valued at the contractual sale prices and related revenues. The latest commercial negotiations between SNEL and SAPP countries have established a reference tariff of US cents 2.5kWh. This price remains well below the long run average incremental cost ofnew power supply in SAPP and given that demand growth seems to be exceeding additions of generation capacity in SAPP, SNEL should be able to negotiate higher prices in the future. We have assumed that prices would increase by 25 percent in 2010, and by another 25 percent in 2015 (which yields a figure of US cents 3.9kWh in 2015). 7. Under these assumptions, the economic net present value (NPV) ofthe Project, calculated at a discount rate of 12 percent, is US$501 million and the internal rate of return is 29 percent. The results of the sensitivity analysis show that the Project is robust to significant variations in its main variables (i.e. capital cost and sales revenues). Even in a low case scenario that combines a 20 percent reduction in revenues 85 from Kinshasa, mining and exports and a 20 percent increase in investment costs, the NPV ofthe Project is US$234 million. The sensitivities are presented in table 9.3 Sensitivity Analysis NPV IRR(%) Base Case 501 29% (1) 20% increase in investment costs 423 24% (2) 20% reduction in revenues in Kinshasa 383 25% (3) 20% reduction in revenues from mining and exports I 429 27% Low case: (1) + (2) + (3) I 234 19% 8. Regional Dimension of the Proiect. The Project has additional economic benefits at a regional level that have not been directly quantified. First, the increases in the available capacity in DRC and in the energy flows between DRC and the other SAPP countries are essential steps to deepen the short and long term markets for power trading in the region. By decreasing the total reserve capacity in the southern Africa region, important savings in investment capital can be made. Furthermore, the Project increases the security of power supply in the southern Africa region. Based on historical data, the probability of occurrence of a major drought in the SAPP countries every 10 years is high. One exception is DRC, which benefits from the very large catchment area of the Congo River spread on both sides of the equator. Thus, the Project will enable the use ofDRC’s generating plants as a backup to mitigate the impact of a possible drought on electricity production in the rest of the SAPP countries. Finally, the increase of cheap hydro electricity supply will substitute for thermal plant generation and contribute to the reduction of fossil fuel emissions. 9. Other Benefits. The Project will also result in the reduction of system losses as a result of new and rehabilitated infrastructure in transmission and distribution (thereby reducing transmission losses from Inga to Kinshasa and distribution losses in Kinshasa). In addition to the benefits quantified in the economic analysis, the Project will also assist SNEL’s institutional development through technical assistance to upgrade the technical, financial and managerial capabilities ofSNEL and its staff. The institutional support is expected to bring about sustained improvement in SNEL’s operational efficiency and financial performance. 10. Distribution ofbenefits. Domestic consumers are the biggest beneficiaries of this Project because of the divergence between the financial price (or what they pay for electricity) and the value to them for the electricity they consume. The second largest beneficiary is SNEL. 11. Least Cost Assessment. The alternative configurations for meeting the Project’s objectives are limited. One alternative would be the construction of a new hydropower plant; however, a new construction is estimated to be costlier (US$1 million or more per installed MW) than the rehabilitation of these existing Inga plant (estimated at US$0.3 million per installed MW); the new construction would also take longer than rehabilitating the existing turbines. Another alternative is the construction and operation of a thermal power plant near Kinshasa to supply the main domestic load center. The investment costs alone would be at least about two to three times the cost of rehabilitating the Inga hydropower plant or about US$400-600 million for generation alone (excluding fuel costs, a major item in a thermal power plant). This would eliminate the need for a large part of the transmission line but would necessitate either the construction ofa fuel pipeline (estimated at over 250km from Matadi, DRC’s main port, which itself is in need ofextensive rehabilitation), or ferrying the fuel through a variety of means (barges along the Congo river and then by truck), which presents major logistical issues and reliability concerns. In addition, DRC would have to pay on an ongoing basis, the costs for fuel that is hampering thermal power plants in many other countries. The least cost option to supply the needed energy for the domestic and export markets is the rehabilitation ofthe Inga hydropower plant and the construction of the second transmission line from Inga to serve Kinshasa. 86 The no-project alternative would deprive DRC of the needed improvements in the power sector and the anticipated US$501 million ofnet economic benefit (as calculated on an NPV basis). C. Financial Analysis of the Project Assumptions spec& to theJinancia1 analysis 12. As described above, the financial analysis and the economic analysis are built around common assumptions, but with several salient differences that yield lower financial returns for SNEL as compared to the Project’s overall economic benefits. There are two major factors: 0 Difference between average electricitv tariffs and the willingness to pay: this difference is especially large in Kinshasa, were low voltage tariffs for domestic users are very low because they have remained unchanged in nominal terms for years while the local currency has depreciated (in comparison, LV commercial users are billed in USD and are charged an average tariff about 9 times higher). 0 Non uavment and losses: In Kinshasa, collection rate for electricity bills is only 50 percent, in addition to non technical losses estimated at 10 percent. This means that only about 45 percent of the power physically supplied to end-users (i.e., net oftechnical losses) is effectively paid to SNEL. 13. The financial analysis is therefore based on the following specific assumptions: In Kinshasa,: o Nontechnical losses of 10 percent o Average tariffs in 2005 were US cents 2.4 per kwh (based on a weighted average of US cents 1.7 for LV and US cents 7.7 for MV). Since 2007, the Government has started to implement a strategy of increasing tariffs. Accordingly, the analysis assumes an average tariff of US cents 2.98 per kwh in 2008 that would be gradually increased to US cents 4.40 per kwh in 20 15 (an aggregate increase of about 50% over the period). o Total collection rate of 52 percent initially in 2008, would improve to 62.5 percent over 6 years as a result of the actions under the Project to increase SNEL’s billing and collection activities. The largest contribution to this improvement would come from residential customers in accordance with the monitoring indicators for the project. 0 For exuorts to SAPP and sales to mines, the price assumption is the same as in the economic analysis, namely US cents 2.5kWh initially increasing by 25 percent in 2010 and another 25% in 2015. Collection from these high end customers has been estimated at 95 percent, based on the good track-record of collection from SAPP and private high voltage customers. Project Rate of Return and Sensitivities 14. Under these assumptions, the financial internal rate ofreturn of the Project (FIRR) would be 20 percent and the NPV (at a 12 percent discount rate) equal US$293 million. Detailed financial streams are presented below in Table 9.9. The returns remain robust under a variety ofscenarios, as presented in Table 9.4 below. Even in a low case scenario combining a 20 percent increase in investment costs together with a 20 percent reduction in revenues from Kinshasa, exports and mining customers, the FIRR would be 14.1 percent. 87 Table 9.4 - Project Financial Rate ofReturn - Sensitivity Financial Analysis - Sensitivity NPV FIRR(%) Base Case 293 20.4% (1) 20% increase in investment costs 216 17.4% (2) 20% reduction in revenues in Kinshasa 254 19.3% (3) 20% reduction in revenues from mining and exports 198 17.8% Low case: (1) + (2) + (3) 81 14.1% Rate of Return by Domestic and Export components 15. This Project is aimed at serving two distinct markets: high voltage users (private mining companies and SAPP), on the one hand, and electricity distribution in Kinshasa, on the other hand. These markets present different financial characteristics. It is possible to dissociate the investments, operating costs and flows of revenues associated with each market, and analyze each component separately. The results are set out in Table 9.5 and Table 9.6 below. Table 9.5 - Ex~ortsand mines component Sensitivity Analysis - Exports and mines NPV FIRR(%) Base Case 374 55.1% (1) 20% increase in investment costs 354 46.4% (2) 20% reduction in revenues 279 44.6% Low case: (1) + (2) 259 37.6% Table 9.6 - Kinshasa Distribution components Sensitivity Analysis - Kinshasa NPV PI=(%) Base Case -104 7.7% I( 1) 20% increase in investment costs -177 5.7% I (2) 20% reduction in revenues -144 5.9% Low case: (1) + (2) -217 4.0% 16. The exercise reveals several points: Under all the scenarios considered, the investments required to supply mining companies and increase exports to SAPP would be highly profitable, with a FIRR ranging from 55.1 percent in the base case to 37.6 percent in the low case scenario. On the contrary, the investments required to bring incremental power supply to Kinshasa yield an internal rate of return varying between 7.7 percent in the base case and 4.0 percent in the worst case, largely the result of the combination ofhigh collection losses in Kinshasa and low tariffs (by contrast, the economic returns are robust given the relatively higher willingness to pay and the fact that non-technical and collection losses do not reduce the economic benefit derived from the consumption ofthe electricity). Financial Impact of the Project for SNEL after on-lending 17. Currently, SNEL’s operations currently generate little cash-flow for investments and the company operates under significant liquidity constraints. The company would therefore not be able to self-finance significant investments regardless of their expected profitability. This Project is very large compared to SNEL current operations. The Project’s cumulative costs are projected to be US$490 million over five years, with more than US$350 million concentrated over about three years. By comparison, the total revenues collected by SNEL in 2005 were US$106 million. 88 18. The proposed on-lending terms are consistent with SNEL’s financial position. 20 year repayment term, and notably the 5 years grace period, would ensure that the repayment of the principal starts after completion of the investments, at a time when SNEL would be benefiting from incremental revenues generated by the project. In addition, in coupling these terms with the proposed 5 percent interest rate will enable SNEL to cover debt service with the incremental cashflows from the Project in a sustainable manner (e.g., even under the low case, SNEL’s FIRR is 14.1%). 89 00 0 g do N W m 0 g bo N W I3 $ 0 EN W ad 0 I I1 0 mo p 3 w N N 0 g mo 1- Q sw0 mv, Ng d 0-m rg-m W c1 0 0 0 c1 3: r r 0 e4 0 r 0 e4 o\ 0 0 e4 W 0 0 c1 H H 0 CJ 0 I+ 0 CJ QI 0 0 CJ 00 0 0 CJ D. Financial Analysis of SNEL 19. SNEL’s generation is almost entirely hydropower and as a consequence the company faces very low variable costs in generation. The replacement value of SNEL’s assets, can be conservatively estimated to be around US$7.3 billion (see Table 9.10 below). While SNEL’s financial performance has somewhat improved over the last three years, the overall picture remains that of a very weak utility, which has not properly maintained or renewed its assets. If SNEL asst s Unit Cost per Quantity Total replacement unit (in costs (us$ us$ooos) million) Installed generation Capacity MW 2,000 2,442 4,884 High Voltage Transmission lines Km 250 5,454 1,364 Substations Number 10,000 71 710 Transformers MV/LV Number 15 3,330 50 Buried MV lines Km 40 2,566 103 Buried LV lines Km 20 10,560 21 1 Total replacement cost CUSS mn) 7,321 20. Given the capital-intensive nature of its operations, a power utility would normally: (i)devote a significant proportion of its operating expenses to maintenance, and (ii)generate a significant positive current cash flow representing a return on the invested capital, allowing the company to service its debt and to fund the renewal of its assets. In fact, over the last three years, SNEL has spent on average less than US$15 million per year on maintenance and repairs, and has generated an operational current cash flow of around US$50 million per year. This represents respectively 0.2 percent and 0.7 percent of the replacement value of SNEL assets. In effect, SNEL has performed almost no preventive maintenance for years, only carrying out repairs when possible or in the face ofemergency conditions requiring attention (as has occurred at the Inga plant and along the existing IngaKinshasa transmission line). One result is that less than 40 percent of installed generation capacity is effectively in operation. 21. The other major weakness in SNEL operations and lack of financial performance are the low tariff levels and poor collection rates. Behind the aggregate indicators regarding commercial performance, the situation for various segments ofcustomers is extremely differentiated: a. Private commercial users (including LV, MV and HV) contribute the most to SNEL’s revenues. These customers represent only 13 percent of electricity sales in volume but 48 percent in term of revenue collected. This is due to a relatively high average tariff (6.8 cents per kwh), as well as a high level ofrevenue collection (85 percent). b. LV residential users (mainly in Kinshasa) contribute the least: they bring only 9 percent ofrevenue while they consume 37 percent in volume. c. Public sector users (State and parastatals) are chronically in arrears or simply do not pay. d. Exports have generated a significant portion of SNEL’s actual revenue collection, but the figure has been low in part given that electricity was sold at the relatively low price ofUS cents 1.5 kwh. This figure has recently increased, which should improve SNEL’s cash flow position. 93 The breakdown for different customer classes is set out below in Table 9.1 1. Table 9.11 : Commercial Information by Customer Class Commercial statistics 2005 Share of Average tariff Collection Average revenue Share of sales (UscentkWh) rate (UscentkWh) revenues State and parastatals 19% 6.3 23% 1.4 17% LV domestic 37% 1.2 32% 0.4 9% LV commercial 2% 11.6 61% 7.1 10% MVprivate 8% 7.3 93% 6.8 32% HV private 4% 2.8 98% 2.7 6% Exports 30% 1.6 84% 1.4 26% Total 100% 3.0 53 yo 1.6 100% I Sub-total Commercial users 13% 6.8 85% 5.7 48% I Source: Estimate SNEL. May 2006 22. Improving revenue collection is key to improving SNEL’s profitability. The contribution of exports to revenues will be mechanically improved with the contractual revision of tariffs which should increase unit prices from 1.5 to 2.5 US centskwh. Increasing revenues from Kinshasa will be harder to achieve because of the technical, organizational and even political/social challenges involved in improving revenue collection from hundred ofthousands ofmostly small users. 23. The Project will contribute both indirectly and directly to the objective of improving SNEL financial position and commercial performance in several ways: a. The Project will increase the quantity and quality of energy delivered to Kinshasa. In addition to increasing volumes, it should also create a situation where increased revenue collection can be justified by improved quality ofservice. b. The Project will, through the rehabilitation of the distribution network in Kinshasa and the construction of a second transmission line (which will increase security of supply), lower technical losses and reduce unserved energy. C. The capacity building component targeted at strengthening SNEL’s commercial activities should help to reduce collection losses, thereby yielding incremental revenues, not only on the additional power provided through the Project, but also generally on SNEL’s revenues in Kinshasa. 24. Currently, electricity exports and sales in HV to private users represent slightly less than a third ofthe revenue of SNEL (and US$29.5 million in 2005). This share will increase significantly as a result of the Project. It is expected that, after the full rehabilitation of Inga, the Project will bring incremental sales to SAPP and mining companies amounting to US$49.8 million annually. Recent financial performance (2004-2006) 25. Based on data communicated by SNEL, from 2004 to 2006, the company has managed to improve its level of generation by about 5 percent and its sales of energy (in US$ millions) by 8 percent. A summary ofSNEL’s overall operating accounts is presented in Table 9.12. 94 Table 9.12: SNEL - Summary of perating. accounts I Unit 2004 2005 I 2006 Energy Generated GWh Energy Sold GWh Losses % Energy Sales US$ m. Average price per k Wh us cents - Revenue Collected US$ m. 107 106 115 - current year US$ m. 69.2 81.3 95.4 - arrears US$ m. 37.6 24.3 19.5 Current collection rate % 41.9% 47.0% 53.6% Total Collection rate % 64.7% 61.1% 64.6% Cash Operating expenses US$ m. -45 -56 -72 0.6 0.8 1.0 - 62 49 -43 37.6% 28.5% -24.3% 9 26 46 - self-fiancing US$ m. 1.3 5.2 31.1 8.0 20.7 15.1 I I )n actual results at end of September. 26. SNEL financial structure is characterized by a high level ofdebt (both long term and short term) and negative equity (see Table 9.13). SNEL operates under severe liquidity constraints which complicates its dealings with suppliers. The bulk of SNEL financial debt is towards the Government. However, the Government also has significant payment arrears towards SNEL for its electricity consumption. Regular exercise of reconciliation and cancellation of cross-debt between SNEL and the Government could be used to clarify SNEL’s financial position. in US$ millions 2002 2003 2004 2005 Fixed assets 401.4 356.3 537.5 541.8 worlung capital 90.4 78.1 54.6 79.0 Cash 2.9 3.1 19.9 21.3 Total assets 494.6 437.5 611.9 642.1 Equity 40.2 25.5 (59.4) (77.2) Leverage (net debt/assets) 92% 94% 110% 112% Long term debt 181.3 135.0 332.4 357.6 Short term debt 273.1 277.0 338.9 361.8 Total liabilities 494.6 437.5 611.9 642.1 urce: SNEL annual audited accountsfor 2003 to 2005 - 2002 unaudited - Conversion in USD by WB. 27. Over the last couple of years, SNEL has taken steps to improve internal controls in the area of revenue collection. Revenue collection for HV and MV customers is centralized, and improved 95 monitoring procedures have been put in place to trace the flow of funds. A recent external diagnostic indicated that the current procedures and practices are satisfactory in this area, but are deficient with respect to LV customers. As a result of improved monitoring of revenue collection and tighter internal controls regarding the use of funds, the company has been able to increase modestly its level of investments and operating expenditures. A breakdown of SNEL’s operating expenditures is provided in Table 9.14. Table 9.14: SNEL - I 1 operating emenditures 2004 2005 2006 Materials and supplies 10.0 8.3 9.0 Services 5.2 6.9 7.5 Transportation 3.7 4.7 6.9 Personnel 23.1 34.1 44.9 Miscellaneous 2.8 2.4 3.3 Total cash operating expenditures I US$ m. I 44.8 56.4 71.6 Financial perspectives 2007-2015 28. The current Project will begin to impact significantly SNEL revenues and operational profitability beginning in 2010 when the second transmission line is commissioned and incremental generation capacity from Inga is scheduled to enter into service. A larger impact of the Project would be felt beginning in 2011. In the meantime, SNEL will need to increase its level of technical performance with the implication of more resources devoted to maintenance and increased self-financed investments. This will require increased revenues. In its 2007 budget, SNEL has presented aggressive targets for improving revenue collection and spending on maintenance. 29. As SNEL devotes more resources to maintenance, it should see in 2007 and 2008 a continuation of the decline in its level of operating margin as a proportion of sales compared to 2006. However, operating cash-flow should start to increase modestly in 2009 thanks to incremental revenues from the Project. From 2010 to 2015, SNEL should become more financially viable (see table 9.15). For example, it should be able to make the necessary expenditures to maintain and renew its assets without external financial assistance, as well as to service its debt obligations (e.g., under this Project). This improvement in SNEL’s financial position would result from a combination of incremental energy sales (primarily the increase in generation under the Project), gradual tariff adjustments and improved revenue collection. 96 In 3 O N 0:: N 20 N N rl 0 N 3 rl 0 N 0 3 0 N Q\ 0 0 N W 0 0 N I- goc O mc 0 mb N v) 0 0 -N .e+ EEiE 5 Annex 10: Safeguard Policy Issues AFRICA: Regional and Domestic Power Markets Development Project (Southern Ahcan Power Market Program, APL-lb) 1. The Project triggered six safeguards policies - OP 4.01 (Environmental Assessment), OP 4.09 (Pest Management), OPN 11.03, being revised as OP 4.11 (Physical Cultural Resources), OP 4.12 (Involuntary Resettlement), OPBP 4.37 (Safety of Dams) and OP/BP 7.50 (Projects on International Waterways). 2. Eight documents relating to environmental, social and resettlements aspects of the Project have been prepared, namely: (i)the Environmental and Social Impact Assessment (ESIA), (ii)Environmental and Social Management Plan (ESMP), (iii)the Environmental and Social Management Framework (ESMF), (iv) the Resettlement Policy Framework (RPF), (v) the Management of Cultural Heritage Framework (MCHF), (vi) the ESIA Executive Summary (French), and (vii) the ESIA Executive Summary (English), as (viii) supplemented by the Pest Management Plan related to the control of black flies (PMP). These operational documents have laid down the principles and mechanisms for management of adverse environmental and social impacts, including mitigation measures, operational responsibilities and budget. 3. The documents have been approved by ASPEN and were disclosed in-country and in the Infoshop in Washington on January 18,2007; the PMP was disclosed April 6,2007. EnvironmentalAssessment (OP 4.01) 4. The Project has been categorized as “B” under OP 4.01 since the infrastructure components raise no major environmental policy, regulatory and institutional issues, and will not compromise people’s health from environmental risks and pollution. Project environmental concerns are not significant, and normal environmental management procedures and practices will suffice to avoid or minimize any such concerns. The Project poses a moderate potential reputational risk for the World Bank. 5. An Environmental and Social Impact Assessment (ESIA) containing an Environmental and Social Management Plan (ESMP) and an Environmental and Social Management Framework (ESMF) were prepared. The ESIA describes the environmental management structure of SNEL, the qualifications, functions and needs of the project team; general health, safety, pollution prevention, and waste disposal procedures; and a training program for project management and contractor personnel. The ESMF describes environmental and social aspects of the Project that will need to be managed, at the level of individual components, including applicable environmental and social regulations. The ESMP specifies mitigation measures for various potential adverse impacts in the pre-construction, construction and operation phases of the project. Funds for implementing the ESMP are included in the project cost estimates. 6. The following environmental impacts on the infrastructure components have been identified by the environmental and social consultants (some sub-components will be further defined during project preparation but no major environmental or social impacts are expected). 7. Component 1: Rehabilitation of generation Capacities at the Inaa Iand I1 Dower plants. This component will finance the rehabilitation of generation capacities at the Inga Iand I1 power plants to provide power to DRC, as well as to the southern Ahcan and central African power pools. The site ofthe Inga 1/2 hydroelectric power station is located approximately 150 km from the mouth of the Congo River. The area is sparsely populated and consists mostly of savanna with gallery forests in the valleys. The construction of Inga 1 was finished in 1972 and Inga 2 in 1981. The Inga 1 and Inga 2 hydropower stations use the same 9 km long canal for their water supply. Only a fraction ofthe water from the huge Congo River has been diverted into this canal for hydropower production. The environmental impacts ofthe construction and operation ofthe Inga 1 and Inga 2 hydropower plants were and still are moderate and manageable, and there are no legacy issues. 98 8. There will be almost no change in the hydrological regime ofthe Congo River. Dredging and re-profiling of the 9 km canal will be needed to bring the capacity closer to the design capacity. The dredging sludge will be tested for chemical pollution. Based on the test results, a safe disposal place will be identified. There are macrophytes and likely PCB problems which need to be managed. The drinking water supply system for the concession is integrated into the dam installations and is completely obsolete and will need to be renovated. Water quality monitoring will be strengthened in order to optimize reservoir management. 9. Component 2: Construction of a transmission line from Inga to Kinshasa: The routing for the transmission line from Inga to Kinshasa ending at the Kingatoko substation has not yet been finalized. The final routing of the line still needs to be further defined. It is expected that land acquisition will be required. The environmental and social consultants studied and compared the impacts of two routes proposed by an earlier study. The two options are: North routing: this option follows the existing transmission line Inga-Shaba at a distance of approx. 1 km. on its southern side and stops at the eastern neighborhoods of Kinshasa. 0 South routing: this option goes first diagonally and crosses the Inga-Kwilu, then it follows the national road and then it follows the train route for a large part. 10. The high-voltage transmission line has a length of about 260 km; 90 percent ofthe line is located in the Bas- Congo region. Three natural habitats were found in the Project area, but a modification ofthe route proposed by the consultants and in certain cases a new design has enabled those critical habitats to be avoided. The proposed transmission line route from Inga to the Kingatoko substation in Kinshasa passes mostly through agricultural land. A sensitive forest area near the Inga hydropower station has been avoided. The transmission lines poses manageable environmental impacts which will be mitigated by the actions described in the RPF and ESMP. 11. The routing would pass through mostly unpopulated areas from Inga to the national road. The area is cultivated with itinerant crops and there is some hunting activity. From Lufu to Kingatoko the area is scattered with villages and has extensive cultivation. The lines passes far from most ofthe towns and villages but in cases where towns cannot be avoided, it would passes through areas with low to medium population density. At the end of the line, it reaches the peripheral zone ofKinshasa which has low to medium housing density. This area has market garden cultivation zones, cash crops and small-scale livestock farms. 12. The end point of the line will be built in Kinshasa. After comparing four possible locations, the consultants recommended to locate the end point at Kingatoko as the one with the least environmental and social impacts. 13. Component 3: Expansion and rehabilitation ofthe distribution network in Kinshasa, including 50,000 new connections. The Project will, in addition to the rehabilitation of portions of the distribution system, electrify new areas within greater Kinshasa that do not currently receive power. 30,000 new connections will be provided in the Kimbanseke area located to the east of the city (the largest un-electrified area within greater Kinshasa, with a population estimated at above 1.2 million). Electrification of Kimbanseke will require the erection of a new substation. The Project will also provide, in aggregate, 20,000 new connections in the Kinseso, Mpasa 1/2/3 and Malweka areas, which are, other than Kimbanseke, the largest remaining un- electrified areas in Kinshasa, with populations estimated each in the 250,000-350,000 range. Resettlement (OP 4.12) 14. Component 1: Inga Rehabilitation: The SNEL concession at the Inga 1 and Inga 2 hydroelectric power stations consists of 21,000 hectares. This concession includes the future sites for Inga 3 and Grand Inga. The ESIA indicates that there are no significant legacy issues regarding compensation for the population for land use rights at the time of the construction of Inga 1 and Inga 2. Most of these people live outside the concession. The area of the concession was and still is sparsely populated. Most villages are located on the hill tops, as a consequence of the presence of riverblindness (onchocerciasis), caused by the black fly Simulium damnosium. The incidence of riverblindness in the area is presently very low, as a result of past and present riverblindness 99 control programs. SNEL staff lives inside the SNEL concession in residential houses and in villages. The social amenities in these villages are very good. Presently there are around 6,000 former SNEL workers living within the concession. SNEL is negotiating with the GoDRC to resettle these old workers outside the concession, but this is not related to the Project. The rehabilitation of the Inga 1 and Inga 2 hydropower plants does not involve any land acquisition or resettlement 15. Component 2: Transmission: It is estimated that 60-80 homes will be affected by the construction of the transmission line component (based on the use ofa 100 m right-of-way, which is more appropriate that the 200 m right-of-way initially contemplated). The number ofresettlements can be further reduced by optimizing the routing of the line at the Bas-Congo area and avoiding other populated areas. Over 60 percent of the homes affected are rudimentary, with a small surface area and built with primary materials such as wood, corrugated iron, uncooked bricks 16. Component 3: Distribution: For the distribution component, it is estimated that 127 homes will be affected. After comparing three sites for the location of the substation for electrifying Kimbanseke, it was decided to locate it in an area with the lowest population density in the Kimbanseke neighborhood. The resettlement cost has been estimated at about US$1 million. Resettlement will be conducted according to the recommendations of the RFP prepared for the project. 17. HIV/AIDS will be managed during construction. With DRC prevalence rates for HIV/AIDS ranging from 1.7 percent to 7.6 percent (depending on the region of DRC), workplace policies and standard clauses for contractors, especially those whose staff will move from place to place during construction, will be included in the pertinent works and other contracts. Dam Safety 18. Consistent with OP 4.37, and according to TORSdeveloped in consultation with the relevant Bank specialist, a consultant dam safety engineering firm has completed for SNEL a review ofthe hydroelectric facilities at the Inga site. No significant concerns were identified, and a strengthened program of maintenance was recommended. Under the grant, SNEL has agreed that it shall adopt a dam emergency preparedness plan by December 31, 2007, that reflects the comments of the Association. SNEL has employed a consultant to assist it in the preparation of the plan. SNEL has also agreed, as a covenant of the Grant, to submit to the Association, by October 3Ist of every year, a facilities and network maintenance plan and associated budget for the forthcomingjnancial year for Inga and the other Projectfacilities, and to report on implementation of the plan. International Waterways 19. OP 7.50 applies to Projects that involve the use of international waterways. The Inga rehabilitation component (Component 1) will involve the use of the Congo River, an international waterway that DRC shares with 8 countries and, as such, OP 7.50 applies. However, the Inga dam is a "run of the river" plant, and the proposed activities (rehabilitation of the dam, dredging and reprofiling of the intake canal) will not modify the water volume. On this basis, and as set out in paragraph 7(a) of OP 7.50, this Project is exempt from the requirement to notify other riparian states about the Project, as the activities will alter neither the quality nor the quantity of the water flowing to other riparian states, nor will the Project be adversely affected by the other riparians' possible water use. Pest Management 20. Black flies (Simulium damnosium), a vector for onchocerciasis, are prevalent at the Inga site and surrounding health zones (Inga and Seke-Banza, with a total of 160,000 inhabitants). The presence of the disease has decreased in the last two years due to mass distribution of Invermectin/ Mectizan(R), a potent antiparasite drug mixture. However, the flies still represent a major nuisance for the population. The nuisance factor is severe and has important socio-economic effects, including on school attendance. 100 2 1. The Project will focus on addressing the black fly nuisance on the Inga site and surrounding health zones by controlling the black fly larvae by spraying Permethrin in the river six times a year in high season and strengthening the existing Inga Entomological Mission (EM), which will monitor the operation’s impact. Particular attention will be paid to monitor hydro-biological impact, strengthen capacities for entomological monitoring and evaluation, and ensure sustainability of the interventions. Service contracts will be used to contract WHO/APOC (African Program for Onchocerciasis Control) to implement the control activities under the joint supervision of SNEL and the Ministry ofHealth, and to strengthen the existing capacity in the EM. 22. The use of insecticide Permethnn, triggers the Pest Management safeguard (OP 4.09). A Pest and Pesticide Management Plan has been prepared (and approved by the Bank) and has been disclosed in-country and subsequently in the Infoshop on April 6,2007. Cultural Property 23. A framework for inanaging cultural properties (MCHF) has been prepared, was approved by the Bank and was released in-country and filed in the Infoshop in January 2007 (ref. OP 4.1 1). Sensitive sites include caves in the vicinity ofthe targeted project area. Monitoring and Evaluation 24. The Environmental and Social Management Unit (ESMU) to be established within SNEL (as a condition of effectiveness of the grant - see discussion below) will monitor the environmental and social impacts of the Project. Monitoring will be undertaken at a number of levels. First, it will be undertaken by the contractors at work sites during construction. The contractors will prepare their own environmental and social management plan, which will be based on the Environmental and Social Management Plan prepared for the Project. SNEL will also undertake independent monitoring so as to verify the outcomes of the contractors actions and to audit implementation of the environmental mitigation measures contained in the plans and construction contract clauses. SNEL will also implement and monitor land acquisition and compensation issues as outlined in the WP. The following parameters will be monitored during project implementation: affluent water quality, waste water, or rainfall runoff discharged from campsites; noise levels during construction; soil erosion including adequate implementation of erosion control measures as relevant; vegetation clearing to avoid removal of unique trees for the erection oftowers; and accidents and health. ESMU 25. Environmental and social safeguard issues will be managed by a new Environmental and Social Management Unit (ESMU), to be established as a condition of effectiveness ofthe grunt. The ESMU will be responsible for implementing the Project’s ESR Plan, as well as environmental and social safeguards issues relating to other SNEL activities. The ESMU’s core staff will initially be drawn from existing capacity within SNEL, trained in connection with a separate IDA-financed operation. The ESMU will be located within the Monitoring and Control Department, which reports directly to SNEL’s Management Committee. Operating costs for the unit over the Project period, including necessary training, are estimated at about US$300,000. 26. High-level institutional support and technical assistance to the ESMU will be provided through consultant services (estimated at US$250,000 for Project-related activities; additional expenses are anticipated given SNEL’s desire to strengthen their overall capacity in this area). Activities will include support for refining the ESR Plan and advising on implementation planning, guidance on the compensation process and knowledge transfer. Detailed preparation and implementation ofcompensation for the Project transmission and distribution components - including crop and orchard damage, resettlement and land and property access redress - will be undertaken by a separate team of consultants, reporting to the ESMU, at an estimated cost of US$150,000, excluding the cost of compensation disbursed. It is estimated that total compensation for these elements will be in the order of US$l,OOO,OOO. Provision has also been made for an independent, periodic (including ex-post) 101 ‘audit’ ofESMU’s work, to ensure that the ESR Plan and its implementation is ofhigh quality (estimated cost of US$lOO,OOO). Provision has also been made for other ESMU-led specialized activities that may be required during Project implementation, including analyses of dredging sludge and the creation of waste storage sites. The implementation of the Pest Management Plan at the Inga site will be independently managed (see discussion above); the ESMU will monitor these activities. 102 Annex 11: Project Preparation and Supervision AFRICA: Regional and Domestic Power Markets Development Project (Southern Afncan Power Market Program, AF'L-lb) Planned Actual PCN review 11/01/2005 11/01/2005 Initial PID to PIC 11/10/2005 11/14/2005 Initial ISDS to PIC 11/10/2005 01/18/2006 Appraisal 11/09/2006 03/08/2001 Negotiations 0111012006 04/04/20 01 Board approval 05/29/2001 Planned date of effectiveness 09/30/2001 Planned date ofmid-term review 04/01/2009 Planned closing date 06/30/20 13 Key institutions responsible for preparation ofthe Project: SNEL 0 Ministry ofEnergy of GoDRC Bank staff and consultants who worked on the Project included: Name Title Unit Philippe Benoit Lead Energy Specialist and TTL AFTEG Patick Auffret Sr. Infrastructure Specialist (Kinshasa) Consultant Rene Mendonca Sr. Power Engineer Consultant Jean-Charles Kra Sr. Financial Management Specialist AFTFM Fabrice Bertholet Financial Analyst AFTEG Josee Bamvi Procurement Assistant AFTTR Rob Mills Energy Economist AFTEG Gerhard Tschannerl Procurement Specialist Consultant Anta Loum Lo Language Program Assistant AFTEG Philippe Mahele Procurement Specialist AFTPC Noureddine Bouzaher Sr. Energy Economist MNSSD Pierre Morin Sr. Procurement Specialist AFTPC Robert Robelus Sr. Environmental Specialist Consultant Mohamed Arbi Ben-Achour Sr Social Scientist AFTS 1 Fabrice Houdart Operations Analyst AFCRI Gilles Veuillot Sr Counsel LEGAF T. Mpoy-Kamulayi Lead Counsel LEGAF Renee Desclaux Finance Officer LOAG2 Agnes Albert-Loth Sr. Finance Officer LOAG2 Bank funds expended to date on Project preparation: 1. Bank resources: US$415,000 2. Trust funds: 3. Total: US$475,000 Estimated Approval and Supervision costs: US$640,000 1. Remaining costs to approval: US$40,000 2. Estimated annual supervision cost: US$150,000 103 Annex 12: Documents in the Project File AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) 1. Feasibility Study, dated January 2007, prepared by Fichtner Engineering. 2. Environmental and Social Impact Assessment, dated December 2006, prepared by SOFRECO. 3. Study of SNEL Financial Systems, dated 2006, prepared by PWC. 4. Study on SNEL Corporate Governance, dated 2006, prepared by PWC. 104 Annex 13: Statement of Loans and Credits AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) ~~~ ~~~ Difference between expected and actual Original Amount in US$ Millions disbursements Project FY Purpose IBRD IDA SF GEF Cancel. Undisb. Orig. Frm. ID Rev’d PI04497 2007 CD-Em. Urban & Social Rehab ERL 0.00 0.00 0.00 0.00 0.00 183.09 0.00 0.00 (FY07) PO88751 2006 ZR-Health Sec Rehab Supt (FY06) 0.00 0.00 0.00 0.00 0.00 140.69 40.08 0.00 PO86874 2005 ZR-Emerg SOCAction (FY05) 0.00 0.00 0.00 0.00 0.00 50.82 8.84 0.00 PO88619 2005 CD-Emergen Living Conditions 0.00 0.00 0.00 0.00 0.00 64.50 12.63 0.00 Impr (FY05) PO71144 2004 CD-Priv Sec Dev & 0.00 120.00 0.00 0.00 0.00 47.43 13.74 0.00 Competitiveness (FY04) PO78658 2004 CD-Emerg Demob Reintegr ERL 0.00 0.00 0.00 0.00 0.00 15.16 -25.02 0.00 (FY04) PO81850 2004 CD-Emerg Econ & SOCReunif ERL 0.00 50.00 0.00 0.00 0.00 75.34 5.49 0.00 (FY04) PO82516 2004 ZR Multisectoral HIV/AIDS 0.00 0.00 0.00 0.00 0.00 70.68 -6.26 0.00 PO57296 2003 CD-Emerg MS Rehab & Recovery 0.00 410.00 0.00 0.00 0.00 294.25 85.44 57.70 ERL (FY03) Total: 0.00 580.00 0.00 0.00 0.00 941.96 134.94 57.70 STATEMENT OF IFC’s Held and Disbursed Portfolio In Millions of US Dollars Committed Disbursed IFC IFC FY Company Loan Equity Quasi Partic. Loan Equity Quasi Partic. Approval Adastra Miner ... 0.00 0.09 0.00 0.00 0.00 0.01 0.00 0.00 2003 Celtel DROC 8.57 0.00 0.00 0.00 8.57 0.00 0.00 0.00 2005 Kolwezi 0.00 4.80 0.47 0.00 0.00 4.46 0.47 0.00 2005 PCB Congo 0.00 0.45 0.00 0.00 0.00 0.45 0.00 0.00 Total portfolio: 8.57 5.34 0.47 0.00 8.57 4.92 0.47 0.00 ~~~ ~~~~~~ Approvals Pending Commitment FY Company Loan Equity Quasi Partic. Approval Total pending commitment: 0.00 0.00 0.00 0.00 Annex 14: Country at a Glance AFRICA: Regional and Domestic Power Markets Development Project (Southern African Power Market Program, APL-lb) Sub- POVERTY and SOCIAL Congo, Saharan Low- Dem. Rep. Afrlca Income 2005 ~ Population. mid-year (miilions) 57.5 2,353 741 Life expectancy GNlpercapita (Atiasmethod, US%) PO 745 580 GNI (Atlas method, US$ billions) 6.9 552 1364 Average annual growth, lS99-05 Population (W 2.7 2.3 19 Labor force (%) 2.7 2.3 2.3 GNI Gross per primary Most recent estimate (latest year available, lS99.05) capita enrollment Poverty (% of population belo wnafionalpo vertyllne) U~anpopulation (%of totalpopulatlon) 32 35 30 Life expectancyat birth (pars) 44 46 59 I 1 Infant mortality (per 1000 live births) P9 r)O 80 Childmalnutrition (%ofchiidmnunder5) 31 29 39 Access to improvedwatersource Access to an impmvedwatersource(Xofpopu1ation) 46 56 75 Literacy(%o fpopuiation age 5+j 67 62 Gross prtmaryenrollment (%of school-agepopulation) 48 93 04 -Congo, Dem Rep. Male 51 99 m Lo mncome gro up Female 46 87 99 KEY ECONOMIC RATIOS and LONO-TERM TRENDS 1985 1995 2004 2005 GDP (US$ biliions) 72 56 66 71 Gross capitalformatiordGDP P5 94 P7 145 Trade +rls of goods and servtces/GDP 275 285 304 345 Gross domestic sav1ngslGDP 144 141 39 62 Gross MtiomlsavingsiGDP 85 I1 88 P9 Current account balancdGDP -13 -82 -59 -83 Domestic Capital Interest paymentslGDP 27 00 09 savings formation Total debt/GDP 859 2346 1802 Total debt servicelexports 248 14 58 Present value of debtlGDP 30 9 Present value of debtlexports 97 9 Indebtedness 885-95 lS95-05 2004 2005 2005-09 (aver8ge annual gmuth) GDP -50 -07 66 65 67 -Congo, Dem Rep GDP percapita 81 -30 35 34 39 - Lowincome gmu~ worts of goods and services -01 91 201 86 63 STRUCTURE of the ECONOMY lgS51995 2004 (%of GDP) Agriculture 318 57.0 48.4 46.0 Industry 310 7.0 23.4 25.3 M anufactunng 0.6 5.3 5.5 Services 37.1 26.0 282 28.7 Household final consumption expenditure 77.9 810 87.9 86.9 General gov't final consumption expenditure 7.7 4.9 8.2 6.6 Imports of goods and services 25.6 23.7 392 42.7 1g85-Q5 IBg5-O5 2004 2o (average annual gm Mh) Agriculture 27 -18 0.6 Industry -P.4 2.4 0.3 Manufacturing -0.9 -4.3 6.9 Services -8.2 -2.1 8.8 Household final consumption expenditure -3.7 0.3 General gov't final consumption expenditure -9.0 -14.3 Gross capital formation -7.4 4.0 imports of goods and services -P.7 24.5 26.4 V.6 Note: 2005 data are preliminaryestimates. This table was produced from the Development Economics LDB database. 'Thediamondsshowfourkeyindicators inthecountry(in bo1d)comparedwithits incomegroupaverage. Kdataaremissing,thediamondvAiI be incomplete. 106 PRICES and GOVERNMENT FiNANCE 1985 1995 2004 2005 Domestic prices ,lnfiaIlon('4 I (%change) Consumer pnces 5419 4.0 213 Implicit GDP deflator 25 8 466 4 8.1 215 Government finance (%of GDP, lncludes current grants) Current revenue It5 29 4 00 01 02 03 M 05 Current budget balance -lO 0.9 Overall surplusldeficit -3 8 6.9 BALANCE of PAYMENTS 1985 1905 2004 2005 ICurrent account balance to GDP ('14 (US$ millions) Ex+olts of goods and services 1979 1744 1985 2233 lmpolts of goods and sewices 1844 1471 2,561 3,55 Resource balance 05 273 -576 -922 Net income -373 -766 -274 -337 Net current transfers 144 29 464 808 Current account balance -94 -465 -386 -451 Financingitems (net) 58 426 248 327 Changes in net reseries 36 39 ua P4 Memo: Reserves including goid (US$ millions) 236 360 Conversion rate (DEC, locsi/US$) 166E-0 7 02E-2 3959 473.9 EXTERNAL DEBT and RESOURCE FLOWS 1985 I995 2004 2005 (US$ millions) Totaidebt outstanding and disbursed 6.83 Q.239 11841 iB RD 46 92 0 0 r2 dB1 IDA 372 1,321 1,993 2.050 Total debt sewice 498 25 P1 IB RD P 0 0 0 IDA 4 0 11 46 Cornpositionof net resourceflovh Official grants 91 161 1,444 Official creditors 72 0 257 Private creditors -36 0 -4 Foreign direct investment (net inflOV.5) 69 -22 0 Podfolio equity(net inflow) 0 0 0 World Bank program Commitments 125 0 378 A. IBRD E - BilEieral Disbursements 58 0 67 226 €4 -IDA D. Other dtilaterd F- Rivate Pnncipai repaynents 9 0 0 29 C-IMF G-Shorl-tr Net flow 49 0 167 198 Interest payments 7 0 11 I7 Net transfers 42 0 156 160 N0te:ThiS tablewas produced from the Development Economics LDB database. 8/t3/06 107 MAP SECTION IBRD 35198 5°E 10°E 15°E 25°E 30°E CENTRAL AFRICAN REPUBLIC SUDAN 5°N To Uba To 5°N ngi Bangasso To Kembe CAMEROON Bangui To Zongo Juba Bondo Faradje U Libenge MOBAYI ele GemenaGBADO-LITE Businga DEM. REP. Titule Watsa Ki OF CONGO Buta bali To KARAWA Aketi Isiro Pakwach Akula Lisala Imese Wamba Bumba ORIENTALE Mongbwalu C i o u n i Bunia UGANDA g Bongandanga g uwim n o Banalia r pori A a Lo b ga u n Lulo Lake O Basankusu Bafwasende Albert Yangambi Beni EQUATEUR Kisangani TSHOPO Butembo Mbandaka Wanie Rakula 0° Boende 0° T sh L Lake uap o CONGO a m a L NORD Edward m u Lubutu a Lake GABON i l Bikoro Ikela a Sa b KIVU l L a L on o u g m ToRUTSHURU Ruhengeri ila a el NYABIONDO k a Victoria a Lowa BELIA MOKOTOS U Goma lin d Lake Kivu C To Inongo i Betamba o Kibuye Yumbi n g AMBWE LUILINGU o Bukavu RWANDA Kutu Kalima Kindu LUTSHURUKURU To Buna MUNGOMBE RUZUZI I&II ATLANTIC Bandundu Lodja Uvira Bujumbura Lukenie MANIEMA Kas KAMPEN SUD- KINSHASA ai Kama kuru KASAI KIVUMANGEMBE BURUNDI BANDUNDU Mangai San OCEAN KINSHASA Ilebo ORIENTAL Bulungu Malela ZONGO KASAI Lusambo To MWEKA Kasongo Lulimba CABINDAPointe- Kenge 5°S TSHELA SANGA 5°S Noire Kikwit KYIMBI (ANGOLA) LUKULA BAS- Idiofa OCCIDENTAL INGA Kongolo LEMBA DEMBA CONGO K TANZANIA To Damba w Mbuji- Boma Mbanza-Ngungu i a l g Kalemie u Kananga Luku Mayi TSHALA Lake MOANDA Matadi Feshi Kabalo 5°E 10°E 15°E Kabinda Tanganyika K w LUBILANJI MANI Tshikapa K L a a u n sa a g i l DEMOCRATIC REPUBLIC OF CONGO o a b Moba Mwene-Ditu a Manono KANIAMA PIANA-MWANGA REGIONAL AND DOMESTIC POWER MARKETS i m Lu a vu m a o KATANGAKILUBI DEVELOPMENT PROJECT L MITWAB Kapanga Pweto KIBU o Kamina PROJECT WORKS: e L u u L l u INGA-KINSHASA PROJECT TRANSMISSION LINE a Lake L DIKOLONGO L ANGOLA u u Kilwa f l i INGA HYDRO POWER PLANT REHABILITATION u ra Mweru a KALULE KINSHASA DISTRIBUTION REHABILITATION AND EXPANSION Sandoa KASENGA To N’SEKE KONI 10°S Lubudi Luwingu 10°S N’ZILO KISANGA EXISTING POWER NETWORK: To MWADINGUSHA Lucano POWER DISTRIBUTION 0 100 200 300 400 Kilometers Dilolo Kolwezi ZAMBIA Lu Lake HYDRO POWER PLANTS (PUBLIC) SELECTED CITIES AND TOWNS a Likasi la ba Malawi HYDRO POWER PLANTS (PRIVATE) PROVINCE CAPITALS 0 100 200 Miles Lubumbashi I THERMAL POWER PLANTS RIVERS To Kitwe W HVDC TRANSMISSION LINE (INGA-SHABA) MAIN ROADS This map was produced by the Map Design Unit of The World Bank. A 220kV TRANSMISSION LINES RAILROADS The boundaries, colors, denominations and any other information L shown on this map do not imply, on the part of The World Bank Sakania ZAMBIA A 110-132kV TRANSMISSION LINES PROVINCE BOUNDARIES Group, any judgment on the legal status of any territory, or any endorsement or acceptance of such boundaries. M 30-50-70kV TRANSMISSION LINES INTERNATIONAL BOUNDARIES 25°E 30°E APRIL 2007 IBRD 35356 SOUTHERN AFRICA 30° 40° SOUTHERN AFRICAN SUDAN ETHIOPIA POWER POOL U ban gi Lake Turkana CAMEROON UGANDA EQ. Congo Lake Albert GUINEA KENYA OwenOwen FallsFalls S KampalaKampala 0° 0° GABON DEM. REP. Lake NairobiNairobi Victoria OF CONGO MusomaMusoma KigaliKigali RWANDA o g MwanzaMwanza n ArushaArusha o CONGO C BujumburaBujumbura 132 kV KinshasaKinshasa BURUNDI 220 kV 132 kV 220 kV PanganiPangani TaboreTabore S S S SingidaSingida HaleHale IngaInga 500 kV DC DodomaDodoma 132132 kVkV CCableable toto ZanzibarZanzibar Lake TANZANIA UbungoUbungo T Tanganyika S MteraMtera IringaIringa DarDar eses SalaamSalaam S S Kasai KidatuKidatu Lake 220 kV LuandaLuanda Mweru KihansiKihansi NzeloNzelo & MwakibeteMwakibete 220 kV CambambeCambambe S Cambambe NsekeNseke S MwadingushaMwadingusha 10° S 330 kV CapandaCapanda & KoniKoni 10° 220 kV S 220 kV KolweziKolwezi KasamaKasama LikasiLikasi Lake Malawi ATLANTIC KaraviaKaravia 330 kV MALAWI PembaPemba S LuanoLuano LomaumLomaum ANGOLA SolweziSolwezi LichingaLichinga 220 kV KitweKitwe PensuloPensulo LilongweLilongwe CuambaCuamba OCEAN AltoAlto MalemaMalema NacalaNacala ZAMBIA 330 kV S S MepandaMepanda MatalaMatala S NkulaNkula AA&B&B CahoraCahora BassaBassa S UncuaUncua S LusakaLusaka S NampulaNampula Zambezi KapichiraKapichira S KafueKafue LowerLower S PhombeyaPhombeya AltoAlto MolocueMolocue S Lake S KaribaKariba SS&N&N MatamboMatambo V Kariba k 220 kV 0 BinduraBindura 220 kV VictoriaVictoria 3 S 3303 kV S GokweGokwe N FallsFalls S S RuacanaRuacana S BatokaBatoka EhuhaEhuha HarareHarare CaiaCaia HwangeHwange 330 kV T 110 kV S 330 kV ZIMBABWE S T ° 20 BeiraBeira ° BOTSWANA InsukaminiInsukamini MarvelMarvel 20 NAMIBIA BulawayoBulawayo FrancistownFrancistown PandePande GasGas FieldsFields V k TemaneTemane GasGas FieldsFields 220 kV 0 533 kV DC 0 4004 kV WindhoekWindhoek SeruleSerule PhokojePhokoje L WalvisWalvis BayBay S INDIAN MorupuleMorupule T LouisLouis TrichardtTrichardt im p MatimbaMatimba o p OCEAN o HVDC or HVAC 400 kV T 220 kV Transmission System GaboroneGaborone InhambaneInhambane S 110 kV 132 kV SpitskopSpitskop CorumanaCorumana KomatipoortKomatipoort ApolloApollo Xai-XaiXai-Xai PretoriaPretoria ArnotArnot MaputoMaputo This map was produced by the Map Design Unit of The T T S MbabaneMbabane KokerboomKokerboom JohannesburgJohannesburg World Bank. The boundaries, LüderitzLüderitz T EdwaleniEdwaleni IIII colors, denominations and T any other information shown 400 kV T CamdenCamden SWAZILAND on this map do not imply, on O the part of The World Bank KuduKudu CCGTCCGT T ra n g 400 kV Group, any judgment on the e S KimberleyKimberley 275 kV DrakensbergDrakensberg legal status of any territory, S or any endorsement or MuellaMuella RichardsRichards BayBay AriesAries BloemfonteinBloemfontein MerapiMerapi acceptance of such SELECTED CITIES AggensisAggensis VanVan DerDer MaseruMaseru boundaries. S DurbanDurban KloofKloof Maseru NATIONAL CAPITAL S 30° SOUTH GriepGriep POSSIBLE Ora e FUTURE PROGRAM EXISTING RIVERS AFRICA ng LESOTHO POWER LINES INTERNATIONAL BOUNDARIES 400 kV REHABILITATED POWER LINES KoebergKoeberg SUBSTATIONS EastEast LondonLondon S CapeCape TownTown S S HYDRO POWER PLANTS 0 100 200 300 400 Kilometers PalmietPalmiet MosselbaaiMosselbaai PortPort ElizabethElizabeth T T THERMAL POWER PLANTS NUCLEAR POWER PLANTS 0 100 200 300 Miles 20° 30° COORDINATION CENTER APRIL 2007