Public Disclosure Authorized - The World Bank · Sector Manager: S. Vijay Iyer Task Team Leader: Philippe Benoit . iv ETHIOPIA ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORT PROJECT:

Document of The World Bank

FOR OFFICIAL USE ONLY

Report No: 41425-ET

PROJECT APPRAISAL DOCUMENT

ON A

PROPOSED CREDIT

IN THE AMOUNT OF SDR 26.44 MILLION (US$41.05 MILLION EQUIVALENT)

TO THE

FEDERAL DEMOCRATIC REPUBLIC OF ETHIOPIA

FOR AN

ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORT PROJECT: ETHIOPIA-SUDAN INTERCONNECTOR

November 20, 2007

Energy Team Sustainable Development Department Africa Region

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.

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CURRENCY EQUIVALENTS

Currency Unit = Ethiopian Birr US$1 = ETB 9.086 (as of November 14, 2007)

US$1.551 = 1 SDR

FISCAL YEAR July 8 – July 7

ABBREVIATIONS AND ACRONYMS

AfDB African Development Bank APL Adaptable Program Loan CA Construction Agreement to be signed between EEPCo and NEC related to the construction

of the transmission interconnection between the two utilities CAS/ISN Country Assistance Strategy/Interim Strategy Note CDM Clean Development Mechanism EEPCo Ethiopian Electric Power Corporation EIRR Economic Internal Rate of Return EMP Environmental Management Plan for the Project, dated January 2007 EMP (Sd) Environmental Management Plan, dated January 2007, relating to NEC’s extension of its

grid to the Ethiopian border EEA Ethiopian Electric Agency EMU EEPCo’s Environmental Monitoring Unit ENSAP Eastern Nile Subsidiary Action Program ENTRO Eastern Nile Technical Regional Office EPSEMP Ethiopian Power System Expansion Master Plan ESIA Environmental and Social Impact Assessment ESIA Project EMP, EMP (Sd), RAP and RAP (Sd) ETB Ethiopian Birr FA Fiduciary Assessment FIRR Financial Internal Rate of Return FRR Financial Rate of Return FY EEPCo’s fiscal year, beginning July 8 and ending July 7 GDP Gross Domestic Product GoE Government of Ethiopia GoS Government of Sudan ICAS Interim Country Assistance Strategy ICS National Interconnected System, namely the interconnected electricity grid IDA International Development Association IPP Independent Power Producer LDC Load Dispatch Center MDGs Millennium Development Goals MW Megawatt NBI Nile Basin Initiative NBTF Nile Basin Trust Fund NEC National Electric Corporation, Sudan’s power utility NPV Net Present Value O&M Operation & Maintenance

FOR OFFICIAL USE ONLY

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.

iii

OMA Operation and Maintenance Agreement to be entered into between EEPCo and NEC related to the implementation of the transmission interconnection between the two utilities

OPGW Optical Ground Wires PAPs Project Affected Peoples PASDEP Plan for Accelerated and Sustainable Development to End Poverty PEFA Public Expenditure and Financial Assessment PMU Project Management Unit PPA Power Purchase Agreement (to be entered into between by EEPCo and NEC) RAP Resettlement Action Plan for the Project, dated January 2007 RAP(Sd) Resettlement Action Plan, dated January 2007, relating to NEC’s extension of its grid to

the Ethiopian border RTUs Remote Terminal Unit SCS Self Contained Systems, namely isolated electricity grids SDPRP Sustainable Development and Poverty Reduction Program 5YPSIP Five Year Power Sector Investment Plan

Vice President: Obiageli Katryn Ezekwesili Country Director: Kenichi Ohashi

Sector Manager: S. Vijay Iyer Task Team Leader: Philippe Benoit

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ETHIOPIA


TABLE OF CONTENTS

Page A. STRATEGIC CONTEXT AND RATIONALE.................................................................1

1. Regional, Country and Sectoral Background ................................................................1 2. Rationale for Bank Involvement ....................................................................................8 3. Higher Level Objectives to Which the Project Contributes ...........................................8

B. PROJECT DESCRIPTION ................................................................................................9 1. Lending Instrument ........................................................................................................9 2. Project Development Objective and Key Indicators ......................................................9 3. Project Components........................................................................................................9 4. Lessons Learned and Reflected in the Project Design .................................................11 5. Alternatives Considered and Reasons for Rejection ....................................................12

C. IMPLEMENTATION ......................................................................................................13 1. Partnership Arrangements ............................................................................................13 2. Institutional and Implementation Arrangements ..........................................................14 3. Monitoring and Evaluation of Outcomes/Results ........................................................14 4. Sustainability ................................................................................................................15 5. Critical Risks and Possible Controversial Aspects.......................................................15 6. Loan/Credit Conditions and Covenants........................................................................17

D. APPRAISAL SUMMARY...............................................................................................18 1. Economic and Financial Analyses................................................................................18 2. Technical ......................................................................................................................24 3. Fiduciary.......................................................................................................................25 4. Social ............................................................................................................................25 5. Environment .................................................................................................................26 6. Safeguard policies ........................................................................................................27 7. Policy Exceptions and Readiness .................................................................................27

Annex 1: Country and Sector or Program Background............................................................28 Annex 2: Major Related Projects Financed by the Bank and/or Other Agencies ....................40 Annex 3: Results Framework and Monitoring .........................................................................43 Annex 4: Detailed Project Description.....................................................................................45 Annex 5: Project Costs .............................................................................................................49 Annex 6: Implementation Arrangements .................................................................................50 Annex 7: Financial Management and Disbursement Arrangements ........................................56 Annex 8: Procurement Arrangements ......................................................................................65 Annex 9: Economic and Financial Analysis ............................................................................72 Annex 10: Safeguard Policy Issues ..........................................................................................90 Annex 11: Project Preparation and Supervision.......................................................................94 Annex 12: Documents in the Project File.................................................................................95 Annex 13: Statement of Loans and Credits ..............................................................................96 Annex 14: Country at a Glance ................................................................................................98

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ETHIOPIA

ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORT PROJECT:

ETHIOPIA-SUDAN INTERCONNECTOR

PROJECT APPRAISAL DOCUMENT

AFRICA

AFTEG Date: November 20, 2007 Team Leader: Philippe Charles Benoit Country Director: Kenichi Ohashi Sector Manager/Director: S. Vijay Iyer

Sectors: Power (100%) Themes: Infrastructure services for private sector development (P)

Project ID: P074011 Environmental screening category: Partial Assessment (B)

Lending Instrument: Specific Investment Loan Project Financing Data

[ ] Loan [X] Credit [ ] Grant [ ] Guarantee [ ] Other: For Loans/Credits/Others: Total Bank financing (US$m.): 41.05 Proposed terms: Standard IDA terms, maturity of 40 years, including a grace period of 10 years

Financing Plan (US$m) Source Local Foreign Total

BORROWER(GoE)/RECIPIENT (EEPCo) 1.30 0.75 2.05 INTERNATIONAL DEVELOPMENT ASSOCIATION

4.33 36.72 41.05

Total: 5.63 37.47 43.10 Retroactive Financing: In accordance with OP 6.00, the Project will be able to charge up to US$8 million of the credit amount for expenditures occurring on or after January 1st, 2008 and up to the credit signing date. The retroactive financing will apply to works and consultant services. Borrower: Federal Democratic Republic of Ethiopia Ministry of Mines and Energy TEL: 00 251 1 16463357 Addis Ababa, Etiopía Responsible Agency: Ethiopia Electricity Power Corporation P. O. Box 1233 Ethiopia Tel: 251 1 560042 Fax: 251 1 550822

FY 2008 2009 2010 2011 Annual 10.00 20.00 8.00 3.05 Cumulative 10.00 30.00 38.00 41.05 Project implementation period: Start – March 1, 2008; End – June 30, 2011

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Expected Effectiveness Date: March 1, 2008 Expected Closing Date: December 31, 2011 Does the Project depart from the CAS in content or other significant respects? Ref. PAD

[ ]Yes [X] No

Does the Project require any exceptions from Bank policies? Ref. PAD D.7 Have these been approved by Bank management? Is approval for any policy exception sought from the Board?

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

Does the Project include any critical risks rated “substantial” or “high”? Ref. PAD C.5 [ ]Yes [X] No

Does the Project meet the Regional criteria for readiness for implementation? Ref. PAD D.7 [X]Yes [ ] No

Project development objective Ref. PAD B.2, Technical Annex 3 The Project’s development objective is to promote Ethiopia's power export revenue generation capacity through the development of regional trade opportunities in the context of the Nile Basin Initiative regional effort. Project description Ref. PAD B.3.a, Technical Annex 4 The Project would have two components: (a) construction of a transmission interconnection between the Ethiopian towns of Bahir-Dar and Metema at the Ethiopia/Sudan border, including substation expansion and rehabilitation, thereby linking the Ethiopian system to Sudan’s grid, which is being extended in parallel to the border, and (b) strengthening EEPCo’s institutional capacity to promote and implement regional power integration. Which safeguard policies are triggered, if any? Ref. PAD D.6, Technical Annex 10 The Environmental Assessment (OP/BP/GP 4.01) and Involuntary Resettlement (OP/BP 4.12) safeguard policies are triggered under the Project. Significant, non-standard conditions, if any, for: Ref. PAD C.7 Loan/credit effectiveness: The main conditions of effectiveness are: • Signing of the Construction Agreement (CA) between EEPCo and NEC, in form and substance

satisfactory to the Association • Signing of the Subsidiary Loan Agreement between the Recipient and EEPCo The main Credit covenants are: • Satisfactory implementation by EEPCo of the EMP and RAP. • EEPCo will, by April 30, 2008, engage and thereafter maintain a Project supervision consultant

under terms of reference acceptable to the Association. • EEPCo will sign the Power Purchase Agreement and the Operations and Maintenance Agreement

with NEC by September 30, 2008. • EEPCo will not amend or waive the terms of the Construction Agreement, the Operation and

Maintenance Agreement and the Power Purchase Agreement without the express consent of the Bank.

• EEPCo will ensure that ongoing operating expenses and investments to be financed from revenues (other than from grants, equity contributions and other similar sources) do not exceed available revenues.

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ETHIOPIA


A. STRATEGIC CONTEXT AND RATIONALE 1. Regional, Country and Sectoral Background a. Regional Background: The Nile Basin Initiative and Emerging Regional Power Trade in Eastern Africa The Nile Basin Initiative 1.1. The “Ethiopia/Nile Basin Initiative Power Export Project: Ethiopia-Sudan Interconnector” is being developed under the umbrella of the Eastern Nile Subsidiary Action Program (ENSAP) of the Nile Basin Initiative (NBI). The NBI is a partnership of the riparian states of the Nile1. The NBI seeks to develop the river in a cooperative manner, share substantial socioeconomic benefits, and promote regional peace and security. This Initiative was discussed by the Executive Directors of the World Bank in March 2003.2 The NBI began with a participatory process of dialogue among the riparian countries that resulted in the agreement on a shared vision: to “achieve sustainable socioeconomic development through the equitable utilization of, and benefit from, the common Nile Basin water resources,” and a Strategic Action Program to translate this vision into concrete activities and Projects.3 The NBI’s Strategic Action Program is made up of two complementary programs: the basin-wide Shared Vision Program to build cooperation and capacity across the basin, and Subsidiary Action Programs to initiate concrete investments at sub-basin levels. 1.2. The NBI has been divided into two sub-groupings: the Eastern Nile, that comprises Egypt, Ethiopia and Sudan, and the Nile Equatorial Lakes sub-region, that comprises Burundi, the Democratic Republic of Congo, Egypt, Kenya, Rwanda, Sudan, Tanzania, and Uganda. The Ethiopia-Sudan interconnector has been developed under the auspices of the Eastern Nile Subsidiary Action Program. The Eastern Nile countries are pursuing cooperative development at the sub-basin level through the investment-oriented Eastern Nile Subsidiary Action Program (ENSAP). The Eastern Nile encompasses the sub-basins: Baro-Akobo-Sobat, Blue Nile, Tekeze-Settit-Atbara, portions of the White Nile in Sudan, and the Main Nile. 1.3. The Eastern Nile Technical Regional Office (ENTRO) has been established by the three Eastern Nile countries to advance the implementation of the ENSAP, which is aimed at the reduction of poverty in the region, economic growth, and the reversal of environmental degradation. Towards this end, in 2001, the Eastern Nile countries identified their first joint project, the Integrated Development of the Eastern Nile (IDEN), which consists of a series of seven sub-projects addressing issues related to flood management, power development and interconnection, irrigation and drainage, watershed management, and multi-purpose water resources management and development in Eastern Nile. In 2004, to accelerate the

1 Burundi, Democratic Republic of Congo, Egypt, Ethiopia, Kenya, Rwanda, Sudan, Tanzania and Uganda. Eritrea is an observer. 2 IDA/SEC M2003-0081, dated February 27, 2003. 3 Nile Council of Ministers, Policy Guidelines for the Nile River Basin Strategic Action Program, February 1999.

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progress of project preparation, the Eastern Nile countries decided to ‘fast track’ those IDEN investment sub-projects which could demonstrate early results of cooperation, including: (a) the Ethiopia-Sudan interconnector; (b) the flood preparedness and early warning project; (c) watershed management projects in each EN country, (d) irrigation and drainage projects in each country, and (e) the Eastern Nile planning model. 1.4. In parallel, a ‘multipurpose track’ is being pursued to identify opportunities for more complex, longer-term, multi-country, multi-sectoral development. This includes a series of cooperative regional assessments in power (referred to as the Eastern Nile Power Trade Investment study), watershed management, and irrigation and drainage, as well as additional strategic studies and consultations to identify a major program of joint multipurpose development and management (the Joint Multipurpose Program). 1.5. The NBI provides a framework for promoting cross-border investments that are designed to generate benefits both at the country and regional levels. Although the power systems are largely undeveloped in the region, there are extensive untapped sources for power generation, coupled with a desire to improve access to electricity for both domestic and industrial/commercial consumers. The Nile countries have identified that an important way to realize benefits from these resources in the near-to-medium term is through regional power trade. Emerging Regional Power Trade in Eastern Africa 1.6. At present there is very limited cross border electricity trading between the countries of the Nile basin or elsewhere in the region surrounding Ethiopia. In those cases where network extensions have been made to accommodate trading, such extensions have usually been on the extremities of the power network—often aimed at supplying a remote load or providing grid power to a small network in a neighboring country. However, countries in eastern Africa, and especially Ethiopia, are aware of the potential benefits from trading power. Therefore, while current levels of power trade among basin countries are low, many of the countries (and notably Ethiopia) are considering ways to increase trade and are exploring suitable investments to realize this objective. The end of longstanding conflicts and expansion of economic development activities in various sub-regions are additional incentives for balancing power supply and demand over time and space. 1.7. An interconnection between Ethiopia, Sudan and Egypt is seen as a major element of the Eastern Nile program. Power trade and related pre-feasibility studies for new generation sites (Karadobi, Mendaya, Border and Dal1) and feasibility of a regional transmission system connecting Ethiopia, Sudan and Egypt are currently underway within ENSAP (Power Trade Investment Program study), and a broader regional power market is being promoted through the NBI's Nile Basin Power Trade Project. 1.8. The countries and utilities of eastern Africa are also better coordinating their efforts at power development through their participation in the establishment of the Eastern Africa Power Pool (EAPP) and the power sector initiative under the Eastern Africa Community (EAC). The proposed interconnection between Ethiopia and Kenya is expected to create a robust transmission capacity to deliver firm power between the two countries and in the medium to longer term allow for power trade to extend further within the sub-region, including to Uganda and Tanzania, as well as potentially to other Nile Equatorial Lakes countries such as Burundi and Rwanda, where various planned interconnections are being studied.

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b. Country and Sector Background: Ethiopia 1.9. Ethiopia is one of the most populous countries in Sub-Saharan Africa and also one of the poorest. At US$180, Ethiopia's per capita GDP is only about a fifth of the Sub-Saharan Africa (SSA) average. Although the country has abundant resources and good potential for development, poverty is pandemic and often linked to environmental and natural resource degradation. Approximately 39 percent of people fell below the basic needs poverty line in the last comprehensive national survey (2004/05), an improvement from the 44 percent poverty headcount observed in 1999/00. 1.10. Government reported broad-based high real GDP growth of 9.6 percent in 2005/06, following 10.5 percent growth in 2004/05, and an 11.9 percent rebound in 2003/04 after a severe drought. The IMF and Government expect GDP growth of about 10 percent in 2006/07. 1.11. The official inflation rate reached 12.3 percent in 2006, and rose to 16.7 percent (year on year) in July 2007, with notable increases in food prices. Exports grew at a 21 percent rate in 2006, but imports increased 22 percent from a larger base, leading to a widening of the balance of payments deficit and a reduction in foreign reserves. While public revenues have shown strong growth, expenditures rose faster, resulting in a small increase in the fiscal deficit (from 5 percent of GDP in 2004/2005 to 5.3 percent of GDP in 2005/2006). The share of pro-poor spending in the budget continued to rise, and in 2005/06 accounted for almost two-thirds of expenditures, while defense dropped from 3.1 percent to 2.6 percent of GDP.

1.12. Over the last decade, GoE has been implementing a reform program aimed at poverty reduction through rapid economic growth and macroeconomic stability. The program was making good headway in poverty reduction in the late 1990s, but was interrupted by the conflict with Eritrea. GoE resumed its efforts following the conclusion of the conflict by developing in 2002 the Sustainable Development and Poverty Reduction Program (SDPRP), through a process of extensive consultations with the private sector and civil society. Despite numerous shocks, such as the drought in 2002-2003, implementation of the SDPRP between 2002/03 and 2004/05 has resulted in important recent gains, especially on human development indicators, transport, the investment climate, small town development, and the fight against food insecurity. Pro-poor spending as a share of the budget has risen from 28 in 1999/2000 to 57 percent in 2004/05. The World Bank Country Economic Memorandum 2006 (CEM) on Growth and Governance finds that important progress has been achieved in the past decade, largely driven by improved institutions, including at the regional and local levels, which have been able to deliver a scaling-up of services and infrastructure. Still, recent progress has been from a low base, and Ethiopia faces a major challenge in meeting many Millennium Development Goals (MDGs).

1.13. GoE is now implementing its second poverty reduction strategy, called the Plan for Accelerated and Sustained Development to End Poverty (PASDEP), which covers 2005/06-2009/10. Building on an analysis of the inputs required to reach the MDGs, PASDEP aims to accelerate the progress achieved in the SDPRP. The five-year program centers around eight priority themes: (i) commercialization of agriculture and promoting much more rapid non-farm private sector growth; (ii) geographical differentiation; (iii) population; (iv) gender; (v) infrastructure – especially roads, energy and irrigation; (vi) risk management and vulnerability; (vii) scaling up service delivery to reach the MDGs; and (viii) employment. Cutting across these themes is an important emphasis on good governance, with plans to strengthen the civil service, accelerate local empowerment, and increase transparency and accountability.

1.14. The May 2006 Interim Country Assistance Strategy (ICAS) aims at supporting GoE in further strengthening its institution building and governance reform agenda, as part of a coordinated multi-donor

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effort. The ICAS program is closely aligned with the PASDEP agenda. The ICAS underlines the important role of governance in fostering development of the private sector, enabling improved service delivery by local governments, and underpinning an expansion of critical economic infrastructure. Elements of the ICAS include support for: merit-based civil service; public financial management; provision of basic services in a fair and accountable way; promotion of free enterprise; improved agricultural productivity; and development of infrastructure as reflected in this transmission line Project. 1.15. Like many other Sub-Saharan countries, a striking feature of Ethiopia’s energy sector is the high proportion of biomass (more than 90 percent) in the energy matrix. Modern forms of energy such as electricity, natural gas or LPG are responsible for less than 10 percent. This pattern of consumption has led to increasing deforestation, shortages of wood fuel, and degradation of rural ecosystems - a problem worsened by inadequate supply-side measures for improving forest stocks.

1.16. The limited supply of modern forms of energy and their high costs relative to the low average income per capita has reinforced the dependence on biomass energy. LPG is not widely used in Ethiopia for heating or cooking, due to the high import costs and the barrier represented by the acquisition of millions of metal containers for household use. In the absence of this form of energy, widely used in other countries, customers face the reality of using fuel wood or electricity for basic need such as heating or cooking. From a country’s perspective, the latter is also a very expensive way to meet household energy needs, except for the most affluent.

1.17. Furthermore, energy in Ethiopia is not used in a very efficient way. In 2006, one kg of oil equivalent produced US$2.1 in GDP, when compared to US$2.8 in Sub-Saharan African countries and US$4.2 in Low Income Countries worldwide. Energy efficiency in Ethiopia has slightly declined over the last four years.

Table 1: GDP per Unit of Energy Use (PPP$/kg oil equivalent) 2002 2003 2005 2006 Ethiopia 2.2 2.6 2.4 2.1 Sub-Saharan Africa 2.6 2.9 2.8 2.8 Low Income Countries 3.6 4.0 4.1 4.2 Source: World Bank Green Books 1.18. Hence, the Government strategy for development of the sector is aimed at improving the supply and use of electricity and biomass energy in an efficient and cost-effective manner. A shift towards hydro-generated electricity may alleviate part of the environmental degradation problem, but the Government is cognizant of the fact that the cost of electricity is a barrier to replacing wood fuel at the household level, unless the tariff becomes heavily subsidized. The Government is also working (with support from the Energy Access Project) to develop energy efficient stoves and to promote the use of bio-fuels (such as ethanol) for cooking (with the support from the private sector) to relieve the pressure on wood fuels. Those are meant to be relatively simple actions that have a significant impact on fuel efficiency and people’s quality of life. 1.19. Ethiopia faces several key fiscal pressures driven by the energy sector for which adjustment is desirable from an economic point of view but problematic from a political perspective. While global oil prices have risen, government has not increased domestic fuel prices since December 2004, resulting in a large fuel subsidy. Similarly, while Government recently approved in 2006 an electricity rate increase of about 22 percent, tariffs remain below the level that would ensure sustainability of the state-owned

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Ethiopian Electric Power Company (EEPCo), given its ambitious expansion plan, and further tariff adjustments will be required over time (see discussion below). Electricity Sub-Sector Issues: 1.20. Access and Electrification Rates. The percentage of the population with connection to electricity is extremely low, currently about 6 percent. Only about 22 percent of the population lives in electrified areas (i.e., areas with some form of electricity supply for residences and businesses). The low level of access to electricity is a major barrier to economic development, as well as to the provision of social services in rural towns and other rural areas. 1.21. Ethiopia is expanding service and consumption. The per capita yearly consumption has steadily grown from 22.3 kWh in 2001/02 to 36 kWh in 2006/07. System losses have decreased from a historical 20 percent to 18.4 percent in 2005/2006. Total energy production in 2006/07 reached 3.1 TWh. In the last 5 years, it has grown at a high rate of 9.6 percent. Peak demand has grown at a higher rate of 10.7 percent, suggesting a higher percentage of residential consumption and also some potential for demand management and energy efficiency.

1.22. The majority of the people are supplied by EEPCo, the vertically integrated power utility. EEPCo has about 1,400,000 customers, including 454,000 in Addis Ababa where the connection rate is 40 percent. In other urban areas, the rate is about 20-30 percent. However, 85 percent of the population lives in rural areas, where the access rate is less than 2 percent. The major load centers are in Addis Ababa, Nazereth, Dire Dawa, Harar, Bahar Dar, Mekele and Awassa. The Addis Ababa load center accounts for over 60 percent of the total demand.

1.23. Ethiopia is presently in a comfortable position as far as its supply and demand balance is concerned. There is enough generation capacity and hydrology has been favorable in the last couple of years. However, the GoE is cognizant about the vagaries of rainfall and the fact that demand may significantly increase. The ICS system faced supply deficits in the past, which led to power rationing. In order to alleviate this problem, EEPCo introduced 80 MW diesel fired power plants in selected parts of the grid. To cope with those risks, GoE is also developing an aggressive generation and transmission program (described below) and is looking at possible energy efficiency interventions to relieve pressure on power system expansion.

1.24. EEPCo, remains committed to increasing the country’s hydro generation capacity. Ethiopia is endowed with cheap hydro resources. Given Ethiopia’s high altitudes, favorable rainfall, and topography, opportunities to develop hydro generation are considerable. Ethiopia’s hydro sites represent the most economic way to harness Blue Nile and other water resources and make those available to neighboring countries. Hydro installation in Ethiopia costs about US$1,200 per installed kW, or about half the cost some other plants being built in eastern Africa. Paradoxically, many of its neighbors are suffering the penury of load shedding and/or investing in expensive generation, while others face very high operating costs based on thermal generation. 1.25. EEPCo is building various additional large hydro plants: (i) Tekeze, with an installed capacity of 300 MW and a projected 980 GWh of firm energy, (ii) Gilgel Gibe II, with an installed capacity of 420 MW and a projected 1500 GWh of firm energy, and (iii) Tana Beles, with an installed capacity of 460 MW and a projected 1830 GWh of firm energy, These three projects are scheduled for commissioning over the next year or so, before commissioning of the Ethiopia-Sudan interconnector. Construction of Gilgel Gibe III, with an installed capacity of 1879 MW and 6,400 GWh of firm energy

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and Amerti with and installed capacity of 100 MW, and 256 GWh of firmed energy has started but financial closure has not been reached yet. GoE plans to add even more generation capacity to the system over the next 5-10 years. Planned projects include Gilgel Gibe IV, Hallele Werabesa, Chamoga Yeda, Genale, and Gojeb on the generation side and various investments in transmission. 1.26. It is expected that the Ethiopian system will have an interim power surplus when these hydropower projects come on line. This reflects on the one hand the relative lumpiness of increases in supply when large plants are commissioned relative to demand which increases more gradually. The amount of available energy will vary periodically, declining gradually as domestic demand grows and increasing as each new hydroelectric project is commissioned, due to the afore-mentioned lumpiness of the investments vis-à-vis the market size in Ethiopia. EEPCo and the World Bank are discussing the advantages and vulnerabilities of high dependence on hydro-generation. Due to the uncertainties that surround a hydro system, the power system in Ethiopia may also at times need energy during periods of low rainfall or periods in which the water levels in the reservoirs need to be recovered, and power could be provided through interconnections. 1.27. EEPCo is currently planning interconnections with Djibouti, Sudan, and Kenya, as well as with Egypt, Tanzania, Southern Sudan, Somalia and Yemen at a later stage. These projects will enable, through exports, the “monetization” of Ethiopia’s hydro resources, as well as provide potential markets to absorb the excess supply created by the afore-mentioned interim power surplus. The interconnections will also give Ethiopia access to a larger thermal generation base, thereby providing a partial hedge against hydrological risks. 1.28. Ethiopia-Sudan, together with the Ethiopia-Djibouti transmission line, are the first interconnections in a broader regional power market envisioned by Ethiopia. The Ethiopia-Djibouti interconnection represents the first of Ethiopia’s power export program. The project, financed by the African Development Bank, will allow Ethiopia to export about 60 MW to Djibouti. The project is expected to be commissioned in 2009. The proposed Ethiopia-Sudan transmission line would be commissioned after Ethiopia-Djibouti and represents the second stage in Ethiopia’s power export program. Ethiopia’s aggressive hydro generation expansion program has generated the capacity for exports. EEPCo is also planning to conduct some feasibility studies for potential regional interconnections, including: (i) the Ethiopia-Kenya Interconnection; (ii) Ethiopia-Southern Sudan, (iii) Ethiopia-Djibouti-Yemen; and (iv) NBI related generation opportunities. 1.29. The World Bank has been working to assist EEPCo and GoE to rationalize the electricity sector expansion plan. The dialogue has emphasized the following points: (i) strengthened least-cost integrated development planning; (ii) development of a master expansion plan that is driven more by projections on growth in demand rather than supply side generation targets; (iii) assessing domestic needs and profitable energy export possibilities; (iv) achieve a better integration between the grid and off-grid electrification; (v) examine demand side interventions, such as energy efficiency and load management on a level playing field with supply options; (vi) mobilizing additional public and private sector financing; and (vii) developing a glide path towards cost-reflective tariffs. The issue of future tariff increases remains central to EEPCo’s long-term financial standing. The Bank is working closely with GoE and EEPCo to rationalize the power sector investment program and to assist in the funding of new projects within a sound tariff regime.

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c. Background: Sudan 1.30. Sudan is rich in resource potential but severely impacted by the effects of a civil war and governance concerns. As a consequence, the country has widespread poverty, a weak and uneven economic base and poor infrastructure. Nevertheless, recent performance of Sudan's economy at a macro level has been strong. Economic growth averaged 6 percent per annum between 2000 and 2004, and at over 10 percent in 2006 is among the highest on the continent. This is largely due to the infusion of oil revenues, increasing quantity of foreign direct investment, good harvests, and a period of relative peace following decades of war and conflict between the North and the South. 1.31. As is the case in neighboring Ethiopia, the predominant source of energy in Sudan is biomass, such as firewood, charcoal, and animal residues. The Government estimates total energy consumption at about 13 million metric tons of oil-equivalence, out of which biomass accounts for about 78 percent. About 15 percent is from oil fuel, and the remaining 7 percent is electricity generated from hydro and thermal power. 1.32. Petroleum has emerged as a major source of economic growth and revenue for the Government of Sudan (GoS). Sudan is currently a net exporter of oil. Oil production in 2006 reached approximately 500,000 bbls/d and is projected to increase to 1,000,000 bbls/d in the coming years. With the production of oil, access to foreign exchange has improved through oil-related foreign investment, oil export earnings, and reduced outlays on imports of crude oil and petroleum products. 1.33. Only 22 percent of the population of Sudan has access to electricity and most of these consumers are in Khartoum where 57 percent of the available electricity is consumed. Existing generation facilities in the National Grid (NG) consist of 342 MW of hydro and 642 MW of thermal capacity (180 MW steam, 450 MW combined cycle, 25 MW gas turbines and 45 MW diesel). Due to the relatively small hydropower plant reservoir storage capacity and the preference given to irrigation, hydropower capacity has frequently been under-utilized. All thermal plants are now fueled from domestic oil production. The demand for electricity has exceeded the supply capability of NEC, and created suppressed demand in all consumer groups, especially in industry. The existing national grid covers only nine of Sudan’s 26 states. 1.34. The primary objective of GoS is to expand access to electricity. To achieve this, the Government aims to increase generation, transmission and distribution capacity and quality by (a) improving and adding new facilities, (b) minimizing losses (technical, managerial or commercial) from the existing network, (c) improving voltage levels throughout the system, (d) expanding access to electricity through national grid connections and independent grids, (e) improving the collection of revenue through the use of modern metering devices, and (f) linking Sudan's grid with those of neighboring countries. 1.35. NEC is the vertically integrated state-owned corporation responsible for expanding the power sector. It currently has approximately 920,000 customers. In addition, there are some separate stand-alone systems (diesels). During the past decade, NEC has designed and implemented a number of development plans in generation, transmission and distribution for the National and Isolated grids in order to eliminate load shedding and severe supply constraints. Those plans fell short in achieving their targets, mainly due to the country’s financial constraints, which reduced investments in the power sector. NEC was restructured several years ago to better equip it to meet Sudan’s electricity sector challenges. A considerable downsizing in personnel has taken place in NEC in the past years, reducing the staff from 20,000 to 7,000. The utility is transforming itself into a relatively efficient and well managed entity.

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2. Rationale for Bank Involvement 2.1. The Bank has been requested by Ethiopia to finance its portion of an interconnector to link the Ethiopian and Sudanese grids. The rationale for Bank involvement is four-fold: • First, this Project will be among the first physical investments under the umbrella of the Eastern Nile

Subsidiary Action Program of the Nile Basin Initiative, an Initiative that has been supported by the Bank since 1999. In supporting this Project, the Bank sees a high potential to foster regional integration and cooperation by contributing to cross-border trade, which in turn will promote cooperation and trust in the highly complex Nile region. Regional projects such as this Project encourage greater cooperation and interdependence among the involved countries and reduce tensions.

• Second, the Project is in line with the Bank’s efforts to support the development of Ethiopia’s power

sector, and, in this regard, EEPCo’s strategy is to become a strong regional power trader. The first component of the Project will support the physical infrastructure to allow the country to export power and the second component will strengthen EEPCo’s capacity to become a key player in a potential regional market and also identify new investments for power exports.

• Third, as a second stage in a broader regional power market (first stage is the AfDB financed

Ethiopia-Djibouti transmission line), the proposed Project supports the Bank’s greater focus on regional integration in Africa. More specifically, regional approaches to energy such as this Project offer scope to improve the utilization of existing supply and production capacities and potentials and to optimize new generation investments across countries. The Project will not only construct the physical infrastructure in Ethiopia to initiate power trade in the region, but will also yield valuable operational experience in cross-border trading and build the institutional, technical, and commercial mechanisms to allow development of a broader regional market.

• Fourth, Bank participation serves as a vehicle to provide for increased attention to social and

environmental aspects, as reflected in the preparation and implementation of an ESIA relating to the activities in both Ethiopia and Sudan.

3. Higher Level Objectives to Which the Project Contributes 3.1. The Project represents one of the first tangible investments to flow from the NBI, and as such is an important step in converting the collaborative intentions of the countries into physical investments and benefits which, in turn, should reinforce increased cooperation. Although the Project does not touch water issues directly, it is the fruit of the cooperation around the Nile and specifically among the Eastern Nile countries. The NBI is an historic initiative in a region characterized by poverty and conflict. The agreement of the 10 countries to cooperate in the development of the region's water resources is of major significance in signaling a shift to stability and growth and to avoiding the economic and humanitarian disasters of conflict and famine. Nile control has long been a source of tension and dispute, and an issue of sovereignty, strategic necessity, and national pride. These tensions have colored geo-political relationships between riparian states and have arguably become obstacles to growth by constraining the regional political economy and diverting resources from economic development. Engagement in the NBI by key countries has involved a choice of cooperation over conflict. Instead of the longstanding dispute over water allocations, it is increasingly recognized that managing the Nile from a system-wide perspective will increase the quality, the available quantity, and the economic productivity of river flows

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3.2. The Project supports the GoE objective of monetizing Ethiopia’s hydropower export potential and improving the security of its system. 3.3. The Project also has important global environmental benefits as it will support the export of hydropower to displace and reduce the use and construction of diesel and other thermal units in Sudan, thereby reducing the emission of greenhouse gases. B. PROJECT DESCRIPTION 1. Lending Instrument 1.1. The proposed lending instrument would be a four-year Sector Investment Loan (SIL). The IDA credit would provide financing to EEPCo (through GoE) for the erection of the Bahir Dar to Metema (border town with Sudan) transmission line. Although the investment represents one of several interconnectors under consideration by EEPCo, a SIL was selected over an Adaptable Program Loan (APL) as subsequent phases of the development of an Ethiopia-centered power market are not sufficiently developed at this stage to support the use of the APL instrument. 2. Project Development Objective and Key Indicators 2.1. The Project’s development objective is to promote Ethiopia's power export revenue generation capacity through the development of regional trade opportunities in the context of the NBI regional effort. The proposed Project will finance the construction of a transmission line between the towns of Bahir-Dar and Metema and up to the border with Sudan. This transmission line will connect the grids of Ethiopia and Sudan as to allow primarily exports of Ethiopian hydropower to Sudan to substitute for Sudan’s thermal generation. 2.2. The Project will take advantage of the hydro-thermal complementarity of the Ethiopian and Sudanese systems to reduce overall generation costs and improve the availability and reliability of supply in Ethiopia. The two countries would be able not only to trade energy but also to integrate better their reserve capacity, thus facilitating such synergies and efficiencies as a reduction in the total reserve margin requirements on the interconnected system, as well as in capital and operating costs. 2.3. In the long term, the Project will improve the effectiveness of the power systems of the Nile Basin countries and beyond, by promoting regional power trade through the establishment of coordinated planning and the erection of transmission interconnections in the context of multi-purpose water and energy resources development in the region. 2.4. Key indicators for the Project will be (a) construction of the 230 kV transmission line from Bahir Dar to Metema and completion of the substation expansion and rehabilitation and telecommunication systems; (b) volume of power exports from Ethiopia to Sudan; and (c) revenues for EEPCo from power sales to Sudan. These indicators will be measured directly by EEPCo. 3. Project Components 3.1. The Project consists of two components:

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Component 1: Construction of transmission interconnection between the towns of Bahir Dar and Metema (at the Ethiopia/Sudan border). (US$39.55 million). This component will include the following three sub-components:

a. Construction and expansion of 296.5 km of transmission lines in Ethiopia, including expansion of

Ethiopia’s existing 260 km single circuit line linking Bahir Dar to Shehedi and a new 36.5 km double circuit 230/220 kV transmission line linking Shehedi to Metema at the border with Sudan (US$27.40 million);

b. Extension and rehabilitation of substations at Bahir Dar, Gondar and Shehedi

($11.15 million); and c. Installation of a fiber optics telecommunications system and supervisory control and telecontrol

equipment (US$1.00 million).

Component 2: Institutional Strengthening and Capacity Building for Regional Development (US$3.55 million): This component will: (i) support the effective implementation and operation of the transmission line and (ii) support Ethiopia’s ability to become a central player in the development of a broader regional power market. This component includes the following sub-components:

a. Support to EEPCO on the implementation and operation of the Ethiopia-Sudan interconnector,

including: o supervisory engineering services to support the erection activities in Ethiopia and to provide

training on transmission and substation operation for the local personnel responsible for the day to day operation of the Ethiopia-Sudan transmission line (US$1.40 million); and

o implementation of the EMP and RAP (US$1.30 million).

b. Supporting Ethiopia’s role as a key power exporter in the regional market, including the following activities: o strengthening EEPCo’s Load Dispatch Center training program on issues related to cross-

border trade (US$0.50 million); o capacity building for EEPCo’s units responsible for regional interconnections in key areas of

power trade (US$0.10 million); and o support to EEPCo to attract sponsors and financing for regional generation projects under a

competitive framework (US$ 0.25 million).

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Table 2: Project Costs Component Total

Costs IDA EEPCo/

GOE 1a. Transmission line 27.40 27.40 1b. Substation expansion and rehabilitation 11.15 11.15 1c. Telecommunications 1.00 1.00

Sub-Total Component 1 39.55 39.55 0.00 2a. Support impl. & operation transmission line 2a.1 Supervision engineer 1.40 `1.40 2a.2 EMP and RAP implementation 1.30 1.30 2.b. Support develop. of Ethiopia’s export potential 2b.1 Support EEPCo’s LDC training program 0.50 0.50 2b.2 Capacity building EEPCo’s regional integration units.

0.10 0.10

2b.3 Competitive new generation schemes 0.25 0.25 Sub-Total Component 2 3.55 1.50 2.05

Total Project Costs 43.10 41.05 2.05 Note: all costs include contingencies

3.2. Sudan will, in parallel, build a transmission line (about 155 km) from Gedaref to the town of Gallabat at the Sudanese/Ethiopian border (across the border from Metema) linking with Ethiopia’s grid through the extension of EEPCo’s grid to Metema being undertaken by Ethiopia under Component 1 of the Project. Sudan will also upgrade its substations and add telecommunication and control equipment. Approximate cost on the Sudanese side is US$25.5 million. 3.3. A more detailed description of Project components can be found in Annex 4 and a detailed cost breakdown can be found in Annex 5. 4. Lessons Learned and Reflected in the Project Design 4.1. Lessons learned from completed national, bilateral and regional Projects include:

• Recognition of value of power exports. Ethiopia’s recognition that cross-border trade provides an important opportunity to generate revenues for the country, and represents an important complement to its domestic-oriented power sector expansion planning. Due to the lumpiness of the hydro investments, it expected that the addional capacity will take some time to be absorbed by the domestic market. Exports enable Ethiopia to rapidly monetize this capacity that in the absence of interconnectors would remain idle for some time.

• The importance of an appropriate framework of commercial and operating agreements. A set of

agreements (i.e. Power Purchase Agreement, Operation and Maintenance Agreement, Construction Agreement) negotiated between the exporting and importing utilities specifying and allocating in a sound manner rights, responsibilities, risks and benefits promotes the sustainability of the underlying commercial arrangement and cooperation between the two countries. The parties are developing commercial agreements and operating contracts, with the support of the Bank and the NBI initiative. The capacity building carried out under the auspices of Energy Access, helped Ethiopia prepare a least cost master plan, which also included some generic

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principles and contractual relations for power exports.

• Benefits of an overarching regional policy framework. Experience with bilateral and regional projects demonstrates the benefits of ensuring that the Project benefits from a well-defined policy and institutional framework, enjoys the full backing of the several governments (including a commitment to trade and other cross-border aspects of the Project), and moves at a pace tailored to each country's situation. The envisaged Project is part of a strong program for regional integration of power development systems under the Nile Basin Initiative and enjoys the active support of the two governments and their respective utilities.

• Importance of a joint approach. Experience in similar projects has shown the importance of

ensuring a joint and coordinated approach to project development. In this Project, the countries have created a Joint Steering Committee to coordinate the bilateral activities (including project design and negotiation of relevant operating and commercial agreements). In addition, each country has set up a project implementation unit in charge of implementing the national components and supporting the Joint Steering Committee. Additionally, ENTRO, through its Power Coordination Unit, coordinates joint impact analyses and consultations, and facilitates information sharing and monitoring.

• Strong implementing agencies. Effective projects require strong capacity from the implementing

entities. The proposed Project would rely on EEPCo and NEC. The utilities have the necessary capacity in the implementation of operation of transmission lines in the national context. The process of project preparation, as well as the capacity building component under the Project, will strengthen the ability of EEPCo, as well as NEC, to construct and operate transmission lines in a cross-border context.

• Government support. Demonstrated government support is an important factor of success for

cross-border projects. The two governments have expressed in various occasions their strong support to the implementation of the transmission interconnection between the two countries and the strategic importance of the Project. The Eastern Nile ministers of energy have also established a Steering Committee under the umbrella of ENSAP and meet at least twice a year to promote cooperation and advance the power trade agenda. The transmission line has also been approved by the three Governments as an ENSAP project.

• Importance of integrating social and environmental aspects into contract design and project

implementation. Energy sector projects under implementation highlight the importance of social and environmental aspects. Accordingly, EEPCo and NEC have moved early in Project design to effectively integrate right of way management and adverse social and environmental impact mitigation with contract design and implementation. NEC management is also aware of problems the country has had in the past on these areas, and has expressed Sudan’s commitment to fully comply with the recommendations of the ESIA. Additional funds are also being provided through the NBTF to strengthen social and environmental capacities of EEPCO and NEC, as well as ENTRO.

5. Alternatives Considered and Reasons for Rejection 5.1. Alternatives were considered at different levels. The first alternative considered was the option of not interconnecting the two countries (the “no Project” alternative) and instead relying on independent national generation and transmission development. The interconnector was favored for several reasons.

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First, the Project provides an opportunity to exploit synergies between the two systems, helping to generate revenues for Ethiopia through the sale of excess hydropower and yielding fuel savings for Sudan. The hydro-thermal complementarities of the two systems will also serve to improve the reliability of power supply, thus making economic activities that are dependent on electricity more efficient, encouraging investment and reducing or avoiding costs of back-up generating reserves. In the long-term, a larger market for electricity would justify larger projects that can better exploit the potential for economies of scale. This Project provides a vehicle to promote increased cooperation and trust in a region that historically has been characterized by highly volatile relations. At the regional level, the construction of the proposed transmission line represents a first step in the envisaged regional power market among the Nile Basin riparians. 5.2. Other alternatives considered included supporting private sector participation in the interconnector through guarantee operations. However, it was determined that it was unlikely the private sector would be willing to participate at this stage in this interconnection, given notably the risk profile of the country and the limited size of this interconnection. 5.3. Alternative routing and technical configurations were also considered as part of the feasibility process. Several routes were analyzed (Option A: Ghedo-Nekemte-Ghimbi-Kurmuk-Roseires (614 km); Option B1: Debre-Markos-Injibara-Roseires (428 km); Option B2: Bahir Dar-Injibara-Roseires (405 km); and Option C: from Gondar to Gedaref). Option C, the Gondar-Gedaref route was chosen the Project as it was determined to be preferable from an environmental, social, and technical perspective. The feasibility of several alternative designs was also assessed, including a 500 kV line and a high-voltage direct current line given the potential in the long term for bulk power transmission from Ethiopia to Egypt and Sudan, but these were determined not to be appropriate at this stage as compared to a 220 kV AC line interconnecting Ethiopia and Sudan. Subsequent interconnections among those countries may be possible in the future, as markets and trading expands. C. IMPLEMENTATION 1. Partnership Arrangements 1.1. The Project is the result in part of the support the NBI has provided for this cooperative venture between Ethiopia and Sudan. The NBI itself has been characterized by strong partnerships since its beginnings. The World Bank, UNDP, and the Canadian International Development Agency (CIDA) served as the initial partners, acting as facilitators and assisting the process of dialogue. Since 1998, additional partners have joined the process and today more than 17 bilateral and multi-lateral agencies support the NBI either directly, or through World Bank trust funds, including the African Development Bank (AfDB), Canada, Denmark, Finland, France, European Commission, Germany, Global Environmental Facility (GEF), Italy, the Netherlands, Norway, Sweden, the United Kingdom, and the United States, the United Nations Development Program (UNDP), the UN Food and Agriculture Organization (FAO), and the World Bank. At the first International Consortium of Cooperation on the Nile (ICCON), held in 2000, and coordinated by the Bank, the international development community pledged more than US$130 million. 1.2. The multi-donor Nile Basin Trust Fund (NBTF), administered by the World Bank, was established in 2003 and today includes more than 10 partners and pledges of more than US$120 million, with additional funding directly supporting NBI institutions and projects. The Bank continues to facilitate the NBI process, provide technical assistance, coordinate partner support through an exceptionally strong

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NBI donor partnership, and oversee the operation for the NBTF, ensuring that trust fund resources meet the objectives of the NBI. The NBI in turn has supported the creation of ENTRO and the development of this joint Project between Ethiopia and Sudan. 1.3. Some project preparation activities are being financed by other donors (with the funds administered by the Bank). The ESIA for the Project has been financed by a PHRD grant and funds for the capacity building on social and environmental issues and for monitoring the EMP and RAP will be provided by a by a new Nile Basin Trust Fund grant. The objective of the grant is twofold. First, to provide technical assistance and capacity building to ENTRO and the three utilities of the Eastern Nile countries to ensure good practice in social and environment (including consultation) in the design and implementation of ENSAP projects. This grant will support capacity building on environmental and social issues for the Ethiopia-Sudan transmission line, and also lay the ground work to ensure good practice for future projects such as the Eastern Nile Joint Multipurpose Program. Second, this grant will support and promote dialogue on power trade issues between the three countries and initiate the establishment of institutional, technical and commercial mechanisms that would foster the development of a regional market. 1.4. Ethiopia is also undertaking the development of a power interconnector with Djibouti, which is being funded by the AfDB. The Ethiopia-Djibouti project, which will likely be commissioned before the Ethiopia-Sudan interconnector, represents the first stage in the implementation of Ethiopia’s efforts to export power to its neighbors. The Ethiopia-Sudan constitutes the second stage, with the anticipated third stage an interconnector between Ethiopia and Kenya to be supported by AfDB, IDA and other donors. 1.5. Consideration is also being given to a parallel carbon finance project. The Ethiopia-Sudan interconnector is potentially eligible for carbon credits as it will reduce CO2 emissions from thermal plants in Sudan by importing cleaner and more competitive hydropower electricity from Ethiopia. 2. Institutional and Implementation Arrangements 2.1. The executing agency is the Ethiopia Electricity Power Company (EEPCo) of Ethiopia. The National Electricity Corporation (NEC) in Sudan will be responsible for implementing the extension of the grid in Sudan to link up with the Ethiopian portion of the interconnector. The two countries have established a Joint Steering Committee in charge of monitoring and supervising the Project. The two utilities have also established separate project management units (PMU) to manage the participation at the utility level; these PMUs work with the Joint Steering Committee (see also discussion in Annex 6). 2.2. As the interconnector is an approved Project under the ENSAP investment portfolio, the Eastern Nile Technical Regional Office (ENTRO) coordinates the preparation of the joint impact analysis and consultations, and facilitates information sharing and monitoring. ENTRO has also established a Power Coordination Unit (PCU) to coordinate the implementation of the power Projects within ENSAP, working in close cooperation with the national water and electricity agencies and utilities in Egypt, Ethiopia and Sudan as well as ENTRO and the Project's Steering and Technical Committees (SC & TC). The PCU is playing a facilitation and coordination role between the two utilities. In addition, ENTRO will assist in monitoring the implementation of the ESIA prepared for the Project, working in close cooperation with the two utilities. 3. Monitoring and Evaluation of Outcomes/Results 3.1. Overall monitoring and coordination of Project activities will be performed by EEPCo, and specifically by its Project Management Unit (PMU). Activities to be monitored include: the timely,

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efficient and transparent (in terms of procurement) construction and commissioning of the transmission line, effective implementation of the EMP and RAP, and the evaluation of the expected benefits of the interconnection in terms of increased power trade. ENTRO will also provide monitoring support (for example on environmental and social aspects). 3.2. Annex 3 presents the Project’s results framework that defines specific outcomes and results to be monitored under this Project. In addition, the Bank will carry out the normal review procedures for procurement, regular supervision missions, the Financial Monitoring Reports (FMRs), the quarterly reports provided by EEPCo, independent annual financial audits of the Project and of the financial statements of EEPCo. The Bank will also carry out a mid-term review in November-2009. 4. Sustainability 4.1. There are several dimensions that are critical to the sustainability of the Project’s development objective:

a. Sound and timely expansion of the generation system in Ethiopia and continued interest of Sudan to buy the surplus power. The availability of power for export from Ethiopia will depend in part on the commissioning of the three hydropower projects currently under construction (namely Gilbel Gilbe II, Tekeze and Tana Beles) before commissioning of the interconnector as these plants provide EEPCo with the capacity to export hydropower to Sudan. On the commercial level, it is important that the price per kW/h falls within a range that keeps Sudan interested in buying power as an alternative to more costly domestic thermal generation, while also generating sufficient returns to EEPCo.

b. Capacity to implement and operate the generation and transmission system in an efficient way. There are risks related to the Project implementation and operation capacity of the two countries. At present neither Ethiopia nor Sudan is interconnected with other countries. An interconnection creates a potential for reduction of the total generation costs, if the combined system is operated in an efficient manner. To assure sustainable gains, operators on both sides (either utilities or independent operators in the future) need to develop technical capacity to sustain the energy flows (efficient trading). To achieve this goal, protocols, rules and systems need to be developed. Capacity building support under the Project will help to build Ethiopia’s capacity to implement effective cross-border trade through this interconnector. The NBI Regional Power Trade project is also developing a training program for EEPCo, NEC, as well as other neighboring countries, to strengthen their technical capacity to develop and manage regional transmission lines.

c. Cooperation and stability. Continued commitment to cooperation by Ethiopia and Sudan represents a key underlying factor for the sustainability of this cross-border relationship. In this regard, a framework that ensures that the benefits of cooperation and integration are evident and shared equitably (as is being contemplated) should promote sustainability.

5. Critical Risks and Possible Controversial Aspects 5.1. For Ethiopia the major risk is the timely completion of the link in Sudan to NEC’s grid in order for the EEPco to be able to sell its power. This risk is mitigated by two principal factors. First, Sudan has already negotiated the financing package to construct the line and has started the contracting process to build the line. Second, the Project generates anticipated positive economic and financial returns for both

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Sudan and Ethiopia (see analysis in Annex 9 of economic benefits to the two countries). The Project does not otherwise present significant technical, commercial, environmental, social, or operating risks.

Table 3: Principal Risks, Ratings and Mitigation Measures Potential Risk Risk

Rating Risk Mitigation

Unavailability of electricity supply from Ethiopia (hydrological, technical, contractual and/or political reasons)

L • Sound commercial arrangements that create an incentive for Ethiopia to trade

• Maintain an effective dialogue at the bilateral level and within NBI

• Effective expansion planning by GoE • Development of hydropower facilities in different river basins

in Ethiopia reduces hydrological risk Delays and cost overruns occur during construction of the transmission line

L • Procurement actions for line have begun • A supervision consultancy will closely monitor the

implementation of the Project under a turn-key approach Weak operational capacity to coordinate cross-border trade

M • Development of OMA and ongoing consultations between EEPCo and NEC

• The capacity building component of the Project will include training on power system planning and interconnected system operation and regulation

Breakdowns in PPA discussions and implementation

M • The utilities have, with the support of external advisors and consultants, developed a framework for distributing financial benefits

• Strong political support for this energy trade • Reasonable distribution of benefits between the two countries • Ongoing dialogue between the two utilities and governments

Impact of political situation in the two countries on the Project

M • Ethiopia-Sudan transmission interconnector provides benefits, and is likely to be insulated from domestic issues

• Sound and equitable commercial framework would support continued cooperation

• In Sudan, the Bank coordinated a Joint Assessment Mission (JAM) which outlines Sudan's needs over a six-year interim period and is administering the two Multi-Donor Trust Funds (MDTFs) - one for war-affected and marginalized areas, in the North and the other for the South, and has recently opened and office in Khartoum. The international community is also active in supporting the peace initiative

Delays in construction of the Sudanese portion of the line

M • The GoS has signed a line of credit and has appointed an international transmission construction contractor already active nearby in Sudan

Lapses in Financial Management and Procurement Processes

M • Track-record of sound financial management practices supplemented by an action plan with EEPCo to strengthen its performance

• Procurement of key contracts initiated that builds on existing EEPCo experience

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Potential Risk Risk Rating

Risk Mitigation

Management of environmental and social issues – failure to implement

M • The draft ESIA estimates that the Project impacts are minimal and limited to the construction phase

• Implementation of the EMP and RAP and of the EMP(Sd) and RAP (Sd) will be closely monitored in both countries by ENTRO, and the Bank will also supervise these activities

• Capacity building on environmental and social issues for the two utilities will be provided through a separate grant

• The Construction and Operation and Maintenance Agreements will include an article requiring implementation of the EMP and RAP in the two countries; compliance with these agreements has in turn been included as a covenant in the Bank’s legal agreements

Overall Risk rating Moderate Risk Rating: H-High; S-Substantial; M- Moderate; L-Low;

Conclusion: Overall, the Project risk is Moderate 5.3. Ethiopia’s strategy to export power to Sudan as its second cross-border interconnector presents certain controversial aspects considering the current international political environment surrounding Sudan. Even though the Bank will not provide financing to Sudan, the Project is expected to have visibility, notably because under the NBI it will be: (a) the first cross-border investment, (b) the first investment in the power sector, and (c) the first investment involving Sudan. 5.4. Sudan’s poor record regarding resettlement issues in connection with the Merowe dam also raises risks; however the risk of problems on resettlement under the Project is not viewed as significant given the small amount of resettlement required (a total of 24 households with their houses will be affected and need to relocate physically) and the attention paid during project preparation to this aspect. 6. Loan/Credit Conditions and Covenants 6.1. The main conditions of effectiveness are: • Signing of the Construction Agreement (CA) between EEPCo and NEC, in form and substance

satisfactory to the Association; and • Signing of the Subsidiary Loan Agreement between the Recipient and EEPCo, in form and substance

satisfactory to the Association. 6.2. The main Credit covenants are: • Satisfactory implementation by EEPCo of the EMP and RAP. • EEPCo will, by April 30, 2008, engage and thereafter maintain a Project supervision consultant

under terms of reference acceptable to the Association. • EEPCo will sign the Power Purchase Agreement (PPA) and the Operation and Maintenance

Agreement (OMA) with NEC by September 30, 2008. • EEPCo will not amend or waive the terms of the Construction Agreement, the Operation and

Maintenance Agreement and the Power Purchase Agreement without the express consent of the Bank. • EEPCo will ensure that ongoing operating expenses and investments to be financed from revenues

(other than from grants, equity contributions and other similar sources) do not exceed available revenues.

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D. APPRAISAL SUMMARY 1. Economic and Financial Analyses 1.1 The major anticipated benefit is from the sale of surplus hydropower electricity from Ethiopia to substitute for costlier thermal generation in Sudan.4 Accordingly, this is the major focus of the following economic and financial analyses. A predominantly hydro system like Ethiopia would also benefit through the Project from being part of a larger power system, with significant thermal generation, which serves as a hedge for periods of low rainfall. There are various assumptions which are common to both analyses, regarding, notably anticipated trade volume.

a. Type of Benefits. The main measurable benefit for Ethiopia (economic) and EEPCo (financial)

will be the revenues from the sale of hydropower to Sudan; this is a function of volumes exported and the sales price. There are also benefits of increased reliability and energy security for the Ethiopian system (which are dependant upon the uncertainties of rainfall patterns) from integrating with the Sudanese grid but these benefits are more difficult to measure.

b. Power Purchase Agreement. As described in Annex 6, the Power Purchase Agreement (PPA)

establishes the terms of trade between the two utilities with respect to price and volumes, and the nature of the commitment ("firmness of the energy") and options in this regard.

i. Firm vs. Annual Scheduled vs. Monthly Scheduled: The countries have negotiated a

ten-year framework for the provision by EEPCo to NEC on an annual basis of up to 200 MW nominal as follows: (x) 100 MW firm for the term of the contract (provided at a 95 percent load factor) (“firm” energy), (y) up to an additional 75 MW (and potentially as high as 100 MW) as offered by EEPCo on an annual basis (“annually scheduled power”), and (z) monthly scheduled power for the three months of high rains (June, July and August) in the range of 25 MW (“rainy month surplus power”). This framework is consistent with the annual pattern and variability of hydro production in Ethiopia.

ii. Price: Base Case, Ps Case and Pe Case: Currently, EEPCo and NEC are finalizing

negotiation of the reference price for the initial three years with discussions varying between US$5 cents and US$6 cents per kW/h for firm power (delivered with a reliability of 95%). Annually scheduled power and rainy month surplus power are set as percentages of the reference price. For purposes of evaluating the Project, a mid-range price has been selected as the Base Case, namely a reference price of US$ 5.5 cents/kWh for firm power, US$2.75 cents/kWh for annually scheduled power (i.e., 50 percent of the reference price), and US$1.65 cents/kWh for rainy month surplus power (i.e., 30 percent of the reference price). In a high benefit (for Ethiopia) price scenario, the reference price has been set at EEPCo’s proposal of US$6 cents/kWh – referred to as the “Pe Case”. In a high benefit (for Sudan) price scenario, the reference price has been set at NEC’s proposal of US$5 cents/kWh – referred to as the “Ps Case”.

4 Similar to transactions between governments and the private sector, the two utilities and Governments of Ethiopia and Sudan are finalizing the negotiation of the commercial arrangements for the trading of power. Reflecting concerns of the utilities, the approximations used in the economic and financial analyses in this section are designed to be distinct of the analyses being used for those negotiations.

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iii. Volumes: Base Case: Under the terms of the PPA, EEPCo has committed to provide 100 MW of firm power to NEC, with an availability of 95 percent, which represents 832 GWh per year. In addition, it estimates that on average EEPCo would provide: (a) 75 MW of annually scheduled power at an availability factor of 60 percent, which translates on average to an additional 394 GWh per year, and (b) 25 MW of rainy month surplus power at a load factor of 60 percent, which equates to an additional 33 GWh per year. This projected average represents a total of 1,260 GWh per year and is used for purposes of the Base Case calculations.

iv. Volumes: High and Low Cases: EEPCo has estimated that in a high case, the load

factor for annually scheduled and rainy month surplus power would be 80 percent rather than 60 percent. Accordingly, a high case sensitivity has been set at 1,402 GWh. A low volume sensitivity assuming the availability of only firm power has been set at 832 GWh (although the likelihood of this situation persisting over a ten-year period is small).

c. Net Profit to EEPCo – Weighted Average Revenues/kWh – Weighted Average Cost of Power

Production/kWh. The net profit to EEPCo from the sale of each kWh is the difference between the weighted average revenues and the weighted average cost of production.

i. Weighted Average Revenues/kWh. The weighted average revenues/kWh is a function

of the three forms of power multiplied by the relevant price and the relevant volumes. The weighted average price for the base case reference price of US$5.5 cents for each volume case is provided below:

Table 4: Weighted Average Revenues to EEPCo (Cost to NEC)

Volumes Base Case Volumes: 1259 GWh

High Case Volumes: 1402

Low Case Volumes: 830 GWh

Price US$ cents/kWh 4.5 4.3 5.5

ii. Weighted Average Cost of Production. The cost of producing the power for EEPCo varies depending on whether or not the power constitutes surplus power. For surplus power, the cost to EEPCo has been estimated at US$0.5 cents, representing maintenance, depreciation of assets, etc. The cost for non-surplus power is estimated at US$4.5 cents, including an estimate of about US$4 cents/kWh for incremental power generation, which is consistent with EEPCo’s experience with its large scale hydropower development. The “annually scheduled” and “rainy month surplus” power represent surplus power. With respect to the commitment to provide firm energy covers the ten-year PPA period, it has been estimated that EEPCo will have at least 5 years in which there will be surplus capacity of 100 MW. The cost of the 100 MW has as a result been estimated at a weighted average cost of US$2.5 cents/kWh (i.e., 50 percent as surplus at US$0.5 cents and 50 percent as incremental generation and other costs estimated at US$4.5 cents). The weighted average cost of production for different volume assumptions is set out in the table below:

Table 5 : Weighted Average Cost to EEPCo





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iii. Transmission Losses: In addition to the cost of kWh, EEPCo will incur losses in delivering that power to the Sudanese border. For purposes of the evaluation of the Project, a figure of 5 percent has been used as the level of losses, which is consistent with EEPCo’s experience.

d. Benefits to Sudan. The benefits to Sudan could potentially be measured by using the average

retail tariff in Sudan (which is about US$9 cents/kWh) or by calculating the fuel savings due to the imports of hydro power. For the purposes of the economic analysis, it has been assumed that the benefit of imported energy by Sudan is notionally US$6 cents/kWh (at the wholesale level), which reflects a conservative valuation of the willingness-to-pay (after netting out transmission and distribution costs) and also approximates fuel savings. This also provides for purposes of the financial analysis a measure of the gross revenues per kWh that NEC would generate from the sale of electricity.

e. Investment costs for EEPCo and NEC. The investment cost for the interconnector for EEPCo is

$38.5M which is the sum of (i) transmission line, (iii) substation expansion, (iii) telecommunications, (iv) supervision consultant, and (v) EMP and RAP implementation. For NEC the total cost is $25.5M and it includes (i) transmission line, (iii) substation expansion, (iii) telecommunications; and (iv) implementation of environmental and social implementation plans.

A. Economic Analysis: 1.2. The economic evaluation of the transmission line will address the following questions: (i) does the Project generate an adequate economic internal rate of return for Ethiopia; (ii) does the proposed Project, as designed, provide an adequate return and represent the least-cost means to connect the two countries, and (iii) does the Project generate an adequate economic internal rate of return for Sudan (which is central to the sustainability of the trade). A1. ERR for Ethiopia 1.3. The economic benefits for Ethiopia are principally the revenues from the export of electricity to Sudan, net of the cost of providing and transporting the power to the Sudanese border. The NPV and EIRR for Ethiopia are very robust in the Base case (namely reference sales price of US$5.5 cents/kWh and annual sales volumes of 1,259 GWh). The figures are respectively US$123.2 million and 65 percent. Sensitivity Analysis 1.4. A sensitivity analysis was carried out for Ethiopia based on the different price assumptions (Pe, Ps). The results are provided in the table below.

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Table 6 : Price Variations (Base Case Volumes: 1259 GWh) Prices Ethiopia Base Case EIRR ( %) 64.6 % (US$5.5 cents/kWh reference price) NPV (US$ MM) $123.2 Pe Case EIRR (%) 72.9% (US$6 cents/kWh reference price) NPV (US$ MM) $147.2 Ps Case EIRR (%) 55.8% (US$5 cents/kWh reference price) NPV (US$ MM) $99.3

1.5. A sensitivity analysis was also carried out for Ethiopia based on the different volume assumptions. The results are provided in the table below.

Table 7: Volume Variations (Base Case Price: US$5.5 cents/kWh) Volumes Ethiopia Base Case (1,259 GWh) EIRR (%) 64.6% (US$5.5 cents/kWh reference price) NPV (US$ MM) $123.2 High Case (1,402 GWh) EIRR (%) 69.5% NPV (US$ MM) $137.5 Low Case (832 GWh) EIRR (%) 48.6% NPV (US$ MM) $80.6

1.6. A sensitivity was also conducted assuming: (i) that the cost of firm power averages US$4.5 cents/kWh rather than US$2.5 cents; (ii) that the capital costs of the investment increase by 10 percent; or (iii) if the commissioning date is delayed by one year. The results are presented in the table below.

Table 8: Variations on the Base Case (Volumes 1259 GWh and Price of US$5.5 cents/kWh) Volumes Ethiopia Base Case (1,259 GWh) EIRR (%) 64.6% (US$5.5 cents/kWh reference price) NPV (US$ MM) $123.2 Cost of Firm Power US$4.5 cents/kWh EIRR (%) 34.4% NPV (US$ MM) $46.4 Capital (Investment) Cost increase of 10% EIRR (%) 59.4% NPV (US$ MM) $119.9 Project Commissioning Delayed 1 year EIRR (%) 45.7% NPV (US$ MM) $100.1

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1.7. As the foregoing analyses indicate, the returns to Ethiopia are robust and remain significant even under a variety of different scenarios. The factors which appear to have the largest impact are significant delays in commissioning of the interconnection and if EEPCo’s anticipated excess capacity does not materialize (i.e., the average price for firm power is at US$4.5 cents). This latter point also reflects the fact that part of the benefits of the Project for Ethiopia quantified in this analysis derive from the ability the Project provides to monetize the incremental generation which EEPCo is expected to commission over the next several years, thereby providing greater returns on what constitute largely sunken costs from an economic perspective. A2. ERR for Sudan 1.8. As described above, the economic benefits for Sudan are primarily a function of two factors: (a) imported volumes, and (b) the difference between the economic benefits to Sudan from importing additional power and the payments made to EEPCo for power. The NPV and EIRR for Sudan are very robust in the Base case (namely annual sales volumes of 1,259 GWh and a reference sales price of US$5.5 cents/kWh, which yields a weighted average price of US$4.5 cents/kWh for those volumes). The figures are respectively US$64.9 million and 60.7 percent. Sensitivity Analysis 1.9. A sensitivity analysis was carried out for Sudan (as for Ethiopia) based on the different price assumptions (Pe, Ps) and volume assumptions. The results are provided in the tables below.

Table 9: Price Variations (Base Case Volumes: 1259 GWh) Prices Sudan Base Case EIRR (%) 60.7% (US$5.5 cents/kWh reference price) NPV (US$ MM) $64.9 Pe Case EIRR (%) 44.8% (US$6 cents/kWh reference price) NPV (US$ MM) $40.9 Ps Case EIRR (%) 75.2% (US$5 cents/kWh reference price) NPV (US$ MM) $88.9

Table 10: Volume Variations (Base Case Price: US$5.5 cents/kWh)

Volumes Sudan Base Case (1259 GWh) EIRR (%) 60.7% (US$5.5 cents/kWh reference price) NPV (US$ MM) $64.9 High Case (1402 GWh) EIRR (%) 74.0% NPV (US$ MM) $86.8 Low Case (832 GWh) EIRR (%) 9.0% NPV (US$ MM) (0.9)

The returns to Sudan are, as with Ethiopia, robust in the Base Case and the sensitivities, except for the low volume case.

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A.3 Combined Ethiopia-Sudan Level Analysis. 1.11. An analysis was also carried out for the Project combining both the benefits from Ethiopia and Sudan (which can be approximated to an analysis of the Project’s benefits to the region), namely the costs are the total investment costs and the cost of producing the power, and the benefits are the economic benefit from power consumption in Sudan. The results, as well as sensitivities for the different levels of energy trade, are set out in the table below:

Table 11: Volumes per year Combined Base Case EIRR (%) 63.2% NPV (US$ MM) $188.1 High Case EIRR (%) 71.2% NPV (US$ MM) $224.3 Low Case EIRR (%) 36.2% NPV (US$ MM) $79.7

1.12. As could be anticipated, the overall returns increase as the volumes traded increase. In essence, the combined returns of the interconnector will be sensitive to the volumes, but not to the sales price, which simply serves as a mechanism to allocate benefits as between the two countries. A.4 Alternatives Assessment 1.13. The combined Ethiopia/Sudan benefits demonstrate that the interconnector is highly preferable to the no-project alternative. Another alternative for Sudan would be the installation of new generation capacity in the country, but such plants are anticipated to be more costly on an all-in cost basis than the weighted average cost of supply provided under the Project (namely US$4.5 cents/kWh). Alternative project structures were considered, notably higher capacity for the line with corresponding higher investment costs. This alternative was rejected as the anticipated trade volumes did not support the incremental investment costs, at least in the short and medium term.

A.5. Other Benefits.

1.14. The Project benefits accrue to the two countries from the benefits of energy trade. The principal anticipated benefit is from the transfer of lower cost hydro power from Ethiopia to Sudan, which should reduce costs and also CO2 emissions. However, in the eventuality of a shortage in Ethiopia and of excess capacity in Sudan, NEC could export power to EEPCo to help EEPCo to meet Ethiopia’s domestic energy demand. As the operation of the joint power systems evolve, and Ethiopia adopts a concept equivalent to the “opportunity cost of water” to make dispatch decisions, there may be situations, even before a shortage materializes, in which Ethiopia decides to import thermal generation from Sudan to keep its reservoirs at prudent levels. In addition, there would be other supplemental benefits in operating the two systems in an integrated fashion such as reduced reserve margins, more flexible planned plant outages, more efficient response to unplanned outages, additional flexibility in new plant construction delays etc.

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The Project also offers environmental benefits related to reduced greenhouse gas emissions through the substitution of kWh generated by thermal fuel with kWh produced from hydropower. 1.15. Annex 9 contains further details on the Project economic and financial analysis. B. Financial Analysis: 1.16. The economic and financial analysis for the Project can be largely equated, especially as the principal economic benefit to Ethiopia is the export revenues generated by EEPCo from the sale of power, and the principal economic cost to Sudan is the cost to NEC of importing power. Given in part this factor, and other similarities between the economic and financial costs, the analysis of the project economics and financials for Ethiopia and Sudan on the one hand, and for EEPCo and NEC on the other hand are largely similar. 1.17. The analysis indicates that the Project is financially viable in all cases for EEPCo. Under the Base Case, EEPCo would achieve FIRR of 64.6 percent and NPV of net benefits of US$123.2 million. The following table summarizes the results of the financial analysis of the Project for EEPCo.

Table 12: Summary Results of Project Financial Analysis for EEPCo (US$5.5 Reference Price) Base Case Low Case High case

Annual Energy Trading Volumes in GWh > 1,259 832 1,402

FIRR 64.6% 48.6% 69.5%NPV of Net Benefits Stream (US$ mln) 123.2 80.6 137.5

1.18. The sustainability the Project generates a positive return for Sudan and Ethiopia as well as for EEPCo thereby promoting the sustainability of the Project. See detailed financial analysis in Annex 9. C. Financial Review of Project Implementing Agency: 1.19. A financial review of the implementing agency, EEPCo, was carried out and the impact of the Project on the financial position of the utility was also assessed. 1.20. Refer to Annex 9, Section C for further details on the financial review of EEPCo. 1.21. The Project is expected to make a positive impact on EEPCo’s financial position, as reflected in the analysis of the Project IRR presented above. Notwithstanding the financial strain presented by GoE/EEPCo’s ambitious capital investment program, EEPCo continues to generate sufficient revenues to meet its ongoing maintenance and other obligations, and to generate further additional cash inflows. The financial analysis developed for the Project confirms that it will add value to EEPCo, especially since it will be able to export its surplus hydro production to displace the more expensive thermal power of Sudan. 2. Technical 2.1. The Project presents no unusual construction and operational challenges. The terrain is flat and presents no major construction challenges. The technologies involved in construction and operation of transmission lines are well known and proven. In addition, the Project would be implemented according to internationally accepted technical criteria and standards. The technical parameters and estimated

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Project costs for the transmission line have been established by a Feasibility Study Update. In addition for the Ethiopian portion of the work, an engineering and design consulting firm has been appointed by EEPCo to support preparatory activities, including the preparation of the bill of quantities and the tender documents for the bid packages -- including a turnkey (design, manufacture, supply and erect) contract for the line -- and to assist with bid evaluation and contract award. The turnkey contract will be awarded according the WB procurement guidelines. EEPCo is also at an advanced stage (PQ evaluation under way) in selecting the supervisory consultant for the two works contracts. A provision in the negotiated Project Agreement between IDA and EEPCo ensures that EEPCo will, by April 30, 2008, engage and thereafter maintain the Project supervision consultant under terms of reference acceptable to the Association. 3. Fiduciary 3.1. An assessment of the financial management system of EEPCo has been undertaken as part of Project preparation. 3.2 The recently completed Joint Budget and Aid Review (JBAR) and the Fiduciary Assessment (FA) show that Ethiopia has made significant progress in strengthening public financial management in recent years. Though most of the recent diagnostic works show an improvement in Public Financial Management, there are weak areas that require attention. Ethiopia’s public financial management reforms are being carried out through the government’s Expenditure Management and Control sub-Program (EMCP) of the government’s civil services reform program. Mobilization behind the EMCP (in terms of financial and human resources), as a key component of the Public Sector Capacity Building Program (PSCAP) being supported by the Bank and other development partners, is a priority. 3.3. EEPCo will coordinate implementation of the Project through its Project Management Unit (PMU). The PMU was created within EEPCo for this specific purpose. The PMU coordinates with and relies on the other specialized departments within EEPCo, including the financial management functions. 3.4. EEPCo has five groups according to its organizational structure. One of the groups is the Finance group headed by a by Deputy Manager for Finance. The finance staff in the Finance Group will handle the financial transactions of this Project. The financial management capacity of EEPCo is satisfactory. The Financial Group and the PMU will maintain accounting records and prepare project financial statements in line with International Accounting Standards/International Financial Reporting Standards. EEPCo’s annual accounts will be audited in accordance with International Standards on Auditing. The financial transactions of the Project will be included in EEPCo’s annual accounts. EEPCo will submit audit reports to IDA six months after the end of each fiscal year. FM Risk is assessed as Moderate. Some key weaknesses need to be addressed to ensure timely and good quality financial reports, and to ensure satisfactory follow-up actions on the audit reports. An action plan to address key FM weaknesses has been agreed. 4. Social 4.1. There are several potential benefits to be gained from the interconnection between Ethiopia and Sudan and future regional energy cooperation on the Nile and beyond. By lowering the electricity supply costs and improving reliability and security of supply, this Project and in the future, regional energy integration in the Nile region can play a key role in poverty reduction. The income growth potential that energy services bring to the poor is considerable. It empowers them to take better advantage of the social services that are offered. Affordable and efficient energy enables communities to light their homes and

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schools, refrigerate their supplies, power their telephones and TVs, and support productive businesses. Electricity is essential for electronic communications and together with roads connects people and their businesses to national and regional markets and beyond, and open up new job and education opportunities. In energizing productive uses, regional energy integration fuels the economic engine for value creation, growth and connecting goods to markets. In addition, access to electricity reduces the negative impacts of inadequate modern energy access, especially for women, which bear a disproportionately high burden. 4.2. Because of the linear nature of a transmission line development, the Project will have a small impact on communities and persons and on private or common property assets beyond the construction phase. In Ethiopia, 680 households will be affected, of which 283 houses will be permanently affected and need to relocated physically (mostly within the lots they already inhabit), and a total of 535 ha with crops and trees will be affected of which close to 3 ha. will be lost permanently while 532 ha will be lost for one year only. In Sudan, a total of 24 households with their houses will be affected and need to relocate physically, and 430 ha will be affected temporarily of which 1.5 ha will be permanently lost. Compensation will be paid where towers or Project Right of Way (ROW) affects residential dwellings or social services, will fragment cultivated fields and compromise productivity and income, will involve the removal of fruit-bearing trees, eucalyptus trees and other economically valuable natural resources, or may partially or totally disturb cultural properties such as churches, mosques, or archaeological sites. For the most part, however, compensation is expected to be characterized by a large number of small payments for the temporary loss of assets. 4.3. The Project’s impact is anticipated to occur predominantly during the construction phase with the deployment of skilled workers into the area and the construction of work camps and temporary access roads. While major attention will be focused on loss of income due to temporary disturbance to crops or grazing areas, and on health conditions related to the influx of workers from outside the region (HIV/AIDS) being the major concern), positive opportunities to Project Affected Peoples (PAPs) may be presented in the form of temporary employment, as well as through income generated by the sale of food to immigrant workers. 5. Environment 5.1. The Project involves the construction of a high voltage transmission line between the towns of Bahir Dar and Metema in Ethiopia that will link with a line that Sudan will build in parallel from Gedaref to Gallabat connecting with the Sudanese grid. Three alternative routes were investigated by the Feasibility Study Update and Option C (the proposed Project) was recommended as the optimal solution. The Project was initially classified as Category A as the preferred Option in the 1995 study was expected to have significantly higher environmental and social impacts, requiring a full ESIA including an Environmental Management Plan (EMP) and a resettlement Action Plan (RAP). After conducting the ESIA, the Ethiopia-Sudan transmission line has been categorized as “B” under OP4.01, since the proposed route (Option C) of the line will run through already developed areas of Ethiopia and Sudan with little or no environmental sensitivity, and through which, in most of the length of the line, an existing line already runs. In many places, the new line will parallel the existing line. 5.2. The ESIA indicates that most impacts associated with the Project are of a temporary nature resulting during construction and can be minimized by good engineering practice and implementation of recommendations outlined in the EMP. The preferred route does not pass through any conservation reserves or protected forest areas and there are no known bird migratory routes affected by the alignment. Much of the natural vegetation along the route has been disturbed already by traditional mixed

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subsistence farming in Ethiopia and mechanized rain-fed agriculture in Sudan such that there is unlikely to be any new loss in biodiversity of plants or vegetation. 5.3. In addition, emissions of greenhouse gases and other air pollutants will be reduced due to the substitution of thermal generation in Sudan by hydropower generation from Ethiopia. 5.4. To mitigate and minimize the environmental impacts, an EMP has been prepared to address these issues from the planning phase through to the implementation and operation phase. The EMP and RAP have been made available in-country in Ethiopia, and the corresponding EMP (Sd) and RAP (Sd) made available in Sudan. The documents were filed in the Bank’s Infoshop in January 2007. 5.5. In Ethiopia, EEPCo’s Environmental Management Unit (EMU) will be responsible for applying and implementing the EMP and RAP. As part of its mandate, the EMU will continue to monitor and report on the implementation of EMP and RAP and will provide quality assurance for environmental and social management. ENTRO will also monitor the implementation of the EMP and RAPs in both Ethiopia and Sudan. 6. Safeguard policies

Safeguard Policies Triggered by the Project Yes No Environmental Assessment (OP/BP/GP 4.01) [X] [ ] Natural Habitats (OP/BP 4.04) [ ] [X] Pest Management (OP 4.09) [ ] [X] Cultural Property (OPN 11.03, being revised as OP 4.11) [ ] [X] Involuntary Resettlement (OP/BP 4.12) [X] [ ] Indigenous Peoples (OD 4.20, being revised as OP 4.10) [ ] [X] Forests (OP/BP 4.36) [ ] [X] Safety of Dams (OP/BP 4.37) [ ] [X] Projects in Disputed Areas (OP/BP/GP 7.60)* [ ] [X] Projects on International Waterways (OP/BP/GP 7.50) [ ] [X]

7. Policy Exceptions and Readiness 7.1. The Project complies with all World Bank applicable policies and no exceptions are necessary.

Indicators of Project readiness are:

• Disclosure in-country and in the Bank InfoShop of the EMP and the RAP. • Prequalification documents for the procurement packages for (i) the transmission line, and (ii) the

substation extension and installation of a telecommunication system have been reviewed by IDA. • The request for proposals for the supervisory consultant to be employed by EEPCo has been

approved by IDA, issued by EEPCo and responses have been received. Technical evaluation of the proposal has been completed and the contract is expected to be signed in early 2008.

• Procurement of contractor services for the Sudanese portion has been completed. • Drafts of the CA and OMA have been endorsed by EEPCo and NEC and submitted to IDA.

* By supporting the proposed Project, the Bank does not intend to prejudice the final determination of the parties' claims on the disputed areas

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Annex 1: Country and Sector or Program Background


A. Regional Context: The Nile Basin Initiative and other eastern Africa power trade initiatives The Nile Basin Initiative 1. The Ethiopia/Nile Basin Initiative Power Export Project: Ethiopia-Sudan Interconnector is being developed under the umbrella of the Eastern Nile Subsidiary Action Program (ENSAP) of the Nile Basin Initiative (NBI). The Nile Basin Initiative (NBI) is a partnership of the riparian states of the Nile5. The NBI seeks to develop the river in a cooperative manner, share substantial socioeconomic benefits, and promote regional peace and security. This Initiative was discussed by the Executive Directors of the World Bank in March 2003.6 The NBI began with a participatory process of dialogue among the riparian countries that resulted in the agreement on a shared vision: to “achieve sustainable socioeconomic development through the equitable utilization of, and benefit from, the common Nile Basin water resources,” and a Strategic Action Program to translate this vision into concrete activities and Projects.7 The NBI’s Strategic Action Program is made up of two complementary programs: the basin-wide Shared Vision Program to build cooperation and capacity across the basin, and Subsidiary Action Programs to initiate concrete investments at sub-basin levels. 2. The NBI has been divided into two sub-groupings: the Eastern Nile, that comprises Egypt, Ethiopia and Sudan, and the Nile Equatorial Lakes sub-region, that comprises Burundi, the Democractic Republic of Congo, Egypt, Kenya, Rwanda, Sudan, Tanzania, and Uganda. The Ethiopia-Sudan interconnector has been developed under the auspices of the Eastern Nile Subsidiary Action Program. The Eastern Nile countries are pursuing cooperative development at the sub-basin level through the investment-oriented Eastern Nile Subsidiary Action Program (ENSAP). The Eastern Nile encompasses the sub-basins: Baro-Akobo-Sobat, Blue Nile, Tekeze-Settit-Atbara, portions of the White Nile in Sudan, and the Main Nile. 3. The Eastern Nile Technical Regional Office (ENTRO) has been established by the three Eastern Nile countries to advance the implementation of the ENSAP, which is aimed at the reduction of poverty in the region, economic growth, and the reversal of environmental degradation. Towards this end, in 2001, the Eastern Nile countries identified their first joint project, the Integrated Development of the Eastern Nile (IDEN), which consists of a series of seven sub-projects addressing issues related to flood management, power development and interconnection, irrigation and drainage, watershed management, and multi-purpose water resources management and development in Eastern Nile. In 2004, to accelerate the progress of project preparation, the Eastern Nile countries decided to ‘fast track’ those IDEN investment sub-projects which could demonstrate early results of cooperation, including: (a) the Ethiopia-Sudan interconnector; (b) the flood preparedness and early warning project; (c) watershed management projects in each EN country, (d) irrigation and drainage projects in each country, and (e) the Eastern Nile planning model.

5 Burundi, Democratic Republic of Congo, Egypt, Ethiopia, Kenya, Rwanda, Sudan, Tanzania and Uganda. Eritrea is an observer. 6 IDA/SEC M2003-0081, dated February 27, 2003. 7 Nile Council of Ministers, Policy Guidelines for the Nile River Basin Strategic Action Program, February 1999.

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4. In parallel, a ‘multipurpose track’ is being pursued to identify opportunities for more complex, longer-term, multi-country, multi-sectoral development. This includes a series of cooperative regional assessments in power (referred to as the Eastern Nile Power Trade Investment study), watershed management, and irrigation and drainage, as well as additional strategic studies and consultations to identify a major program of joint multipurpose development and management (the Joint Multipurpose Program). 5. The NBI provides a framework for promoting cross-border investments that are designed to generate benefits both at the country and regional levels. Although the power systems are largely undeveloped in the region, there are extensive untapped sources for power generation, coupled with a desire to improve access to electricity for both domestic and industrial/commercial consumers. The Nile countries have identified that an important way to realize benefits from these resources in the near-to-medium term is through regional power trade. Emerging Regional Power Trade in Eastern Africa 6. At present there is very limited cross border electricity trading between the countries of the Nile basin or elsewhere in the region surrounding Ethiopia. In those cases where network extensions have been made to accommodate trading, such extensions have usually been on the extremities of the power network—often aimed at supplying a remote load or providing grid power to a small network in a neighboring country. However, countries in eastern Africa, and especially Ethiopia, are aware of the potential benefits from trading power. Therefore, while current levels of power trade among basin countries are low, many of the countries (and notably Ethiopia) are considering ways to increase trade and are exploring suitable investments to realize this objective. The end of longstanding conflicts and expansion of economic development activities in various sub-regions are additional incentives for balancing power supply and demand over time and space. 7. Interconnection between Ethiopia, Sudan and in a more distant Egypt is seen as a major element of the Eastern Nile program. Power trade and related pre-feasibility studies for new generation sites (Karadobi, Mendaya, Border and Dal1) and feasibility of a regional transmission system connecting Ethiopia, Sudan and Egypt are currently underway within ENSAP (Power Trade Investment Program study), and a broader regional power market is being promoted through the NBI's Nile Basin Regional Power Trade Project. 8. The countries and utilities of eastern Africa are also better coordinating their efforts at power development through their participation in the establishment of the Eastern Africa Power Pool (EAPP) and the power sector initiative under the Eastern Africa Community (EAC). The proposed interconnection between Ethiopia and Kenya is expected to create a robust transmission capacity to deliver firm power between the two countries and in the medium to longer term allow for power trade to extend further within the sub-region, including to Uganda and Tanzania, as well as potentially to other Nile Equatorial Lakes countries such as Burundi and Rwanda, where various planned interconnections are being studied. B. Ethiopia: Country and Sectoral Background Country Background 9. Ethiopia is one of the most populous countries in Sub-Saharan Africa and also one of the poorest. At US$180, Ethiopia's per capita GDP is only about a fifth of the Sub-Saharan Africa (SSA) average. Although the country has abundant resources and good potential for development, poverty is pandemic and often linked to environmental and natural resource degradation. Approximately 39 percent of people

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fell below the basic needs poverty line in the last comprehensive national survey (2004/05), an improvement from the 44 percent poverty headcount observed in 1999/00. 10. GoE reported broad-based high real GDP growth of 9.6 percent in 2005/06, following 10.5 percent growth in 2004/05, and an 11.9 percent rebound in 2003/04 after a severe drought. The IMF and GoE expect GDP growth of about 10 percent in 2006/07.

11. The official inflation rate reached 12.3 percent in 2006, and rose to 16.7 percent (year on year) in July 2007, with notable increases in food prices. Exports grew at a 21 percent rate in 2006, but imports increased 22 percent from a larger base, leading to a widening of the balance of payments deficit and a reduction in foreign reserves. While public revenues have shown strong growth, expenditures rose faster, resulting in a small increase in the fiscal deficit (from 5 percent of GDP in 2004/2005 to 5.3 percent of GDP in 2005/2006). The share of pro-poor spending in the budget continued to rise, and in 2005/06 accounted for almost two-thirds of expenditures, while defense dropped from 3.1 percent to 2.6 percent of GDP.

12. Over the last decade, GoE has been implementing a reform program aimed at poverty reduction through rapid economic growth and macroeconomic stability. The program was making good headway in poverty reduction in the late 1990’s, but was interrupted by the conflict with Eritrea. GoE resumed its efforts following the conclusion of the conflict by developing, in 2002, the Sustainable Development and Poverty Reduction Program (SDPRP), through a process of extensive consultations with the private sector and civil society. Despite numerous shocks, such as the drought in 2002-2003, implementation of the SDPRP between 2002/03 and 2004/05 has resulted in important recent gains, especially on human development indicators, transport, the investment climate, small town development, and the fight against food insecurity. Pro-poor spending as a share of the budget has risen from 28 percent in 1999/2000 to 57 percent in 2004/05. The World Bank Country Economic Memorandum 2006 (CEM) on Growth and Governance finds that important progress has been achieved in the past decade, largely driven by improved institutions, including at the regional and local levels, which have been able to deliver a scaling-up of services and infrastructure. Still, recent progress has been from a low base, and Ethiopia faces a major challenge in meeting many Millennium Development Goals (MDGs). 13. GoE is is now implementing its second poverty reduction strategy called the Plan for Accelerated and Sustained Development to End Poverty (PASDEP). Building on an analysis of the inputs required to reach the MDGs, PASDEP will aim to accelerate the progress achieved in the SDPRP. The five-year program centers around eight priority themes: (i) commercialization of agriculture and promoting much more rapid non-farm private sector growth; (ii) geographical differentiation; (iii) population; (iv) gender; (v) infrastructure – especially roads, energy and irrigation; (vi) risk management and vulnerability; (vii) scaling up service delivery to reach the MDGs; and (viii) employment. Cutting across these themes is an important emphasis on good governance, with plans to strengthen the civil service, accelerate local empowerment, and increase transparency and accountability. 14. The May 2006 Interim Country Assistance Strategy (ICAS) aims to support GoE in further strengthening its institution building and governance reform agenda, as part of a coordinated multi-donor effort. The ICAS program is closely aligned with the PASDEP agenda. The ICAS underlined the important role of governance in fostering development of the private sector, enabling improved service delivery by local governments, and underpinning an expansion of critical economic infrastructure. Elements of the ICAS include support for: meritocratic civil service; public financial management; provision of basic services in a fair and accountable way; promotion of free enterprise; improved agricultural productivity; and development of infrastructure as reflected in this transmission line Project. A new CAS is under preparation.

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Energy Sector Specific Issues

15. Like many other Sub-Saharan countries, a striking feature of Ethiopia’s energy sector is the high proportion of biomass in the energy matrix (more than 90 percent) relative to modern forms of energy such as electricity, natural gas or LPG. This pattern of consumption has led to increasing deforestation, shortages of wood fuel, and degradation of rural ecosystems - a problem worsened by inadequate supply-side measures for improving forest stocks.

16. The limited supply of modern forms of energy and their high costs relative to the low average income per capita has reinforced the dependence on biomass energy. LPG is not widely used in Ethiopia for heating or cooking, due to the high import costs and the barrier represented by the acquisition of millions of metal containers for household use. In the absence of this form of energy, widely used in other countries, customers face the reality of using fuel wood or electricity for basic need such as heating or cooking. From a country’s perspective, the latter is also a very expensive way to meet household energy needs, except for the most affluent.

17. Furthermore, energy in Ethiopia is not used in a very efficient way. In 2006, one kg of oil equivalent produced US$2.1 in GDP, when compared to US$2.8 in Sub-Saharan African Countries and US$4.2 in Low Income Countries worldwide. Energy efficiency in Ethiopia has slightly declined over the last four years.

Table 1.1: GDP per Unit of Energy Use (PPP$/kg oil equivalent) Country 2002 2003 2005 2006 Ethiopia 2.2 2.6 2.4 2.1 Sub-Saharan Africa 2.6 2.9 2.8 2.8 Low Income Countries 3.6 4.0 4.1 4.2

Source: World Bank Green Books 18. Hence, the Government strategy for development of the sector is aimed at improving the supply and use of electricity and biomass energy in an efficient and cost-effective manner. A shift towards hydro-generated electricity may alleviate part of the environmental degradation problem, but the Government is cognizant of the fact that the cost of electricity is a barrier to replacing wood fuel at the household level, unless the tariff becomes heavily subsidized. The Government is also working (with support from the Energy Access Project) to develop energy efficient stoves and to promote the use of bio-fuels (such as ethanol) for cooking (with the support from the private sector) to relieve the pressure on wood fuels. Those are meant to be relatively simple actions that have a significant impact on fuel efficiency and people’s quality of life. 19. Ethiopia faces several key fiscal pressures driven by the energy sector for which adjustment is desirable from an economic point of view but problematic from a political perspective. While global oil prices have risen, government has not increased domestic fuel prices since December 2004, resulting in a large fuel subsidy. Similarly, while Government has recently approved an electricity rate increase of about 22 percent, tariffs remain below the level that would ensure sustainability of the state-owned Ethiopian Electric Power Company (EEPCo), given its ambitious expansion plan, and further tariff adjustments will be required over time. 20. Even considering the positive steps Government has taken to scale back its investment plans, there remain other dimensions where prudent political decisions will be important for overall economic stability. First, it will be important to attract more ODA and FDI, which will require rapid improvement in governance. Second, Ethiopia faces several key fiscal pressures driven by the energy sector for which adjustment is desirable from an economic point of view but problematic from a political perspective.

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While global oil prices have risen, government has not increased domestic fuel prices since December 2004, resulting in a large fuel subsidy. Similarly, while Government has recently approved an electricity rate increase of about 22 percent, tariffs remain below the level that would ensure sustainability of the state-owned Ethiopian Electric Power Company (EEPCo), given its ambitious expansion plan, and further tariff adjustments will be required over time. Electricity Sub-Sector in Ethiopia 21. In the electricity sub-sector, specifically, the main issues are the: (i) low rate of the population’s access to power supply (less than 6 percent based on the number of people actually connected to electricity supply or about 15 percent when all persons living in electrified areas are counted); (ii) insufficient generation capacity to support the expansion of the market and scale-up of energy in the rural areas; and (iii) the financial deterioration of EEPCo, a historically strong utility, under the weight of ambitious distribution and generation expansion plans, compounded by low tariff levels. 22. Institutional Framework. The transmission and supply of electricity through the Interconnected System (ICS) is exclusively provided by EEPCo. Investment in generation has been opened for foreign and local private investors. In order to regulate the activities of the sector, the Ethiopian Electricity Agency (EEA) was established several years ago. Any investor interested in non-hydro power generation is required to be licensed by the Ministry of Mines, who is responsible for the planning of non-hydro resources. 23. EEPCo, under the Ministry of Mines and Energy, has been responsible for the generation, transmission, distribution and sales of electricity in Ethiopia. EEPCo is also responsible for the preparation of a power sector expansion programme for the approval of the Ministry of Infrastructure and the Government. The overall administration and management of EEPCo is the responsibility of the General Manager under the Management Board. EEPCO is currently undergoing a restructuring process to adopt a new company structure more flexible for future unbundling activities of the utility. Thus, the core functions of EEPCO are grouped in a manner to suit to the respective functions and administered by seven Deputy General Managers. 24. Access and Electrification Rates. The percentage of the population with connection to electricity is extremely low, currently about 6 percent. The low level of access to electricity is a major barrier to economic development, as well as to the provision of social services in rural towns and other rural areas. 25. Ethiopia is expanding service and consumption. The per capita yearly consumption has steadily grown from 22.3 kWh in 2001/02 to 32.9 kWh in 2005/06. System losses have decreased from a historical 20 percent to 18.4 percent in 2005/2006. Total energy production in 2005/06 reached 2.9 TWh. In the last 5 years, it has grown at a high rate of 9.6 percent. Peak demand has grown at a higher rate of 10.7 percent, suggesting a higher percentage of residential consumption and also some potential for demand management and energy efficiency.

26. The majority of the people are supplied by EEPCo, the vertically integrated power utility. EEPCo has about 1,130,000 customers, including 360,000 in Addis Ababa where the connection rate is 33 percent. In other urban areas, the rate is about 20-30 percent. However, 85 percent of the population lives in rural areas, where the access rate is less than 2 percent. The major load centers are in Addis Ababa, Nazereth, Dire Dawa, Harar, Bahar Dar, Mekele and Awassa. The Addis Ababa load center accounts for over 60 percent of the total demand.

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Table 1.2: Number of Consumers by Tariff Category & System (as of June 2003) TARIFF ICS SCS TOTAL

CATEGORY NUMBER % NUMBER % NUMBER % Domestic 637,016 86.13 30,084 80.41 667,100 85.85 Commercial 91,867 12.42 6,974 18.64 98,841 12.72 Street Lighting 1,267 0.17 85 0.23 1,352 0.17 Low Voltage Large Industrial

8,871 1.20 235 0.63 9,106 1.17

High Voltage Large Industrial

101 0.01 3 0.01 104 0.01

Own 474 0.06 34 0.09 508 0.07 TOTAL 739,596 100 37,415 100 777,011 100

27. Load (Demand) Forecast. During the last 10 years there have been severe supply side constraints (mainly shortage of generation capacity) greatly depressing the growth in electricity sales. On the other hand, only a small fraction of the population has had access to electricity. GOE has now set new policies of using indigenous energy resources as a means to improve the living conditions of the population and accelerate economic growth. The set electrification targets are ambitious and their achievement greatly depends on the available internal and external financing.

Table 1.3: Summary of Target Forecast for EEPCO CS GENERATION PEAK DEMAND YEAR

GWh/a Growth %/a MW Growth %/a 2005 2911 578 2010 6552 17.6 1301 17.6 2013 10038 15.3 1993 15.3

Table 1.4: Summary of EEPCO ICS Generation and Peak Demand (Low Forecast) GENERATION PEAK DEMAND YEAR

GWh/a Growth %/a MW Growth %/a 2005 2561 513 2010 4146 10.1 830 10.1 2013 5497 9.8 1101 9.8 2020 9403 8.0 1883 8.0

28. Generation: Hydro and Other Sources. The main grid (ICS) is supplied through two forms of energy sources; these are the hydroelectric and thermal developments, where the latter one is comprised of diesel and geothermal plants. The total installed capacity of the ICS generation is 767 MW. There are eight hydroelectric plants distributed in four river basins throughout the country, representing a total capacity of 670 MW as shown in the following table. Due to de-ratings the reliable or the dependable capacity of these plants is estimated to be around 647 MW. Their average energy generation is around 2,837 GWh/year.

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Table 1.5: ICS Existing Power Plants

No.

Plant Installed Capacity (MW)

Dependable capacity (MW)

Average Energy (GWh/year)

Hydro 1 Koka 43.2 38.4 110.0 2 Awash II 32.0 32.0 165.0 3 Awash III 32.0 32.0 165.0 4 Finchaa 134.0 128.0 640.0 5 Melka Wakena 153.0 152.0 543.0 6 Tis Abay I 11.4 11.4 85.2 7 Tis Abay II 73.0 68.0 282.0 8 Gilgel Gibe I 192.0 184.0 847.0

Hydro Total 670.6 646.6 2836.7 Geothermal

1 Aluto-Langano 7.3 7.3 49 Diesel

1 Kality 10.0 10.0 128.8 2 Awash 7 kilo 30.0 30.0 51.5 3 Dire Dawa 40.0 40.0 233.0

Diesel Total 80.0 80.0 413.3 Grand Total 757.9 733.9 3299.0

29. The SCS consists of isolated small hydro and diesel stations in various locations. The system has an aggregate capacity of 21.5 MW of which 6.2 MW represents small hydro generation. 30. EEPCo remains committed to increasing its hydro-power plant capacity, which it views as an environmentally friendly cost-competitive option (in particular in a high and volatile oil price environment). Ethiopia is endowed with competitive hydro resources. Given Ethiopia’s high altitudes, favorable rainfall, and topography, opportunities to develop hydro generation are massive. Ethiopia represents the most economic way to harness Blue Nile resources and make those available to neighboring countries. Hydro installation in Ethiopia costs about US$1,200 per installed kW, or about half the cost of some other plants being built in East Africa. Paradoxically, many of its neighbors are suffering from the penury of load shedding and/or investing in expensive generation, while others face a very high operating cost based on thermal generation.

31. The GoE is cognizant of the opportunity to “monetize” this potential and has intensified efforts in developing hydro generation. So far, EEPCo has been the primary vehicle for this expansion, either acting as a builder and owner, or possibly in the future as a single buyer for energy to be produced by third parties. GoE is also exploring the possibility of having more active private capital participation in generation, but to date it has found only modest interest from private investors. This capacity building component under this Project will provide support to EEPCo to be more effective in soliciting private investment in this regard.

32. EEPCo is building three additional large plants: (i) Gilgel Gibe II, with an installed capacity of 420 MW and a projected 1500 GWh of firm energy, (ii) Tekeze, with an installed capacity of 300 MW and a projected 980 GWh of firm energy, and (iii) Beles with an installed capacity of 460 MW and a projected 1833 GWh of firm energy. The three projects are scheduled for commissioning over the next year and half, prior to commissioning of the Ethiopia-Sudan interconnector. Construction of Gilgel Gibe III, with an installed capacity of 1879 MW and 6,400 GWh of firm energy and Amerti with and installed capacity of 100 MW, and 256 GWh of firmed energy has started but financial closure has not been reached yet. GoE plans to add even more generation capacity to the system over the next 5-10 years.

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Planned projects include Gilgel Gibe IV, Hallele Werabesa, Chamoga Yeda, Genale, and Gojeb on the generation side and various investments in transmission.

Table 1.6: Planned Generation Capacity in 20015

Plant Installed Capacity (MW)

Average Energy (GWh/year)

Existing generation 757.9 3299 New Generation

Tekeze 300 980 Gilbel Gibe II 420 1500 Tana-Beles 460 1833 Gilbe-Gibe III 1800 6300

Total New Generation 2980 10613 Grand Total 3737.9 13912

33. Transmission System. The ICS transmission network consists of transmission lines of 230 kV, 132 kV, 66 kV and 45 kV to connect generation stations to substations and load centers. The following table describes the existing transmission lengths and number of substations by voltage level.

Table 1.7: Existing Transmission and Substations No. Voltage level Transmission length Substation 1 230 kV 1,715 11 2 132 kV 2,514 45 3 66 kV 1,742 26 4 45 kV 476 23 Total 6,447 105

34. Ethiopia-Sudan, together with the Ethiopia-Djibouti transmission line, are the first interconnections in a broader regional power market envisioned by Ethiopia. The Ethiopia-Djibouti interconnection represents the first of Ethiopia’s power export program. The project, financed by the African Development Bank, will allow Ethiopia to export about 60 MW to Djibouti. The project is expected to be commissioned in 2009. The proposed Ethiopia-Sudan transmission line would be commissioned after Ethiopia-Djibouti and represents the second stage in Ethiopia’s power export program. Ethiopia’s aggressive hydro generation expansion program has generated the capacity for exports. EEPCo is also planning to conduct some feasibility studies for potential regional interconnections, including: (i) the Ethiopia-Kenya Interconnection; (ii) Ethiopia-Southern Sudan, (iii) Ethiopia-Djibouti-Yemen; and (iv) NBI related generation opportunities. 35. Load Dispatching and Telecommunication Systems. Ethiopia has been constructing its first Load Dispatching Center (LDC) in Ethiopia (supported by EIB in the context of IDA’s Energy Access Project). The Project is planned to be ready at the end of 2007. The LDC is located at the Weregenu 132 kV substation, in the suburbs of Addis Ababa. The LDC system includes power application software packages, generation-oriented functions, SCADA software and inter-control communications. Interchange transaction scheduling and evaluation software are included for the interconnections to Sudan and Djibouti. The SCADA system will supervise the HV network from 230 kV to 45 kV, and the initial plan includes 80 remote terminal units (RTUs). The telecommunication system is based both on new digital power line carriers (PLCs), and on existing PLC analog system. Radio links will be used in the Addis Ababa area. The upgrading of the telephone system is included in the project. EEPCo has decided to equip all new high-voltage lines with optical ground wires (OPGW).

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36. Investment Program. The overall investment program involves resources of US$12.5 billion for the next ten years. Most of the investments in the period focus on the expansion of generation capacity as shown in Table 1.8.

Table 1.8: EEPCo Investment Program 2006/07 to 2015/16 Sector Percentage Generation 67.5% Transmission 6.6% Distribution 3.5% UEAP 11.9% Studies 1.7% Institutional Strengthening 0.9% Loans Repayment 0.5% Interest During Construction 7.5% Total 100.0%

Source: EEPCo

37. EEPCo, which does not have the financial capacity to raise the funding for this ambitious program, will be supported by GoE which will make significant equity or other forms of contributions to support the planned investments in generation, transmission and distribution, as well as in rural electrification, thereby relieving the financial pressure on the utility. Budgetary resources have been tentatively allocated to the power sector, representing about 45.6 million Birr or US$5.2 billion for the next five years, as shown in Table 1.9. However, the actual implementation will depend on the financial resources allocated by GoE to EEPCo in this regard.

Table 1.9: GoE Investment Support to EEPCo

Year Birr (MM) US$ (MM)

2006 8.614 9902007 11.013 1.2662008 9.091 1.0452009 10.219 1.1752010 6.690 769

2006-10 45.627 5.245

GoE Investment Support to EEPCo

Source: PASDEP

38. The World Bank has been working to assist EEPCo and GoE to rationalize the electricity sector expansion plan. The dialogue has emphasized the following points: (i) strengthened least-cost integrated development planning; (ii) development of a master expansion plan that is driven more by projections on growth in demand rather than supply side generation targets; (iii) assessing domestic needs and energy export possibilities; (iv) achieving a better integration between the grid and off-grid electrification; (v) examining demand side interventions, such as energy efficiency and load management on a level playing field with supply options; (vi) efforts to attract both public and private sector funding; and (vii) developing a glide path towards cost reflective tariffs. 39. Carbon Finance Project Prospects. A Carbon Project related to this transmission line Project is potentially eligible under the Kyoto Protocol’s Article 12 which establishes the Clean Development Mechanism (CDM) allowing public and private sector parties in industrialized countries to invest in greenhouse gas mitigation projects implemented in developing countries. The CDM enables investors to receive a credit toward their emission reduction targets under the Kyoto Protocol, which entered into

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force on January 1, 2005. Ethiopia ratified the Kyoto Protocol on September 21, 2005. Sudan ratified the Kyoto Protocol on 16 February 2005. The transmission would qualify as it allows the substitution of thermal generation in Sudan with low emission hydro-power imported from Ethiopia. c. Sudan Country and Sectoral Background

40. Sudan is rich in natural resources but severely impacted by the effects of a civil war and governance concerns. As a consequence, it is burdened by widespread poverty, a weak and uneven economic base and poor infrastructure. Nevertheless, recent performance of Sudan's economy at a macro level has been strong. Economic growth averaged 6 percent per annum between 2000 and 2004, and at over 10 percent in 2006 is among the highest on the continent. This is largely due to the infusion of oil revenues, increasing quantity of foreign direct investment, good harvests, and a period of relative peace following decades of war and conflict between the North and the South. The main issues on the Sudanese electricity sub-sector are: (i) low electrification rate (about 22 percent), (ii) insufficient generation capacity to support the expansion of the market and scale-up of energy in the rural areas; and (iii) insufficient reserve capacity to meet fluctuations in hydro-generation (in case of severe drought conditions) resulting in unreliable power supply and need for industry to maintain costly back-up. 41. Institutional Framework. The Ministry of Energy and Mining has the overall responsibility for policy formulation in the power sub-sector, and the administration of other energy resources including oil and gas. NEC’s main function is to generate, transmit, distribute and sell power, and to purchase electricity from independent producers. The National Electricity Act of 1982, which established NEC, was replaced by the National Electricity Corporation Act of 2000 and 2001. NEC is responsible for preparing the power sector expansion program for the short (1 year), medium (5 years) and long term (20 years), which is submitted for approval to the Ministry of Energy and Mines. In 2004, NEC prepared a medium term development plan for the period 2005-2010, and has developed a program covering a 25-year period. 42. NEC operates under the oversight of a Board of Directors. The Board of Directors is responsible of the general policy of NEC. The Board of Directors reports to the Ministry of Energy and Mines. NEC is led by its Managing Director, who is responsible for corporate operations and management. The Managing Director is assisted by seven directors (General Directorates). The transmission line under the Project (namely from Gedaref to the border with Ethiopia) is under the responsibility of the General Directorate for Planning and Projects. 43. Access and Electrification Rates. About 5 million people (around 22 percent of the population) have access to electricity with the residential sector as the dominant portion. Khartoum consumes about 57 percent of the available energy. Geographically, the existing grid is limited to a small part of the country covering only 9 of the 26 states within Sudan. In addition, 14 larger towns are supplied from isolated grids fed by diesel generators. GoS has set an ambitious program aimed at electrifying 75-80 percent of the country by 2020. This will require 12,000 MW of additional generating capacity. In parallel, the Government intends to expand the grid focusing on targeted areas comprising population centers in Southern Sudan, Kordofan and other areas. 44. Load (Demand) Forecast: NEC’s medium term (2004-2014) target demand forecast for the grid is summarized in the table below. The Target Forecast assumes a demand growth in the coming few years of over 30 percent average annual growth in 2005-2010, when the current substantial suppressed demand will be covered, along with an increase of the generation capacity, especially as a result of the commissioning of Merowe.

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Table 1.10: NEC Target Demand Forecast Generation Peak Demand Year

GWh/a Growth %/a MW Growth %/a 2005 3,960 818 2010 15,796 31.9 3,191 31.3 2014 24,589 11.7 4,929 11.5

45. The average annual addition of domestic consumers to NEC’s grid has been between 20,000 and 30,000 per year. NEC has prepared a list of committed/planned large scale industrial and other projects that are anticipated to represent large sources of additional load. These projects include industrial developments, tourism and agricultural projects, as well as electrification plans for the Nile and Northern States. These projects are expected to add over 1000 MW of new load by 2010. When these new committed loads are added, it would mean further additional need for thermal generation capacity in NEC’s grid, which would further enhance possibilities for replacing thermal generation in Sudan by hydropower from Ethiopia. 46. Generation system: The generation facilities in the Sudanese National Grid (NG) consist of 342 MWs of hydro and 700 MWs of thermal capacity (180 MW steam, 450 MW combined cycle, 25 MW gas turbines and 45 MW diesel). The operation of the hydropower plants (Roseires, Sennar, Jebel Aulia and Kashm El Girba) has to suit irrigation requirements. The total annual average energy production from the hydropower plants is estimated at 1,236 GWh. In addition, there are fourteen isolated distribution networks which are served by local diesel generators. The Isolated System represents around 13 percent of the total installed capacity. 47. The largest generation project currently under construction is the Merowe hydropower plant. The project is located at Merowe Island near the fourth cataract on the Main Nile, approximately 350 Km north of Khartoum. The installed capacity will be 1250 MW, but will provide highly seasonal output due to the changing flow conditions of the Nile. The average annual generation will be 5700 GWh. The first turbine generators will be commissioned end 2007 and the last turbines by end 2008. Committed thermal plants include the upgrade of the existing Gerri 2 gas turbines to a combined cycle plant (as is the case of Gerri 1). There are also plans for private power generation on an IPP-basis using slow speed diesels at Kilo X 1 (275 MW) and for the Khartoum North extension (200 MW of steam turbines).

Table 1.11: ICS Existing Power Plants

Plant Installed

Capacity (MW) Dependable

capacity (MW) Average Energy

(GWh/year) Hydro

Roseires 280 280 1,069 Sennar 15 14 80 Jebel Aulia 30 30 57 Khasm El Girba 17 17 30

Hydro Total 342 341 1,236 Dr. Sherief 1 &2 180 180 1,064 Kilo X 15 0 0 Fao 12 10 27 Kuku 25 20 30 Garri (combined cycle) 450 420 1,367 Kashm El Girba 7 4 6 Kassala 11 8 11

Thermal Total 700 642 2,505 Grand Total 1042 983 3,741

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48. NEC is currently planning to use crude oil in some of the coming power plants because of a shortage of domestic heavy fuel oil. Recently opened new fields could enable Sudan to increase oil production in 2010 to 1,000,000 bbls/day. This would ensure that NEC would have access to a favorable fuel mix for its thermal power plants, depending on the expansion of the refinery capacity. 49. Transmission System: The main grid covers a relatively small part of the country along the Blue Nile, but NEC is currently undertaking a large extension program. The system includes a double circuit 564 km 220 kV transmission line from the Roseires hydropower station to the Kilo X substation near Khartoum. There are two intermediate transformer stations at Sennar Junction and Meringan. A new 220/110/33 kV substation (GIAD) has been constructed at El Bagair. A double circuit 220 kV runs from Gerri thermal plant to Eid Babiker substation and continues to Kilo X. A 110 kV double-circuit ring is located around Khartoum.

50. The construction of a third circuit (a double-circuit 220 kV line) from Roseires via Renk and Rabak to Khartoum has started, as well as a double-circuit 220 kV line from Singa to Gedaref. A double-circuit 220 kV line from Khartoum to Shendi and Atbara has been completed. Two single-circuit 500 kV lines from the Merowe hydropower plant to Khartoum and a single 500 kV line from Merowe to Atbara have been recently completed. As part of the Merowe power plant development, 220 kV lines have been constructed from Atbara to Port Sudan and from Merowe via Dongola to Wadi Halfa. A 220 kV is planned to be extended via Um Ruwaba to El Obeid in the first phase and at a later stage further west and southwest. 51. Southern Sudan. In the medium term, Southern Sudan is foreseen to remain isolated from the National Grid, and would rely on diesel-based thermal generation and later on local hydro generation. At a later time, it would be interconnected with the National Grid. 52. Losses in Distribution. Technical losses are estimated to remain at the current level of 14 percent, but NEC is taking actions to reduce non-technical and commercial losses. To this end, NEC’s current policy is to connect all small consumers with pre-paid meters in order to reduce payment arrears and to reduce the non-technical losses. 53. Load Dispatching Center (LDC) and Telecommunication Systems. NEC has recently completed the construction of an LDC and installed a new LDC system. Related LDC software includes power applications, forecast applications, network applications and distribution management applications. The LDC project includes new RTUs for initially 16 substations. Additionally, 9 existing RTUs will be connected to the LDC. The telecommunication system supporting the LDC will consist of optical ground wires (OPGWs). The ground wires in the existing lines will be replaced with OPGWs. The OPGW between Kilo X and Roseires will be installed, partially as live-line installation. NEC has decided to equip all new high-voltage power lines with OPGWs.

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Annex 2: Major Related Projects Financed by the Bank and/or Other Agencies


World Bank Projects – Ongoing

Project ID

Project Name

Summary Sector DO Rating

IP Rating

P101556 EAREP II The Project’s development objective is to establish a sustainable program for expanding access to electricity in rural communities, including grid and off-grid solutions, thus supporting broad-based economic development and helping alleviate poverty.

Energy and Mining

S S

P097271 EAREP I The Project’s development objective is to establish a sustainable program for expanding access to electricity in rural communities, thus supporting broad-based economic development and helping alleviate poverty.

Energy and Mining

S S

P049395 Energy Access

The Energy Access Project will help establish a sustainable program for expanding the population's access to electricity, and improve the quality of electricity supply.

Energy and Mining

MS S

P077380 Energy Access GEF

The project will reduce the barriers to the wide spread adoption of renewable energy technologies, in particular solar photovoltaic (PV) and micro-hydro power generation in rural areas, thereby contributing to the reduction in greenhouse gas (GHG) emissions via displacement of kerosene and diesel that would otherwise be used for lighting and electricity generation

Energy and Mining

MS S

P050272 Priv. Sector Development Capacity Building

The key objective of the project is to facilitate increased participation of the private sector in the economy by creating conditions for improving its productivity and competitiveness. This goal will be achieved by helping accelerate the process of divestiture of public enterprises and facilitating increased private participation; improving the business environment and increasing competition and the contestability fo markets; strengthening the linkages and integration of the Ethiopian economy into the global markets; strengthening support for technical and business management skills and thus improving the productivity at the firm level.

Private Sector

MU MU

P078458 ICT Assisted Development

The objective of this project is to assist communities to improve their livelihood through the use of appropriate Information and Communication Technologies (ICT) that facilitate increased access to markets, development information, and public services.

Private Sector

S S

P082998 Road Sector Develop. Program Phase 2 Suppl. 2

The objectives of the Second Road Sector Development Support Program Project are to increase the road transport infrastructure, and improve its reliability, strengthen the capacity for road construction, management and maintenance, and, create conditions conducive to private sector participation in the road transport sector.

Transport S S

P044613 RSDP– APL1 The objective of the first phase of the Second Road Sector Development Project is to restore and expand Ethiopia's road network to reduce poverty and increase employment through promoting growth and access in a socially and environmentally sustainable manner.

Transport MS MS

P076735 Water Supply & Sanitation

The objective of the Water Supply and Sanitation Project for Ethiopia is increased access to sustainable water supply and sanitation

Water Supply

S S

MS: Moderately Satisfactory; S: Satisfactory; MS: Moderately Unsatisfactory; U: Unsatisfactory

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World Bank Projects Completed within the Last 5 Years

Proj ID Project Name

Summary Sector Exit FY IEG rating

P000732 ET-Education Sector Devel. SIM (FY98)

The main objective of ESDP I (1997/98-2001/02) continued into the ESDP II period (2002/03-2004/05) --expanding access and coverage with equity and improved quality towards the long-term goal of achieving universal primary education.

Education 2004 Moderately satisfactory

P000734 ER Road Rehabilitation (FY93)

The project objectives are to: (a) rehabilitate and improve sections of the Mille-Assab road; (b) assist the Government in its effort to improve the maintenance capacity on the remainder of the road between Addis Ababa and Mille; and (c) strengthen the capacity of the Ethiopian Roads Authority to better assess potential road problems and plan future road maintenance and rehabilitation needs in a timely fashion.

Transport 2003 Satisfactory

P000736 ET – Energy II

The project objectives are: (a) to increase the efficiency and sustainability of Ethiopia’s power sector, and to increase electricity use for economic growth and improved quality of life; and (b) to improve utilization efficiency of rural renewable energy.

Energy and Mining

2006 Moderately Satisfactory

P000752 ET Seed System Development (FY95)

The project aimed to contribute to the national goal of increased agricultural production and productivity by laying the foundation for the development of a broad-based and competitive seed industry which draws its strength both from the formal and the informal seed systems.

Rural Sector

2003 Moderately unsatisfactory

P000753 National Fertilizer Sector (FY95)

The objective of the National Fertilizer Development Project is to help achieve accelerated and sustainable growth in agricultural production and productivity with a view to improving food security and reducing poverty.

Rural Sector

2002 Unsatisfactory

P000755 ET – Road Sector Development Report

The primary aim of this project is to contribute to Ethiopia’s economic development by: (1) improving trunk and regional rural road access and utilization to meet the agricultural and other economic development needs; (2) building up the institutional capacity in both the public and private sectors for sustainable road development and maintenance; and (3) providing economic opportunity for the rural poor both through increased employment in rural road works and development of appropriate and affordable means of transport services.

Transport 2005 Satisfactory

P000764 ET-Water Supply Develop. & Rehabilitation (FY96)

The main objectives of the Water Supply Development and Rehabilitation Project are to ensure the long-term viability of water supply and sanitation operations in line with the Government's regionalization policies and, in the long run, improve the health and productivity of the population.

Water Supply and Sanitation

2003 Moderately satisfactory

P000771 ET-Social Rehab & Dev Fund (FY96)

The Ethiopian Social Rehabilitation and Development Fund Project (ESRDF) will provide to poor, mainly rural communities the assets and services needed to improve their economic and social standards.

Social Protection

2005 Moderately satisfactory

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Donor Operations

Project Name Summary Agency Region Rural Electrification Project

Extension of Substations HV, MV and LV lines to 335 towns and villages AfDB Sawla-Key Afer and

Akista Alem Ketema

Indian Government sponsored Electrification

Electrification of 27 towns Indian Gov’t.

Hagare-Mariam Mega

BADEA-financed Rural Electrification Project

The project will provide electrification for 44 towns in two regions, Amhara and Gurage. Capacity building will take place in the form of technical assistance to linemen.

BADEA Weliso Area

Kuwait-financed project under UEAP

The project will electrify 27 rural towns. It will provide improvements to 4 substations and construct 3 transmission lines.

Kuwait Fund

Afar Region

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Annex 3: Results Framework and Monitoring

ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORT PROJECT : ETHIOPIA-SUDAN INTERCONNECTOR

Results Framework

PDO Outcome Indicators Use of Outcome Information Promote Ethiopia's power export revenue generation capacity

Quantity of electricity traded (exports/imports) between Ethiopia and Sudan Increased foreign exchange from power sales to Sudan

To assure benefits of exports of surplus, lower cost, and less polluting power

Intermediate Results One per Component

Results Indicators for Each Component

Use of Results Monitoring

Component One: Electricity and related communication infrastructure expanded and upgraded

Component One: Transmission line erection completed on schedule Number of substations upgraded Telecommunication and telecontrol systems in place and fully operational

Component One: Assess progress in construction of transmission line and substation expansion

Component Two: Increased capacity to implement regional interconnectors

Component Two : Work of supervision consultant satisfactory to EEPCo and Bank EMP and RAP implemented in compliance with WB safeguard policies

Component Two: Assess enhanced capacity on power trade

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A

rran

gem

ents

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45

Annex 4: Detailed Project Description


1. The Project consists of two components:

• Component 1: Construction of a transmission interconnection between the towns of Bahir Dar and Metema (the Ethiopian town at the border with Sudan), to link with Sudan’s extension of its grid to the border, including (a) erection and expansion of transmission line; (b) extension and rehabilitation of substations; and (c) installation of a fiber optics telecommunications system and supervisory control.

• Component 2: Institutional strengthening and capacity building for regional development:

(i) to support the effective implementation and operation of the Ethiopia-Sudan interconnector transmission line and (ii) to strengthen Ethiopia’s capacity to analyze and implement regional interconnections, including: (a) supervisory engineer services to support the erection activities in Ethiopia; (b) support to implementation of the EMP and RAP; (c) strengthening EEPCo’s operation of its Load Dispatch Center to manage the operation of the Ethiopia-Sudan interconnectors and other regional operations; (d) strengthening EEPCo’s regional interconnection units in the area of power trade; and (e) support to EEPCo in promoting generation for regional exports through competitive processes.

A. Component 1: Transmission Line Interconnection and Related Facilities 2. The Project involves the construction in Ethiopia of a new transmission line, the augmentation of some existing lines (single circuit to double circuit), and the expansion/upgrading of existing sub-stations. These works will allow Ethiopia to interconnect with a transmission line being built in parallel on the Sudanese side with the objective of being able to transport over 200 MW. The two lines will be linked at the border at the towns of Metema (in Ethiopia) and Gallabat (in Sudan). A diagram of the transmission line and substation work is presented further below. 3. Transmission Line Erection (US$ 27.40 million). The largest cost component of the Project is the construction of the 296.5 km transmission line, including OPGW-wire. This sub-component includes: (a) the construction of an HV double circuit 230/220 kV, 3-phase a.c. transmission line from Shehedi Substation to the border with Sudan with a total length of 36.5 km, and (b) the reinforcement expansion of the existing 260 km single circuit 230 kV line from Bahir Dar Substation to Gondar Substation and further to Shehedi Substation with a second circuit that involves (i) construction of a second single circuit transmission towers sytem from Bahir Dar to Gondar to complement the existing single ciruit tower system, and (ii) stringing of a second line on the double circuit tower system previously erected between Gondar and Shehedi. In parallel, Sudan will extend through a double circuit line its grid from Gederaf to the border at Gallabat where the Ethiopian and Sudanese lines will be connected. 4. A turnkey (design, manufacture, supply and erect) contract will be used to build the transmission line. The line will be constructed according to the guidelines and standards of the International Electro-technical Commission (IEC) and other international standards. The line will have a nominal voltage of 230kV with the highest system voltage of 245kV and will be built on conventional lattice steel towers. All aluminum conductors of 2-450 mm.sq. will be used except for the second circuit of the Shehidi-Gondar section on existing towers which will be on 2-181 mm.sq. conductors.

46

Transmission line diagram

5. In Sudan, NEC is employing an international contractor to do the detailed design and supply the materials. Construction of the tower footings will be undertaken by local contractors working under the supervision of NEC. NEC staff will do the erection of the towers and stringing of the line. NEC has experience in building transmission lines and will work with the support of the international contractor. 6. Substation Expansion and Rehabilitation (US$11.15 million). This subcomponent consists of extensions to the Bahir Dar, Gondar and Shehedi substations. The additional bays to be provided will consist of switching equipment, measuring transformers, OPGW connection devices, surge arresters and compensating reactors. In addition busbar extensions with civil works are also included. 7. Fiber optics telecommunications system and telecontrol equipment (US$1.00 million). A power inter-exchange monitoring and control system will be established to facilitate effective power trade and ensure reliable operation of the Ethiopia-Sudan interconnection. The control system proposed will include: (a) application software to manage the power inter-exchange scheduling between the Load Dispatch Centers (LDC’s) of the two countries; (b) real-time monitoring and alarm systems for the network components including reporting facilities; and (c) voice, email and document messaging. The telecommunication system will be based on OPGW in the tie-line. The number of fibers is 24. To cover long-distances, special optic amplifiers (boosters) and some repeaters will be used. Multiplexing will be based on digital SDH-hierarchy and will be located at the terminal substations. Data, voice messaging and protection services will use this system.

Border Sudan Ethiopia

Gedaref Substation

Shehedi Substation

Gondar Substation

157.5 km 36.5 km 122 km 138 km

Bahir Dar Substation

Substation

New 230/220 kV transmission line

Existing 230 kV transmission line

New 230/220 kV line bays

Existing 230/220 kV line bays

47

8. To fulfill the scheme, telecommunication is needed along the tie-line and from the terminal substations to the load dispatch centers in both countries. Ethiopia’s LDC is located at the Weregenu 132 kV substation in Addis Ababa. Sudan’s LDC is located in Kilo X substation near Khartoum. TRhe LDC systems will be provided with the inter-exchange software to manage the technical and operational needs. Upgrades will be provided to the substations and will be connected to the local RTUs to enable the supervision and control facilities for the operation of a SCADA system. 9. Two construction packages will be prepared for the infrastructure sub-components to be funded by the IDA Credit:

a. For the transmission line in Ethiopia (including OPGW), an EPC contractor will be selected to carry out the design, supply and erection of the line (including OPGW):

• Erection of about 137.5 km of a single circuit 230 kV, 3-phase a.c. line between the existing Substations Bahir Dar and Gondar. The line will have twin AAAC 450 mm.sq. conductor per phase, single optical fibre cable shield wire and will be built on self supporting, tapered configuration, vertical formation galvanized steel lattice towers with each leg having a separate footings of pad and chimney concrete type;

• Stringing of about 122 km of a single circuit 230 kV, 3-phase a.c. line having twin

AAAC 181 mm. sq. conductor per phase with associated fittings on the existing two circuit tower structures from Gondar Substation to Shehedi Substation;

• Erection of about 36.5 km of a double circuit 230 kV, 3-phase a.c. line from the existing

Shehedi Substation to the Ethiopia-Sudan border. The line will have twin AAAC 450 mm.sq. conductor per phase, single optical fibre cable shield wire and will be built on self supporting, tapered configuration, vertical formation galvanized steel lattice towers with each leg having a separate footings of pad and chimney concrete type.

b. Substation Expansion (including tele-control and communications) in Ethiopia:

• Erection of one 230 kV outgoing line bay including tele-control and communication equipment at the Bahir Dar Substation;

• Erection of one 230 kV outgoing line bay and one 230 kV incoming line bay including

tele-control and communication equipment at the Gondar Substation; and • Erection of two 230 kV outgoing line bays and one 230 kV incoming line bay, including

tele-control and communication equipment, at the Shehedi Substation.

10. Extension of Sudanese Grid. Sudan will, in parallel, build a transmission line from Gedaref to the town of Gallabat (about 155 km) and on to the border with Ethiopia to connect its grid to the extension being undertaken by Ethiopia under Component 1 of the project. Total cost of the project on the Sudanese side is approx. US$25.5 million (see Annex 5). B. Component 2: Institutional Strengthening and Capacity Building for Regional Development (US$3.55 million) 11. The aim of this component is (i) to support the effective construction and operation of the transmission line, including the establishment of operating rules for the interconnected system and the

48

training of personnel in power system planning and design, and interconnected system operation and regulation; (ii) to ensure that the environmental and social plans for the Project are implemented in accordance with Bank standards, and (iii) to build necessary institutional and human capacity to initiate the establishment of institutional, technical and commercial mechanisms that would allow and development of a broader regional market. 12. The capacity building component provides various forms of support: (a) specific training on operation for the transmission line, and (b) capacity building on the broader objectives and needs of power trade to initiate the development of a power trading architecture in the sub-region. A summary of the main sub-components is included below:

a. Support to EEPCo on the implementation and operation of the transmission line, including the following activities:

• Supervision Engineer (US$1.40 million). All works contracts in Ethiopia will be supervised by an engineering consultant. This consultant will also ensure that the protection and telecommunications systems between the two LDCs are properly implemented. The supervision consultant will also provide training on equipment operation and maintenance for the local crews responsible for the day to day operation of the transmission line.

• Implementation of the Environmental Management Plan (EMP) and Resettlement Action

Plan (RAP) (US$1.30 million). The EMP and RAP include mitigation, management and monitoring measures to be taken during implementation and operation of the transmission interconnection that are aimed at offsetting or reducing adverse environmental and social impacts. EEPCO will be responsible for the implementation of the EMP and RAP; it will hire qualified environmental and social expertise to assist and strengthen the utility’s environmental and social management unit (EMU) to support implementation of the EMP and RAP and supervise the work of the contractors.

b. Supporting Ethiopia’s role as a key power exporter in the region, including:

• Strengthening the Load Dispatch Center training program (US$0.50 million). As part on the actual contract for the construction of the LDC centers in Ethiopia, a training program for the operation of center has been included. Additional training on issues related to cross-border trade is required and will be financed by the project.

• Capacity building on regional power trade issues (US$0.10 million). This activity will

enhance EEPCo’s capacity, notably of the units responsible for regional interconnections, in key areas of power trade (including training and equipment acquisition), such as defining and preparing trading arrangements and procedures, and technical and safety guidelines for the operation of the Ethiopia-Sudan and other interconnectors.

• Promotion of generation projects for regional exports through competitive processes

(US$0.25 million). This activity will provide advisory and logistical support to EEPCo to explore potential sponsors and financiers for generation projects.

49

Annex 5: Project Costs ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORT PROJECT:

ETHIOPIA-SUDAN INTERCONNECTOR A. Ethiopia

Project Cost By Component and/or Activity

Local US $million

Foreign US $million

Total US $million

Total Including contingencies

1a. Transmission Line 2.80 21.20 24.00 27.401b. Substation expansion and rehabilitation 1.00 8.65 9.65 11.151c. Telecontrol and telecommunications 0.00 0.85 0.85 1.002a1. Supervision engineer 0.00 1.20 1.20 1.402a2. EMP and RAP 1.10 0.00 1.10 1.302a3. Support LDC training program 0.00 0.40 0.40 0.502b1. Capacity building regional transmission units

0.00 0.10 0.10 0.10

2b2. Generation promotion 0.00 0.22 0.22 0.25Total Baseline Cost 4.90 32.62 37.52 Physical Contingencies (5%) 0.20 1.60 1.80 Price Contingencies (10%) 0.53 3.25 3.78

Total Project Costs 5.63 37.47 43.10 43.10 B. Sudan Project Component Cost 1. Transmission Line 20.802. Substation expansion and rehabilitation 3.503. Telecontrol and telecommunications 0.604. EMP and RAP implementation 0.70

Total Project Costs 25.60This estimate includes contingencies. C. Total (Ethiopia and Sudan) Project Cost By Component and/or Activity Ethiopia Sudan Total 1a. Transmission Line 27.40 20.80 48.20 1b. Substation expansion and rehab. 11.15 3.50 14.65 1c. Telecontrol and telecoms. 1.00 0.60 1.60 2a1. Supervision engineer 1.40 0.00 1.40 2a2. EMP and RAP 1.30 0.70 2.00 2a3. Support LDC training program 0.50 0.00 0.50 2b1. Capacity building for Reg. Dpt. 0.10 0.00 0.10 2b2. Generation promotion 0.25 0.00 0.25

Total Project Costs 43.10 25.60 68.70 This estimate includes contingencies.

50

Annex 6: Implementation Arrangements


A. Organizational Structure 1. The Project will be implemented by EEPCo using a turn-key kind of arrangement through its Ethiopia-Sudan Transmission Project Management Unit (PMU). A Project Steering Committee (SC) has been established by EEPCo and NEC to coordinate the development of the interconnector across the two countries. The Nile Basin Initiative Eastern Nile Technical Regional Office (ENTRO) through its Power Coordination Unit has been providing support and will assist in monitoring the implementation of the interconnector, in particular the environmental management and resettlement action plans. 2. This annex describes (a) the inter-country/inter-utility implementation arrangements, (b) the national management units, and (c) the role of the Eastern Nile Technical Regional Office. i. Inter-country/Inter-utility Arrangements 3. The Project will be implemented by the two utilities, EEPCo and NEC. The utilities will enter into the Construction Agreement and the Operation and Maintenance Agreement, which provide frameworks for the implementation of the Project. The utilities will also enter into a Power Purchase Agreement setting out the commercial terms for the sale of power between the two countries (see discussion below under “Contractual Arrangements”).

Organization for the Construction Phase:

4. The construction phase will include the following arrangements:

• Project Manager and Project Construction Units: The Steering Committee will nominate a Project Manager for the construction Phase. The Project Manager will be responsible to supervise and monitor the construction work in both countries. The parties have already established Project Implementation Units and designated a Manager for each unit.

• Ad Hoc Task Forces: The Steering Committee will nominate and supervise temporary Ad Hoc Task Forces to deal with specific tasks and issues, like preparation of the Operation and Maintenance Agreement, training programs, etc.

51

Organization during Construction Phase

5. On the commissioning of the transmission line, the Project Manager and the SC will terminate their activities. Organization for Operation of the Line: 6. After the line is commissioned, the following arrangements are proposed by EEPCo and NEC, as reflected in the CA and OMA agreements (described further below):

• Interconnection Committee: For the operation of the interconnection, the parties will establish a permanent Interconnection Committee (IC) with two permanent working groups: (i) the Operations Working Group and (ii) the Planning Working Group.

• Operations Working Group: This group will be responsible for the coordination of all matters

related to the interconnected operation of the power systems.

• Planning Working Group: This group will be responsible for the long-term arrangements and coordination (3…10 years).

Steering Committee (SC) CEOs + PM + Project Managers (+

Financiers, government reps.)

Project Manager (+ consultant staff)

EEPCO Eth-Sud

Interconnector Unit

NEC Planning &

Projects Directorate

Staff

Ad Hoc Task Forces (by joint management assignments) Agreements

Operations

Training

52

Organization during Operations

ii. EEPCo 7. The Ethiopia Electric Power Authority (EEPCo) is responsible for the generation, transmission, distribution and sales of electricity in Ethiopia (see also description in Annex 1). The overall administration and management of EEPCo is under the responsibility of the General Manager who operates under the oversight of a Management Board. EEPCo has established a Project Management Unit (PMU) and designated a Project Manager directly under the supervision of the General Manager to coordinate the preparation and implementation of the Project. iii. NEC 8. The Ministry of Electricity has the overall responsibility for policy formulation in the power sector. The National Electricity Corporation Act of 1982 which established NEC was replaced by the National Electricity Corporation Act of 2000 and 2001. The main function of NEC is to generate, transmit, distribute and sell electricity. The Managing Director of NEC is responsible for corporate operations and management, assisted by seven directors (General Directorates). The Ethiopia-Sudan transmission interconnection “Project Implementation Unit” was established under the General Directorate of Planning and Projects. iv. ENTRO 9. The Eastern Nile Technical Regional Office (ENTRO) was established in June 2002 by three Eastern Nile governments, Egypt, Ethiopia and Sudan. ENTRO is a coordinating and implementing agency of the Eastern Nile Subsidiary Action Plan (ENSAP), which aims to develop the water resources of the Eastern Nile Basin in a sustainable and equitable way to ensure prosperity, security, and peace for all its peoples. ENTRO operates under national ENSAP Teams (ENSAPT) and Eastern Nile Council of Ministers (ENCOM). The overall purpose of ENTRO is to support ENSAPT and ENCOM in developing, implementing, and managing the ENSAP, and in the short term, in the preparation for implementation of the first ENSAP Project, the Integrated Development of the Eastern Nile Project (IDEN), and a Joint Multi-purpose Program.

Steering Committee (SC) CEOs + Committee Heads + Ad Hoc

Heads (+ government reps.)

Interconnection Committee (IC)

Operations WG • Procedures • Maintenance • Security • Training

Planning WG • Load

forecasts • Power exch. • River flows • Expansions

Ad Hoc Task Forces (by joint management assignments)

Contracts

53

10. A Steering Committee, comprising the Chief Executive Officers of the three Power Utilities in Egypt, Ethiopia and Sudan, representatives of the Electricity Ministries in the three countries, and ENTRO provide overall programmatic and strategic guidance to power Projects within the framework of ENSAP and the NBI. A Technical Committee (TC) supports the steering committee and ENTRO in technical issues. The Technical Committee consists of two representatives from each of the three EN countries, one from the ministry responsible for electricity with broad knowledge of sector reform and regulation, and the other from the power utility with experience in transmission and system operations. 11. Role of the ENTRO regarding the Ethiopia-Sudan Transmission Interconnection Project: ENTRO has played an important supporting role to NEC and EEPCo in the development of the Ethiopia-Sudan interconector, and is anticipated to continue to play a facilitating role. ENTRO through the PCU is administering a PHRD grant that financed the preparation of the Environmental and Social Impact Assessment for the transmission line (see Annex 10). In addition, ENTRO will continue to support the two utilities in the preparation and implementation of the transmission line, and will assist in monitoring environmental and social impacts, and the resettlement plans in the two countries. B. Contractual Arrangements

12. There are several key contracts to be entered into between EEPCo and NEC: (i) the Construction Agreement (CA), which regulates the mode of coordinating the construction activities in Ethiopia and Sudan, (ii) the Operation and Maintenance Agreement (OMA), which sets the terms for the operation of the line, once constructed, and (iii) the Power Purchase Agreement (PPA), which sets the commercial terms for the exchange of power between the two countries.

13. Construction Agreement. This agreement sets out the main framework on how the construction phase is to be carried out. This agreement specifies the design and construction responsibilities of both utilities, as well as the objectives of the interconnection, the ownership rights, and the financial obligations of each party. It also establishes the administrative framework to monitor and govern the construction contracts between the utilities and contractors (taking account the commitments of the utilities to manage the environmental and social impacts of the Project).

14. Operation and Maintenance Agreement. This agreement sets forth the main organization and responsibility principles for the operating bodies in each country. These bodies are the National Load Dispatch Centers and the Substations. The responsibility of the National Load Dispatch Centers in both countries is to monitor, control and plan power generation, transmission and exchange. They have the overall responsibility for network security. The staff of the utilities will plan, prepare and agree on switching instructions, and will also be responsible for inspection, maintenance and repair of the line. 15. Construction and Supply Contractors. EEPCo will employ a contractor to erect the transmission line and undertake the substation expansion and related activities. NEC will employ a contractor to do the detailed design and supply the materials, and will employ local contractors for the tower footings. 16. Supervisory Engineer. EEPCo will employ a supervisory engineer to supervise the construction activities. The supervisory engineer will also help to ensure coordination with NEC’s activities. 17. Power Purchase Agreement (PPA). This agreement establishes the terms of trade between the two utilities, including energy export prices and volumes. The two countries have agreed in principle to a PPA for a ten-year term. With respect to volumes, the countries have negotiated a framework for the provision by EEPCo to NEC on an annual basis of up to 200 MW nominal as follows: (a) 100 MW firm for the term of the contract (provided at a 95 percent load factor) (“firm” energy), (b) up to an additional 75 MW (and potentially as high as 100 MW) as offered by EEPCo on an annual basis (“annually scheduled power”), and (c) monthly scheduled power for the three months of high rains (June, July and August) in the range of 25 MW (“rainy month surplus power”). The parties are discussing the pricing structure for the annually scheduled and rainy monthly surplus power. Currently, EEPCo and NEC are finalizing

54

negotiation of the price for the initial three years with discussions varying between US$5 cents and US$ 6 cents for firm power. For purposes of evaluating the project, a mid-range price has been selected, namely, the PPA has been analyzed assuming a reference price of US$5.5 cents for firm power, a price for annually scheduled power set at 50 percent of the reference price, and a price for rainy month surplus power set at 30 percent of the reference price.

Contractual Relations

C. On-lending Terms for Project Funds provided by GoE to EEPCo 18. The proceeds of the IDA credit will be provided by GOE to EEPCo through a subsidiary loan agreement. The funds will be provided for a term of 20 years, with a five year grace period at an interest rate of 6 percent per annum (with foreign exchange risk borne by EEPCo). D. Implementation of the Works Contracts in Ethiopia 19. The works to be carried out in both countries were determined by feasibility studies carried out by international consultants in 1988, 1995, and 2004. The final feasibility study recommended technical parameters. Subsequently, EEPCo appointed an engineering consultant (on terms agreed with the Bank) to review the relevant design features and technical specifications and to prepare bidding documents for the two contracts to be carried out in the Ethiopian side. The two contracts will be procured under ICB in accordance with the World Bank procurement guidelines through works contracts after pre-qualification of bidders. The engineering consultant will assist EEPCo in the preparation of all bidding documents, correspondence with bidders, conducting a pre-bid conference, evaluation of bids related clarifications, pre-contract discussions with the selected bidder and finalization of the contracts. EEPCo has already issued PQ documents for both ICB contracts, obtained responses and submitted its PQ evaluation report to the Bank. The Bank has reviewed this report and sent its comments for a resubmission by EEPCo. 20. For the supervision of the two contracts, EEPCo will engage a supervision consultant. The supervision consultant will be engaged till the completion and commissioning of the project and will function in the capacity of ‘Project Engineer’ under the two contracts.

E E P C O

N E C

Supervisory Engineer

Contractor

• Construction Agreement • Operation and Maintenance

Agreement • Power Purchase Agreement

Contractor

55

E. Implementation of the Works Contracts in Sudan 21. The Sudanese section of the interconnection will be financed through a bilateral credit agreement with India’s export/import bank. An international contractor has been selected to prepare the detailed design and supply all goods related to the works. NEC will hire local contractors to do the civil works and NEC’s own staff will erect the towers and string the lines. NEC has considerable experience in carrying out similar works in this manner and will commence the construction activities before end 2007. Representative projects recently constructed or to be commissioned within a year include: (i) the 200 kV ring around Khartoum, 200 km; (ii) the 220 kV Khartoum-Atbara 300 km line; (iii) the 220 kV Roseires-Atbara-Khartoum 650 km line; and (iv) the 220 kV Singa-Gedaref 180 km line.

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Annex 7: Financial Management and Disbursement Arrangements


Introduction

1. The financial management assessment is conducted in line with the Financial Management Practice Manual issued by the FM Board on 3 November 2005. The objective of the assessment is to determine whether the implementing entities have acceptable financial management arrangements, which will ensure: (1) the funds are used only for the intended purposes in an efficient and economical way, (2) the preparation of accurate, reliable and timely periodic financial reports, and (3) safeguard the entities’ assets. The FM assessment conducted in March 2007 for the Second Electricity Access Rural Expansion Project, which is implemented by the Ethiopian Electric Power Corporation (EEPCo), has been used as an input for this assessment as the project is implemented by EEPCo as well.

Executive Summary

2. The recently completed Joint budget and Aid review (JBAR) and the Fiduciary Assessment (FA) show that Ethiopia has made significant progress in strengthening public financial management in recent years. Though most of the recent diagnostic works show an improvement in Public Financial Management, there are weak areas that require attention. Ethiopia’s public financial management reforms are being carried out through the government’s Expenditure Management and Control sub-Program (EMCP) of the government’s civil services reform program. Mobilization behind the EMCP (in terms of financial and human resources), as a key component of the Public Sector Capacity Building Program (PSCAP) being supported by the Bank and other development partners, is a priority.

3. EEPCo will implement the project through its Project Management Unit (PMU). The PMU coordinates with and relies on the other specialized departments within EEPCo, including the financial management functions.

4. EEPCo has five groups according to its organizational structure. One of the groups is the Finance group headed by a by Deputy Manager for Finance. The Finance Group has Treasury and Controller Departments. The finance staff of the Finance Group will handle the financial transactions of this project. The financial management capacity of EEPCo is satisfactory. The PMU and Finance Group will be maintain accounting records and prepare project financial statements in line with International Accounting Standards/International Financial Reporting Standards. EEPCo’s annual accounts will be audited in accordance with International Standards on Auditing. The financial transactions of the project will be included in EEPCo’s annual accounts. EEPCo will submit audit reports to IDA six months after the end of each fiscal year. FM Risk is assessed as Moderate. Some key weaknesses need to be addressed to ensure timely and good quality financial reports, and to ensure satisfactory follow-up actions on the audit reports. An action plan to address key FM weaknesses has been agreed.

Summary of Project Description

5. The proposed lending instrument would be a four year Sector Investment Loan (SIL). The IDA credit would provide financing to EEPCo (through GoE) for the implementation of the Ethiopian portion of the line. The Project’s long-term development objective is to improve the effectiveness of the power systems in the Eastern Nile region by promoting regional power trade through the establishment of coordinated

57

planning and the erection of transmission interconnections in the context of multi-purpose water and energy resources development in the region. The Project will also take advantage of the hydro-thermal complementarity of the Ethiopian and Sudanese systems to reduce overall generation costs and improve the availability and reliability of supply in the two countries.

Country Issues

6. The recently completed Joint budget and Aid review (JBAR) and the Fiduciary Assessment (FA) show that Ethiopia has made significant progress in strengthening public financial management in recent years. As part of the JBAR, the development partners conducted a Public Financial Management (PFM) status review at the federal and regional levels using the PEFA framework. Generally Ethiopia scores high in macroeconomic management, including aggregate fiscal discipline and minimizing fiscal risks. Satisfactory progress was also noted in budgeting and accounting reform, though the adequacy and quality of budget reporting leaves room for improvement and remains a key concern.

7. The FA, which was completed in early 2005, notes that considerable progress has been made in implementing FM reforms in both federal and regional level administrations. The areas of improvements include budget processes, internal controls and cash management. Also, some steps have been taken in reforming internal and external audits. The recent PFM review indicates the need for further improvements in financial reporting (reducing delays in in-year and annual reporting), external audits, and scrutiny of public finances as part of overall PFM reforms. At the regional level, the situation varies from region to region. The roll-out of PFM reforms occurred first in SNNP and Tigray regions, with the support of the Government and donor initiatives to support these reforms. They both show improvement in the overall public finance function and a consequential reduction in fiduciary risk. Other Regions are at an earlier stage of investment in PFM or have not yet commenced their plans and therefore demonstrated less progress in PFM improvement. More recently, Amhara and Oromiya have improved there performance significantly, as evidenced by timeliness in closure of accounts and also implementation of the budget and accounts reforms. However, there continues to be capacity and staffing issues in areas such as audit in all the regions. An additional concern is that while there are some improvements in the financial discipline associated with government funds, the increasing use of other funding routes (such as in the Food Security Program) has the potential to increase fiduciary risk. This is because the use of alternative funding routes creates additional workload in areas where capacity is already stretched.

8. Ethiopia’s public financial management reforms have been managed by and are being implemented under the Expenditure Management and Control sub-Program (EMCP) of the government’s civil services reform program. EMCP has developed a revised strategic plan to implement the nine components of the sub-program Mobilization behind the EMCP (in terms of financial and human resources), as a key component of the Public Sector Capacity Building Program (PSCAP) which is supported by the Bank and other development partners, is a priority.

58

Risk Assessment and Mitigation Risk Risk

rating Risk Mitigating

Measures Incorporated into

Project Design

Conditions for

Effectiveness (Y/N)

Remarks

Inherent risk M Country level S N This risk arises from weak capacity,

including shortage of qualified accountants and auditors, and weaknesses in the country’s PFM system. It is being addressed by the Government outside this project through the ongoing EMCP which is supported by PSCAP. Also, PSDCBP is supporting some private sector initiatives

Entity level M N EEPCo has previous experience in implementing Bank-financed projects and is currently implementing 3 other Bank-financed projects

Project level M N The project design is simple, with only 1 implementing agency handling project funds. Project activities and funds flow mechanisms are well defined.

Control Risk M Budgeting L N EEPCo and RIPD prepare annual

budget and expenditures are incurred inline with the budget.

Accounting M N EEPCo has a good system of accounting, which is capable of recording and reporting financial transactions

Internal Control

M N

Funds Flow L N Financial Reporting

S Contents of unaudited interim financial reports agreed

N There have been delays in producing regular financial statements. The quality of financial reports submitted to the Bank under previous projects is variable and needs improvement. EEPCo is introducing a new computerized accounting system and this is expected to solve the delays in producing financial statements

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Risk Risk rating

Risk Mitigating Measures

Incorporated into Project Design

Conditions for

Effectiveness (Y/N)

Remarks

Auditing S Action Plan to close accounts early so that audits can be completed on time, to ensure actions on issues highlighted in audit reports, and to receive the outstanding Management Letters was agreed.

N In the past, audit reports were issued late. As indicated above the introduction of the new computerized accounting system will facilitate closing of accounts on time and the auditors could issue their reports on time

H-High, S-Substantial, M-Moderate, L-Low The overall financial management risk rating for this project is assessed as Moderate.

Strengths

9. The country’s discipline in executing budget and complying with the existing government regulations are the major strengths indicated in most of the PFM diagnostic works conducted so far. This project is mainly implemented by a PMU located at EEPCo’s central level. The PMU has well trained and experienced staff to implement the project. The PMU will work with the Finance Unit that has qualified and experienced staff to handle the financial transactions of the project. Weaknesses and Action Plan 10. The action plan below has been agreed: Significant Weaknesses

Action Responsible body Completion

Delays in closing EEPCo’s accounts and late submission of audit reports

EEPCo would close its accounts at least three months after the end of each fiscal year

EEPCo Finance Group 30 September of each year

EEPCo’s entity audit report for the year ended July 7, 2006 has significant qualifications

EEPCo would indicate its proposed actions to address these qualifications in a satisfactory manner

EEPCo December 31st, 2007

EEPCo has not submitted its auditor’s Management Letter for the entity audit and the audit of the Energy Access Project for the year ended July 7, 2006

EEPCo would provide these Management Letters, along with a statement of actions taken or which will be taken to address weaknesses or issues highlighted in the Management Letters.

EEPCo December 31st, 2007

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Implementing Entity 11. The implementing entity is Ethiopian Electric Power Corporation (EEPCo). EEPCo is also an implementing entity of 3 other ongoing Bank-financed projects: Energy Access Project (P049395), Electricity Access Rural Expansion Project (EAREP –I, P097271) and EAREP II (P101556). EEPCo will implement the project through its Ethiopia-Sudan Interconnector Project Management Unit (PMU). The Project Management Unit has a Manager, and is supported by electrical engineers, mechanical engineers and accountants. It is an office reporting directly to the Deputy General Manager for Transmission and Operations. The PMU office coordinates with and relies on the other specialized departments within EEPCo, including the financial management functions. Budgeting 12. On annual basis, EEPCo prepares its consolidated budget. The annual budget is prepared on the basis on detailed plan prepared each of the units in EEPCO. The annual budget shows the sources and uses of funds. The sources of funds include own revenue, government contributions, and credits and grants. The annual budget is approved by the Board of Management of EEPCo. Each unit in EEPCo prepares its own budget and EEPCo prepares a consolidated budget for the entity as a whole. 13. As indicated above EEPCo obtains funds from the federal government and presents its budget request to the federal government. EEPCo follows the federal government budget calendar in preparing its budget and submitting the same to the Ministry of Finance and Economic Development (MoFED). Release of funds from MoFED to EEPCO is done on the basis of the annual budget. EEPCO is required to submit utilization of money to MoFED on regular basis. Accounting 14. EEPCO has accounting policies and procedures for the entity as whole. The PMU, being part of the entity follows the policies and procedures of the entity. EEPCo uses accrual basis of accounting with a double entry accounting system. EEPCo uses the International Financial Reporting Standards (IFRS) in recording and reporting its financial transactions. The PMU’s accounting records are integrated with the entity accounting system with general and subsidiary ledgers. EEPCo uses a computerized accounting system with a mainframe computer. For the future, the entity will introduce new accounting software 15. EEPCo has a Finance Group headed by Deputy Manager for Finance. The Finance Group has Treasury and Controller Departments. The Finance Group has 618 staff including all descentralized accounting processes, out of which 438 are professional staff and 180 are support staff. Out of the 438 professional staff, 147 are degree holders and the rest are diploma holders. Internal Controls 16. Internal control comprises the whole systems of control, financial or otherwise, established by management in order to (a) carry out the project activities in an orderly and efficient manner, (b) ensure adherence to policies and procedures and (c) safeguard the assets of the project and secure as far as possible the completeness and accuracy of the financial and other records. 17. EEPCP has good system of internal control system, which helps the management of the project in achieving the project objectives in orderly and efficient manner. The entity’s financial policies and procedures manual specify the detail internal control procedures to be applied in managing funds. The main focus of the internal control is placed on the following:

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• Segregation of duties • Physical control of assets • Authorization and approval • Clear channels of command • Arithmetic and accounting accuracy • Integrity and performance of staff at all levels • Supervision

18. EEPCO has an Internal Audit Department, which directly reports to the General Manager of EEPCO. The Internal Audit Department has 27 staff, 8 with first degree and the others with diploma. The staff of the Internal Audit Department will include the financial transactions of the project in their annual audit program. Fund Flows and Disbursement Arrangements Retroactive Financing 19. In accordance with OP6.00, the Project will be able to charge up to US$8 million of the credit amount for expenditures occurring on or after January 1st, 2008 and up to the credit signing date. The retroactive financing will only apply to Categories 1, 2 of the Disbursement Schedule, namely for works and consultant services. Flow of Funds 20. EEPCO will open a Designated Account in the National Bank of Ethiopia. The DA will be held in the United States Dollars. IDA, from the Credit Account, will transfer money to the DA. Expenditures incurred for project eligible expenditures may be paid from the DA. Based on approved work program, the PMU will transfer four months estimated expenditures from the DA to a local currency account. No money will be transferred to EEPCo regional offices from the proceeds of the credit. 21. Currently, there are outstanding balances in special/designated accounts under lapsed credits under IDA projects. IDA has informed the GoE that, according to Bank policies on financial management of projects, unless these outstanding balances are recovered, the Credit for the Project will be foreclosed from the ability to effect disbursements by means of advances to a Designated Account. Disbursement Methods 22. The Project will utilize disbursement methods based on Designated Account Advance, reimbursements against full documentation or against Statements of Expenditure, Direct Payment, and Special Commitment.8 At the beginning of the Project, disbursements will be made on the basis of full documentation or statements of expenditures (SOEs). It will be possible use the interim unaudited financial reports for the replenishment of the DA once IDA is satisfied with the adequacy of the financial arrangements.

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Minimum Value of Applications 23. The minimum value for Direct Payment and Special Commitment will be USD 200,000 Use of Statements of Expenditures (SOEs) 24. Full supporting documentation evidencing eligible expenditures would be provided for payments against contracts valued above USD 500,000 for works, USD 100,000 for consulting firms and USD 50,000 for individual consultants. For expenditures below these limits, a summary report of the Statements of Expenditure (SOEs) would be used. 25. The supporting documentation for requests for direct payment should be records evidencing eligible expenditures (copies of receipt, supplier’s invoices, etc). 26. The project will submit a Bank statement and a reconciliation of the designated account together with the withdrawal application on a monthly basis. 27. All supporting documentation for SOEs will be retained at the PMU and must be made available for review by periodic World Bank review missions and external auditors. 28. The contents of the interim un-audited financial reports have been agreed and sample formats will be attached to the disbursement letter. Designated Account 29. The Designated Account will be managed by EEPCo. The minister of MoFED will delegate officials in EEPCo to manage the Designated Account. The currency for the Designated Account will be the United States dollar. 30. The total allocation of the Designated Account will be USD 1.00 million. Counterpart Funding 31. The Government must make all arrangements necessary to ensure the timely mobilization of the counterpart funds required for project implementation. Financial Reporting 32. Recording and reporting of project transactions at the PMU of EEPCo is integrated with the entity accounting system. The PMU will have its own ledgers in EEPCo’s computerized accounting systems and the financial reports of the project are extracted from the overall system. There have been delays in producing regular financial statements. The quality of financial reports submitted to the Bank under previous projects is variable and needs improvement. EEPCo is introducing a new computerized accounting system and this is expected to solve the delays in producing financial statements 33. The PMU together with the Finance Unit will produce interim unaudited Financial Reports (IUFRs) and will submit the IUFRs to IDA 45 days after the end of each quarter. At a minimum, the financial reports must include: (i) the sources and uses of funds (for the quarter and cumulatively for the year-to-date and the project), (ii) expenditures by main expenditure classifications and comparisons with budget, with explanations for significant variances; (iii) beginning and ending cash balances; (iv) and supporting schedules.

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Auditing 34. EEPCo has submitted the audited entity financial statements for the year ended July 7, 2006 to IDA, and is current on the audit reports on the ongoing Bank-financed project (Energy Access Project).9 The audit report for this project was received close to the due date (marginal delay of a few days). There has been a steady improvement in timeliness over the past 3 years. The audit report was unqualified. EEPCo has however not yet submitted the auditor’s Management Letter (Refer: IDA’s letter of April 25, 2007). The FM Action Plan (includes that the Management Letter would be submitted by December 31, 2007 along with a report from EEPCo on actions taken or to be taken on any issues or weaknesses highlighted in the Management Letter. The latest entity audit reports of EEPCo were received about 12 months after the end of the year. Going forward, this needs to be completed and submitted in a more timely manner. The audit report contains some qualifications: the auditors were unable to satisfy themselves about items reflected as receivables (since no breakdown of these balances were available) and goods in transit (since these were long outstanding items); and the auditors have reported that balances between the Head office and Regions have not been reconciled. These are important issues that need to be addressed as a matter of priority. The FM Action Plan includes that EEPCo would indicate its proposed action to address these qualifications in a satisfactory manner by December 31st, 2007. This would be closely monitored as part of project supervision. 35. The annual project financial statements of the PMU will be included in the entity accounts of EEPCo. The notes to EEPCo accounts will show: (i) the sources and uses of funds for the project (in local currency and equivalent dollars), (ii) the cumulative disbursements received from the World Bank and confirmation that these are included as liabilities in EEPCo’s entity accounts, and (iii) a statement of movement of the Designated Account of the project, and confirmation that balance of the Designated Account (if this is used on the project) is included in the assets of EEPCo.10 The auditors will review the financial transaction of the Project during their audit of EEPCo’s accounts. The annual audited financial statements, along with the audit report and management letter, will be submitted to IDA not later than six months after the end of the fiscal year. The terms of reference for the audit will be agreed by March 31, 2008. EEPCo will make available to IDA the current contract for its financial audits and would make any modifications in this contract needed to ensure compliance with World Bank requirements for this Project and the other World Bank-financed projects being implemented by EEPCo. Audit reports to be submitted are summarized below:

Audit Report Due Date EEPCo: Entity Financial Statements (which includes notes on the sources and uses of funds on the project, IDA disbursements, and Designated Account balances)

By January 6 of each year (starting 2009)

36. The accounts will be audited by an external auditor acceptable to IDA and the audit will be conduct in line with International standards on Auditing. Since the Federal Auditor General is responsible for auditing all government funds, it will conduct the audit or assign other external auditor acceptable to IDA for the project. The existing external auditor of EEPCo is the Audit Services Corporation.

9 The first audit reports for the EAREP I and EAREP II are not yet due. 10 An acceptable (but less preferred) alternative would be for EEPCo to submit the separate audit reports and financial statements for the project and entity.

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Supervision Plan 37. Considering the nature of the project, the Bank’s supervision mission should be as regular as possible. Each year, there should be at least two supervision missions. In addition to these supervision missions, the Bank would review quarterly unaudited interim financial reports (IFRs), and audit reports and Management Letters of EEPCo (including of the project). As part of project supervision, the Bank would monitor the implementation of action to address any issues highlighted in the audit reports and Management Letters.

Disbursement of the IDA Credit

Table C: Allocation of Credit proceeds

Expenditure Category Amount in US$ million Financing percentage (1) Works a. transmission line 24.00 b. substations, including telecommunications 10.50

100%

(2) a. Consultant’s services for supervision consultant

1.20 100%

b. Consultant’s services for other regional activities 0.10 (3) Unallocated 5.25 Total Amount 41.05

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Annex 8: Procurement Arrangements


A. General 1. Procurement for the proposed Project would be carried out in accordance with the World Bank’s "Guidelines: Procurement Under IBRD Loans and IDA Credits" dated May 2004, revised October 2006; and "Guidelines: Selection and Employment of Consultants by World Bank Borrowers" dated May 2004, revised October 2006, and the provisions stipulated in the Financing Agreement. The various items under different expenditure categories are described in general below. For each contract to be financed by the Credit, 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 would include two design, supply and installation contracts, one for the transmission lines (estimated at USD 27.40 million) and the other for the substations, telecontrol/telecommunications (estimated at USD 11.15 million). Both bid packages will be issued on a single lot basis. The procurement will be done using the Bank’s Standard Bidding Documents (SBD) for ICB works contracts after pre-qualification of suitable contractors. 3. Procurement of non-consulting services: All non-consulting service will be funded by GoE/EEPCo. Such services envisaged under the Project would include transport services and insurances etc. to be carried out under procedures agreed with or satisfactory to the Bank. 4. Selection of Consultants: Supervisory services for the two main works contracts indicated above will be secured on QCBS basis from suitably qualified consultancy firms to be short listed following an invitation for EOI. The consultants to be shortlisted should have substantial experience in the supervision of transmission line and substation work including telemetering, telecommunications, protection and SCADA applications. The cost of this assignment is estimated at US$1,400,000. In addition there will be smaller assignments for the training component as well as for carrying out feasibility studies. Short lists of consultants for services estimated to cost less than US$200,000 equivalent per contract may be composed entirely of national consultants in accordance with the provisions of paragraph 2.7 of the Consultant Guidelines. 5. The Bank’s Standard Request for Proposals (SRFP) would be used for all consulting assignments estimated to cost US$100,000 equivalent or more. For assignments less than US$100,000, national Standard Request for Proposal documents acceptable to the Bank may be used, otherwise, the Bank’s SRFP document should be used. The appropriate selection method for consulting contracts is set out in the Procurement Plan. 6. Operating Costs: All operating costs associated with the Project will be funded by GoE/EEPCo. These items would consist of items such as operation and maintenance costs for equipment, communication charges, transportation costs and travel allowances to regularly carry out field supervision, office supplies, fuel and other consumables. The operation costs financed by the Project would be procured using the implementing agency’s administrative procedures which were reviewed and found acceptable to the Bank.

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7. Others: A number of training courses will be funded under the Credit to facilitate the capacity building of EEPCo staff in power trading, least cost expansion planning, operation and maintenance of power facilities and related topics. The cost of these training programs is expected to be less than USD 2 million in total. B. Assessment of the agency’s capacity to implement procurement 8. The Country Procurement Assessment Report (CPAR) done in 1998 and 2002 has identified procurement capacity as one of the major weaknesses in public sector procurement. The GoE has taken measures to rectify the weaknesses noted in the CPAR and a new procurement law was enacted in January 2005 and is applicable at the federal government level. Standard Bidding Documents have been prepared and issued by the government to be used for all procurements financed by the federal government budget. At this time, four of the nine regional states have adopted the public procurement law. 9. Procurement activities of the Ethiopian section of the Project will be carried out by EEPCo through the Project Management Unit (PMU) for the Project. The PMU will be supported by EEPCo staff with experience in carrying out procurement work of goods, consultants and turnkey Projects. Bid documents and bid evaluation reports of all ICB bids will be carried out by consultants already selected by EEPCo. Major consultant assignments and other procurement of high value contracts will be prepared by the PMU, and will first be reviewed by EEPCo’s purchase committee consisting of three department directors, manager legal services and manager procurement division. Thereafter, the packages will also be reviewed by EEPCo’s management team consisting of the General Manager and five Deputy General Managers. The central procurement division is also generally responsible to oversee procurement procedures, policy, regulatory, standardization, and supervising activities carried out in various branch units of EEPCo. EEPCo has been handling procurement of transmission lines and substations for a number of years on a turnkey basis as well as on procurement of goods and installation by force account. During the last three years, it has handled approximately US$300 million worth of procurement similar to the current Project. 10. An assessment of the capacity of EEPCo (and the PMU) to implement procurement actions for the Project was carried out by the Bank’s task team procurement specialist in July 2006 and February 2007. The assessment reviewed the organizational structure for implementing the Project and the interaction between the Project’s staff responsible for procurement and the organization’s relevant central units for administration and finance. 11. In addition, the following points were noted from an independent procurement review (IPR) of the procurement activities and performance of EEPCo and its four executing bodies, carried out by an International Consultant in October 2005. The review included assessment of the procurement process, records keeping, competence of staff and the organizational setup for handling procurement functions. 12. From the IPR and review of the performance of EEPCo on previous Projects the following key issues and risks concerning procurement for implementation of Projects have been identified: (i) in general, the staff involved in procurement is not primarily concerned with procurement as they have many other functions, and procurement appears to be only done “on the side”; (ii) procurement records and files are not complete and kept in a systematic and organized manner, and (iii) there are delays in the evaluating bids and contract processing. 13. A procurement manual that includes standard service times and record keeping that would guide staff on how decisions are made within EEPCo would be developed and adopted by the Project staff.

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14. Risks to the major procurement items will be mitigated by employing international consultants (already selected) who will be responsible for direct supervision and guidance on the two main contract items from bid preparation to contract award. With respect to the other procurement actions of a much reduced value (mainly the selection of consultants for capacity building and small value goods), risks are mitigated by arranging to augment the unit’s staff for short periods by staff experienced in procurement work. EEPCo has a number of officers with substantial experience in handling procurement work. EEPCo will assign the required staff on a short term basis to facilitate processing the procurement work under the Project without delay. 15. The overall Project risk for procurement is Average. C. Procurement Plan and Implementation Plan 16. The Borrower has developed a Procurement Plan for Project implementation which provides the basis for the procurement methods for goods, works and consultants. This plan was discussed in detail during the credit negotiations and accepted by the Bank after making necessary refinements. It is also being made available in the Project’s database and in the Bank’s external website. The Procurement Plan will be updated in agreement with the Bank annually or as required to reflect the actual Project implementation needs. The plan includes relevant information on works and consulting services under the Project as well as the timing of each milestone in the procurement process and the current version is attached as Attachment I to this Annex. D. Review by IDA 17. All supply and installation and works contracts estimated to cost US$500,000 equivalent or more will be subject to IDA prior review in accordance with the procedures set in Appendix I of the Procurement Guidelines. Any amendments to existing contracts raising their values to levels equivalent or above the prior review thresholds are subject to IDA review. All contracts awarded on the basis of direct contracting will require prior review and clearance of IDA regardless of the contract value. The review by IDA of the individual contracts is detailed in the Procurement Plan in Attachment I. 18. Consultancy contracts with firms with estimated value of US$100,000 or more, and consultancy contracts with individuals estimated value of US$50,000 equivalent or more will be subject to prior review by IDA in accordance with the procedures set in Appendix I of the Consultants Guidelines. All single source selection as well as Terms of Reference (TOR) for all consultancy contracts irrespective of the contract value, will be subject to IDA prior review. All training and workshops will be carried out on the basis of programs, which shall have been approved by the Bank on an annual basis, 19. The above limits are in accordance with the risk rating. 20. Post reviews of contracts awarded below the above threshold levels will be carried out selectively by IDA during supervision missions and/or by an independent procurement auditor. E. Frequency of Procurement Supervision 21. Post review procurement activities will be substantially limited in this Project. Accordingly, in addition to the prior review supervision to be carried out from Bank offices, it is recommended that an annual supervision mission will visit the field to carry out post review of procurement actions.

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F. Contract Award Disclosure Requirements 22. Publication of contract awards in UNDB online and dgMarket would be required for all ICB, NCB, Direct Contracting and the Selection of Consultants for contracts exceeding a value of US$100,000. In addition, where prequalification has taken place, the list of pre-qualified bidders will be published. With regard to ICB, and large-value consulting contracts, the Borrower would be required to assure publication of contract awards as soon as the Bank has issued its “no objection” to the contract award recommendations. With regard to Direct Contracting and NCB, publication of contract awards could be in aggregate form on a quarterly basis. All consultants competing for an assignment involving the submission of separate technical and financial proposals, irrespective of its estimated contract value, should be informed of the result of the technical evaluation (number of points that each firm received), before the opening of the financial proposals. The implementing agency would be required to offer debriefings to unsuccessful bidders and consultants. G. Fraud, Coercion and Corruption: 23. All procuring entities as well as bidders, suppliers and contractors shall observe the highest standard of ethics during the procurement and execution of contracts financed under the project in accordance with Paragraph 1.14 and 1.15 of the Guidelines: Procurement under IBRD Loans and IDA Credits, May 2004 revised in October 2006: and Paragraph 1.22 and 1.23 of the Guidelines: Selection and Employment of Consultants by World Bank Borrowers, May 2004 revised in October 2006. H. Details of the Procurement Arrangements Involving International Competition 24. The project’s detailed activities for the first 18 months of implementation are detailed in the procurement plan that has been discussed and agreed between the Bank and the Government of Ethiopia during negotiations.

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Attachment 1

PROCUREMENT PLAN

General Project Information: Ethiopia/Nile Basin Initiative Power Export Project: Ethiopia-Sudan Interconnector

Project ID No: P074011 Project Implementing Agency (PIA): Ethiopia Electricity Power Corporation (EEPCo) Bank’s Approval Date of the Procurement Plan: October 30, 2007 Date of General Procurement Notice: Issue No. WB346-696 dated January 18, 2007

Period covered by this procurement plan: November 1st, 2007 – April 30th, 2009

GOODS, WORKS AND NON-CONSULTING SERVICES Prior Review Threshold: Procurement Decisions subject to Prior Review by the Bank as stated in Appendix 1 to the Guidelines for Procurement:

Procurement Prior Review Threshold Comments 1. Works/Supply & Installation of Plant &

Equipment >=500,000 All Contracts

2. Non-Consultant Services >=500,000 All Contracts 3. Direct Contracting All Values All Contracts

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Procurement Packages with Methods and Time Schedule

1 2 3 4 5 6 7 8 9 Ref. No.

Contract (Description)

Estimated Cost (USD thousands)

Procurement

Method

P-Q Domestic Preferenc

e (yes/no)

Review by Bank (Prior / Post)

Expected Bid-

Opening Date

Comments

1 Transmission lines (works contact)

27,400 ICB Yes Yes Prior January 15th, 2008

PQ evaluation has been done. Bank comments received and EEPCo resubmitting package for final review

2 Substation & telecontrol (works contract)

12,150 ICB Yes Yes Prior January 15th, 2008

PQ evaluation has been done. Bank comments received and EEPCo resubmitting package for final review

Note: 1. The costs include contingencies

SELECTION OF CONSULTANTS Prior Review Threshold: Selection decisions subject to Prior Review by Bank as stated in Appendix 1 to the Guidelines Selection and Employment of Consultants:

Selection Prior Review Threshold Comments 1. Consultant firms > 100,000 All Contracts 2 Individual Consultants (IC) >=$50,000 All Contracts 3. Single Source (SS)

(Firms/Individuals) All Values All Contracts

4. Training All Values All Contracts Any Other Special Selection Arrangements: None

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Consultancy Assignments with Selection Methods and Time Schedule

1 2 3 4 5 6 7 Ref. No.

Description of Assignment

Estimated Cost (USD)

Selection

Method

Review by Bank (Prior / Post)

Expected Proposals

Submission Date

Comments

1. Supervision consultant

1,400,000 QCBS Prior Received: August 30, 2007

RFP issued and technical evaluation being submitted to Bank

2. Capacity building related studies

100,000 QCBS Prior May 15, 2008 First of several

Note: The capacity building assignments are to follow the needs assessment to be identified by the Supervision consultant in item 1 (a) The costs include contingencies (b) Consultancy services estimated to cost above USD 100,000 per contract for firms, above USD 50,000 per contract for individuals and all single source selection of consultants (firms and individuals) will be subject to prior review by the Bank. (c) Short lists composed entirely of national consultants: Short lists of consultants for services estimated to cost less than USD 200,000 equivalent per contract may be composed entirely of national consultants in accordance with the provisions of paragraph 2.7 of the Consultant Guidelines.

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Annex 9: Economic and Financial Analysis


A. Common Assumptions regarding Economic and Financial Analyses 1. The major anticipated benefit is from the sale of surplus hydropower electricity from Ethiopia to substitute for costlier thermal generation in Sudan.11 Accordingly, this is the major focus of the following economic and financial analyses. A predominantly hydro system, like Ethiopia, would also benefit through the Project from being part of a larger power system, with significant thermal generation, which serves as a hedge for periods of low rainfall. There are various assumptions which are common to both analyses, regarding, notably anticipated trade volume. a. Type of Benefits. The main measurable benefit for Ethiopia (economic) and EEPCo (financial)

will be the revenues from the sale of hydropower to Sudan; this is a function of volumes exported and the sales price. There are also benefits of increased reliability and energy security for the Ethiopian system (which are dependant upon the uncertainties of rainfall patterns) from integrating with the Sudanese grid but these benefits are more difficult to measure.

b. Power Purchase Agreement. As described in Annex 6, the Power Purchase Agreement (PPA)

establishes the terms of trade between the two utilities with respect to price and volumes, and the nature of the commitment and options in this regard.

i. Firm vs. Annual Scheduled vs. Monthly Scheduled: The two countries have negotiated a

ten-year framework for the provision by EEPCo to NEC on an annual basis of up to 200 MW nominal as follows:

(x) 100 MW firm for the term of the contract (provided at a 95 percent load factor) (“firm” energy), (y) up to an additional 75 MW (and potentially as high as 100 MW) as offered by EEPCo on an annual basis (“annually scheduled power”), and (z) monthly scheduled power for the three months of high rains (June, July and August) in the range of 25 MW (“rainy month surplus power”).

ii. Price: Base Case, Ps Case and Pe Case: Currently, EEPCo and NEC are finalizing negotiation of the reference price for the initial three years with discussions varying between US$5 cents/kWh and US$6 cents/kWh for firm power. Annually scheduled power would be set at 50 percent-60 percent of the price of the firm power and rainy month surplus power set at 30 percent-40 percent of the reference price. These figures will be fixed as part of the finalization of the PPA.

(w) For purposes of evaluating the project, a mid-range price has been selected as the Base Case, namely, a reference price of US$5.5 cents/kWh for firm power, US$2.75 cents/kWh for annually scheduled power (i.e., 50 percent of the reference price), and US$1.65 cents/kWh for rainy month surplus power (i.e., 30 percent of the reference price).

11 Similar to transactions between governments and the private sector, the two utilities and Governments of Ethiopia and Sudan are finalizing the negotiation of the commercial arrangements for the trading of power. Reflecting concerns of the utilities, the approximations used in the economic and financial analyses in this section are designed to be distinct of the analyses being used for those negotiations.

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(x) In a high benefit (for Ethiopia) price scenario, the reference price has been set at EEPCo’s proposal of US$6 cents/kWh – referred to as the “Pe Case”. (y) In a high benefit (for Sudan) price scenario, the reference price has been set at NEC’s proposal of US$5 cents/kWh – referred to as the “Ps Case”. (x) In both the Pe and Ps Cases, the prices for annual scheduled and rainy month surplus power have been set for simplicity at 50 percent and 30 percent respectively of the reference price.

iii. Volumes: Base Case: Under the terms of the PPA, EEPCo has committed to provide 100 MW of firm power to NEC, with an availability of 95 percent, which represents 832 GWh per year. In addition, it estimates that on average EEPCo would provide: (a) 75 MW of annually scheduled power at an availability factor of 60 percent, which translates on average to an additional 394 GWh per year, and (b) 25 MW of rainy month surplus power at a load factor of 60 percent, which equates to an additional 33 GWh per year. This projected average represents a total of 1260 GWh per year. A projection of EEPCo’s generation capacity (given notably the scheduled commissioning of the Gilge Gibe II, Tekeze and Tana Beles plants currently under construction, and EEPCo’s plans for the export-oriented Gilge Gibe III plant) compared with projections of domestic demand over the ten-year period of the PPA indicate that EEPCo would have the power available to provide to NEC. For its part, NEC has an incentive to take the power made available by EEPCo given that the weighted average price for NEC (i.e., about US$4.5 cents/kWh) which compares favorably to, for example, thermal generation costs that are nearer to US$6 cents/kWh or higher) and that it can absorb the projected 1259 GWh (or more). Accordingly, the projected availability of 1259 GWh is used for purposes of the Base Case calculations.

iv. Volumes: High and Low Cases: EEPCo has estimated that in a high case, the load

factor for annually scheduled and rainy month surplus power would be 80 percent rather than 60 percent. Accordingly, a high case sensitivity has been set at 1402 GWh, which represents the sum of: 832 GWh of firm power, 526 GWh or annually scheduled power (75 MW times 80 percent load factor), and 44GWh of rainy month surplus power (25 MW times 80 percent load factor). In contrast, assuming poorer hydrological conditions, EEPCo would have the option not to proffer either annually scheduled or rainy month surplus power but would remain committed to provide the firm power. Accordingly, a low volume sensitivity has been set at 832 GWh (although the likelihood of this situation persisting over a ten-year period is small).

These cases are presented in the following table. The proposed volumes will apply for the first ten years from commissioning of the transmission line.

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Table 9.1: Scenarios of Exports from EEPCo to NEC Base Case Low Case High Case Firm power and associated energy: • MW Capacity • Availability for 12 months • Annual energy

100MW

95% 832GWh

100MW

95% 832GWh

100MW

95% 832GWh

Annually pre-scheduled firm energy: • MW Capacity • Availability for 12 months • Annual energy

75MW

60% 394GWh

N/A

75MW

80% 526GWh

Monthly pre-scheduled non-firm energy during wet season (June, July, Aug): • MW Capacity • Availability for 3 months • Annual energy

25MW 60%

33GWh

N/A

25MW 80%

44GWh Total annual energy trading

1,259GWh

832GWh

1,402GWh

c. Net Profit to EEPCo – Weighted Average Revenues/kWh – Weighted Average Cost of Power

Production/kWh. The net profit to EEPCo from the sale of each kWh is the difference between the weighted average revenues and the weighted average cost of production.

i. Weighted Average Revenues/kWh. The weighted average revenues/kWh is a function of the

three forms of power multiplied by the relevant price and the relevant volumes. The weighted average price for the base case reference price of US$5.5 cents for each volume case is provided below:

Table 9.2: Weighted Average Revenues to EEPCo (Cost to NEC)





ii. Weighted Average Cost of Production. The cost of producing the power for EEPCo varies depending on whether or not the power constitutes surplus power. For surplus power, the cost to EEPCo has been estimated at US$0.5 cents, representing maintenance, depreciation of assets, etc. The cost for non-surplus power is estimated at US$4.5 cents, including an estimate of about US$4 cents/kWh for incremental power generation, which is consistent with EEPCo’s experience with its large scale hydropower development. The “annually scheduled” and “rainy month surplus” power represent surplus power as it is anticipated that EEPCo will make available these forms of power only following its determination (annually around October at the end of the rainy season for the former and monthly during the rainy months of June, July and August for the latter) that is has surplus power in its system. The analysis for the firm power is more involved. The commitment to provide firm energy covers the ten-year PPA period. Over this period, there is anticipated to be numerous years in which there will be excess capacity of at least 100 MW given both: (i) EEPCo’s sunken costs in the 3 plants to be commissioned over the next three years and (ii) the lumpiness of generation relative to demand (i.e., generation capacity increases as a step function as new plants are commissioned, such as Gilge Gibe 3 with its projected capacity of 1500 MW, while demand growth is more linear and gradual, as power becomes available and new customers are connected or increase consumption). Accordingly, it has been estimated that EEPCo will have at least 5 years in which there will be surplus capacity of 100 MW. The cost of the 100 MW has as a result been estimated at a weighted average cost of US$2.5 cents/kWh (i.e., 50 percent as surplus at US$0.5 cents and 50 percent as incremental generation and other costs estimated at US$4.5 cents). The weighted average cost of production is set out in the table below:

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Table 9.3: Weighted Average Cost to EEPCo





iii. Transmission Losses: In addition to the cost of kWh production, EEPCo will incur losses in delivering that power to the Sudanese border. For purposes of the evaluation of the Project, a figure of 5 percent has been used as the level of losses, which is consistent with EEPCo’s experience.

d. Benefits to Sudan. The benefits to Sudan could potentially be measured by using the average

retail tariff in Sudan (which is about US$9 cents/kWh) or by calculating the fuel savings from substitution of hydro imports for fuel consumption. For the purposes of the economic analysis, it has been assumed that the benefit of imported energy by Sudan is notionally US$6 cents/kWh (at the wholesale level), which reflects a conservative valuation of the willingness-to-pay (after netting out transmission and distribution costs) and also approximates fuel savings. This also provides for purposes of the financial analysis an estimate of the gross revenues per kWh that NEC would generate from the sale of electricity.

e. Investment Costs for EEPCo and NEC. The investment cost for the interconnector for EEPCo is

US$38.5M which is the sum of (i) transmission line, (iii) substation expansion, (iii) telecommunications, (iv) supervision consultant, and (v) EMP and RAP implementation. For NEC the total cost is US$25.5M and it includes (i) transmission line, (iii) substation expansion, (iii) telecommunications and (iv) implementation of environmental and social implementation plans.

B. Project Economic Analysis 2. The economic evaluation of the transmission line will address the following questions: (i) does the Project generate an adequate economic internal rate of return for Ethiopia; (ii) does the proposed Project, as designed, provide an adequate return and represent the least-cost means to connect the two countries, and (ii) does the Project generate an adequate economic internal rate of return for Sudan (which is central to the sustainability of the trade)? B1. ERR for Ethiopia 3. The economic benefits for Ethiopia are principally the revenues from the export of electricity to Sudan, net of the cost of providing and transporting the power to Sudan. The NPV and EIRR for Ethiopia are very robust in the Base case (namely reference sales price of US$5.5 cents/kWh and annual sales volumes of 1,259 GWh). The figures are respectively US$123.2 million and 65 percent. Sensitivity Analysis 4. A sensitivity analysis was carried out for Ethiopia based on the different price assumptions (Pe, Ps). The results are provided in the table below.

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Table 9.4: Price Variations (Base Case Volumes: 1259 GWh) Prices Ethiopia Base Case EIRR (%) 64.6% (US$ 5.5 cents/kWh reference price) NPV (US$ MM) $123.2 Pe Case EIRR (%) 72.9% (US$ 6 cents/kWh reference price) NPV (US$ MM) $147.2 Ps Case EIRR (%) 55.8% (US$ 5 cents/kWh reference price) NPV (US$ MM) $99.3

5. A sensitivity analysis was also carried out for Ethiopia based on the different volume assumptions. The results are provided in the table below.

Table 9.5: Volume Variations (Base Case Price: US$5.5 cents/kWh) Volumes Ethiopia Base Case (1259 GWh) EIRR (%) 64.6% (US$ 5.5 cents/kWh reference price) NPV (US$ MM) $123.2 High Case (1402 GWh) EIRR (%) 69.5% NPV (US$ MM) $137.5 Low Case (832 GWh) EIRR (%) 48.6% NPV (US$ MM) $80.6

6. A sensitivity was also conducted assuming: (i) that the cost of firm power averages US$4.5 cents/kWh rather than US$2.5 cents; (ii) that the capital costs of the investment increase by 10 percent; or (iii) if the commissioning date is delayed by one year. The results are presented in the table below.

Table 9.6: Variations on the Base Case (Volumes 1259 GWh and Price of US$5.5 cents/kWh) Volumes Ethiopia Base Case (1259 GWh) EIRR (%) 64.6% (US$ 5.5 cents/kWh reference price) NPV (US$ MM) $123.2 Cost of Firm Power US$ 4.5 cents/kWh EIRR (%) 34.4% NPV (US$ MM) $46.4 Capital Cost increase of 10% EIRR (%) 59.4% NPV (US$ MM) $119.9 Project Commissioning Delayed 1 year EIRR (%) 45.7% NPV (US$ MM) $100.1

7. As the foregoing analyses indicates, the returns to Ethiopia are robust and remain significant even under a variety of different scenarios. The factors which appear to have the largest impact are significant delays in commissioning of the interconnection and if EEPCo’s anticipated excess capacity does not materialize (i.e., the average price for firm power is at US$ 4.5 cents). This latter point also reflects the fact that part of the benefits of the project for Ethiopia derive from the ability the project provides to the country to monetize the incremental generation, which EEPCo is expected to commission over the next

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several years, thereby providing greater returns on what constitute largely sunken costs from an economic perspective. B1A. Ethiopian Hydrological Risks 8. Hydro systems are subject to the volatility and to some extent unpredictability of rainfall. Despite the catchment areas for the major hydro plants in Ethiopia not being as vulnerable to drought spells as other regions in the country, volatility in hydro production cannot be ignored, particularly in light of: (i) the fact that the size of the reservoirs being relatively modest; and (ii) the impact of climate change in the horn of Africa. Therefore, this risk element has to be taken into account. It is known that firm energy is a notional, stochastic concept, based on a probability of the system being able to deliver energy during 95 percent of the time. It means that in 5 out of 100 years, the firm energy will not be available to be traded. The simulation also assumed that EEPCo in its capacity as system operator would dispatch the system in a conservative way by not allowing the reservoirs to over-deplete, and running a higher risk of spillover during the rainy season. In order to capture the element of volatility, a very simple probabilistic model (similar to a Monte Carlo simulation) was developed. Intra- and inter-year volatility was taken into account, based on historic rainfall series (evaporation not taken into account). Results from this simulation indicate: (a) the projected amount of energy to be traded in the Base Case under the PPA (i.e. 1,259 GWh) is reasonable, and (b) there is some risk of unavailability of power for trade in dry years (which is relevant to Ethiopia only to the extent there is a corresponding penalty). B2. ERR for Sudan 9. As described above, the economic benefits for Sudan are primarily a function of two factors: (a) imported volumes, and (b) the benefits to Sudan of additional power consumption. The NPV and EIRR for Sudan are very robust in the Base case (namely annual sales volumes of 1,259 GWh and a reference sales price of US$5.5 cents/kWh, which yields a weighted average price of US$ 4.5 cents/kWh for those volumes). The figures are respectively US$64.9 million and 60.7 percent. Sensitivity Analysis 9. A sensitivity analysis was carried out for Sudan (as for Ethiopia) based on the different price assumptions (Pe, Ps) and volume assumptions. The results are provided in the tables below.

Table 9.7: Price Variations (Base Case Volumes: 1259 GWh) Prices Sudan Base Case EIRR (%) 60.7% (US$5.5 cents/kWh reference price) NPV (US$ MM) $64.9 Pe Case EIRR (%) 44.8% (US$6 cents/kWh reference price) NPV (US$ MM) $40.9 Ps Case EIRR (%) 75.2% (US$5 cents/kWh reference price) NPV (US$ MM) $88.9

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Table 9.8: Volume Variations (Base Case Price: US$5.5 cents/kWh) Volumes Sudan Base Case (1259 GWh) EIRR (%) 60.7% (US$5.5 cents/kWh reference price) NPV (US$ MM) $64.9 High Case (1402 GWh) EIRR (%) 74.0% NPV (US$ MM) $86.8 Low Case (832 GWh) EIRR (%) 9.0% NPV (US$ MM) (0.9)

10. The returns to Sudan are, as with Ethiopia, robust in the Base Case and the sensitivities, except for the low volume case. The following table indicates the returns to Sudan under alternative benefit streams (willingness to pay). Again, the returns are positive in all cases, except for the low volume case.

Table 9.9: Scenarios for NEC Cost Savings

Volumes (Ref Sales Price = US$5.5 cents/kWh) Sudan

Cost Savings US$6.0

cents/kWh Base Case

Cost Savings US$5.5 cents/kWh

Cost Savings US$6.5 cents/kWh

Base Case (1259 GWh) EIRR (%) 60.7% 41.2% 78.1% (US$5.5 cents/kWh reference price) NPV (US$ MM) $64.9 $35.8 $94.0 High Case (1402 GWh) EIRR (%) 74.0% 54.0% 92.0% NPV (US$ MM) $86.8 $54.4 $119.2 Low Case (832 GWh) EIRR (%) 9.0% N/A 27.6% NPV (US$ MM) $(0.9) $(20.1) $18.4

B3 Combined Ethiopia-Sudan Level Analysis. 11. An analysis was also carried out for the project combining both the benefits from Ethiopia and Sudan (which can be approximated to an analysis of the project’s benefits to the region), namely the costs are the total investment costs and the cost of producing the power, and the benefits are the benefits to Sudan of consuming additional power. The results, as well as sensitivities for the different levels of energy trade, are set out in the table below:

Table 9.10: Combined analysis

Volumes per year Combined Base Case EIRR (%) 63.2% NPV (US$ MM) $188.1 High Case EIRR (%) 71.2% NPV (US$ MM) $224.3 Low Case EIRR (%) 36.2% NPV (US$ MM) $79.7

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12. As could be anticipated, the overall returns increase as the volumes traded increase. In essence, the combined returns of the interconnector will be sensitive to the volumes, but not to the sales price, which simply serves as a mechanism to allocate benefits as between the two countries. B4. Alternatives Assessment 13. Alternative project structures were considered, notably higher capacity for the line with corresponding higher investment costs. This alternative was rejected as the anticipated trade volumes did not support the incremental investment costs. The combined Ethiopia/Sudan benefits demonstrate that the interconnector is highly preferable to the no-project alternative. Another alternative is the installation of new generation capacity in Sudan but these plants have been anticipated to be more costly on an all-in cost basis than the weighted average cost of supply provided under the Project (namely US$4.5 cents/kWh). B5. Other Benefits

14. The Project benefits accrue to the two countries from the benefits of energy trade. The principal anticipated benefit is from the transfer of lower cost hydro power from Ethiopia to Sudan, which should reduce costs and also CO2 emissions. However, in the eventuality of a shortage in Ethiopia and of excess capacity in Sudan, NEC could export power to EEPCo to help EEPCo meet its domestic energy demand. As the operation of the joint power systems evolve, and Ethiopia adopts a concept equivalent to the “opportunity cost of water” to make dispatch decisions, there may be situations, even before a shortage materializes, in which Ethiopia decides to import thermal generation from Sudan to keep its reservoirs at prudent levels. In addition, there would be other supplemental benefits in operating the two systems in an integrated fashion such as reduced reserve margins, more flexible planned plant outages, more efficient response to unplanned outages, additional flexibility in new plant construction delays etc. The Project also offers environmental benefits related to reduced greenhouse gas emissions through the substitution of kWh generated by thermal fuel with kWh produced from hydropower. C. Project Financial Analysis Methodology 15. The financial analysis evaluates the commercial viability of the Project from the viewpoint of each Project entity, namely EEPCo and NEC. The financial evaluation for each entity is considered on the basis of the various cost and benefit streams as set out in the table below.

Table 9.11: Financial Cost and Benefit Streams EEPCo NEC Investment costs � � Operating costs: Variable energy supply costs of EEPCo Fixed costs of the transmission line

� �

�

Benefits: Export revenues of EEPCo Avoided thermal costs of NEC

�

�

16. The financial viability of the Project for each entity is evaluated in terms of the financial internal rate of return (FIRR). The Project is considered financially viable if the minimum tests of 10% FIRR and a positive NPV of net benefits are met. Although the operating life of the interconnection is thirty five (35) years, the financial analysis covers the construction period plus ten years’ operating life from commissioning, thereby matching the period of the PPA. Construction is expected to commence in 2008 and the line is forecast to be commissioned on January 1, 2010 for purposes of this analysis (although an

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earlier commissioning in late 2008 is being targeted, which would increase the returns by bringing forward the benefits). The financial analysis thus covers the period from 2008 to 2019. Generation expansion plans and demand forecasts beyond 2019 are considered to be very speculative and have not been considered in this analysis. Financial Analysis Results 17. Detailed financial analysis workings and results are provided in Attachments 1 and 2. EEPCo 18. The analysis indicates that the Project is financially viable in all cases for EEPCo. Under the base case, EEPCo would achieve FIRR of 64.6 percent and NPV of net benefits of US$123.2 million. The following table summarizes the results of the financial analysis of the project for EEPCo.

Table 9.12: Summary Results of Project Financial Analysis for EEPCo Base Case Low Case High case


FIRR 64.6% 48.6% 69.5%NPV of Net Benefits Stream (US$ mln) 123.2 80.6 137.5

NEC 19. The Project is financially viable for NEC in all cases except under the low volume case. Under the Base Case, NEC would achieve a FIRR of 60.7 percent and a NPV (@ 10 percent) of US$64.9 million. The following table summarizes the results of the financial analysis of the project for NEC.

Table 9.13: Summary Results of Project Financial Analysis for NEC Base Case Low Case High case


FIRR 60.7% 9.0% 74.0%NPV 64.9 -0.9 86.8 Revenues/Benefits, Operating Costs and Margins 20. The following table shows the revenues/benefits, operating costs and operating margins per kWh of energy exported by EEPCo under the three alternative trading volume scenarios and with three alternative EEPCo tariffs.

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Table 9.14: Revenues/Benefits, Costs and Margins in USc/kWh All figures in constant USc/kWh

Firm powerFirm energy

Non-firm energy

AnnualenergyGWh EEPCo NEC EEPCo NEC EEPCo NEC

Base Case (Moderate Energy Volumes) 1,259Revenues/Benefits 4.54 6.00 4.13 6.00 4.95 6.00Operating costs 1.85 4.56 1.85 4.14 1.85 4.97Operating margin 2.69 1.44 2.28 1.86 3.10 1.03

Low Case (Low Energy Volumes) 832Revenues/Benefits 5.50 6.00 5.00 6.00 6.00 6.00Operating costs 2.54 5.53 2.54 5.03 2.54 6.03Operating margin 2.96 0.47 2.46 0.97 3.46 -0.03

High Case (High Energy Volumes) 1,402Revenues/Benefits 4.35 6.00 3.95 6.00 4.74 6.00Operating costs 1.71 4.36 1.71 3.97 1.71 4.76Operating margin 2.64 1.64 2.24 2.03 3.03 1.24

5.00 6.002.751.65

2.501.50

3.001.80

EEPCo's export tariffs (USc/kWh)5.50

21. EEPCo’s operating margins are healthy in all cases (see discussion above on determination of EEPCo costs). NEC’s operating margin is also positive except that it would be marginally negative under the low volume case with EEPCo’s reference price for firm power is set at 6.0USc/kWh. Sensitivity Analysis 22. The robustness of the Project is tested for sensitivities to various key assumptions considered in the Base Case. Results of the various sensitivities for both EEPCo and NEC are indicated in the following table.

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Table 9.15: Sensitivity Results

EEPCo NECSensitivity

EEPCo tariff increase from 5.5 to 6USc/kWh + 9.1%FIRR 72.9% 44.8%NPV 147.2 40.9

EEPCo tariff decrease from 5.5 to 5USc/kWh -- 9.1%FIRR 55.8% 75.2%NPV 99.3 88.9

EEPCo energy cost for 100MW firm power increase from 2.5 to 4.5USc/kWh + 80.0%

FIRR 34.4% 60.7%NPV 46.4 64.9

EEPCo energy cost for annual & monthly scheduled power increase + 10.0%

FIRR 64.2% 60.7%NPV 122.3 64.9

NEC's cost savings decrease - 7.7%FIRR 64.6% 41.2%NPV 123.2 35.8

Trx line operating costs increase + 10.0%FIRR 64.5% 60.7%NPV 123.1 64.8

Capital cost increase + 10.0%FIRR 59.4% 55.9%NPV 119.9 63.0

Project commissioning delay 1 yearFIRR 45.7% 43.3%NPV 100.1 52.5

Combined effect of all negativesFIRR 14.9% 14.5%NPV 9.9 5.3

Most sensitive parameterEEPCO firm power cost

NEC cost saving

Moderate Energy Volumes (1259GWh/y)

Note: Combined effect considers all the negative sensitivities. Thus, in the case of EEPCo, tariff decrease is taken, and in the case of NEC, tariff increase is taken.

Base Case

EEPCo 24. In all sensitivity cases, the minimum threshold return criteria would be met for EEPCo. The biggest financial impact on EEPCo would be if its underlying variable bulk energy supply costs were 4.5USc/kWh (for example, if none of the power being provided were surplus power). Although this particular cost estimate is considered to be unrealistically high, it has been used to stress test the Project’s returns. Delays in project implementation will have the second biggest financial impact for EEPCo. The combined effects all the negative variables will still provide positive returns for EEPCo. NEC 25. In all sensitivity cases, the minimum set criteria would be met for NEC. A 10 percent decreases in assumed benefits accruing to NEC will have the biggest financial impact for NEC. Delays in project

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implementation and commissioning will have the second biggest financial impact for NEC. As in the case of EEPCo, the combined effects all the negative variables will still provide positive returns for NEC. Key Assumptions 26. The key assumptions made for the financial analysis of the project are given in the various tables given below. These were also used as appropriate for the economic analysis.

Table 9.16:Key Assumptions for Project Financial Analysis

Ethiopia SudanEEPCo NEC Source

Transmission loss 5.00% 5.00% Feasibility Study Update, Feb 2006Electricity export tariff of EEPCo, US$/kWh:

Firm power & associated energy 0.0550 WBAnnually pre-scheduled firm energy 0.0275 WBMonthly pre-scheduled non-firm energy in wet season (June, July, Aug) 0.0165 WB

Variable energy supply costs of EEPCo, US$/kWh:Firm power & associated energy 0.0250 WBAnnually pre-scheduled firm energy 0.0050 WBMonthly pre-scheduled non-firm energy in wet season (June, July, Aug) 0.0050 WB

Cost savings for NEC, US$/kWh 0.0600 WBO&M cost for TL - Fixed, US$ millions/annum 0.3452 0.2148 Feasibility Study Update, Feb 2006O&M cost for TL - Variable, US$/kWh 0.000 0.000 Feasibility Study Update, Feb 2006Annual domestic inflation 5.0% 5.0% WBCurrency conversion rate, Euro/$ 0.71 0.71 WBDiscount rate 10.0% 10.0% WBCorporate income tax 0.0% 0.0% WBBase year of cost (beginning of fiscal year) 2007 2005 WB for Ethiopia/Feasibility Study Update, Feb 2006 for SudanConstruction start year (beginning of fiscal year), planned 2008 2008 WBConstruction duration, years 2.0 2.0 WBCommissioning year 2010 2010 WBOperating life, Years 35 35 WBReturn on equity 0% 0% WB

Disbursement profile for construction costs: Ethiopia SudanF.C. L.C. F.C. L.C.

Yr 1 40% 40% 40% 40% WBYr 2 50% 50% 50% 50% WBYr 3 10% 10% 10% 10% WBSalvage 0% 0% 0% 0% WB

Financing plan:Debt 100% 72% 100% 86% WBGovt. equity cont 0% 28% 0% 14% WB

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D. Financial Review of Project Implementing Entities Financial Review of EEPCo 27. EEPCo’s performance review is based on the utility’s audited financial statements for EFY1998 (GFY2005/0612), unaudited draft financial statements for EFY1999 (GFY2006/07), and budgets for the current year EFY2000 (GFY2007/08). 28. EEPCo’s operational performance is satisfactory. Electricity sales in EFY1998 (GFY2005/06) rose by 14.2 percent (12.1 percent in the previous year) to 2,363GWh. Growth in the current year EFY1999 (GFY2006/07) is forecast at 7.2 percent. Total system losses, including auxiliary losses, are estimated at between 19 percent and 20 percent. EEPCo connected 174,000 new customers to the grid in EFY1998 (176,000 in the previous year), compared with planned 250,000. Total number of customers as of July 7, 2006 reached 1.055 million. EEPCo plans to connect 300,000 new customers in the current fiscal year. Numbers of customers per employee increased from 83 to 90 in the last year. The overall billing collection rate at present is estimated at around 96 percent. 29. EEPCo’s financial situation remains weak in view of its heavy investment program. Effective July 8, 2006, electricity tariffs were increased by 22 percent across the board, except for the life-line tariff (consumption up to 50kWh/month) which remained unchanged. The new weighted average tariff is estimated at 0.534Birr/kWh (0.06US$/kWh). 30. Electricity revenue in FY05/06 increased by 25.1 percent to Birr1,163 million (US$131 million), and it is forecast to increase in the current fiscal year by 14.8 percent to Birr1,335 million (US$150 million). Operating profit after depreciation in FY05/06 increased by 58 percent to Birr435 million (US$49.2 million); however, the result for the current fiscal year is forecast to show a decline of 28 percent to Birr 313 million (US$35.2 million). Operating profit per kWh sales to end-use customers increased from 0.133Birr/kWh (0.015US$/kWh) to 0.188Birr/kWh (0.021US$/kWh) in FY05/06, and is forecast to drop to 0.125Birr/kWh (0.014US$/kWh) in the current fiscal year. 31. The Government approved a debt restructuring plan in 2006 and 2007. This involves a conversion into equity of Birr 1.826 billion (US$205 million), rescheduling of arrears of Birr291 million (US$33 million) to be repaid over ten years starting May 2006, and extension of grace period by five years to 2011 for various loans involving US$317 million (interest accruing during the extended grace period will be added to principal and repaid with principal). Following the debt restructuring, EEPCo’s balance sheet has been strengthened. The current ratio is expected to improve from 0.8 in FY04/05 to an estimated 3.8 in FY05/06. However, liquidity remains tight with “free” cash balances of about Birr200 million (US$22 million), equivalent to 54 days’ of present annual revenues. In view of the company’s large investment needs, the cash balance is not particularly healthy. The debt/equity ratio as at July 7, 2006 was 38 percent. 32. EEPCo generated net cash inflows from operating activities of Birr336 million (US$38 million) and Birr613 million (US$69 million) in FY04/05 and FY05/06 respectively. Forecast for the year fiscal year indicates that the utility will generate operating net cash inflows of Birr832 million (US$94 million). Debt service payments amounted to Birr216 million (US$24 million) in FY04/05 and Birr152 million (US$17 million) in FY05/06, and are projected to increase to Birr312 million (US$35 million) in FY06/07. 33. EEPCo’s investment program is very ambitious. In FY05/06, total capital expenditure amounted to US$490 million (US$245 million in FY04/05). For the current FY06/07, the company’s budget indicates capital expenditure of US$1,755 million. This plan is not realistic as all of the required financing is not secured and EEPCo does not have the resources to fund more than US$60 to US$75 million from internal

12 Year ending July 7, 2005

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cash generation. EEPCo’s capital investment program for the next nine years to 2015 is estimated at US$6.4 billion. Major projects include (a) the addition of new hydro capacity of 1,330MW to 2010 and a further 2,185MW to 2015, (b) 100MW of coal fired plant, (c) various transmission lines and substations connecting new plants to the grid, (d) inter-connection with Djibouti and Sudan, (e) distribution network rehabilitation and expansion, (f) universal electrification access program, and (g) annual connection of 350,000 new customers. EEPCo’s load growth targets envisage the doubling of national electricity consumption every five years. 34. EEPCo has recently entered into contractual commitments for the construction of 1,800MW Gilgel Gibe III hydro plant, at an estimated cost of US$1.7 billion, to be disbursed over six years. EEPCo expects to disburse approximately US$135 million in the current fiscal year; US$48 million has already been paid as advance for local currency costs, and $74 million is under processing for advance payment of foreign currency costs. Funding for foreign currency costs is expected to be raised through issue of Commercial Bank of Ethiopia (CBE) bonds. EEPCo has secured CBE bonds of Birr2.8 billion (US$315 million) to date, and expects to raise a further Birr2 billion in the current fiscal year and Birr1 billion in FY07/08. The Government contributed Birr 1.2 billion (US$132 million) in FY05/06 towards the Universal Electricity Access Project. A similar contribution is anticipated in FY06/07. 35. Under the recently revised financial covenant of IDA’s Energy Access credit, EEPCo is to ensure that it shall not incur any new investment or debt unless the company generates sufficient revenues to meet its operational expenses, working capital needs, debt service requirements, and investments that are to be funded from own revenues. This covenant was met in the last two years. However, the company will not be in a position to implement its capital investment plan, and consequently, a sizeable proportion of planned investments will have to be deferred or slipped into future years. The issue of future tariff increases, however, remains central to EEPCo’s long-term financial standing. The Bank is working closely with GoE and EEPCo to rationalize the power sector investment program, and to assist in the funding of new projects. 36. EEPCo’s key performance indicators for the past three fiscal years and forecasts for the current fiscal year are provided in Table 9.17 below. Project Impact for EEPCo 37. The project is expected to have a positive impact on EEPCo’s financial position, as reflected in the analysis of the Project IRR presented above. Notwithstanding the financial strain presented by GoE/EEPCo’s ambitious capital investment program, EEPCo continues to generate sufficient revenues to meet its ongoing maintenance and other obligations, and to generate further additional cash inflows. The financial analysis developed for the Project confirms that it will add value to EEPCo, especially since it will be able to export its surplus hydro production to displace the much more expensive thermal power of Sudan.

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Table 9.17: EEPCo: Key Performance Indicators

Fiscal year ending July 7 GFY >>> 2004 2005 2006 2007Fiscal year ending Sene 30 EFY >>> 1996 1997 1998 1999

Audited Audited Unaudited Forecast

Operational indicatorsElectricity sent out (GWh) 2,281 2,548 2,834 3,045Network losses (auxiliary, T&D) 20.3% 20.1% 19.6% 19.1%Electricty sales (GWh) 1,846 2,069 2,315 2,503Growth in electricity sales (%) 10.4% 12.1% 11.9% 8.1%Av. no. of customers (000's) 737 840 979 1,205Av. no. of employees 9,716 10,149 10,819 10,705No. of customers per employee 76 83 90 113Electricty sales (MWh) per employee 190 204 214 234

Average revenue, expenses & profitAv. electricty revenue (Birr/kWh) 0.455 0.449 0.449 0.534Av. electricty revenue (US$/kWh) 0.052 0.051 0.051 0.060Av. operating expenses (Birr/kWh) 0.373 0.382 0.402 0.525Av. operating expenses (US$/kWh) 0.043 0.043 0.045 0.059Av. operating profit/(loss) (Birr/kWh) 0.131 0.133 0.188 0.125Av. operating profit/(loss) (US$/kWh) 0.015 0.015 0.021 0.014

ProfitabilityOperating margin (%) 26.0% 25.9% 31.8% 19.2%Return on equity (%) 1.5% 2.5% 3.8% 0.8%Billing & collection performanceAv. collection period (days) 26 26 30 30Av. billing collection rate (%) 98% 97% 98% 98%Cash generationSelf-financing ratio 20% 2% 8% 7%Debt service cover 1.7 1.6 3.5 2.6LiquidityCurrent ratio 1.5 0.8 3.8 0.5GearingDebt/equity ratio (%) 35% 37% 38% 55%

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Financial Review of NEC 38. The financial review of NEC is based on the utility’s published annual report for the year ended December 31, 2004. The annual report does not contain an auditor’s report on NEC’s financial statements. 39. Electricity sales, including isolated, in 2003 and 2004 rose by 10.5 percent and 7.6 percent to 2,320GWh and 2,496 GWh respectively. Peak demand on the national grid reached 534MW and 611MW in 2003 and 2004 respectively. Thermal generation accounted for 70 percent of total energy production. Network losses, including auxiliary consumption, amounted to 34.8 percent in 2003 and 33.4 percent in 2004. Customer numbers increased by 15,474 in 2004 and reached a total of 751,892 at end 2004. 40. The weighted average retail electricity tariff13 in 2004 increased by about 16 percent to 23.4SD/kWh (0.092US$/kWh). Electricity revenue in 2004 went up by 24 percent to reach SD59 billion (US$229 million). In addition, NEC received a fuel subsidy from the Government of SD15 billion (US$58 million) in 2004 and SD17 billion (US$65 million) in 2003. Cash operating expenses, excluding depreciation and provisions for bad and doubtful debts, amounted to SD68 billion (US$264 million) in 2004 and SD63 billion (US$241 million) in 2003. Fuel costs accounted for 51 percent and 66 percent of total cash operating expenses in 2004 and 2003 respectively. NEC incurred net losses of SD3.27 billion (US$12.7 million) in 2004 and SD3.12 billion (US$12 million) in 2003. In terms of unit of electricity sold, net losses amounted to 0.72SD/kWh (0.003 US$/kWh) and 0.572SD/kWh (0.002US$/kWh) in the last two years. 41. At the operating level (after fuel subsidy), there was a net cash outflow of SD9.5 billion14 (US$37 million) in 2004. Debt service payments during the year accounted for SD7.3 billion (US$28 million). Capital expenditure in 2004 amounted to SD25.8 billion (US$100 million), of which SD7.3 billion (US$28.4 million) was financed through equity. External borrowing in 2004 amounted to SD35.6 billion (US$138 million). There was a net increase in cash balances of SD0.7 billion (US$2.9 million) in 2004. 42. NEC’s cash balances as at December 31, 2004 amounted to SD2.9 billion (US$11.2 million), representing under 18 days’ of annual electricity revenues. Current ratio was healthy at 4.3 times as at end 2004. Long-term loans as at December 31, 2004 amounted to SD52 billion (US$207 million) and the debt/equity ratio was low at 14 percent. 43. NEC’s key performance indicators for 2003 and 2004 are provided in Table 9.18 below. Project Impact for NEC 44. The project is expected to have a positive impact on NEC’s financial position, as reflected in the analysis of the Project IRR presented above. The financial analysis developed for the Project confirms that it will add value to NEC, especially since it will be able to displace the more expensive thermal power with the cheaper hydro imports from EEPCo.

13 The weighted average retail tariff quoted throughout this report is exclusive of taxes which may be added to customer bills. The term “retail” tariff refers to end-use customer tariffs. 14 There is a net debtor (“current account with areas”) balance of SD42.3 billion (US$168 million) appearing in NEC’s balance sheet as at December 31, 2004. The net movement on this account in 2004 amounts to SD12.7 billion (US$50 million). If this increase in net current assets is excluded, there would be a positive cash inflow at the operating level of SD3.2 billion (US$12 million) in 2004. This debtor balance may represent unreconciled balances between NEC’s operational areas.

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Table 9.18: NEC: Key Performance Indicators

Year ending December 31 2003 2004Actual Actual

Operational indicatorsPeak demand (MW) 534 611Electricity generation (GWh) 3,560 3,749

of which: thermal 67% 70%Network losses (auxiliary, T&D) 34.8% 33.4%Electricty sales (GWh) 2,320 2,496Growth in electricity sales (%) 10.5% 7.6%

Av. no. of customers (000's) 723 744Av. no. of employees 7,321 7,117No. of customers per employee 99 105Electricty sales (MWh) per employee 317 351

Average revenue, expenses & profitAv. electricty revenue:

SD/kWh 20.5 23.7US$/kWh 0.079 0.092

Av operating expenses (KD/kWh sold):Fuel 16.6 14.9Depreciation 2.7 3.3All other 10.6 12.6Total 29.859 30.8

Av. operating expenses (US$/kWh sold):Fuel 0.064 0.058Depreciation 0.010 0.013All other 0.041 0.049Total 0.114 0.119

Av. operating profit/(loss):KD/kWh sold (0.720) (0.572)US$/kWh sold (0.003) (0.002)

Av. Cost of fuel (US$/kWh thermal generation) 0.061 0.055

ProfitabilityOperating margin (%) -2.5% -1.9%Return on equity (%) -0.9% -0.9%Billing & collection performanceAv. collection period (days) 152 115Av. billing collection rate (%) 101%Cash generationSelf-financing ratio -63%Debt service cover 0.93LiquidityCurrent ratio 5.2 4.3GearingDebt/equity ratio (%) 6% 14%

Inflation (Sudan) 7.7% 8.4%Average exchange rate during year (SD/US$) 260.8 258.3

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Attachment 1 to Annex 9 Financial Analysis, EEPCo (Ethiopia)

Financial Analysis - Ethiopia

Base Case (Moderate Energy Volumes)Net

Year Electricity Investments Variable Total Export Cost Total benefits Cash flow Total Totaltransmitted energy supply Fixed Variable operating revenue to saving costs benefits

(GWh) costs of EEPCo costs EEPCo for NEC2007 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02008 0 17.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -17.1 15.5 0.02009 0 21.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -21.4 17.7 0.02010 1,259 4.3 22.9 0.3 0.0 23.3 57.2 0.0 57.2 29.6 20.7 42.92011 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 15.9 39.02012 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 14.5 35.52013 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 13.1 32.32014 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 11.9 29.32015 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 10.9 26.72016 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 9.9 24.22017 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 9.0 22.02018 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 8.2 20.02019 1,259 0.0 22.9 0.3 0.0 23.3 57.2 0.0 57.2 33.9 7.4 18.2

12,593 42.7 229.4 3.5 0.0 232.9 571.5 0.0 571.5 295.9 154.7 290.2Ratios

Financial IRR 64.6%Net Present Value of Net Benefits Stream 123.2Benefit/Cost Ratio 1.88

Low Case (Low Energy Volumes)Net


(GWh) costs of EEPCo costs EEPCo for NEC2007 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02008 0 17.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -17.1 15.5 0.02009 0 21.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -21.4 17.7 0.02010 832 4.3 20.8 0.3 0.0 21.2 45.8 0.0 45.8 20.3 19.1 34.42011 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 14.4 31.32012 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 13.1 28.42013 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 11.9 25.82014 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 10.9 23.52015 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 9.9 21.42016 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 9.0 19.42017 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 8.2 17.62018 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 7.4 16.02019 832 0.0 20.8 0.3 0.0 21.2 45.8 0.0 45.8 24.6 6.7 14.6

8,322 42.7 208.1 3.5 0.0 211.5 457.7 0.0 457.7 203.5 143.8 232.4Ratios


High Case (High Energy Volumes)Net


(GWh) costs of EEPCo costs EEPCo for NEC2007 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02008 0 17.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -17.1 15.5 0.02009 0 21.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -21.4 17.7 0.02010 1,402 4.3 23.7 0.3 0.0 24.0 60.9 0.0 60.9 32.7 21.2 45.82011 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 16.4 41.62012 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 14.9 37.82013 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 13.5 34.42014 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 12.3 31.32015 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 11.2 28.42016 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 10.2 25.82017 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 9.3 23.52018 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 8.4 21.42019 1,402 0.0 23.7 0.3 0.0 24.0 60.9 0.0 60.9 37.0 7.6 19.4

14,016 42.7 236.5 3.5 0.0 240.0 609.5 0.0 609.5 326.8 158.3 309.5Ratios


O&M costs for TLOperating Cost Streams Benefit Streams Discounted Values



90

Annex 10: Safeguard Policy Issues

ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORT PROJECT:

ETHIOPIA-SUDAN TRANSMISSION INTERCONNECTOR 1. The Project triggers two safeguards policies – OP4.01 (Environmental Assessment) and OP4.12 (involuntary Resettlement). An Environmental Management Plan, a Resettlement Action Plan for Ethiopia and a Resettlement Action Plan for Sudan were prepared by the two countries, with the support of ENTRO, approved by ASPEN on December 21st, 2006. These reports were disclosed in the two countries and in the Infoshop in January 2007. 2. These three operational documents have laid down the principles and mechanisms for the management of adverse environmental and social impacts, including mitigation measures, operational responsibilities and budget. Environmental Assessment (OP4.01) 3. The Project has been categorized as “B” under OP4.01 since it is a transmission line through already developed areas of Ethiopia and Sudan with little to no environmental sensitivity. In many places in Ethiopia the line will parallel an existing line or involves the stringing of a second line on existing towers. 4. An Environmental and Social Impact Assessment (ESIA) containing an Environmental Management Plan (EMP) was prepared by the two countries, with the support of ENTRO. The ESIA describes the environmental management structure of EEPCo and NEC, the qualifications, functions and needs of the project teams in the two countries; general health, safety, pollution prevention, and waste disposal procedures; and a training program for project management and contractor personnel. The EMP specifies mitigation measures for various potential adverse impacts in the pre-construction, construction and operation phases of the project. Funds for implementing the EMP are included in the project cost estimates. 5. The Project raises no 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 during final route alignment, construction and operation. Analysis of Alternatives 6. Three alternative routes were investigated. These routes pass through the Amhara, Oromiya and Benishangul-Gumuz regions of Ethiopia and the Al Qadarif and An-Nil-al-Azraq states of Sudan. The recommended route – Option C – is approximately 446 km in length, starting from Bahir Dar in Ethiopia and connecting to El Gedaref substation in Sudan via the border towns of Metema and Gallabat. This route has been considered as the most cost effective option by the Updated Feasibility Study. The ESIA compared the potential environmental and social impacts associated with the three proposed routes and the following table summarizes the findings.

91

92

7. The preferred route – Option C – is much more accessible and has been under much more human development compared to the other options. The ecological mitigation measures are also more manageable in route C, where the biophysical impacts are expected to be minimal and short-term. Option C does not pass through any conservation reserves or protected forest areas. 8. Monitoring Plan. The Monitoring Plan for the EMP for the Project will be undertaken at a number of levels. First, it will be undertaken by the Contractors at work sites during construction, under the direction and guidance of the Supervision Consultant who is responsible for reporting to the implementing agencies. EEPCo will undertake independent monitoring of selected parameters to verify the results of the Contractor and to audit direct implementation of environmental mitigation measures contained in the EMP and construction contract clauses for the Project. EEPCo and NEC also have the direct responsibility to implement and monitor land acquisition and compensation issues as outlined in the two RAPs. 9. Both Ethiopia and Sudan have national environmental protection agencies that have the overall responsibility for issuing approval for the Project and ensuring that their environmental guidelines are followed during Project implementation. ENTRO (supported by a separate grant) will also monitor the implementation of the EMP and RAPs in the two countries. In parallel, ENTRO will facilitate the implementation of a training program on environmental and social issues in Ethiopia and Sudan to strengthen the capacities of the two utilities to address priority social and environmental issues associated with the design and implementation of power sector projects. 10. Environmental monitoring of the following parameters will be done during Project implementation: water quality of any affluent, 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 of towers; and accidents and health. Resettlement (OP4.12) 11. Two Resettlement Action Plans were prepared to ensure that a systematic assessment of potential losses will be made and action taken to minimize damage or loss to affected people by the construction of the proposed transmission line. The RAPs consider loss of access to resources (dwellings, crops, woodlots, grazing lands, wells, businesses, cultural properties and social services) and temporary displacement due to construction. The RAPs build upon the following sources:

• Broad consultation with local stakeholders • Rapid surveys of all route options • 100 percent census of option C in the two countries • Sample socio-economic surveys of Options A, B1 and B2.

12. Because of the linear nature of a transmission line, it is estimated that the interconnector will have minimal impact on communities and persons, and on common and private property assets. Some resettlement will occur due to the construction of the line, therefore two separate Resettlement Action Plans (RAPs) have been prepared, one for Ethiopia and one for Sudan. In Ethiopia, it is estimated that 680 households will lose land permanently for tower bases. The impact on each household for permanent land loss will not be more than 49 m2 (per tower base). A total of 283 residential buildings are located within the Project right-of-way and will have to be removed. Permanently affected houses are not located in one area, but are spread across the 296 km route. Impact on residences will not require full resettlement, but will involve shifting the residence to a different portion of the property, or in case of a town, to within the vicinity. In Sudan, the total number of hectares that will be temporarily affected by the right-of-way is 438 ha. while 1.53 will be permanently affected by the construction of approximately

93

312 towers. Only 24 houses will be permanently affected and will be relocated. The following two tables summarize the resettlement and relocation impacts in the two countries.

Summary of Resettlement/Relocation Impacts in Ethiopia

Summary of Resettlement/Relocation Impacts in Sudan

94

Annex 11: Project Preparation and Supervision

ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORTS PROJECT:

ETHIOPIA-SUDAN INTERCONNECTOR Planned Actual PCN review May 2004 May 2004 Initial PID to PIC June 2006 June 2006 Initial ISDS to PIC June 2006 June 2006 Appraisal March 2007 March 2007 Negotiations April 2007 November 2007 Board/RVP approval December 2007 Planned date of effectiveness April 2008 Planned date of mid-term review November 2009 Planned closing date December 31, 2011 Key institutions responsible for preparation of the Project: EEPCo in Ethiopia; parallel support from ENTRO and NEC Bank staff and consultants who worked on the Project included: Name Title Unit Philippe Benoit Task Team Leader AFTEG Alexandra Planas Operations Officer AFTWR (Consultant) Luiz Maurer Senior Energy Specialist AFTEG Chrisantha Ratnayake Power Engineer and Proc.

Specialist AFTEG (Consultant)

Gulam Dhalla Financial Specialist AFTEG (Consultant) Kristine Ivarsdotter Senior Social Development

Specialist AFTS1

Jorge Uquillas Senior Social Development Specialist

AFTS1

Robert Robelus Senior Environmental Assessment Specialist

AFTS1

Eshetu Yimer Senior Financial Management AFTFM Jonathan Pavluk Senior Counsel LEGAF Christine Onyango Counsel LEGAF (Consultant) Luis Schwarz Senior Financial Officer LOAG2 Tesfaalem Iyesus Senior Procurement Specialist AFTPC Richard Olowo Senior Procurement Specialist AFTPC Reynold Duncan Peer Reviewer Kurt Schenk Peer Reviewer MNSIF Astrid Hillers Peer Reviewer AFTNL Bank funds expended to date on Project preparation:

1. Bank resources: US$150,000 2. Trust funds: US$380,000 PHRD for ESIA 3. Total: US$530,000

Estimated Approval and Supervision costs:

1. Remaining costs to approval: 20,000 2. Estimated annual supervision cost: 100,000

95

Annex 12: Documents in the Project File

ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORT PROJECT : ETHIOPIA-SUDAN TRANSMISSION INTERCONNECTOR

1. Feasibility Study Update: Final Report. Hifab Oy, Sogreah Consultants and Fingrid. October 2006.

2. Final Report Environmental and Social Impact Assessment. SMEC Consultants. October 2006

3. Resettlement Action Plan for Ethiopia. SMEC Consultants. October 2006

4. Resettlement Action Plan for Sudan. SMEC Consultants. October 2006 5. NEC Annual Report 2004.

6. NEC Annual Report 2005.

96

Annex 13: Statement of Loans and Credits ETHIOPIA/NILE BASIN INITIATIVE POWER EXPORTS PROJECT:


Original Amount in US$ Millions

Difference between expected and actual

disbursements

Project ID FY Purpose IBRD IDA SF GEF Cancel. Undisb. Orig. Frm. Rev’d

P101556 2008 ET-Elect. Access Rural II SIL (FY07) 0.00 130.00 0.00 0.00 0.00 132.05 0.00 0.00

P101473 2007 ET-Urban WSS SIL FY07) 0.00 65.00 0.00 0.00 0.00 97.05 -7.33 0.00

P098093 2007 ET-Productive Safety Nets II (FY07) 0.00 0.00 0.00 0.00 0.00 129.48 33.33 0.00

P098031 2007 ET-Multi-Sectoral HIV/AIDS II (FY07) 0.00 0.00 0.00 0.00 0.00 26.67 9.75 0.00

P092353 2007 ET-Irrigation & Drainage SIL (FY07) 0.00 100.00 0.00 0.00 0.00 100.36 0.00 0.00

P091077 2007 ET-APL3-RSDP Stage III Proj (FY07) 0.00 225.00 0.00 0.00 0.00 226.87 0.00 0.00

P097271 2006 ET-Electricity Access (Rural) Expansion 0.00 133.40 0.00 0.00 0.00 135.67 49.10 0.00

P094704 2006 ET-Financial Sector Cap Bldg. Project 0.00 0.00 0.00 0.00 0.00 14.32 1.07 0.00

P079275 2006 ET- Cap. Building for Agric. Serv (FY06) 0.00 54.00 0.00 0.00 0.00 47.50 -1.83 0.00

P077380 2006 ET-GEF Energy Access Prj (FY06) 0.00 0.00 0.00 4.93 0.00 4.63 0.00 0.00

P074015 2006 ET-Protection of Basic Services (FY06) 0.00 0.00 0.00 0.00 0.00 88.38 2.83 0.00

P050272 2005 ET-Priv Sec Dev CB (FY05) 0.00 19.00 0.00 0.00 0.00 21.43 4.35 0.00

P082998 2005 ET-Road Sec Dev Prgm Ph 2 Supl 2 (FY05)

0.00 160.90 0.00 0.00 0.00 220.26 55.84 11.55

P078692 2005 ET-Post Secondary Education SIL (FY05) 0.00 40.00 0.00 0.00 0.00 35.83 26.05 0.00

P078458 2005 ET-ICT Assisted Dev SIM (FY05) 0.00 25.00 0.00 0.00 0.00 21.43 12.29 0.00

P074020 2004 ET-Pub Sec Cap Bldg Prj (FY04) 0.00 100.00 0.00 0.00 0.00 50.82 18.70 0.00

P076735 2004 ET-Water Sply & Sanitation SIL (FY04) 0.00 75.00 0.00 0.00 0.00 77.81 22.29 0.00

P075915 2003 ET-Pastoral Community Dev APL (FY03) 0.00 0.00 0.00 0.00 0.00 1.38 -6.99 0.00

P044613 2003 ET-RSDP APL1 (FY03) 0.00 0.00 0.00 0.00 0.00 74.85 39.40 0.00

P049395 2003 ET-Energy Access SIL (FY03) 0.00 132.70 0.00 0.00 0.00 128.74 96.75 0.00

P050938 2003 ET-Dec Serv Del CB (FY03) 0.00 26.20 0.00 0.00 0.00 12.30 7.29 3.28

P057770 2002 ET-Cultural Heritage LIL (FY02) 0.00 5.00 0.00 0.00 0.00 1.91 0.92 0.00

P050383 2002 ET-Food Security SIL (FY02) 0.00 85.00 0.00 0.00 0.00 57.11 19.65 0.00

Total: 0.00 1,376.20 0.00 4.93 0.00 1,706.85 383.46 14.83

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ETHIOPIA

STATEMENT OF IFC’s Held and Disbursed Portfolio

In Millions of US Dollars Committed Disbursed IFC IFC FY Approval

Company Loan Equity Quasi Partic. Loan Equity Quasi Partic.

Total portfolio: 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Approvals Pending Commitment FY Approval

Company Loan Equity Quasi Partic.

Total pending

commitment: 0.00 0.00 0.00 0.00

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Annex 14: Country at a Glance ETHIOPIA/ NILE BASIN INITIATIVE POWER EXPORT PROJECT:


99

Annex 15: MAP ETHIOPIA/ NILE BASIN INITIATIVE POWER EXPORT PROJECT:


Metema

GonderAzezo

Aykel

Gorgora

Doka

Shehedi

WahniMaganan

GallabatAtruh

KonnainaSaraf Saeed

TawareetAlhamraa

KassabKagara

Dangura

Kola Diba

AsmaraKhartoum

Djibouti

AddisAbaba

El Gedaref

Girba

HalfaKassala

El Fau

HawataSinger

Sennar

MeringanManagil

Mashkur

Hassa Heisa

Garri

Shendi

Atbarra

Berber

Aroma

JebelAuliaGetania

Rank Roseires

Um DarfaBau

Kam KamGizan

Kurmuk

Rabak

Um RowabaObeid

Al DubebatAbu Zabad

Muglad

Heglig

Abye

Ed Daein

Al Fasher

Nyala

Al Rahad

El Fula

500 MW

520 MW

415 MW

850 MW

900 MW

1250 MW

315 MW

1500 MW

Adwa Adigrat

Dabat

Bahir Dar

Dangla

FinotSelam

BitchennaDebre Markos

GhedoGuder

(Hormat)Dembi Dolo

Gambela

AdamituluAssela

Hossaina

Wolayta SodoShashemene

Melka Wakena

Shakisso

Alghobosh

Shereik

Abu Hamed

Merowe

Debba

Dongola

Karma Port Sudan

Sawakin

Dawro

South

Omo

MajiBench

Keficho

Gurage

Sidama

Borena

Bale

Liben

Afder

Gode

Fik

Korahe

Warder

Degehabur

EastHarerghe

WestHarerghe

Arsi

East

Shew

a

Jijiga

ShinileThreeFive

One

Four

Two

EastSouth

Central

West

North Gonder

WagHemra

SouthGonder

NorthWello

SouthWello

West

GojamEast

Gojam

Metekel

Aso

saN.W. Shewa

EastWellega

WestWellega

KamashiWest Shewa

Jimma

IllubaborThree One

TwoFour

BurjiKonso

K.A.T.

Hadiya

AgewAwi

Wolayta

GamoGofa

Shekicho

TongoSp.

Crom

iya

NorthShewa

Ye

m

Ged

io

DirashiAmaro

Guji

A F A R

T I G R A Y

AMHARA

BENESHANGUL

DIREDAWA

HARARI

S N N P R

GAMBELA

S O M A L I

OROMIYA

GUMUZ

R E P U B L I C

O F

Y E M E N

S U D A N

S U D A N

K E N Y A

E R I T R E A

SOMAL IA

DJIBOUTI

UGANDA

R e d

S e a

I N D I A N

O C E A N

Gulf of Aden

Blue

Nile

Nile

Whi

te

LakeTurkana

Ganale

Dorya

Shebele

Wabi

LakeTana

Nile

ToLow Dal

ToKass

35° 40° 45°

5°

10°

15°

45°

40°35°30°

30°

10°

20° 20°

15°

5°

ETHIOPIA

This map was produced by theMap Design Unit of The World Bank.The boundaries, colors, denominationsand any other information shown on thismap do not imply, on the part ofThe World Bank Group, any judgment onthe legal status of any territory, or anyendorsement or acceptance of suchboundaries.

E T H I O P I A

N I L E B A S I N I N I T I AT I V EPOWER EXPORT PROJECT STAGE:


ETHIOPIA POWER SYSTEM:

EXISTING SUBSTATIONS

HYDRO POWER PLANTS

TRANSMISSION LINES: 230 kV 132 kV

IBRD 35378

NOVEMBER 2007

EXIST I NG & PROPOSED SUDAN POWER SYSTEM:

SUBSTATIONS

MAJOR POWER PLANTS

TRANSMISSION LINES: 500 kV 220 kV 110 kV

PROJECT TRANSMISSION LINE

NATIONAL CAPITALS

WEREDA BOUNDARIES

ZONE BOUNDARIES

REGION BOUNDARIES

INTERNATIONAL BOUNDARIES

0 100 200 300

KILOMETERS

400 500