Document of The World Bank FOR OFFICIAL USE ONLY Report No: 58368-NP PROJECT APPRAISAL DOCUMENT ON A PROPOSED CREDIT IN THE AMOUNT OF SDR 17.3 MILLION (US$ 27.4 MILLION EQUIVALENT) AND A PROPOSED GRANT IN THE AMOUNT OF SDR 6.7 MILLION (US$ 10.6 MILLION EQUIVALENT) TO NEPAL FOR THE KABELI TRANSMISSION PROJECT April 12, 2011 Sustainable Development Department South Asia 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. CURRENCY EQUIVALENTS Exchange Rate Effective = January 31, 2011 Currency Unit = Nepalese Rupee (NRs) NRs. 72 = US$1 US$1.56194 = SDR 1 FISCAL YEAR July 16 ­ July 15 ABBREVIATIONS AND ACRONYMS ADB Asian Development Bank IDA International Development Association AEPC Alternative Energy Promotion Centre IEE Initial Environmental Examination BSPN Biogas Sector Partnership Nepal IFC International Finance Corporation CAS Country Assistance Strategy INPS Integrated Nepal Power System CREP Community Rural Electrification Program IPP Independent power producer DCS Distribution and Consumer Services IPR Implementation Progress Report DDC District Development Committee MOE Ministry of Energy DEES District Energy and Environment Sections MOF Ministry of Finance DEF District Energy Fund MW Megawatt DOED Department of Electricity Development NEA Nepal Electricity Authority Nepal-India Electricity Trade and Transmission EA Environmental Assessment NIETTP Project EIRR Economic Internal Rate of Return OAG Office of Auditor General EMP Environmental Management Plan OBA Output-based aid ESAP Energy Sector Assistance Programme PAP Project-affected Person Energy Sector Management Assistance ESMAP PDO Project Development Objective Program ESSD Environment and Social Studies Department PDP Power Development Project ESMU Environmental and Social Management Unit PEFA Public Expenditure and Financial Accountability ETFC Electricity Tariff Fixation Commission PPA Power Purchase Agreement FRP Financial Restructuring Plan PTC Power Trading Corporation GAAP Governance and Accountability Action Plan RAP Resettlement Action Plan GON Government of Nepal REDP Rural Energy Development Programme GRC Grievance Redress Committee SBD Standard Bidding Document GWh Gigawatt-hour (1 million kWh) SIA Social Impact Assessment IAS International Accounting Standards SMF Social Management Framework ICB International Competitive Bidding SREP Scaling-up Renewable Energy Program Implementation Completion and Results ICCR VDC Village Development Committee Report Vice President: Isabel Guerrero Country Director: Susan Goldmark Sector Director: John Stein Sector Manager (Acting): Malcolm Cosgrove-Davies Task Team Leader: Michael Haney lxxxix NEPAL Kabeli Transmission Project CONTENTS Page I. STRATEGIC CONTEXT AND RATIONALE ................................................................. 1 A. Energy in the Context of Development .............................................................................. 1 B. Government's Response to the Electricity Crisis ............................................................... 3 C. Key Power Sector Development Issues .............................................................................. 3 D. Rationale for Bank involvement ......................................................................................... 5 E. Higher level objectives to which the project contributes .................................................... 5 II. PROJECT DESCRIPTION ................................................................................................. 5 A. Project location ................................................................................................................... 5 B. Lending instrument ............................................................................................................. 6 C. Project cost and financing ................................................................................................... 6 D. Project development objective and key indicators.............................................................. 7 E. Project components ............................................................................................................. 7 F. Lessons learned and reflected in the project design............................................................ 7 G. Alternatives considered and reasons for rejection .............................................................. 9 III. IMPLEMENTATION ...................................................................................................... 9 A. Institutional and implementation arrangements .................................................................. 9 B. Monitoring and evaluation of outcomes/results ................................................................ 11 C. Sustainability..................................................................................................................... 12 D. Critical risks and possible controversial aspects ............................................................... 12 E. Grant/credit conditions and covenants .............................................................................. 14 IV. APPRAISAL SUMMARY ............................................................................................. 15 A. Economic and financial analyses ...................................................................................... 15 B. Technical ........................................................................................................................... 16 C. Fiduciary ........................................................................................................................... 16 D. Social................................................................................................................................. 17 E. Environment...................................................................................................................... 19 F. Safeguard policies ............................................................................................................. 21 xc G. Policy Exceptions and Readiness...................................................................................... 21 Annex 1: Sector Background ..................................................................................................... 22 Annex 2: Major Related Projects Financed by the Bank and/or other Agencies ................. 28 Annex 3: Results Framework and Monitoring ........................................................................ 29 Annex 4: Detailed Project Description ...................................................................................... 32 Annex 5: Project Costs ............................................................................................................... 35 Annex 6: Implementation Arrangements ................................................................................. 36 Annex 7: Financial Management and Disbursement Arrangements ..................................... 40 Annex 8: Procurement Arrangements ...................................................................................... 45 Annex 9: Economic and Financial Analysis ............................................................................. 49 Annex 10: Safeguard Policy Issues ............................................................................................ 71 Annex 11: Governance Framework .......................................................................................... 76 Annex 12: Operational Risk Assessment Framework ............................................................. 79 Annex 13: Project Preparation and Supervision ..................................................................... 83 Annex 14: Documents in the Project File ................................................................................. 84 Annex 15: Statement of Loans and Credits .............................................................................. 85 Annex 16: Country at a Glance ................................................................................................. 86 Annex 17: Map ............................................................................................................................ 88 xci NEPAL KABELI TRANSMISSION PROJECT PROJECT APPRAISAL DOCUMENT SOUTH ASIA SASDE Date: April 12, 2011 Sectors: Power (50%); Renewable energy (50%) Country Director: Susan G. Goldmark Themes: Rural services and infrastructure (50%); Sector Manager/Director: Malcolm Infrastructure services for private sector Cosgrove-Davies/John Henry Stein development (50%) Team Leader: Michael Haney Project ID: P112893 Environmental category: Partial Assessment Lending Instrument: Specific Investment Joint IFC: Loan (SIL) Joint Level: Project Financing Data [ ] Loan [X] Credit [X] Grant [ ] Guarantee [ ] Other: For Loans/Credits/Others: Total Bank financing (US$m.): 38.00 Financing Plan (US$m) Source Total Government of Nepal 7.75 International Development Association 38.00 Community contributions 1.88 District Development Committees and Village Development Committees 0.06 Total: 47.68 Borrower: Nepal Responsible Agencies: Dr. Jivendra Jha Managing Director Nepal Electricity Authority Kathmandu Nepal neamd@mos.com.np Dr. Narayan Chaulagain Executive Director Alternative Energy Promotion Centre xcii Khumaltar Heights, Lalitpur Kathmandu Nepal Tel: +977-1-5548468, 5539237 narayan.chaulagain@aepc.gov.np Estimated disbursements (Bank FY/US$m) FY 12 13 14 15 16 Annual 3.8 5.7 11.4 13.3 3.8 Cumulative 3.8 9.5 20.9 34.2 38.0 Project implementation period: Start August 1, 2011 End: March 31, 2015 Expected effectiveness date: September 1, 2011 Expected closing date: June 30, 2015 Does the project depart from the CAS in content or other significant respects? [ ]Yes [X] No Does the project require any exceptions from Bank policies [X]Yes [ ] No Have these been approved by Bank management? [X]Yes [ ] No Is approval for any policy exception sought from the Board? [ ]Yes [X] No If yes, please explain: The audit reports for the on-going Power Development Project (Cr. 3766, Gr. H039, Cr. 4637, Gr. H506) have not been received by their due date. In accordance with the provisions of BP 10.02 Annex A, an exception from the Vice President of Operational Policy and Country Services, and the Vice President and Controller has been authorized for the presentation of this operation to the Board while the delayed audit reports are awaited. Does the project include any critical risks rated "substantial" or "high"? [X]Yes [ ] No Does the project meet the Regional criteria for readiness for implementation?. [X]Yes [ ] No Project development objective: The project development objectives are: (i) to support the addition of transmission capacity to the Integrated Nepal Power System; and (ii) to provide access to electricity and cooking fuel to communities in the area of the Kabeli 132 kV transmission line. Project description Component 1: Construction of a new 132 kV transmission line in eastern Nepal, with associated technical assistance. Component 2: Construction of distribution lines and associated infrastructure to provide access to electricity to communities in the area of the transmission line, with associated technical assistance. Component 3: Provision of access to electricity and cooking fuel through off-grid schemes in communities for which grid extension (Component 2) is not a feasible option, with associated technical assistance. xciii Which safeguard policies are triggered, if any? 1. Environmental Assessment (OP/BP 4.01) 2. Indigenous Peoples (OP/BP 4.10) 3. Involuntary Resettlement (OP/BP 4.12) 4. Forests (OP/BP 4.36) Significant, non-standard conditions, if any, for: Board presentation: None Credit/grant effectiveness: 1. The NEA Subsidiary Agreement has been executed on behalf of Government of Nepal and NEA. Disbursement: 1. The NEA Project Implementation Plan has been adopted by NEA in form and substance satisfactory to the Association; 2. NEA has submitted to the Association appropriate documents, satisfactory in substance to the Association, setting out the institutional arrangements for the implementation of environmental and social safeguard activities under Parts 1 and 2 of the Project; and 3. The AEPC Project Implementation Manual has been adopted by AEPC in form and substance satisfactory to the Association. xciv I. STRATEGIC CONTEXT AND RATIONALE A. Energy in the Context of Development 1. With a population of about 29 million and a per capita income of USD 400 (Atlas method), Nepal is a relatively sparsely populated and poor country, compared to other countries in South Asia. Nepal's level of development with respect to energy is low by global and South Asia regional standards. An estimated 88% of the country's total primary energy demand is met by traditional (non-commercial) forms of energy, reflecting the overwhelmingly rural distribution of population in Nepal1 and the virtual absence of relatively clean, commercialized forms of energy outside of urban areas. This heavy reliance on traditional energy sources brings with it the well-known problems of limited opportunities for rural economic development; environmental degradation; inefficiency in provision of energy services; and health impacts, particularly for women and children. 2. About 46% of the population in Nepal is believed to have access to reliable sources of electricity (grid and off-grid), with a significant disparity between access levels in urban Nepal (around 90%) and rural Nepal (around 30%).2 Actual consumption of electricity remains very low, even for urban Nepalis, as a result of severe limitations in the supply of electricity which has not kept up with the sharp rise in demand of recent years. Nepal's total grid-connected generation capacity amounts to a meager 698 MW but the actual available capacity at any moment is generally considerably less for a variety of reasons. Nepal's installed generation capacity per capita is less than one-fifth that of India. 3. Exacerbating this low level of development is a long-term crisis in the electricity sector. Load-shedding (rationing of electricity to grid-connected consumers) has long been a facet of the hydro-dependent power system in Nepal, where protracted conflict and weak institutions and finances have discouraged investment and hampered the addition of power generation capacity. Moreover, the Nepal power system lacks adequate storage to capture the wet season surplus water that could be used to augment low flows and boost generation in the dry season. The supply-demand gap has grown sharply in recent years, with a peak demand of about 885 MW. In the dry season 2010/11, load-shedding has take place for up to 14 hours a day. Current projections indicate that Nepal could end load-shedding by 2015, assuming timely completion of the first major cross-border transmission line between Nepal and India. Until then (and possibly longer), Nepal will continue to be burdened by a heavy reliance on costly, and often polluting, alternative means for meeting the economy's demand for electricity, or to do without electricity, at a high cost to its people and its economy. 4. Hydropower Development in Nepal. Nepal's significant hydropower potential is well known, as are the many challenges to developing this potential.3 Despite the fact that the 1 Despite a high rate of urbanization (estimated at just under 5% per annum over 2005-2010), the rural population in Nepal is believed to account for about 80% of the total population. 2 In Nepal, as in many countries, data on access to electricity are scanty and somewhat contradictory. The challenges to accurately measuring access to electricity are many in Nepal and include the largely rural distribution of population, the difficult terrain of the country and the dynamic nature of the question. 3 The most commonly cited figures for Nepal's theoretical and economic hydropower potential are 83,000 MW and 42,000 MW, respectively. However, these are probably obsolete estimates; re-optimization of power production and 1 Ministry of Energy (MOE) has issued survey licenses for hydropower projects that total to more than 10,000 MW, various barriers to hydropower development have held back the development of new generation projects; today's installed capacity represents less than 1% of the estimated potential. These barriers include (in addition to the overarching factors of conflict and transition that have characterized the last 15 years in Nepal4): the absence of significant cross-border transmission capacity that would allow Nepal to export surplus generation capacity to India (the relatively small size of the Nepal economy means that Nepal would need only a fraction of its total hydropower potential to meet the country's own demand for electricity); deficiencies in the coordination of generation planning by MOE with transmission planning by the national utility, the Nepal Electricity Authority (NEA); a shortage of investment funds for new transmission capacity even for relatively small-scale domestic projects; a tariff structure that has not been revised in nine years; the high financing costs faced by developers of generation projects and the difficulty of coming to financial closure; uncertainty as perceived by independent power producers (IPPs) of the process of negotiating Power Purchase Agreements with NEA; the potential for politicization of hydropower projects that is sometimes fanned by local and regional political interests; and local law-and-order problems that local authorities are often not able to control. While the efforts of the Government and its agencies, developers and other sector stakeholders to address these many obstacles are slowly bringing results, the large-scale development of Nepal's hydropower potential will clearly be a long-term process. 5. World Bank Group support to the energy sector in Nepal. The World Bank Group is supporting energy sector development in Nepal through existing IDA and IFC investments. The ongoing IDA-funded Power Development Project (PDP) includes support to increase transmission capacity and strengthen the distribution system; rehabilitation of existing generation capacity; and technical assistance for the Nepal Electricity Authority (NEA) in such areas as: transmission business planning; technical, financial and legal support to preparation of the first high-voltage transmission link with India; procurement capacity; and financial management. The PDP also provides financing to the Government's microhydro village electrification program which is implemented by the Alternative Energy Promotion Centre; and technical assistance to the Ministry of Energy. IFC has investments in the Khimti HEP (60 MW) and the Bhote Koshi HEP (36 MW) and is expanding its portfolio of investments in hydropower in Nepal. Nepal is currently executing an output-based aid (OBA) grant in support of the Nepal Biogas Program. The Nepal Village Microhydro Project is a carbon offset activity under which Nepal has the right to claim emission reduction credits for electricity produced by community- own microhydro projects. In addition to these activities under implementation and the proposed project, the World Bank is considering for financing the proposed Nepal-India Electricity Trade and Transmission Project (NIETTP) and the Kabeli "A" Hydroelectric Project, which would utilize the proposed Kabeli Corridor transmission line. The World Bank is also partnering with the Asian Development Bank (ADB) to support the Government of Nepal's preparation of the Scaling-Up Renewable Energy Program (SREP), for which Nepal is one of six pilot countries. the possibility of open access to the deregulated power markets in India suggest that the actual hydropower potential could be much higher. 4 The Comprehensive Peace Agreement signed in 2006 brought to an end a decade of armed conflict in Nepal. A Constituent Assembly (CA) was elected in 2008 to draft a new constitution; the deadline for this process has been extended to May 2011. No party has a majority in the CA and since the early 1990s governments have been short- lived. 2 World Bank Group lending activities are complemented by a series of non-lending technical assistance activities that are funded by the Energy Sector Management Assistance Program (ESMAP) and other sources. 6. Other development partners are also supporting energy sector development in Nepal. The ADB is currently financing the Energy Access and Efficiency Improvement Project which is supporting investments in transmission and distribution networks; loss reduction; renewable energy; and energy efficiency. The ADB also finances numerous technical assistance activities in support of energy sector development. Together with the Japan International Cooperation Agency, the ADB is considering for financing the Upper Seti Hydroelectric Project, a 127 MW storage hydropower generation project. As mentioned above, the ADB is also partnering with the World Bank to support the Government of Nepal's preparation of the Scaling-Up Renewable Energy Program. Denmark and Norway are active in supporting energy sector development in Nepal, both on the bilateral level and in the multilateral context. On the bilateral level, Denmark and Norway are both major donors to the Energy Sector Assistance Program which supports increasing access to electricity in rural Nepal through renewable energy applications. Norway and Nepal have recently signed a twinning arrangement under which technical assistance will be provided by the Norwegian national transmission company, Statnett, to the Nepal Electricity Authority. Norway is also considering provision of aid to finance investments in the national transmission system. Together with several other countries, Denmark and Norway are donors to the Climate Investment Funds, two of which are under preparation in Nepal (the Pilot Program for Climate Resilience and the Scaling-Up Renewable Energy Program). Other countries ­ notably, Germany, the United Kingdom, the Netherlands and Japan ­ have relatively small programs in the energy sector and also contribute to the Climate Investment Funds B. Government's Response to the Electricity Crisis 7. In response to the dramatic worsening of electricity supply that took place in 2008, the Government declared a "national energy crisis" in December 2008, and approved an Electricity Crisis Management Action Plan which is currently under implementation (with support from IDA for some specific investments). The Action Plan includes demand- and supply-side investments aimed at alleviating load-shedding in the short and medium term. In addition, the Action Plan includes longer-term investments, including notably development of cross-border transmission links with India and development of large hydropower generation projects, including large storage projects. 8. The Electricity Crisis Management Action Plan includes a focus on developing new transmission corridors to facilitate the development of new generation projects which require transmission capacity to evacuate their power to the national grid. The Kabeli Corridor is one of five priority transmission corridors identified in the Action Plan. C. Key Power Sector Development Issues 9. The demand-supply gap. As described above, Nepal is currently suffering from a deficit of electricity that manifests itself in load-shedding that reaches 14 hours a day in the dry season. This deficit of electricity is a fundamental obstacle to economic and human development in Nepal. Moreover, demand continues to grow briskly, putting constant pressure on the capacity 3 of the power system to supply the economy with electricity in the volume demanded. The primary objective of the Government's Electricity Crisis Management Action Plan is to bring the demand and supply for electricity into balance. 10. Increasing access to electricity. While access to electricity is high in urban areas (90% or higher), it is very low in rural areas of Nepal, where most of the population lives. This means that efforts to increase the overall level of access to electricity must be focused on a large number of small communities that are scattered over mountainous and difficult terrain. Accomplishing this in a timely and cost-effective manner is one of the most significant development challenges facing Nepal today. 11. Financial restructuring of NEA. NEA is loss-making and heavily indebted. NEA's financial position has deteriorated sharply in recent years, the result of rapidly rising costs and the absence of increases in retail tariffs since 2001, among other factors (see Annex 9). NEA is unable to service its debts, let alone generate funds for urgently needed capital investments and rehabilitation programs. Under the prevailing conditions, NEA incurs a loss for every kilowatt- hour of electricity it sells, which provides a disincentive to increase supply of electricity at a time of acute deficit of electricity. A financial restructuring plan has been drafted and is under review by GON. The severity of this problem, against the backdrop of the ongoing load-shedding crisis and prolonged political transition, suggests that its resolution will require some time. For now, the dire financial condition of NEA and the absence of tariff adjustments remain major obstacles to power sector development in Nepal. 12. Improving the environment for private investment. While successive governments in Nepal have expressed a commitment to attracting the private sector to develop hydropower projects, financial and implementation constraints have not allowed the public sector to play an effective role in building the common infrastructure (roads and transmission corridors) needed to foster hydropower development. The rationale for public development of such projects is compelling as they usually bring high economic returns and it is not efficient to burden individual projects with the costs of this common infrastructure. In addition to provision of physical infrastructure, the public sector plays a critical role in determining policy and procedures; progress in this area has also been limited. Attracting and retaining private investment will require provision of common infrastructure, procedural streamlining, regulatory improvements and structural reforms. In some parts of the country, law-and-order problems work against private investment. 13. Increasing storage capacity. Nepal's power system is heavily dependent on run-of-river type of hydropower plants with little or no storage capacity to respond to seasonal variations in river flows and in power demand. The river flows and, hence, the generation capability of the power stations, are substantially lower in the period December-May than in the period June- November. However, the demand for power peaks in the winter, when supply capacity is lowest. This mismatch between supply capability and demand is the root cause of the severe load- shedding in Nepal. Increased storage would enable Nepal to make use of surplus water in the wet season and to respond more efficiently to fluctuations in demand. The development of increased storage capacity is a formidable challenge with complex technical, financial, riparian, environmental and social dimensions. 4 14. Increasing cross-border transmission capacity. Increased electricity trade with India will benefit Nepal, in the short term allowing for critically needed imports to address the electricity crisis and, in the longer term, providing a market for the surplus energy from generation projects in Nepal that are expected to come on-line in the future. Strengthening of the cross-border transmission infrastructure and the associated capacity-building to allow Nepal to maximize the benefits of power export are major development priorities for the Nepal power sector. (The Bank is supporting these efforts under the proposed Nepal-India Electricity Trade and Transmission Project. D. Rationale for Bank involvement 15. Power sector development in Nepal is highly constrained by NEA's insolvency, a shortage of funds for public and private projects, and a poor investment climate overall. At the same time, the long-term energy crisis in Nepal is hampering efforts to develop the economy. IDA funding will help add sorely needed core infrastructure that is a prerequisite for the development of the hydropower potential in the Kabeli Corridor, where about a dozen private power generation projects are in various stages of preparation. 16. The project is included in the joint IDA/IFC Interim Strategy Note for Nepal (FY10-11). The ISN recognized the direct relationship between the years of under-investment in infrastructure (particularly in the power sector) and the current low level of economic development. The ISN articulates a role for IDA and IFC in supporting new hydropower generation and associated investments in power sector infrastructure. E. Higher level objectives to which the project contributes 17. Electricity is a core component of modern economic infrastructure; worldwide, economic growth correlates highly with growth in electricity consumption. Inadequate electricity supply is a major constraint on economic and human development. By augmenting Nepal's power sector infrastructure, the project contributes to economic development in Nepal. The project is consistent with the goals of the second pillar of the Interim Strategy Note (2010-11), "Laying the Foundation for Sustainable and Inclusive Economic Growth". II. PROJECT DESCRIPTION A. Project location 18. The project will be located in eastern Nepal and will be the first significant power sector development project in this part of Nepal. Despite the absence of power sector infrastructure the region is relatively prosperous thanks primarily to the remittances from workers abroad; emigration to other countries for economic reasons has traditionally been high from this region of Nepal. 19. The transmission line will extend from north of Panchthar District, to Damak in the south, in Jhapa District. Substations will be built in the vicinity of Kabeli Bazaar (a village on the Kabeli River) and at the towns Phidim, Ilam and Damak. At present, a few small generating 5 plants with an aggregate capacity of about 10 MW distribute their output locally through a low- voltage network. Several new generating stations are under development in the corridor and their output will be evacuated through the proposed transmission line to the national grid. 20. The project's location is significant from the perspective of the strategic development of the Integrated Nepal Power System as it will open up the extreme east of Nepal for power sector development and will shorten the distance required to transmit electricity to the country's main industrial center at Biratnagar. It is expected that the utilization rate of the transmission line will be relatively low in the first five years of its operation, with power wheeled through the line reaching capacity of 140 MW around 2023 as per current projections. B. Lending instrument 21. The proposed lending instrument is a Specific Investment Loan (SIL), to be provided as an IDA credit and as an IDA grant in the proportions indicated by GON. C. Project cost and financing 22. Tables 1 and 2 provide an overview of the projects by component and the sources of financing, respectively. Project costs are detailed in Annex 5. Rural electrification, technical assistance and training supported under the project will be funded on grant terms. Table 1. Project Costs Table 2. Financing Plan Total Total Project Cost By Component (USD mln) Financing Plan (USD mln) Component 1: Kabeli Corridor 132 kV Transmission Line 31.56 Government of Nepal 7.75 Component 2: Community-based Rural Electrification-Grid Extension 5.71 IDA 38.00 Component 3: Rural Enhanced Energy Services 2.32 Community contributions 1.88 Total Baseline Costs 39.59 Contingencies 3.46 Taxes and Duties 0.99 DDC/VDC 0.06 Project development cost 1.04 Total Project Costs 45.08 Interest During Construction and Financing Charges 2.61 Total Cost including IDC and Financing Charges 47.68 Total 47.68 6 D. Project development objective and key indicators 23. The project development objectives are: (i) to support the addition of transmission capacity to the Integrated Nepal Power System; and (ii) to provide access to electricity and cooking fuel to communities in the area of the Kabeli 132 kV transmission line. As the project implementation period will correspond to the construction period of the transmission line and the rural electrification investments, the associated key performance indicators focus on implementation progress, including construction of the physical assets and implementation of the Resettlement Action Plan, and provision of access to electricity to households in the area. E. Project components 24. The project has three components which in addition to physical investments include associated technical assistance and project management costs: (a) Component 1: the Kabeli Corridor 132 kV Transmission Line Component, to be implemented by NEA; (b) Component 2: the Community-based Rural Electrification-Grid Extension Component, to be implemented by NEA; and (c) Component 3: the Rural Enhanced Energy Services Component, to be implemented by the Alternative Energy Promotion Center (AEPC). 25. Component 1. Kabeli Corridor 132 kV Transmission Line Component (IDA funding $32.24 million). Under this component, a 90-kilometer 132 kV double circuit transmission line and four substations (of which three will be funded by IDA) will be constructed. Technical assistance to facilitate project implementation will also be provided under this component. 26. Component 2. Community-based Rural Electrification-Grid Extension Component (IDA funding $4.36 million). The funds of this component will scale up NEA's existing Community Rural Electrification Program. Under this component, NEA will extend the grid, where technically feasible, to currently unelectrified communities located within (approximately) 2.5 kilometers of either side of the transmission line (creating a zone that is five kilometers in width). Technical assistance to facilitate project implementation will also be provided under this component. 27. Component 3. Rural Enhanced Energy Services Component (IDA funding $1.40 million). This component will provide funding for off-grid rural electrification of communities for which grid extension is not a feasible option as well as for improved cooking fuel through biogas applications. The component will also fund technical assistance to facilitate project implementation and will support a pilot effort to connect village microhydro schemes to the grid. F. Lessons learned and reflected in the project design 28. Procurement. The project design reflects the lessons of NEA's recent experience with contracts tendered through international competitive bidding (ICB) under the PDP. Bid documents for the main transmission line contract of the proposed project were prepared under 7 World Bank guidelines and issued well in advance of appraisal and as of April 2011 the proposals were under evaluation. Using the funds of the ongoing PDP, NEA has engaged an international procurement advisor to bolster the utility's procurement capacity for all IDA- funded contracts, including those anticipated under the proposed project. 29. Contract management. Poor contract management can lead to disputes with contractors and costly delays. The successful implementation experience of the Khimti-Dhalkebar 220 kV transmission line (funded by the PDP) is partly attributable to the Owner's Engineer who was engaged by NEA to supervise that contract. The technical assistance component of the proposed project follows the same design. The proposed NIETTP provides for an Owner's Engineer, which will be a reputable international firm with transmission project design and construction capability. The scope of services proposed for this consultant includes providing on-the-job training to NEA staff in project management. The scope of work of the Owner's Engineer includes the Kabeli Corridor Transmission Line. 30. Implementation capacity. The implementation of large-scale energy projects under conditions prevailing in Nepal today presents a number of obstacles that generally fall on the developer to resolve. These distinct but interlinked challenges range from contracting and contract management to the need to manage social dimensions of project implementation (including often heightened expectations of immediate benefits from the project; resistance or opposition to the project; and concerns around specific aspects of project impacts). Experience from the ongoing Power Development Project has demonstrated the importance of intense field supervision to ensure that implementation problems are addressed in a timely fashion. Multi- sector teams comprising technical, safeguards, governance and fiduciary experts are essential for developers as well as for the Bank. In recent years, the Bank has significantly scaled up its in- country capacity for project management in Nepal, including significant expansions of the energy, fiduciary, governance/accountability and safeguards teams. Project developers, including NEA, have increasingly recognized the importance of incorporating in project team's professionals with a wide range of skills, as reflected in the project implementation arrangements for the proposed project. 31. Need for adequate benefits-sharing mechanisms. After many years of limited development, following the end of the armed conflict in 2006, expectations of a "peace dividend" and inclusive growth have been high, particularly in rural Nepal. At present, many people living in the territory through which the proposed transmission line will pass do not have access to reliable sources of electricity. While it would generally not be economic to distribute power directly from the transmission line to households in the area given low population densities and low levels of consumption of electricity by rural households, the experience of similar development projects indicates the importance of incorporating in the project adequate measures for sharing benefits with communities in the project zone. Community-level consultations confirmed general support for the project with the proviso that the benefit of electricity be shared. Accordingly, the project design includes support for rural electrification. This feature of the proposed project is important both to advance the development of the region and to promote social cohesion. 8 G. Alternatives considered and reasons for rejection 32. Transmission corridor. NEA has identified more than two dozen discrete transmission investments needed to enhance the national power grid, including several in river basins throughout the country where licenses for hydropower projects have been issued. Other transmission corridors were considered for development now, and rejected in favor of the proposed project and a small number of other transmission corridors which are considered to have the best prospects for adding generation capacity to the Integrated Nepal Power System within the foreseeable future. 33. Voltage level. NEA considered the option of designing the proposed investment at the 220 kV level in order to increase its capacity to carry electricity that is expected to be generated from larger projects that may come up in the northeast of Nepal (north of the Kabeli Corridor as defined). This option was rejected in favor of an alternative evacuation route for the larger projects, allowing the proposed Kabeli transmission line to remain at the 132 kV level. 34. Route alignment. Different alternatives were considered for transmission line alignment. The proposed route was selected based on criteria that included social and environmental factors such as the desirability of avoiding settlements and the risks of forest and slope instability and erosion. 35. "No project" scenario. In view of the low level of development of the power sector in Nepal and the severe and prolonged nature of the electricity crisis in Nepal, the "no project" alternative was not considered a credible alternative. III. IMPLEMENTATION A. Institutional and implementation arrangements 36. Components 1 and 2 will be implemented by NEA and Component 3 will be implemented by AEPC. Both agencies have several years of experience implementing components of the ongoing IDA-funded Power Development Project that are similar to their respective components under the proposed project. 37. Coordination between components. The primary component from a planning and implementation perspective is Component 1, as the final alignment of the transmission line (which can be determined only during the construction process) will determine the detailed planning of the rural electrification components which will be carried out after commencement of the construction of the transmission line. An NEA-AEPC coordinating committee will be established to coordinate the two community-based rural energy components. The detailed planning for these two components is a linked process, as communities that cannot for whatever reason feasibly be provided access to electricity through grid extension will be considered for off-grid applications. 38. Components 1 and 2. NEA's Grid Development Business Unit will be responsible for overall coordination of the NEA components and specifically for the implementation of the 9 Kabeli transmission line and substations (component 1). NEA's Distribution and Consumer Services Business Unit (East) will oversee the community-based rural electrification/grid extension component (component 2). 39. For component 1, NEA has formed the Kabeli Corridor 132 KV Transmission Line Project Unit (the Kabeli Project Unit) which is headed by an experienced transmission engineer. The Kabeli Project Unit oversees all aspects of project development and implementation, including: preparation of work plans and budgets; preparation of estimates, tendering and contracts; implementation and monitoring of environmental and social safeguards; supervision of contracts; approval of contractor's invoices; progress reporting; participation in commissioning and approvals; preparation of acceptance certificates; assessment of infrastructure at the end of the contractors' liability period; and implementation of the Governance and Accountability Action Plan (GAAP). The Kabeli Project Unit is also responsible for acquiring land required for construction of substations, transmission line foundations and right of way, and forest clearance. 40. The Kabeli Project Unit Manager reports to the Director of the Transmission Line and Sub-Station Construction Department. Within the Kabeli Project Unit, there are three sub-units at the corporate level dealing with Administration, Finance and Public Relations, and Environment Mitigation which will be headed by the respective unit chiefs. At the field level, there are three sub-units (Damak Sub-unit, Ilam Sub-unit and Phidim Sub-unit) each of which will be headed by qualified engineers. The Finance Officer heads the Finance Sub-unit. The Project Manager will overall coordinate procurement activities and will be a contact point for procurement-related matters. Each of the three field level unit managers will oversee the procurement function of their respective unit. NEA has engaged an international Procurement Advisor who will provide overall support to various projects funded by IDA to contribute to procurement capacity-building of NEA staff. 41. An Environmental and Social Management Unit (ESMU) will be constituted under the Kabeli Project Unit. The ESMU will draw on NEA staff resources such as ESSD and will also engage consultants. The ESMU will be responsible for implementation of the Environmental Management Plan (EMP), safeguard provisions of the Project Implementation Plan, SIA, RAP, and SMF as well as for regular monitoring and reporting of contractor compliance, implementing environmental mitigation activities that are beyond the contractor's scope of responsibility, and facilitating and coordinating safeguard activities. In addition, NEA will engage consultants to carry out an independent review and monitoring of the implementation of environmental and social managements plan every six months including for the mid-term and the project completion reviews. 42. Under the supervision of the Kabeli Project Unit, the construction of the transmission line, substations and local distribution lines will be carried out by contractors who will have responsibility for day-to-day management of their respective subprojects during the construction phase. The contractor's management team for the transmission line will consist of a project manager, a site manager and a civil engineer. In addition to the primary responsibility for construction of the physical assets, the contractors will have certain contractual obligations with respect to management of environmental and social aspects of project implementation. 10 43. Component 2 will scale up NEA's existing Community Rural Electrification Program (CREP), which provides for grid extension, and will be implemented in keeping with the procedures established for this program. The Distribution and Consumer Services (DCS) Business Unit (East) will be responsible for managing all aspects of the component, including design; contracting and contract management; land acquisition and safeguards; payments to contractors; and reporting and monitoring. The implementation methodology will be based on turnkey contracts, with which NEA has extensive experience under CREP and which greatly ease the implementation burden faced by NEA compared to the alternative approach of numerous contracts requiring coordination. 44. Component 3. AEPC will implement this component under the procedures established for the agency's community-level programs. These procedures have functioned satisfactorily under the ongoing PDP which is providing funding for AEPC's REDP. Community energy programs are implemented through the District Development Committees (DDCs), as per the Local Self-Governance Act (2000). District Energy and Environment Sections (DEES) have been established under the DDCs, with the mandate to support local-level capacity-building, planning and M&E, creation of District Energy Funds (DEF), and to undertake resource mobilization through supporting organizations, financial institutions and the private sector. Funds are channeled from AEPC to the DEF. A local NGO will be hired as a Support Organization through a competitive selection process and will work with participating communities to help them establish Community Functional Groups which will oversee the implementation of the community-level energy projects. B. Monitoring and evaluation of outcomes/results 45. NEA and AEPC will be responsible for the regular monitoring of the implementation of their project components. Each agency will submit trimesterly implementation progress reports in an agreed format to the World Bank no later than 45 days after the end of each trimester. The trimesterly reports will cover the progress and expected completion dates for works and equipment supply contracts, progress on institutional components, implementation of the EMP, RAP and GAAP, and technical assistance activities funded under the project. The reports will include the following analysis and data: (a) comparison of actual physical and financial outputs with forecasts, and updated 6-month project forecasts; (b) project financial statements, including sources and application of funds, expenditures by category statement, and special accounts reconciliation statement; (c) a procurement management report, showing status and contract commitments; and (d) comparison of planned EMP/RAP/GAAP implementation with actual. 46. Each agency will also prepare annual reports (to be presented as the third of the annual trimesterly implementation progress reports) which will be submitted to the Bank by August 31 of each year of project implementation. In addition to (a) to (c) above, the reports will cover: (a) the progress of each component, implementation of key features of the EMP, RAP and GAAP, key performance indicators, operation of project facilities, and financial statements; and (b) the Annual Work Plan for implementation, annual funds required for implementation with breakdown by each source of funding, an updated disbursement profile, planned actions for mitigating negative effects during construction, and target indicators for the coming year. The 11 mid-term review of the project is planned for August 2013. Each agency will submit to the Bank an Implementation Completion and Results Report (ICRR) for its respective components within three months of the project closing date. 47. For the NEA components, the staff of the ESMU will be drawn from NEA's Environment and Social Studies Department (ESSD) and consultants recruited from the market. As recommended by the Initial Environmental Examination5 (IEE), the ESMU will report on the compliance with and progress on implementation of environmental and social mitigation measures. An agency will be hired for independent review and monitoring to be carried out every six months and including the mid-term and project completion reviews. C. Sustainability 48. The sustainability of the investments supported by the proposed project will depend significantly on: (i) the degree to which the independent power producers succeed in bringing their new generation projects online; (ii) NEA's capacity to pay for power contracted from the IPPs; (iii) NEA capacity to operate a transmission line of this profile; and (iv) the value that local communities place on having access to electricity. 49. The Kabeli Corridor has been identified as a priority transmission corridor in the Government's Electricity Crisis Management Action Plan. NEA has demonstrated technical capacity to implement and maintain transmission lines of this voltage: the INPS already includes more than 1,500 km of transmission lines at the 132 kV level which are owned and maintained by NEA. Power purchase agreements (PPAs) have been signed between NEA and several IPPs who are developing projects in the Kabeli Corridor. These PPAs are prerequisites to achieving final closure and will provide a formal legal framework that will be conducive to supporting the sustainability of the investment. The multi-year experience of NEA's Community Rural Electrification Program confirms that the high value placed by households on reliable access to electricity will help ensure the sustainability of the rural electrification components. Early results from an ongoing IDA-funded study of the long-term sustainability of community- managed microhydro schemes indicate a similarly high degree of sustainability of schemes that have been in operation for five years or more. D. Critical risks and possible controversial aspects 50. Projects risks were considered from a variety of perspectives, including extensive consultations with local, regional and national concerned groups and experts, and are described in detail in the project Operational Risk Assessment Framework (Annex 12) and the peace filter that has been developed for operations in Nepal. Generally, the most significant project risks (discussed below) are considered manageable through specific project design and implementation measures that have been adopted in the course of project preparation. At the same time, it is noted that the socio-political situation in Nepal is fluid and country-level risks are generally not amenable to mitigation on the project level. 5 Under the laws of Nepal, the "Initial Environmental Examination" is the statutory requirement for certain categories of projects including most transmission lines. The IEE for the Kabeli transmission line was approved by GON in November 2010 and is binding on NEA. 12 51. The Comprehensive Peace Agreement that was signed in 2006 and brought to an end the decade of armed conflict in Nepal also ushered in an era of expectations of a "peace dividend" after long years of limited development, particularly in rural Nepal. Nepal's ratification in 2007 of the ILO Convention on Indigenous and Tribal Peoples (No. 169) has likely contributed to this general expectation in areas of significant population of indigenous and tribal peoples, which include the area of the proposed project.6 The rural electrification components have been incorporated into the project in order to address the legitimate and important desire of people living in the project zone (who may not be directly "project-affected" as this terms is conventionally understood) to gain access to electricity in connection with the development of power sector infrastructure in the Kabeli Corridor. A subsidiary risk emanating from the effort to meet this demand of local communities is the possible dissatisfaction of those communities which for reasons of economic and technical feasibility may fall outside the zone to be electrified. Efforts will be made to ensure that the areas to be electrified on a priority basis are identified in consultation with local communities. Extensive consultations were carried out in the context of project preparation and measures have been incorporated in project design to ensure ongoing consultations and communications during project implementation. 52. The physical transmission and distribution investments are routine in nature. Technical and construction risks emanate primarily from the susceptibility of hilly areas (constituting the majority of the territory through which the transmission line will pass) to landslides and erosion; contractors and NEA are well aware of these risks and appropriate construction methods will be adapted under the supervision of civil engineers and geotechnical experts. NEA has recent experience in building a transmission line in such terrain through the PDP-funded Khimti- Dhalkebar 220 kV transmission line. 53. The economic viability of the transmission line would be affected if the small-to- medium-sized generation projects planned for the Kabeli Corridor fail to materialize. However, it should be stressed that the transmission line itself is effectively a precondition for projects to obtain investment finance, as developers must demonstrate that the power they generate can be brought to the grid. Extensive consultations have been carried out with developers working in the Kabeli Corridor during the course of project preparation and this due diligence indicates that several projects are being advanced (through investment in detailed studies, land acquisition, initial efforts to obtain financing, etc.) by credible developers. 54. There are no national parks or otherwise protected areas in the vicinity of the transmission route, and no physical resettlement is anticipated. Generally, safeguards risks are not significant and are manageable through the mitigation measures that have been agreed in the course of project preparation and incorporated in the project safeguards documents that meet the requirements of the relevant World Bank operational policies. 55. The experience of both implementing agencies with investments of a similar nature that are being funded under the PDP indicates that implementation agency risks for the proposed 6 ILO Convention No. 169 is binding on those countries that ratify it, as Nepal did in September 2007. The Ministry of Local Development has drafted a National Action Plan for the implementation of ILO 169 which is under review by the Government of Nepal. 13 project are not high. Ongoing capacity-building activities at NEA (including in the areas of financial management and procurement) that are funded by the PDP will be augmented with technical assistance provided under the proposed project (for both NEA and AEPC) and the proposed NIETTP. 56. It should be noted that the proposed project improves the risk profile of the Bank's support to power sector development in Nepal. The transmission line is being constructed in order to transmit power that will be generated by Nepali companies and consumed by Nepali consumers. It will also provide local electricity access. This domestic orientation of the project is a strong positive factor in the public perception of the project and of the role of the World Bank Group in supporting power sector development in Nepal. E. Grant/credit conditions and covenants 57. Conditions for Board Presentation: None 58. Conditions of Effectiveness: a. The NEA Subsidiary Agreement has been executed on behalf of Government of Nepal and NEA. 59. Conditions of Disbursement: a. The NEA Project Implementation Plan and the AEPC Project Implementation Plan have been adopted by pertinent authority of NEA and AEPC respectively. b. NEA has finalized arrangements for the implementation of environmental and social safeguards activities related to Components 1 and 2 of the Project satisfactory to the Association. 60. During Project Implementation: Government of Nepal a. Ensure the availability to NEA and AEPC of the budget funding necessary to finance those parts of the project not funded by IDA, including the Damak substation. Nepal Electricity Authority a. Report on progress in implementation with key performance indicators and including an updated milestone plan for construction of the Kabeli Corridor 132 kV transmission line and the rural electrification grid extension investments, with any necessary measures to keep to the commissioning targets, according to the reporting schedule agreed with the Bank; b. Carry out the Governance and Accountability Action Plan as agreed with the Bank; c. Implement the Resettlement Action Plan and Environment Management Plan as agreed with the Bank; 14 d. Carry out a Resettlement Impact Assessment study to assess the changes in the living standards of resident project-affected people before the mid-term review and after the completion of the construction of the transmission line. Agree with the Bank, and take action to address any issues raised by the impact assessment studies; e. Provide all the entitlements due to the PAPs under the RAP, i.e. compensation for land acquisition, payment of rehabilitation grant and provision of developed plots, which would be allotted to the PAPs, as applicable, before beginning any construction activities on such land required for the project. Alternative Energy Promotion Centre a. Report on progress in implementation with key performance indicators and including an updated implementation plans for off-grid rural electrification and energy service enhancement schemes financed under Component 3; b. Carry out the Governance and Accountability Action Plan as agreed with the Bank; c. Implement the relevant environmental assessment guidelines7 and prepare Vulnerable Community Development Plans for each village in which village energy schemes will be installed under Component 3. IV. APPRAISAL SUMMARY A. Economic and financial analyses 61. The Economic Internal Rate of Return (EIRR) in the base case scenario is 38%, with an NPV of $434 million. The base case scenario includes projects totaling to around 73.5MW (against a total of about 164 MW for which licenses have been issued) that are assumed to come online over 2015-17. Sensitivity analysis was carried out to consider variations relative to the base case assumptions in: (i) fuel price for alternative generation; (ii) change in the level (MW) of capacity evacuation on the line; and (iii) and cost escalation. The sensitivity analysis showed that the proposed investment is highly robust with respect to the variation of the major quantifiable independent variables. Even if only 37 MW were to come on-line (against a base case scenario of 73.5 MW, the transmission line still shows a robust EIRR of 32%. If construction costs for the independent hydropower plants rise by 300% against assumed costs, the EIRR is 14%. 62. The results of the financial analysis indicate that the project is financially viable, with the projected equity IRR of 22.2% exceeding the Weighted Average Cost of Capital. The 25-year levelized tariff of US 0.745 cents/kWh (NPR0.559/kWh) is higher than par for projects in the region due to the relatively low capacity utilization of the transmission line in the initial years of the project. The transmission line would have low utilization over the first five years of operation, with power wheeled through the line reaching capacity of 140 MW around 2023 as per current projections. In the first year of operation (2014), 60 MW is expected to be available 7 AEPC "environmental assessment guidelines means", collectively: (i) AEPC Environment Assessment Guidelines for Community-owned and Managed Micro Hydro Schemes" dated March 2003; and (ii) Environmental Management and Mitigation Plan dated September 2010 prepared for biogas schemes. 15 for transmission, which is expected to grow to 140 MW by 2023. Sensitivity tests indicate that project is robust. 63. NEA Corporate Financial Assessment. NEA's financial position is very weak and the utility is technically insolvent, with internal cash flows unable to service existing debt or fund any capital expansion without significant support from external sources. Interest payable to GON accounted for around 76% of the total current liabilities of NPR 29.2 billion as of FY09. Revenues from electricity sales have remained stagnant at around NPR14.7 billion as there have been no tariff increases in Nepal since 2001. Operating costs have increased about 16% (at 7.7% CAGR) during FY 2007-2009, with distribution and power purchase costs (accounting for 20% and 58% of total costs respectively) growing at a compound rate of 18.5% and 5% respectively. NEA's generation costs grew at 14.4% in the same period. A financial restructuring plan for NEA has been drafted and is under review by GON. The measures proposed include write-off of accumulated losses; reduction of GON's on-lending interest rate to 5%; re-capitalization of part of NEA; and a 30% increase in tariffs. However, the scope of NEA's insolvency, against the backdrop of the ongoing load-shedding crisis and political transition, suggest that the resolution of this problem will require some time. B. Technical 64. The technical core of the project is a 132 kV transmission line with substations and some local distribution lines. Presently NEA operates more than 1,500 km of transmission lines at the 132 kV level and the proposed project is well within NEA's technical capacity. The rural enhanced energy services component scales up an established program that is a core function of AEPC. In keeping with established practice for construction of transmission lines, while the transmission corridor and location of angle points have been determined before the award of the main contract, the final location of most of the towers will be determined by the contractor based on site-specific conditions and in keeping with criteria designed to minimize adverse impacts of the investment. 65. The procurement of the contract for the transmission line and substations component is advanced; bids have been submitted by nine entities from three countries and as of April 2011 the bids are under evaluation. C. Fiduciary 66. Procurement. A procurement capacity assessment of NEA was carried out in December 2010. On the basis of this assessment, the overall procurement risk for the project was rated "moderate". NEA has prepared a procurement plan that was agreed with the Bank on March 3, 2011. The procurement plan will be available in the project's database and in the Bank's external website and will be updated annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. 67. Procurement under Component 3 will follow the procedures in use under the component of the PDP that is under implementation by AEPC. Procurement of the electro-mechanical equipment required for microhydro schemes and other renewable energy applications will be 16 handled on the basis of pre-qualification of contractors and consultants and on standard rates that are fixed annually. This model significantly increases the likelihood of high-quality work and accountability to communities, as the contractors and consultants have an interest in maintaining their AEPC status as pre-qualified contractors in this growth industry. 68. Financial Management. The most recent assessment of NEA's financial management capacity was carried out in December 2010. The assessment brought to light certain deficiencies in NEA's financial management (FM); these have been noted more at the entity level than at the project level. The overall project financial management (FM) in the context of the ongoing PDP is "unsatisfactory" due to limitation in institutional capability as well as the lack of adequate controls as pointed out in the audit report of NEA's 2008/09 accounts. Efforts are underway to address the FM challenges at the entity level through the institutional development component of the PDP. To address the qualified observations of the auditors and other systemic issues, NEA has agreed to implement an Action Plan, which IDA finds satisfactory, with the aim to address most issues by December 2012. 69. NEA has recently engaged an international consulting firm for the "Institutional Strengthening­Financial Management" assignment and the consultant has started work from December 2010. The consultant will help NEA to: (i) introduce reform in NEA's accounting framework; (ii) develop and implement a new Financial Accounting System; (iii) revise the accounting policy and manual based on International Accounting Standards; (iv) provide training to NEA staff; (v) assist in clearing the backlog of audit irregularities; (vii) prepare job descriptions of Finance and Accounts staff; and (viii) implement computerization of the financial management system in NEA. These interventions are expected to substantially mitigate the risks currently observed at the entity level. 70. Audit Arrangements. The audit of NEA's financial accounts as well as project accounts of projects funded by the Bank is the responsibility of the Office of Auditor General (OAG). For the fiscal year 2009/10, the Auditor General has appointed a private auditor to audit the financial accounts of NEA. This audit is delayed and, according to information provided by GoN, is expected to be completed in May 2011. To avoid such delays in the future, GoN and NEA have indicated their intention to request that the Auditor General appoints an independent (private) auditor acceptable to the Bank for the three-year period 2010/11-2012/13 to audit both NEA's financial accounts and project accounts. 71. The current experience of the PDP of which AEPC is an implementing agency indicates that the existing capacity for financial management at AEPC is adequate. AEPC has established good FM systems and sound financial management practices. The few deficiencies observed by the Bank team relate to improving the internal control system and maintaining of books of accounts and are being addressed through an Action Plan agreed under the PDP. D. Social 72. The proposed project crosses the territory of twenty-five Village Development Committees (VDCs) of four districts in eastern Nepal. It entails no population displacement. The physical components of the project that will lead to direct physical impacts involve 17 construction of substations, erection of approximately 300 towers, establishment of transmission lines, camps and storage. NEA has completed a Social Impact Assessment (SIA) and developed a Resettlement Action Plan (RAP) for the angle towers whose final locations have been fixed, and a Social Management Framework (SMF) for the rest of the towers and other project components whose final siting can be determined only during project implementation based on site-specific construction considerations. These documents have been disclosed in keeping with World Bank policy. Negative social impacts of the grid extension rural electrification component are expected to be negligible as the low-voltage distribution lines will be erected along established rights of way (roads, etc.) where possible and NEA uses standard instructions to contractors to minimize the negative impact of these investments. 73. For the Rural Enhanced Energy Services Component, AEPC will prepare Vulnerable Community Development Plans for each village in which microhydro schemes are installed, in keeping with the practice established under the ongoing Power Development Project. 74. The SIA was carried out during October-November 2010 along the corridor of VDCs impacted by the transmission line. The SIA revealed that farming and animal husbandry are the basic livelihood activities in the project area, with remittances from abroad also an important source of income. The project districts are home to as many as 70 castes and subcastes and janajati groups. The most populous janajati groups are the Limbu, Rai, Tamang and Magar. Extensive consultations with these groups as well as others in the project area indicated that the overwhelming majority supports the project and expects to benefit from the project through improved electrification and other opportunities. 75. A RAP was prepared to address the impacts of the construction of towers at the angle points. The social planning team carried out a census of the affected population and an inventory survey of the project impacts. A profile was established for every affected household that recorded their household demographic profiles, land holdings, livelihood and income sources and expected losses under the project. The project will require 2.8 ha of private land. These will impact a total population of 203 in 34 households. The 34 households belong to eight ethnic groups that, despite the difference in their ethnicity, exhibit a high degree of homogeneity in their economic livelihood activities and in how they access natural resources. The SIA concluded that a common approach is sufficient to address the land loss impact and to assist project-affected people in livelihood rehabilitation. The RAP described the entitlement policy in keeping with Nepal national and World Bank safeguard policies. The livelihood rehabilitation package consists of cash compensation at replacement cost and additional livelihood assistance. 76. NEA will be responsible for the implementation of the RAP. Regular internal monitoring will be carried out by project staff for effective project implementation. An independent agency will be engaged to monitor and evaluate safeguards aspects of project implementation. 77. The SMF was developed in keeping with relevant Nepal national and World Bank policies to address any adverse social impacts from activities whose impact boundaries can be determined only during implementation. It describes the legal and policy framework, basic principles and entitlement policy to be followed in the planning of these project activities. It also prescribes the procedures and requirements for public consultation as well as the monitoring 18 process. The SMF lays out the planning steps, review and approval process and the institutional setup and responsibilities for managing and monitoring the planning and implementation of any action plans. 78. A project Grievance Redress Committee (GRC) will be established under the project. The GRC's responsibilities and working procedures are described in the RAP. E. Environment 79. In November 2010, NEA completed, in accordance with national law, an Initial Environmental Examination (IEE) of the transmission line and substations. An Environmental Management Plan (EMP) was prepared on the basis of the IEE; these documents have been disclosed in keeping with World Bank policy. 80. There is no protected area or known conservation site in or around the project area including the transmission line alignment and substation sites. The identified environmental risks are limited to the vicinity of the transmission line and the substations and can be mitigated through simple mitigation measures that have been incorporated into the EMP. The overall environmental impact of the project is expected to be moderate and the project has been assigned Category B. 81. For the two rural electrification components, detailed site investigations that will be carried out in the implementation stage will determine whether grid extension or off-grid electrification is the optimal form of electrification for rural settlements in the project area. The potential negative environmental impacts of the low-voltage distribution lines are expected to be similar to that of the transmission line (described below), however with reduced scale and severity. NEA has several years of experience implementing rural electrification by grid extension and has established standard criteria to avoid or minimize the environmental impacts of the placement of the distribution lines and associated distribution transformers (through avoidance of forests, houses and other structures used by people, etc). The following measures have been agreed to identify and manage the potential environmental impacts of the rural electrification grid extension investments: (i) the Environmental Screening Criteria and Procedures, developed for the Community-based Rural Electrification Grid-Extension Component as part of NEA's Project Implementation Plan, will be used during planning, route/site selection, design and construction of each package, (ii) each community-based rural electrification proposal will be screened for potential environmental impacts; (iii) site-specific Environmental Mitigation Implementation Plans, if required, will be prepared, and (iv) compliance monitoring will be carried out for activities under this component as in the case of the transmission line component. 82. For the Rural Enhanced Energy Services Component, AEPC will follow the relevant environmental assessment guidelines. The guidelines for microhydro schemes provide checklists of potential environmental issues related to the siting of micro hydropower plants and construction and operation activities together with potential mitigation measures as well as a sample matrix for environmental assessment. Pre-investment environmental assessments (EAs) carried out under the PDP have been generally satisfactory and have exceeded safeguard 19 requirements by covering wider issues of environmental management at the village level. An EA is one of the three documents (viz; Technical Feasibility, EA and VCDP) that constitute the Detailed Project Report of a micro hydropower scheme. The EA recommends that mitigation measures that are directly related to the micro hydropower scheme's safety (e.g. landslides protection works around scheme components) are internalized within the scheme costs and Bills of Quantity. 83. The main adverse environmental impacts of the transmission line and substations as described in the IEE include: (i) impacts on forest and wildlife (33 km of the transmission line pass through community, government and private forests); (ii) increased soil erosion and slope instability and landslides due to vegetation clearance and excavation activities, particularly in the fragile Siwalik hill and steep sections of the Midhills; (iii) occupational health and safety (OHS) of workers working on the towers, at cable stringing, excavation on difficult hilly terrains, and electric shocks as well as health and safety of communities that could be impacted by workers' poor sanitation practices, HIV/AIDS risks from outside workers, and disposal of hazardous wastes; and (iv) impacts resulting from the substations and hazardous wastes generated there. The IEE estimates the total forest area affected by the project at about 59 hectares, out of which around 24 hectares belongs to 17 community forests at different places. The project will permanently occupy less than one hectare of the community forest; whereas approximately 23 hectares of community forests are affected due to restrictions on the height of trees and bushes in the right of way. The project will work with the forest users in implementing the mitigation measures (see Annex 10 for details). 84. The Environmental Management Plan (EMP) included in the IEE addresses the main expected adverse impacts of the proposed transmission line and substations. The identified mitigation measures will be detailed and customized for each site's specific conditions in the course of implementation. As a large number of tower locations will be fixed only during the early stage of construction, site-specific mitigation measures can best be designed and detailed during the construction survey. NEA, therefore, has taken a pragmatic approach in detailing site- specific mitigation measures: (i) NEA has initiated preparation of a sample Site-Specific Environmental Mitigation Implementation Plan (Sample SS-EMIP) building on the EMP included in the IEE; and (ii) NEA will prepare SS-EMIP for the entire length of the transmission line and substations as soon as locations are firmly defined. The sample SS-EMIP will helpful in initiate early and timely implementation of site-specific mitigation works. The environmental mitigation activities of the contractor as envisaged by the EMP are included in the Standard Bidding Documents. The estimated costs of the implemented of the EMP have been incorporated in the project costs (see Annex 10). 20 F. Safeguard policies Safeguard Policies Triggered by the Project Yes No Environmental Assessment (OP/BP 4.01) [X] [] Natural Habitats (OP/BP 4.04) [] [X] Pest Management (OP 4.09) [] [X] Indigenous Peoples (OP/BP 4.10) [X] [] Physical Cultural Resources (OP/BP 4.11) [] [X] Involuntary Resettlement (OP/BP 4.12) [X] [] Forests (OP/BP 4.36) [X] [] Safety of Dams (OP/BP 4.37) [] [X] Projects on International Waterways (OP/BP 7.50) [] [X] Projects in Disputed Areas (OP/BP 7.60)* [] [X] G. Policy Exceptions and Readiness 85. The audit reports for the on-going Power Development Project (Cr. 3766, Gr. H039, Cr. 4637, Gr. H506) have not been received by their due date. In accordance with the provisions of BP 10.02 Annex A, an exception from the Vice President of Operational Policy and Country Services, and the Vice President and Controller has been authorized for the presentation of this operation to the Board while the delayed audit reports are awaited. * By supporting the proposed project, the Bank does not intend to prejudice the final determination of the parties' claims on the disputed areas 21 Annex 1: Sector Background NEPAL: Kabeli Transmission Project 1. Sector dimensions. Nepal's level of development with respect to energy is low by global and South Asia regional standards. Nepal's only significant commercial energy resource is its hydropower potential, which is most frequently estimated as 83,000 MW (theoretical) and 42,000 MW (economic).8 Nepal possesses no fossil fuel resources of note. 2. An estimated 88% of the country's total primary energy demand is met by traditional (non-commercial) forms of energy (fuel wood, agricultural waste and animal dung), reflecting the overwhelmingly rural distribution of population in Nepal and the virtual absence of relatively clean, commercialized forms of energy outside of urban areas. This heavy reliance on traditional energy sources brings with it the well-known problems of limited opportunities for rural economic development; environmental degradation; inefficiency in provision of energy services; and health impacts, particularly for women and children. The rest of Nepal's energy balance is: imported petroleum products (8.2 percent), electricity (1.8%), coal (1.8%), and renewable energy (0.5 percent). 3. About 46% of the population in Nepal is believed to have access to reliable sources of electricity (grid and off-grid), with a significant disparity between access levels in urban Nepal (around 90%) and rural Nepal (around 30%).9 4. Despite the country's significant hydropower potential, the power system is small and highly supply-constrained. The installed power generation capacity is about 698 MW, the peak demand is 885 MW and the customer base consists of 1.85 million consumers. The vertically integrated national power utility, the Nepal Electricity Authority, owns 473 MW of hydropower stations and 53 MW of diesel fuel based units which are connected to the grid, and 5 MW of isolated small hydropower stations and two small isolated solar power stations. Independent power producers own the remaining 167 MW of grid-connected capacity. 5. The transmission system consists of 1,563 km of 132 kV lines and 355 km of 66 kV lines. The total substation capacity for transformation from 132 kV and 66 kV into lower voltages amounted to 1,415 MVA. Two 220 kV lines (147 km) and two 132 kV lines (158 km) are under construction. Load dispatch is centrally controlled through a Load Dispatch Center10 that connects all 66 kV and above sub-stations and generating stations in Nepal. 6. In FY 2010, the energy made available to the national grid was 3,689 GWh consisting of NEA's own generation (57.4 percent), power purchased from the IPPs in Nepal (26 percent) and power imported from India (16.6 percent). Most of NEA's own generation came from its hydropower units and less than 0.6 percent was from its diesel units. Total billed sales amounted 8 These are probably obsolete estimates; re-optimization of power production and the possibility of open access to the deregulated power markets in India suggest that the actual hydropower potential could be much higher. 9 In Nepal, as in many countries, data on access to electricity are scanty and somewhat contradictory. The challenges to accurately measuring access to electricity are many in Nepal and include the largely rural distribution of population, the difficult terrain of the country and the dynamic nature of the question. 10 Sinaut Spectrum 4.2.3. 22 to 2,678 GWh indicating system losses of 27.4 percent of which about a third is considered attributable to non-technical losses (such as theft). 7. In the total number of customers, households had a share of about 95 percent, while industry and irrigation had each a share of less than 2 percent. In the total electricity sales (in GWh), households had the largest share (41.4 percent), followed by industries (37.6 percent), and commercial consumers (7.2 percent). Exports to India amounted to about 2.8 percent of the total sales. Total revenue from sale of electricity amounted to about Nrs. 18 billion, of which 41 percent came from households, 35.2 percent came from industry, 9.9 percent came from commercial consumers, and 2.78 percent came from power exports to India. 8. Collections are reported to be around 95% of the billed sales for most consumer categories. However collections from local bodies for street lighting (which has a share of about 2.5 percent of the total sales) have been a chronic problem and NEA has periodically been forced to write off large amounts of receipts. Collections from government offices and agencies have also often been problematic. 9. Past Growth and Load Forecast. During the decade FY 2001-FY 2010, compounded annual growth rates were 9.5 percent in peak demand, 7.4 percent in energy sales, and 7.9 percent in energy made available to the grid. At the same time the number of consumers grew at 10.6 percent a year. 10. Load forecasts are made by NEA based on econometric modeling but without any end- use analysis and bottom-up approach to supplement it. According to NEA's latest forecast, the peak demand is expected to grow from 967 MW in FY 2011 to 3679 MW in FY 2028 at a compound annual rate of 8.2 percent. The annual growth is expected to be greater at 8.8 percent during FY 2011-FY 2020 and at a slower rate of 7.6 percent during the remaining 8 years. The energy requirements are expected to grow from 4,431 GWh in FY 2011 to 17404 GWh by FY 2028 at a compounded annual rate of 8.4 percent. 11. To meet the forecast load at least partially NEA has under construction four new hydro projects with a total installed capacity of about 500 MW. Eight other new projects with a total installed capacity of 1,422 MW (including some storage projects) are in the planning and preparation stage. In addition, the private sector is expected to add substantial new capacity including a few large export-oriented projects (see private sector below). 12. Power exchanges with India. The existing transmission system has three 132 kV links and several 33 kV and 11 kV links to the grids of adjoining State Electricity Boards of India operating in a radial mode. The 33 kV and 11 kV links have limited transfer capacity and were intended to handle a few MW of utility-to-utility exchanges needed for isolated communities on either side of the border. A ceiling of 50 MW for such exchanges was envisaged in 1991. Most of them are non-operational now or are being phased out, and exchanges take place now largely through the three 132 kV lines. In 2001 the level of exchange was agreed to be increased to 150 MW to be handled through higher voltage lines to be constructed for this purpose and more importantly on a commercial basis. 23 13. Trading arrangements were agreed with the Power Trading Corporation (PTC) of India. One of the three 132 kV lines (completed two years ago) is meant to supply 70 GWh of power from Tanakpur of India free of charge to the far western region of Nepal under the Mahakali Treaty between the two countries. The power flows from India are based on three types of arrangements: (a) Provisions of the River Treaty; (b) Power Exchange Agreements; and (c) Power Trade arrangements with PTC of India. The volume of power exchange between the two countries is given in Table 1 below. Table 1: Volume of Power Exchanges between Nepal and India (GWh) FY 2006 FY 2007 FY 2008 FY 2009 FY 2010 Imports from 266.23 328.83 425.22 356.46 612.58 India (GWh) Exports to 96.55 76.87 60.10 46.38 74.48 India (GWh) 14. The increasing volume of imports from India is reflective of growing power shortages in Nepal and the result of the recently commissioned new 132 kV line. As noted earlier, in FY 2010 such imports contributed to 16.6 percent of the total energy available to the Nepalese grid. 15. Role of private sector. The private sector has a noteworthy presence in Nepal's power sector. Twenty-two IPPs own 167 MW of hydropower stations and sell their output to NEA on the basis of Power Purchase Agreements (PPAs). Butwal Power Company owns generating stations and a distribution system with over 23,000 consumers. About 107 km of transmission line is owned by the private sector. There are also a number of community-managed small distributions systems scattered across the country. The role of the private sector in the power sector will become even more prominent as eight more IPP projects with a total capacity of 47.3 MW are under construction, while PPAs have been concluded with 27 IPPs for new or expanded capacity totaling 136.2 MW. In addition, licenses for site survey and project preparation have been issued to private investors by the government in respect of 28 export-oriented hydropower projects (with capacities ranging from 102 MW to 900 MW) with a total capacity of 8,246 MW. 16. Sector institutions and market structure. The Ministry of Energy is responsible for energy sector policy formulation and sector oversight. With the Ministry, the Department of Electricity Development (DOED) is responsible for issuing licenses, preparing large hydropower projects, attracting the private sector and setting electricity standards. The inter-ministerial Water and Energy Commission (WEC) is responsible for coordination of water-energy issues and integrated energy planning. The Electricity Tariff Fixation Commission (ETFC) determines electricity tariffs. The Alternative Energy Promotion Centre (AEPC) under the Ministry of Environment is responsible for small-scale renewable energy applications. 17. The Nepal Electricity Authority is a vertically integrated state-owned national power utility which owns most of the transmission system and distribution system and a major portion of the country's generation assets. It acts as single buyer, buying the full output of the IPPs based on PPAs and importing power from India and selling this power along with its own output. NEA handles load dispatch and is responsible for power export. 24 18. Tariffs. Retail tariffs are fixed by the Electricity Tariff Fixation Commission which was established under the Electricity Act of 1992 with seven members including a chairman from outside the government and the Director General of DOED as its member secretary. Its mandate is to determine retail end-use tariffs for customers served by the grid-connected distribution systems. In the small isolated systems tariffs are determined by the owners of the generation assets. The Commission has not revised tariffs since 2001 and the current system-wide average tariff stands at about NRs 6.71/kWh (about 8.9 US cents/kWh). Industrial consumers at 11 kV and above have the option to use a time-of-day tariff which provides different rates for peak hours, off-peak hours, and normal hours. Key Power Sector Development Issues 19. The Nepal power sector faces several complicated, interrelated development challenges, which are described below. 20. Increasing access to electricity. While access to electricity is high in urban areas (90% or higher), it is low in rural areas of Nepal, where most of the population lives. Many communities, moreover, are small and scattered over mountainous and difficult terrain, rendering efforts to increase the overall level of access to electricity more difficult and more costly. While this challenge is mitigated to some extent by the high rate of urbanization in Nepal today, it is anticipated that for many years to come Nepal will be a largely rural country. Bringing the benefits of electricity to rural Nepalis in a timely and cost-effective manner is one of the most significant development challenges facing Nepal today. 21. Financial restructuring of NEA. NEA is loss-making and heavily indebted. NEA's financial position has deteriorated sharply in recent years, the result of rapidly rising costs and the absence of increases in retail tariffs since 2001, among other factors (see Annex 9). NEA is unable to service its debts, let alone generate funds for urgently needed capital rehabilitation and expansion programs. Under the prevailing conditions, NEA incurs a substantial loss for every kilowatt-hour of electricity it sells, which provides a disincentive to increase supply of electricity at a time of acute deficit of electricity. A financial restructuring plan has been drafted and is under review by GON. The large scale of this problem suggests that its resolution will take some time. For now, the dire financial condition of NEA and the absence of tariff adjustments remain serious obstacles to power sector development in Nepal. 22. Improving the environment for private investment. While successive governments in Nepal have expressed a commitment to attracting the private sector to develop hydropower projects, financial and implementation constraints have not allowed the public sector to play an effective role in building the common infrastructure (roads and transmission corridors) needed to stimulate hydropower development. The rationale for public development of such projects is compelling as they usually bring high economic returns and it is not efficient to burden individual projects with the costs of this common infrastructure. In addition to physical infrastructure, the public sector plays a critical role in determining policy and procedures; under current conditions in Nepal, progress in this area has also been limited. Attracting and retaining private investment will require Nepal to replace the high-level declamatory commitment to private participation in the power sector needs with provision of common infrastructure, procedural streamlining, regulatory improvements and structural reforms. 25 23. Increasing storage capacity. Nepal's power system is heavily dependent on run-of-river type of hydropower plants with little or no storage capacity to respond to seasonal variations in river flows and in power demand. The river flows and, hence, the generation capability of the power stations, are substantially lower in the period December-May than in the period June- November. However, the demand for power peaks in the winter, when supply capacity is lowest. This mismatch between supply capability and demand is the root cause of the severe load- shedding in Nepal. Increased storage would enable Nepal to make use of surplus water in the wet season and to respond more efficiently to fluctuations in demand. The development of increased storage capacity is a formidable challenge with complex technical, financial, environmental and social dimensions.11 24. Increasing cross-border transmission capacity. Increased electricity trade with India will benefit Nepal, in the short term allowing for critically needed imports to address the electricity crisis and, in the longer term, providing a market for the surplus energy from generation projects in Nepal that are expected to come on-line in the future. Strengthening of the cross-border transmission infrastructure and the associated capacity-building to allow Nepal to maximize the benefits of power export are major development priorities for the Nepal power sector. 25. Government's Policy and Sector Development Approach. Government of Nepal has advanced a policy approach to promote the addition of hydropower generation capacity, including run-of-river stations as well as storage plants and public as well as private projects. Projects to meet the demand of grid-connected consumers as well as small sized (off-grid) micro and mini hydro projects that cater to isolated communities are being developed. Since 2000, alternative energy approaches based on solar energy, bio-gas, and biomass are also being pursued using limited state subsidies. The Rural Energy Policy (2006) seeks to promote modern technology in relation to the above options and improved household-based subsidy mechanisms. The approach to the hydropower projects is outlined in the Hydropower Development Policy of 2001, which emphasizes development of hydropower not only to meet domestic demand but also to earn export revenues by exporting electricity. This policy further emphasizes the role of the domestic and foreign private sector, as well as public-private partnerships, to develop such projects, and advocates the adoption of investment-friendly, transparent, and streamlined procedures to attract private parties for this purpose. The Hydropower Development Policy rationalized royalty and tax incentives for such projects. 26. To fully implement the various aspects of the Policy and to improve the sector regulatory arrangements in the country in 2008 a new draft Electricity Act and draft Nepal Electricity Regulatory Commission Act were submitted to the Constituent Assembly where they have since been under review. 27. In 2009 the government formulated the 38-Point Electricity Crisis Management Action Plan which is currently under implementation. The Action Plans include demand- and supply- side investments aimed at alleviating load-shedding in the short and medium terms. In addition, the Action Plans include longer-term investments, including notably development of cross- 11 Recently, there have been some indications of an interest in taking up for consideration large-scale storage projects, both on the government-to-government level in the case of "megaprojects" such as the proposed Pancheshwar Dam on the border between Nepal and India, and with the objective of attracting private sector involvement in the sector, as in the case of the proposed Budhi Gandaki HEP storage plant. Such large projects 26 border transmission links with India and development of large hydropower generation projects. The Action Plans also includes a focus on developing new transmission corridors to facilitate the development of new generation projects which require transmission capacity to evacuate their power to the national grid. 27 Annex 2: Major Related Projects Financed by the Bank and/or other Agencies NEPAL: Kabeli Transmission Project WORLD BANK AIDED PROJECTS IN THE ENERGY SECTOR OVER LAST TEN YEARS Board IP DO Project Name Status Approval rating rating Sector Issues Addressed Power Development Ongoing 22 May 2003 U S Develop Nepal's hydropower potential to help meet Project electricity demand; improve access of rural areas to electricity services; and promote private participation in the power sector. Village Micro Hydro Ongoing 30 June 2007 Carbon offset project that aggregates emission reduction Project credits from off-grid microhydro schemes. Biogas Program Ongoing 2 June 2006 Carbon offset project that seeks to increase access to modern household cooking fuel from renewable energy sources and reduced emissions of carbon dioxide. Nepal-India Electricity Planned Development of regional electricity markets; provision of Trade and Transmission additional capacity to import electricity in Nepal to help Project contribute to the growing demand for electricity. Ratings: HS= Highly satisfactory; S=Satisfactory; MS=Moderately Satisfactory; MU=Moderately Unsatisfactory; U=Unsatisfactory; HU=Highly Unsatisfactory; NA=Not Applicable; NR=Not Required ASIAN DEVELOPMENT BANK (ADB) AIDED PROJECTS IN THE ENERGY SECTOR OVER THE LAST TEN YEARS Project Name Type Approval Date Executing Sector Issues Agency Energy Access and Loan and 27 Nov. 2009 Nepal Electricity Reliable and energy efficient power supply with Efficiency Improvement Grant Authority increased access and operational efficiency. Project Rural Electrification, Loan 21 Dec. 1999 Nepal Electricity Financial sustainability of NEA; connection of about Distribution and Authority 123,000 rural households; and reduction of NEA Transmission Project transmission and distribution losses. 28 Annex 3: Results Framework and Monitoring NEPAL: Kabeli Transmission Project Results Framework PDO Project Outcome Indicators Use of Project Outcome Information The development objectives of the Increased transmission capacity in To review, monitor and verify Project are: (i) to support the the Integrated Nepal Power System. achievement of the PDOs addition of transmission capacity to the Integrated Nepal Power System; Number of communities that have and (ii) to provide access to received access to enhanced off-grid electricity and cooking fuel to energy services under the project. communities in the area of the Kabeli 132 kV transmission line. Intermediate Outcomes Intermediate Outcome Use of Intermediate Indicators Outcome Monitoring Component 1: the Kabeli Corridor Timely and satisfactory progress Monitor progress of project 132 kV Transmission Line. toward delivery of Component 1 implementation and impact in outputs, as planned, including achieving project objectives. implementation of the contracts for construction of the transmission line and substations; the RAP; the EMP. Component 2: Community-based Number of new households Monitor progress of project Rural Electrification-grid extension connected to the grid in Panchthar implementation and impact in and Ilam Districts (total). achieving project objectives. Component 3: Rural Enhanced Off-grid rural electrification Monitor progress of project Energy Services schemes, % of agreed program implementation and impact in completed. achieving project objectives. 29 Arrangements for results monitoring Data Collection and Reporting Baseline MTR ICRR Frequency and Data Collection Responsibili Outcome Indicators Reports Instruments ty for Data Collection Increased power supply: Trimesterly Reports from NEA Increased transmission capacity in the Integrated Nepal Power 0 MW 0 MW 150 MW progress NEA and Bank System. (capacity) implementation supervision report (some missions outcomes indicators will be available only after the contributing project components are completed) Number of communities that have received access to enhanced 0 10 25 Trimesterly Reports from AEPC off-grid energy services under the project progress AEPC implementation report Output indicators by component Component 1: Construction of Kabeli Corridor Line (132kV): Trimesterly report Reports from NEA Foundation Works Completed 0% 50% 100% on implementation NEA and Bank Towers erected 0% 40% 100% progress supervision Kilometers of conductors installed 0% 25% 100% missions Damak substation construction 0% 60% 100% Ilam substation construction 0% 50% 100% Phidim substation construction 0% 20% 100% Kabeli substation construction 0% 10% 100% Financial Disbursement (% of projected cost to completion) 0% 30% 100% Component 2: Community-based Rural Electrification-Grid Extension: Number of new households connected to the grid in 0 1,000 5,200 Trimesterly Reports from NEA Panchthar and Ilam Districts (total) progress NEA and Bank implementation supervision report missions 30 Data Collection and Reporting Baseline MTR ICRR Frequency and Data Collection Responsibili Outcome Indicators Reports Instruments ty for Data Collection Component 3: Rural Enhanced Energy Services Component: Trimesterly reports Reports from AEPC AEPC and Bank supervision missions Microhydro schemes, total new capacity installed (kW) 0 100kW 250kW Toilet-attached biogas (cooking fuel) (no. of new schemes) 0 80 200 Solar home system (no. of new schemes) 0 100 300 Institutional solar systems (no. of new schemes) 0 5 15 * The breakdown of new households connected to the grid or provided with off-grid electricity will be determined by detailed studies to be carried out during implementation. 31 Annex 4: Detailed Project Description NEPAL: Kabeli Transmission Project Component 1: Kabeli Corridor 132 kV Transmission Line and associated infrastructure 1. The Kabeli Corridor 132 kV Transmission Line will consist of an approximately 90-km double circuit transmission line that will be strung from the Damak substation (Jhapa District) and terminate at Kabeli substation in Panchthar District. Optic Fibre Ground Wire (OPGW) will be provided with the new transmission line while the existing shielded wire in the adjoining Duhabi-Anarmani transmission line section will be replaced. In addition, there will be substations at Ilam and Phidim. The transmission line will be looped in and out at Ilam and Phidim substations. One circuit of the transmission line will be terminated at Pinaseghat (the proposed location of the Kabeli "A" HEP for which IDA funding has been requested) and the other circuit will be terminated in the Kabeli substation in Amarpur VDC of Panchthar district. The transmission line will pass through hills in the Churia range, valleys in the hilly regions, sparse settlements and forests. 2. The transmission line will entail erection of approximately 300 towers, associated foundations and around 500 km of conductor stringing, and will be constructed under a single turn-key contract. The Damak substation is being constructed under a single contract funded by the GON and the other substations will be constructed with IDA funding. 3. The work to be carried out by the contractor for the transmission line will include: (i) detailed check survey including final route alignment and profiling, right of way identification, tower spotting, optimization of tower locations, soil resistivity measurement and geotechnical investigation; (ii) engineering, design, prototype tower testing, fabrication and supply of all type of transmission line towers including bolts, nuts and washers, hangers, D-shackles and all types of tower accessories like phase plate, circuit plate, number plate, danger plate, anti climbing device, (iii) supply of conductor, insulator, optical fiber ground wire (OPGW), hardware fittings, and conductor & OPGW accessories, (iv) transporting of all materials, equipments to the related Site(s), storage and equipment preservation at related Site including all services to be required at customs (i.e. unloading, loading, storing at customs stores and other services at customs including hiring of a suitable storing area), (v) Design of foundations for different soil conditions for different type of towers, classification of foundation for different type of towers and casting of foundation for tower footings as per approved drawings; (vi) erection of towers, tack welding of bolts and nuts including supply and application of zinc rich primer & enamel paint, tower earthing, fixing of insulator strings, stringing of conductors and earth wires along with all necessary line accessories, (vii) replacement of existing shield wire by OPGW for Duhabi­Anarmani section, (viii) installation of Optical fiber terminal equipment, (ix) commissioning, site and acceptance testing, (including type tests required)including supply of the measuring instruments and testing equipment necessary for testing, (x) providing of the special tools, instruments and devices to be used in erection, testing, (xi) training of the personnel as agreed with NEA, (xii) Submission of monthly progress reports, (xiii) all precaution to be taken for safe erection and operation, (xiv) connection between substation take-off structure and dead-end towers, (xv) environmental management as detailed in the contract, and (xvi) other items not specified above but required as per the bid forms and price schedules in use for the contract. 32 4. The entire stringing of the conductors and OPGW shall be carried out by the tension stringing technique; depending on the contractor's experience, stringing by helicopter may be permitted. In hilly or mountainous terrain or in thick forest areas, stringing work may also be carried out manually. 5. Geo-references: Latitude Longitude Kabeli Bazaar (village) 27°16'40" N 87°44'56" E Phidim (town) 27°08'27.99" N 87°45'50.52" E Ilam (town) 26°54'28.52" N 87°55'32.73" E Damak (town) 26°41'55.51" N 87°37'36.57" E Component 2: Community-based Rural Electrification--Grid Extension 6. The funds of this component will scale up NEA's existing Community Rural Electrification Program by extension of the existing low-voltage grid in Ilam and Panchthar Districts. Under this program, NEA has extended the grid to provide access to electricity to more than 150,000 households since 2003. GON through NEA covers 80% of the capital costs and communities provide the remaining 20%. After the grid extension is completed, the assets are turned over to the community which owns and manages the assets henceforth (with provision of initial technical assistance from NEA). NEA provides electricity to each community in bulk and the community is responsible for paying NEA for its consumption as per the bulk meter. Field investigations examined the need for electrification in communities living within a zone defined by 2.5 kilometers on either side of the alignment of the transmission line (for a total of 5 kilometers). Table 1 presents the results of the field investigations by district. District Electrified (HHs) Not electrified % (HHs) electrified Jhapa 468 0 100% Ilam 4,540 1,936 70% Panchthar 1,360 3,785 26% Total 6,368 5,721 53% 7. This component will provide access to electricity to households in the defined zone that presently do not have access to electricity. Detailed site investigations will determine whether grid extension or off-grid electrification is the optimal form of electrification; detailed design of the distribution system will also be carried out after these site investigations. The component will fund the construction of 11 kV distribution lines, 400/230 v distribution lines, distribution transformers and associated engineering services and technical assistance. The component will be implemented by NEA's Distribution and Consumer Services Business Unit (East). The implementation of this component will be phased to coordinate with the construction schedule of Kabeli, Ilam and Phidim sub-stations. 33 Component 3: Rural Enhanced Energy Services Component 8. This component will provide funding for off-grid rural electrification of communities for which grid extension is not a feasible option as well as for improved cooking fuel through biogas applications. The component will also fund technical assistance to facilitate project implementation and will support a pilot effort to connect village microhydro schemes to the grid. The community-level energy schemes that will be supported under this component are established programs at AEPC. The table below details the types of energy schemes that will be supported at the community level under this component and the specific targets that have been agreed for each type of scheme. Energy scheme Targets Electrification Microhydro 250kW of new microhydro generation capacity to be installed to benefit 2000 HHs in 14 VDCs in Ilam and Panchthar districts Solar ­ homes 300 HHs to be electrified in Ilam and Pancthar districts Solar ­ schools and health 10 school and 5 health posts to be electrified in posts Ilam and Pancthar districts Improved cooking fuel Biogas 200 HHs to be provided with toilet-attached biogas stoves for cooking 34 Annex 5: Project Costs NEPAL: Kabeli Transmission Project Local Foreign Total Project Cost By Component and Activity (in thousand USD) Component 1: Kabeli Corridor 132 kV Transmission Line Component Land acquisition, R&R 3,000 0 3,000 Environmental Management Plan 900 0 900 Kabeli Corridor 132 kV TL 0 12,653 12,653 Substations: Ilam, Phidim, Kabeli 0 9,722 9,722 Substation: Damak 0 3,556 3,556 Minor civil works 468 0 468 Office equipment 28 0 28 Project management* 292 486 778 Technical assistance 0 319 319 Environmental Monitoring 139 0 139 Component sub-total (not including contingencies and IDC) 31,563 Component 2: Community-based Rural Electrification-Grid Extension Component Equipment supply and installation (incl community contributions) 1,042 4,167 5,209 Project management* 0 194 194 Technical assistance 306 0 306 Component sub-total (not including contingencies and IDC) 5,709 Component 3: Rural Enhanced Energy Services Component Community Subprojects (incl community contributions) 1,760 0 1,760 Technical assistance 213 0 213 Grid connection pilot 0 83 83 Incremental operating costs of AEPC/project mgmt 260 0 260 Component sub-total (not including contingencies and IDC) 2,317 Subtotal (before financing and IDC) 39,589 Taxes and Duties 993 993 Project development cost 1,037 1,037 Physical and price contingencies 3,457 3,457 Total excluding IDC 45,076 Interest During Construction and Financing Charges 2,607 2,607 Total Cost including IDC and Financing Charges 47,683 * Part of project management costs are captured under the NIETTP which will fund the Owner's Engineer whose scope of work includes the Kabeli Transmission Line. 35 Annex 6: Implementation Arrangements Nepal: Kabeli Transmission Project 1. Components 1 and 2 will be implemented by NEA and Component 3 will be implemented by AEPC. Both agencies have several years of experience implementing components of the ongoing IDA-funded Power Development Project that are similar to their respective components under the proposed project, for which they have drafted project implementation manuals. 2. Coordination between components. The primary component from a planning and implementation perspective is Component 1, as the final alignment of the transmission line (which can be determined only during the construction process) will determine the detailed planning of the rural electrification components which will be carried out after commencement of the construction of the transmission line. An NEA-AEPC coordinating committee will be established to coordinate the two community-based rural energy components. The detailed planning for these two components is a linked process, as communities that cannot for whatever reason be provided access to electricity through grid extension will be considered for off-grid electrification and enhanced cooking fuel investments. 3. Components 1 and 2. NEA's Grid Development Business Unit will be responsible for the implementation of the Kabeli transmission line and substations (component 1) and NEA's Distribution and Consumer Services Business Unit (East) will have oversight over the rural electrification/grid extension component (component 2). On the entity level and for purposes of conveying monitoring reports, audits, etc., to the Bank, the two components implemented by NEA will be coordinated by the Grid Development Business Unit (see Annex 7). 4. For component 1, NEA has formed the Kabeli Corridor 132 KV Transmission Line Project Unit (the Kabeli Project Unit) which is headed by an experience transmission engineer. The Kabeli Project Unit has oversight for all aspects of project development and implementation, including: preparation of work plans and budgets; preparation of estimates, tendering and contracts; implementation and monitoring of environmental and social safeguards; supervision of contracts; approval of contractor's invoices; progress reporting; participation in commissioning and approvals; preparation of acceptance certificates; assessment of infrastructure at the end of the contractors' liability period. The Kabeli Project Unit is also responsible for acquiring land required for construction of substations, transmission line foundations and right of way (RoW), and forest clearance. 5. The Kabeli Unit Project Manager reports to the Director of the Transmission Line and Sub-Station Construction Department. The General Manager of Grid Development Business Unit bears overall responsibility for the transmission system. Within the Kabeli Project Unit, there are three sub-units at the corporate level dealing with Administration, Finance and Public Relations and Environment Mitigation, and three sub-units at the field level ­ Damak Sub-unit, Ilam Sub-unit and Phidim Sub-unit. Each of the central sub-units will be headed by the respective unit chiefs, and each of the field level sub-units will be headed by qualified engineers. The Finance Officer heads the Finance Sub-unit. The Project Manager will overall coordinate procurement activities and will be a contact point for procurement-related matters. Each of the three field level units manager will oversee the procurement function of the respective unit. 36 NEA has engaged an international Procurement Advisor who will provide overall support to various projects funded by IDA contribute to procurement capacity-building of NEA staff. 6. An Environmental and Social Unit (ESU) will be constituted under the Kabeli Project Unit with two sub-units, the Environmental and Social Implementation Sub-unit (ESI-SU) and Environmental and Social Monitoring Sub-unit (ESM-SU). Consisting of staff of NEA, the ESI- SU will be responsible for implementing environmental measures beyond the contractor's responsibility as well as for coordinating with other agencies. 7. Under the supervision of the Kabeli Project Unit, the construction of the transmission line, substations and local distribution lines will be carried out by contractors who will have responsibility for day-to-day management of their respective subprojects during the construction phase. The contractor's management team for the transmission line will consist of a project manager, a site manager and a civil engineer. In addition to the primary responsibility for construction of the physical assets, the contractors will have certain contractual obligations with respect to environmental management. 8. Component 2 will scale up NEA's existing Community Rural Electrification Program (CREP), which provides for grid extension, and will be implemented in keeping with the procedures established for this program. The Distribution and Consumer Services (DCS) Business Unit (East) will be responsible for managing all aspects of the component, including design; contracting and contract management; land acquisition and safeguards; payments to contractors; and reporting and monitoring. The implementation methodology will be based on turnkey contracts, with which NEA has extensive experience under CREP and which greatly ease the implementation burden faced by NEA compared to the alternative approach of numerous contracts requiring coordination. 9. Component 3. AEPC will implement this component under the procedures established for the agency's community-level programs such as the REDP which is receiving IDA funding under the ongoing PDP. A project manager at AEPC has been appointed for overall management of this component and will coordinate, as needed, with the REDP (microhydro), Energy Sector Assistance Programme (ESAP) (solar) and the Biogas Support Programme (BSP), in the course of the implementation of the component. Community energy programs are implemented through the District Development Committees (DDCs), as per the Local Self- Governance Act (2000). District Energy and Environment Sections (DEES) have been established under the DDCs, with the mandate to support local-level capacity-building, planning and M&E, creation of District Energy Funds (DEF), and to undertake resource mobilization through supporting organizations, financial institutions and the private sector. Funds are channeled from AEPC to the DEF. A local NGO will be hired as a Support Organization through a competitive selection process and will work with participating communities to help them establish Community Functional Groups which will oversee the implementation of the community-level energy project. Monitoring and evaluation of outcomes/results 10. NEA and AEPC will be responsible for the regular monitoring of the implementation of their project components. Each agency will submit trimesterly implementation progress reports 37 in an agreed format to the World Bank no later than 45 days after the end of each trimester. The trimesterly progress reports will cover the progress and expected completion dates for works and equipment supply contracts, progress on institutional components, implementation of the EMP, RAP and GAAP, and technical assistance activities funded under the project. The reports will include the following analysis and data: (a) comparison of actual physical and financial outputs with forecasts, and updated 6-month project forecasts; (b) project financial statements, including sources and application of funds, expenditures by category statement, and special accounts reconciliation statement; and (c) a procurement management report, showing status and contract commitments. 11. Each agency will also prepare annual reports by no later than August 31 of each year of project implementation. The reports will cover: (a) the progress of each component, implementation of key features of the EMP, RAP and GAAP, key performance indicators, operation of project facilities, and financial statements; and (b) the Annual Work Plan for implementation, annual funds required for implementation with breakdown by each source of funding, an updated disbursement profile, planned actions for mitigating negative effects during construction, and target indicators for the coming year. The mid-term review of the project is planned for August 2013. Each agency will submit to the Bank an Implementation Completion Report (ICR) for its respective components within three months of the project closing date. 12. For the NEA components, the ESM-SU will be responsible for environmental monitoring during construction, and to some extent, will also serve the purpose of third party monitoring. An independent consultant will be recruited as ESM-SU. The IEE recommends two-monthly compliance monitoring of the implementation of mitigation measures during construction phase. An independent agency will be engaged to undertake half yearly external monitoring of the RAP implementation. 13. The diagram below illustrates the implementation arrangements for the project. 38 NEA Board AEPC Board Grievance Redress Committee Managing Director Executive Director National Program Managers ­ REDP, GM, Grid Development GM, DCS (East) ESAP, BSP Project Manager, Director, TLCD Director, DCS Kabeli Component Kabeli Project Uni Project Manager, PRO Project Manager Rural Electrification NEA-AEPC Rural Technical Account Electrification Kabeli Coordination Committee Monitoring Administration Procurement Advisor Energy Development Support Organization/ EMSU Officer/ Technical Community mobilizer Officer co-coordinator/ District Energy and Community mobilizer Damak Unit Ilam Unit Phidim Unit Environment Section (DEES), Panchthar, Ilam 39 Annex 7: Financial Management and Disbursement Arrangements NEPAL: Kabeli Transmission Project Country Financial Management Environment 1. The Nepal Country Financial Accountability Assessment that was conducted jointly by the Government of Nepal (GON) and IDA in 2002 and subsequently updated in 2005, concluded that the failure to comply with the impressive legal and regulatory fiduciary framework makes the fiduciary risk in Nepal "high", but the risk is similar to that in most developing countries. The situation has not significantly changed since then. The Public Financial Management (PFM) Review (May 2007) reaffirmed that the PFM system in Nepal is well designed but unevenly implemented. The PFM benchmarks established in 2008 based on the Public Expenditure and Financial Accountability (PEFA) framework led by the government with technical assistance of the World Bank have endorsed the continuing "high" fiduciary risk with several PFM indicators rated at the low end of the scale. The joint DfID and World Bank progress reviews carried out in September 2008 and in February 2009 revealed little progress in the implementation of the PEFA Action Plan. Some of the prevailing country level risks include deteriorating control environment, insufficient monitoring, increasing threat of collusion and intimidation to bidders, weakening oversight agencies with the absence of institutional leaders which include the Auditor General and the Chief Commissioner of the CIAA have a wider impact on the country's accountability environment including at the sectoral or project level. 2. While these challenges prevail, improving overall financial accountability framework remains a high priority of the government. Frequent transition of political leadership in the government has been the main cause of slow movements in accelerating PFM reforms as envisaged by the PEFA Action Plan. Examples of the government's commitment to improving the PFM framework even during the challenging transition period include the promulgation of the Public Procurement Act and Public Procurement Regulations in 2007, amendment of the Financial Administration Regulations in 2007, and the self-assessment of various PFM Indicators as per PEFA Guidelines in 2007. Implementation of these frameworks through an integrated PFM reform package through a set of mutually supportive actions that are realistic and can generate positive impacts is critical to mitigate fiduciary risks. Such a package has been reflected in the PFM Strategy Document prepared by the government. A high level steering committee chaired by the Finance Secretary provides the necessary forum for close monitoring on implementation with continuation of collaborative support from development partners. Financial Management Assessment of Implementing Agencies NEA for Components 1 and 2 and AEPC for Component 3 3. The Nepal Electricity Authority (NEA) and the Alternative Energy Promotion Center (AEPC) will be the implementing agencies of the proposed Kabeli Transmission Project. Both agencies have a long working relationship with the Bank in implementing various power projects, including under the ongoing Power Development Fund Project. 40 4. The World Bank is supporting energy sector development in Nepal through the ongoing Power Development Project (PDP), where NEA is a major beneficiary of the IDA funds. The overall project financial management (FM) rating of the ongoing PDP is "unsatisfactory" since the issues pointed out in the audit report of NEA at the NEA entity level have not been addressed to date. However, efforts are underway to address these issues: NEA has prepared and is implementing an Action Plan to address financial management deficiencies at the utility. 5. NEA has recently recruited an international consulting firm for the "Institutional Strengthening ­ Financial Management" assignment and the consultant has mobilized in December 2010. The consultant will help NEA to: (i) introduce reform in accounting framework of NEA, (ii) develop and implement new Financial Accounting System, (iii) revise the accounting policy and manual based on International Accounting Standards (IAS), (iv) provide training to NEA staff, (v) assist in clearing backlog of audit irregularities, (vii) preparation of job description of Finance and Accounts staff, and (viii) computerization of financial management system in NEA. These interventions are expected to substantially mitigate the risks currently observed at the entity level. The implementation of the Action Plan is being supported by the institutional development component of the Power Development Project. It is to be noted that, due to delay in initiating the implementation of agreed Action Plan, several of the issues and challenges raised in the earlier audit reports are likely to continue in the next one or two audit reports, but showing a decreasing trend. 6. At the project level, implementation experience of ongoing project at NEA and AEPC indicates moderate risk. A few deficiencies observed at the project level by the Bank team that relate to improving internal control system and maintaining of books of accounts are being addressed through the specific Action Plan agreed during implementation support missions. At the project level in NEA, it has been agreed that a dedicated Finance Office will be deployed. 7. Adequacy of FM Arrangements. From the fiduciary perspective, based on current assessment, the overall FM risk rating is substantial. 8. Planning and Budgeting. The proposed operation will follow the procedure of NEA. Annual budgets will be prepared by NEA, prior to the beginning of each new fiscal year, in line with the entities annual budgeting program. The budget will include details in respect of the investments financed under IDA. These budgets would be monitored by NEA on a trimester basis and reported through the Financial Monitoring Reports. A separate identifiable budget head will be defined for the Project in the Government's "Red Book" so that the program implementation could be tracked and monitored. 9. In case of AEPC, planning and budgeting system as in the ongoing project will continue. A separate identifiable budget head will be defined for the AEPC component in the "Red Book". 10. Project Financial Accounting, Reporting and Internal Controls. In order to ensure that project financial statements are consolidated, NEA and AEPC will ensure that separate books of accounts are maintained for the project and accounts are prepared on an accrual basis. As in the ongoing PDP, NEA and AEPC will prepare trimester Implementation Progress Reports (IPR) which will include Financial Monitoring Report (FMR) separately. Accounting 41 information will be regularly updated to timely generate financial reports. NEA and AEPC will maintain required ledgers including the Special Designated Accounts Ledger. Internal control process of the NEA and AEPC will be applied to monitor the progress of the project in accordance with sound accounting practices. The NEA accounting systems contain the following features: (i) application of consistent accrual accounting principles for documenting, recording, and reporting its financial transactions; (ii) a well-defined chart of accounts that allows meaningful summarization of financial transactions for financial reporting purposes; (iii) maintenance of various ledgers including the Designated Accounts register; (iv) the asset register; (v) monthly closing and reconciliation of accounts and statements; and (vi) the production of annual financial statements. The AEPC accounting systems also contain similar features except that the accounting system is cash based. 11. Progress Reporting, Monitoring and Disbursement. As part of progress reports, NEA and AEPC will separately submit the Implementation Progress Report (IPR) on a trimester basis. The interim financial report of the project IPR will report total investments to be separated by specific category and/or component so that total investments as envisaged can be tracked and monitored. The project IPR will be prepared from outset, showing the sources and uses of funds, output monitoring report, procurement management report and narrative progress report in formats agreed with the Bank. Formats currently used for PDP shall apply for both these components. To match the government planning and reporting cycle, the IPR will be produced on a trimester basis and submitted within 45 days from the end of the preceding trimester. The financial monitoring report will include (a) transfers of funds to and from the special designated accounts, (b) expenditure statements against each budget head by detail classification according to the chart of accounts, as funded for the project, (c) an output based progress report, and (d) an update on the procurement plan. 12. Internal Audit. The Internal Audit Department in NEA has been upgraded. The Deputy Managing Director is the Chief of the Internal Audit Department. As the Internal Audit Department reports directly to the Managing Director, it is not independent from the management and internal audit function may not be effective. In order to make internal auditing more effective, the Bank team has recommended that the Internal Audit Department report directly to the Board of Directors. 13. External Audit. The Office of the Auditor General (OAG) is responsible for auditing the accounts of NEA and AEPC. Audit of the NEA will be carried out by a qualified and experienced private auditing firm appointed by the Auditor General. Audit reports for FY2009/10 for both NEA and AEPC were due on January 15, 2011. However, there is a delay in the submission of these audit reports. To avoid such delays in the future, GoN and NEA have indicated their intention to request the Auditor General to appoint an independent (private) auditor acceptable to the Bank for the three year period 2010/11-2012/13 and the auditor should audit both NEA's financial accounts and project accounts. In the case of AEPC, OAG will carry out the audit. 14. Furthermore, to address the issue of delays in the submission of audit reports, it is recommended that both NEA and AEPC proactively plan the audit process closely with the 42 auditors to reduce the time lag from the existing levels of delay. The following audit reports will be monitored in the Audit Report Compliance system (ARCS): Implementing Audit Auditors Audit Due Date Agency AEPC Project Financial Statements Office of the Auditor General 6 months after the end of each fiscal year NEA Project Financial Statements Qualified and Experienced Audit 6 months after the end of Firm appointed by the OAG each fiscal year NEA Entity (NEA) Financial Qualified and Experienced Audit 6 months after the end of Statements Firm appointed by the OAG each fiscal year 15. Supervision. Intensive supervision of financial management will be undertaken by the Bank which will include follow-up on the implementation of the agreed Action Plan for financial management improvement at NEA and AEPC among other things. The FM rating will be reviewed periodically and assess the progress. A detailed FM review will be carried out on a trimester basis to ensure that agreed actions are on track. 16. Allocation of financing proceeds. Disbursement under proposed financing will be made as indicated in the following table, which indicates the percentage of financing for different categories of expenditures of the project. Allocation of Financing Proceeds Credit Grant Amount in Expenditure Category US$ million US$ million Total Financing Financing Percentage Component 1 (a) Goods and Works 27.40 3.60 31.00 100% (b) Consulting Services 0.00 1.24 1.24 100% Component 2 (a) Goods and Works 4.06 4.06 100% (b) Consulting Services 0.00 0.30 0.30 100% Component 3 (a) Community Sub- project Grants 0.00 0.86 0.86 100% (b) Consulting Services, Training 0.00 0.28 0.28 100% (c) Incremental Operating Costs 0.00 0.26 0.26 80% Total IDA Financing 27.40 10.60 38.00 43 17. Disbursement Arrangements. The applicable disbursement methods include: Advance, Reimbursement, Direct Payment and Special Commitment. To facilitate disbursement, two separate Designated Accounts (DA) will be established for NEA and AEPC. The supporting documents for reimbursement and reporting eligible expenditures paid from the DAs should include: (a) List of payments against contracts that are subject to the Bank's prior review, together with records evidencing eligible expenditures (e.g., copies of receipts, supplier invoices); and (b) Statement of Expenditure (SOE) for all other expenditures/contracts. In addition, a DA reconciliation statement should be submitted for reporting eligible expenditures paid from the DAs. The Direct Payment applications should be supported by the records evidencing eligible expenditures, e.g., copies of receipts, supplier invoices. 18. Retroactive Financing. Retroactive financing will be provided for component 1 effective from March 1, 2011, not exceeding US$ 5 million for eligible expenditures under Categories (a) and (b). 19. Review of Statement of Expenditures (SOEs). During supervision, the Bank team will closely review SOE claims to ensure that funds are utilized for the intended purposes. Any ineligible expenditure identified during such reviews will need to be refunded to IDA. 20. Designated Accounts. The Designated Accounts in US Dollars will be established on terms and conditions satisfactory to IDA to be used for the purpose of payments of goods, services and reimbursing pre-financed expenditures of operating costs and training. The authorized allocations for the Designated Account of the NEA will be US$ 2,000,000 and of the AEPC US$ 300,000. 44 Annex 8: Procurement Arrangements NEPAL: Kabeli Transmission Project 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 May 2010; and "Guidelines: Selection and Employment of Consultants by World Bank Borrowers" dated May 2004 revised October 2006 and May 2010, and the provisions stipulated in the Legal Agreement. The various items under different expenditure categories are described in general below. For each contract to be financed by the Credit/Grant, the different procurement methods or consultant selection methods, the need for pre- qualification, estimated costs, prior review requirements, and time frame are agreed between the Borrower and the Bank in the Procurement Plan. The Procurement Plan will be updated at least annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. 2. Procurement of Works: Works procured under components 1 and 2 of the project would include: supply and installation of the Kabeli-Damak transmission line (estimated cost $ 12.6 million) and construction of three sub-stations at Kabeli, Phidim and Ilam (estimated total cost $ 9.2 million) and supply and installation of distribution network ($1.8 million). The transmission line and substations contract will be procured through ICB using the Bank's Standard Bidding Documents (SBD) and the rural electrification grid extension contracts will be procured through NCB using the National SBD agreed with or satisfactory to the Bank. 3. Procurement of Goods: Under components 1 and 2, no separate procurement of goods is planned as of now. However, if it is subsequently decided that the same are required, these will be procured through ICB using the Bank's SBD. Procurement of small value goods (e.g. office equipment) may be procured through shopping procedures. Under component 3, procurement of goods will be carried out in accordance with established AEPC procedures based on pre- qualified suppliers and fixed rates. 4. Procurement of non-consulting services: The project does not entail procurement of any non-consulting services. 5. Selection of Consultants: The project entails procurement of short duration contracts with consulting firms and individual consultants. Such contracts may be procured through any of the methods described in the World Bank's Consultant Guidelines, and the applicable method for each shall be provided in the approved procurement plan. 6. Short lists of consultants for services estimated to cost less than $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. 7. Incremental Operating Costs: The project will finance incremental operating costs of AEPC, including office equipment and supplies, vehicle operation and maintenance, 45 communication and insurance costs, IT and office administration costs, utilities, travel, per diem and supervision costs and salaries of locally contracted employees required for the implementation of component 3, up to an aggregate ceiling of $260,000. B. Assessment of the agency's capacity to implement procurement 8. Procurement activities under components 1 and 2 will be carried out under the oversight of the Kabeli Corridor Transmission Line project unit of the Nepal Electricity Authority. The project manager of this unit is a senior electrical engineer who will be assisted by other junior engineers. While the junior engineers will initiate all procurement actions, the project manager, who has past experience of IDA funded procurement, will be responsible for overall supervision and monitoring of project procurement. 9. An assessment of the capacity of the Implementing Agency to implement procurement actions for the project has been carried out by the country procurement unit on December 10, 2010. The assessment reviewed the organizational structure for implementing the project and the interaction between the project's staff responsible for procurement Officer and the NEA's relevant central unit for administration and finance. 10. The Agency has well developed By-Laws that detail the different monetary thresholds for delegation of procurement authority, description of how qualification and evaluation criteria are to be formulated for each contract, bidding procedures and procedures for procurement decisions etc. As the Agency is headed by a senior official with adequate experience of IDA-funded procurement procedures and requirements, and the project entails only four supply and install contracts which are all flagged as prior review, no major risks are identified for project procurement. 11. The overall project risk for procurement is moderate. C. Procurement Plan 12. The Borrower, at appraisal, has developed a procurement plan for project implementation which provides the basis for the procurement methods. This plan has been agreed between the Borrower and the Project Team on March 3, 2011. The Procurement Plan will be updated in agreement with the Project Team annually or as required to reflect the actual project implementation needs and improvements in institutional capacity. D. Frequency of Procurement Supervision 13. In addition to the prior review supervision to be carried out from Bank offices, the capacity assessment of the Implementing Agency has recommended two supervision missions per year to visit the field to carry out post review of procurement actions. 46 E. Details of the Procurement Arrangements Involving International Competition 1. Goods, Works, and Non Consulting Services (a) List of contract packages to be procured following ICB and direct contracting: 1 2 3 4 5 6 7 8 Ref. Contract Estimated Procurement P-Q Domestic Review Expected No. (Description) Cost Method Preference by Bank Bid- (Million (yes/no) (Prior / Opening US$) Post) Date 1 Kabeli 12 .0 ICB NO YES Prior October Corridor 2010 transmission (actual) Line 2. Three sub- 9.2 ICB NO YES Prior March stations at: 2011 a) Kabeli; 2.6 NO YES Prior August b) Phidim; 4.0 NO YES Prior 2011 c) Ilam 2.6 NO YES Prior 3 Supply and 1.8 NCB/ICB NO YES Prior for Nov installation of any 2011 distribution contract (first system over package) $ 500,000 equivalent (b) ICB contracts identified above and all direct contracting will be subject to prior review by the Bank. 47 2. Consulting Services (a) List of consulting assignments with short-list of international firms. 1 2 3 4 5 6 7 Ref. No. Description of Estimated Selection Review Expected Comments Assignment Cost Method by Bank Proposals (Prior / Submission Post) Date 1. Engineering $ 325,000 QCBS Prior June 2011 and Design Services 2. Quality $ 675,000 QCBS Prior Aug 2011 Assistance and Supervision Services 3. Environment $139,00 Post Nature of work, type al of Monitoring consultants and selection method to be defined. 4. PR/Environ $ 430,000 QCBS/CQ Post/Prior Methods and review ment /Ind requirements to be finalized later 5. TA for Rural $207,000 QCBS/CQ Post/Prior Methods and review Enhanced /Ind requirements Energy to be Services finalized later component (b) Consultancy services estimated to cost above US$ 200,000 equivalent per contract, all single source selection of consultants (firms) and contracts with individuals estimated to cost above $10,000 per contract will be subject to prior review by the Bank. (c) Short lists composed entirely of national consultants: Short lists of consultants for services estimated to cost less than US$ 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. 48 Annex 9: Economic and Financial Analysis NEPAL: Kabeli Transmission Project A. Economic Analysis 1. Nepal's electricity deficit is estimated at about 16% of the annual energy demand12. In 2009-10, only 3,689 GWh (of which 612 GWh were imports from India) out of 4,367 GWh of estimated energy demand was served. The deficit of 678 GWh was covered with unserved demand (load shedding). According to NEA, peak capacity demand is increasing by almost 9% a year, with the energy demand increasing by 13% annually13. This chronic shortage is covered by alternative generation methods (generally diesel-fired generators) as well as severe load shedding, estimated to average about 12 hours per day in the dry season, going up as high as 14 to 16 hours a day in the capital towards the end of the dry season. 2. Nepal has no significant fossil fuel reserves of its own and imports all fossil fuels used through India. Therefore, any potential additional thermal power plant would only increase the country's dependence on imported fuels, which under market conditions of recent years equates to much more expensive power and is not considered a viable development option for Nepal. Given the extremely low level of development and drastically inadequate power supply situation, the `no-project' alternative is not an option for Nepal. 3. Water is an abundant resource in Nepal that has not been harnessed to even a small fraction of its potential for electricity generation. Many proposed power generation plants are unable to secure financing due to the absence of transmission (evacuation) capacity and the limited risk tolerance of capital markets in Nepal. 4. The proposed Kabeli Corridor 132 kV transmission line would be an addition to the Integrated Nepal Power System (INPS) that would evacuate power from several small and medium-sized hydropower plants planned in the Kabeli Corridor (defined by the alignment of the transmission line which is designed to pick up the output of hydropower projects on the Kabeli River and on some smaller rivers in the area). In addition to these projects, other hydropower investments are being prepared in other basins. 5. The boundary for the economic analysis includes the actual transmission line as well as the hydropower plants in the Kabeli Corridor which are deemed likely to be come online between 2015-17 and, on this basis, included in the base case scenario. The estimated annual generation from 73.5 MW generation capacity in the corridor amounts to around 400 GWh, much less than the shortage projected for 2015, when the first of the projects in the Kabeli Corridor could begin generating. Consequently, this analysis assumes that all of the power generated by the plants in the base case will be consumed in the INPS. 6. The Economic Internal Rate of Return (EIRR) of the project at the economic discount rate of 10% is 38% and NPV is $434 million. The returns are robust to significant variations in 12 From NEA Annual Report 2009/2010, page 11. Available at http://www.nea.org.np. 13 Ibid. 49 key variables but highly sensitive to the price of fuel for the generators used in the absence of supply from the grid and hence, to the international oil price. However, there is no realistic oil price scenario that renders the project unviable. Boundary of project for economic appraisal: The corridor 7. The Ministry of Energy's Department of Electricity Development issues licenses to independent power producers (IPPs). The IPPs are expected to ascertain the feasibility of projects for which they hold licenses; arrange financing; construct the plants; and sell the power to the Nepal Electricity Authority (NEA) under Power Purchase Agreements (PPAs). To date, the Ministry of Energy has issued licenses for IPP projects totaling about 164MW14 in the Kabeli Corridor. However, it is by no means certain that all the projects for which licenses have been issued will be developed. For purposes of establishing the base case for the economic analysis, the due diligence looked at whether the developers (a) had signed a PPA with NEA; (b) demonstrated significant progress in securing financing; (c) mobilized construction or contracted a construction contractor; (d) completed or advanced land acquisition; (e) established a field office and constructed access roads; and (f) have experience of constructing or managing at least one hydropower power project in Nepal. Not all of the projects have achieved all these parameters, but progress on several of these parameters was considered sufficient to include the project in the base case. Based on the review of these variables, it is expected that a total of about 73.5MW of capacity will come online from 2015-17. The benefits of the project are assumed to accrue from the 73.5 MW capacity in the base case scenario (however, the line has been designed to accommodate evacuation of the entire 164 MW, whenever that capacity is commissioned). Listed below are the projects included in the base case. 14 These capacities are indicative and can change during detailed study phase, design and construction. Recent experience in Nepal shows that the peak capacities are often scaled up from those mentioned in the first stage of licensing. 50 Table 1: List of IPPs on Kabeli corridor expected to come online by 2015-2017 and criteria for selection Status of Land Capacity Acquisition (As of Status of Financing (As Hydropower Local Mobilization (As of Project Name (kW) Developer Feb 2011) of Feb 2011) Experience Feb 2011) Consortium Projects totaling Mai Valley discussions 21MW under Access Roads done, Upper Mai Khola 9,980 Hydropower 98% land acquired completed construction colony built Three projects totaling 47.5MW under construction Contractor agreement Sanima Land acquisition Financing closed at and another 472MW signed, civil work Mai Khola 15,600 Hydropower completed 13.5% under development underway Three projects totaling 47.5MW Financial closure under construction Constructor Sanima Land acquisition expected in June and another 472MW agreements signed, Mai Cascade 4,500 Hydropower completed 2011 under development civil works started Discussions with Projects totaling Will share access roads Mai Valley consortium same as 21MW under and colony with Upper Upper Mai C 6,100 Hydropower 80% land acquired Upper Mai Khola on. construction Mai Khola Operating an existing plant; developing Kabeli Energy Land acquisition Being prepared for another 30MW Local field office Kabeli 37,360 Limited underway World Bank financing project operational 73,540 MW 51 8. Costs: For purposes of the economic analysis, the costs of the proposed transmission line as well as the costs of hydropower plants planned for the corridor were considered. The estimated capital cost of the transmission line is $35.7 million, which is converted to economic costs by excluding taxes and transfers, resulting in an economic cost of $30.3 million. The annual O&M costs of the transmission line were taken as 1.5% of the capital cost. Assuming a total of 73.5 MW of hydropower projects, the estimated capital cost for the hydropower plants in the base case was taken as $141 million, expended equally across the years of construction, 2012-2017 (both years included). The annual O & M cost is taken to be 5% of the capital costs of these hydropower plants. 9. Benefits: The benefits that are expected to accrue from the investment are the avoided costs of alternative forms of generation of electricity that consumers would be forced to resort to in the absence of the project. The analysis assumes that the alternative power would be produced from diesel-fired generator sets of a standard size of 153kW. The product of the per-unit alternative coping cost and the anticipated average annual energy generation from the projects in the base case is taken as the benefit accruing from the investment. The price of diesel used for alternative generation is NRs. 70/litre (October 2010 price), and the analysis assumed that the diesel gensets are used for 12 hours a day, every day of the year. The cost of producing electricity through diesel generator sets under these assumptions is US$0.20/kWh (2010 dollars and prices) and the benefits of the project are valued at this price. 10. The analysis employs a cost-benefit framework to arrive at the EIRR and NPV of the project. The EIRR in the base case scenario is 38% with an NPV of $434 million. 52 Initial Investments (costs) Coping Costs avoided (benefit) Transmission line Power Plants 73.54 Avoided costs from Diesel Generation Total Benefit as calc from avoided cost of diesel Capex O&M Capex O&M costs power Cash Flow (US Year US $ m US $ m US $ m US $ m $m) 2011 3.030 0.000 0.000 0.000 3.030 0.000 3.030 2012 9.090 0.000 23.484 0.000 32.573 0.000 32.573 2013 12.120 0.000 23.484 0.000 35.603 0.000 35.603 2014 6.060 0.000 23.484 0.000 29.544 0.000 29.544 2015 0.000 0.454 23.484 2.348 26.287 54.064 27.777 2016 0.000 0.454 23.484 2.348 26.287 54.064 27.777 2017 0.000 0.454 23.484 2.348 26.287 54.064 27.777 2018 0.000 0.454 4.697 5.151 108.128 102.977 2019 0.000 0.454 4.697 5.151 108.128 102.977 2020 0.000 0.454 4.697 5.151 108.128 102.977 2021 0.000 0.454 4.697 5.151 108.128 102.977 2022 0.000 0.454 4.697 5.151 108.128 102.977 2023 0.000 0.454 4.697 5.151 108.128 102.977 2024 0.000 0.454 4.697 5.151 108.128 102.977 2025 0.000 0.454 4.697 5.151 108.128 102.977 2026 0.000 0.454 4.697 5.151 108.128 102.977 2027 0.000 0.454 4.697 5.151 108.128 102.977 2028 0.000 0.454 4.697 5.151 108.128 102.977 2029 0.000 0.454 4.697 5.151 108.128 102.977 2030 0.000 0.454 4.697 5.151 108.128 102.977 2031 0.000 0.454 4.697 5.151 108.128 102.977 2032 0.000 0.454 4.697 5.151 108.128 102.977 2033 0.000 0.454 4.697 5.151 108.128 102.977 2034 0.000 0.454 4.697 5.151 108.128 102.977 2035 0.000 0.454 4.697 5.151 108.128 102.977 2036 0.000 0.454 4.697 5.151 108.128 102.977 2037 0.000 0.454 4.697 5.151 108.128 102.977 2038 0.000 0.454 4.697 5.151 108.128 102.977 2039 0.000 0.454 4.697 5.151 108.128 102.977 NPV (US $m) `434.10 IRR 38% 53 Sensitivity Analysis 11. Sensitivity analysis was carried out to consider variations relative to the base case assumptions in: (i) fuel price for alternative generation; (ii) change in the level (MW) of capacity evacuation on the line; and (iii) and cost escalation. The sensitivity analysis showed that the proposed investment is highly robust with respect to the variation of the major quantifiable independent variables. 12. Variation in diesel prices: A landlocked country with no fossil fuel resources of note, Nepal imports petroleum products from India for all common uses of these products: power generation, transport, LPG for cooking, etc. The sensitivity analysis indicated that the cost of imported fuel has the greatest impact on the economic viability of the project; however, variation is relevant only if fuel prices decrease and only a highly improbable decrease in the fuel price would have an appreciable impact on the EIRR. The sensitivity analysis considered decreases in the price of diesel that would, necessarily, lower the EIRR of the proposed investment. As Table 1 indicates, even a decrease of more than 50% (from NRs 70 to NRs 30) yields a robust EIRR of 19.4%. The switching value corresponds to a fuel price of NRs 15.85/litre. Taking into account the dynamics of international oil prices in recent years, the probability of a price decrease of this magnitude is considered to be extremely low. Table 2: Variation of EIRR with change in diesel price (NRs/l) Fuel Price sensitivity Base = 70 38% 10 4.9% 20 13.1% 30 19.4% 40 24.7% 50 29.5% 60 33.9% 70 37.9% 80 41.7% 90 45.3% 100 48.6% 110 51.8% 120 54.9% 130 57.8% 140 60.5% 54 13. Uncertainty in capacity to be developed: The transmission line will evacuate power from several hydropower plants in the Kabeli Corridor. The most significant determinant of the economic viability of this line is, thus, how many of these projects are able to secure financing and to overcome the range of construction risks and actually begin to produce electricity. The technical uncertainty of hydropower projects, together with the other risks associated with hydropower development, introduces a degree of variability in the total power that can be expected to be evacuated by the proposed transmission line. 14. The sensitivity analysis indicated that the project is robust to a considerably reduced level of power evacuation as well, which reflects the high economic value of electricity. If only the Kabeli "A" HEP project were to come online, the transmission investment would still be robust with an EIRR of 32%. Table 3: Variation of EIRR with reduction in capacity evacuated by proposed Kabeli Transmission Line as % of kW base EIRR Base Case 73,540 100% 38% 57,940 79% 36% 43,460 59% 34% Only Kabeli A 37,360 51% 32% Figure 1: Variation of EIRR with reduction in capacity evacuated by proposed Kabeli Transmission Line 39% 38% 37% 36% E 35% I 34% R 33% R 32% 31% 30% 29% 100% 79% 73% 59% 51% Percentage of generation capacity installed on corridor on a base case of 73.5MW 55 15. Delays in Commissioning: Energy projects in the region often suffer delays in commissioning due several factors like lack of financing, civil strife, delay in the permits process, etc. While the analysis has been conducted keeping in mind a realistic expectation of delays, we find that the project is robust for a delay of several years. Table 4: Variation of EIRR with delays in commissioning beyond base case Delays in commissioning years EIRR 1 31% 2 26% 3 23% 16. Variability in cost: As seen in Table 5 which shows the variation of project EIRR with cost escalation, even if the construction costs for projects and the transmission line to almost 400% of the assumed costs, the EIRR is robust around 10%. Table 5: Variation of project EIRR with cost escalation Cost overrun EIRR Base case (100%) 38% 125% 32% 150% 28% 175% 24% 200% 22% 225% 19% 250% 17% 275% 16% 300% 14% 325% 13% 350% 12% 375% 11% 400% 10% 425% 9% 450% 8% 475% 8% 500% 7% 56 Figure 1: Variation of EIRR with increase in hydropower plant construction costs on the corridor EIRR variation with cost overrun 40% 30% 20% 10% 0% B. Financial Analysis 17. Nepal Electricity Authority (NEA) is technically insolvent, with internal cash flows unable to service existing debt or fund any capital expansion without significant support from external sources. This, coupled with its inability to meet demand, rapidly rising power purchase costs and inability to raise tariffs in its recent history would imply that without rapid implementation of reforms, the company would continue along the downward spiral of increasing costs, decreasing revenues and chronic underinvestment. 18. Nepal Electricity Authority (NEA) revenues from electricity sales have remained stagnant over the 2007-2009 period15 at around NPR14.7BN with average tariff yields declining slightly (0.8%) over the same period. There has been no substantial tariff hikes in Nepal since 2001. 19. Total Operating costs have increased 37% over the same period, with distribution and power purchase costs - accounting for 17% and 60% of total costs respectively in FY2009 - growing at 40% and 10% respectively. Cost of generation grew at 31% over the 2007-2009 period. 20. According to NEA, the significant increase in generation costs are attributable to increasing staff costs due to hikes in employee remunerations instituted by the Government of Nepal, a 48% increase in repairs and maintenance due to a major overhauling program of power houses as well as increase in cost of spare parts and services. 21. Present collections from the crucial industrial and commercial sectors are reported to be good while collections from domestic and non-commercial sectors are considered reasonable. Collections from municipalities for street lighting and temples have been very weak over the 15 The Financial Year in Nepal extends from July 16 - July 15 57 time period under consideration. NEA had not been able to keep its accounts receivable and account payable within a 90-day limit. 22. The growth in cost of power purchase and cost of generation in conjunction with the stagnation in average tariffs, have brought operating margins down from 23% to 9% in two years. The rapidly deteriorating operating margin exerts pressure on NEA financials and limits their ability to fund capacity expansion plans crucial for a country with a substantial and growing demand-supply gap. 23. Interest Payable to GON accounted for around 76% of the total current liabilities of 29,221 MM NPR as of FY09. The interest payable consisted of 12,993 MM NPR of interest payments due and 9,112 MM NPR of IDC (interest during construction). The amount of interest payable is significant and equals around 16.87 times the operating profit in FY09. 24. The projections for NEA financials indicate that cash flow shortfalls are expected over the 2011-2013 period, and the shortfalls are modelled as equity injections by the Government of Nepal. 25. A financial restructuring plan (FRP) has been prepared by a task force set up by the Cabinet. The reforms proposed by this FRP are summarized below and in the project file. The key reforms proposed are the write-off of accumulated losses and foreign technical assistance, reduction of interest rate to 5 percent, capitalization of 50 percent of foreign grants as loans, and, eventually, tariff adjustments. Analysis of the reform proposals indicates that the company would indeed be able to become viable and remain so, assuming periodic actions on tariffs and continued enhancements of revenues. This FRP has not been endorsed by the new Government nor has it been fully discussed with national stakeholders. 58 Draft Financial Restructuring Plan: Proposed Reforms Clause in Title Definition Implementing Agency Auxiliary Agencies Report 9.1 Corporate Financial Reform 9.11 Increase Share Capital (a) Increase Authorized capital From NPR 30 BN to NPR 75 BN Council of Ministers MoF16, MoE17 and NEA and Adjust Reserve & Writing off accumulated loss NPR 11.8 BN Surplus Conversion of Interest During Construction (IDC) of NPR 9.62 BN into Equity Of the 20% equity component for project investment in Nepal, the GoN to NEA ratio would be revised from 5% and 15% to 10 and 10% respectively Writing off Foreign Technical Assistance received instead of capitalization as equity and/or Long Term loan, and any capital assistance received to be included in GoN loan amount recognized 9.1.2 Finalization of (a) Finalizing SLA and confirming the Loan to be accounted Council of Ministers MoF, MoE and NEA Subsidiary Loan (b) Projects funded through foreign grants shall be capitalized at 50% of such Agreement with GoN grants, which will be accounted as loan instead of grant and capitalization of projects constructed from foreign grants 9.1.3 Reduce Interest Rates (a) Reduce Interest Rate from 8% to 5% financing through foreign source Council of Ministers MoF, MoE (b) Reduce Interest Rate on local sources from 6.5% to 5% (c) Foreign Grants onlent by GoN to be charged at 2.5% (50% recognition charged at 5%) (d) There shall not be any change in interest rates which are currently below 5% (e) Compute IDC at the rate of 50% of the applicable rate. 9.1.4 Capitalization of Middle (a) Capitalize NPR 6.67 BN out of the NPR 13.54 BN KFW grant Council of Ministers MoF, MoE and NEA Marsyangdi Hydro (b) Capitalize NPR 4.75 BM as IDC and Foreign exchange loss during Electric Project construction 9.1.5 Settlement of (a) The outstanding dues between NEA and GoN shall be adjusted and net MoF MoE, MoLD18, MoI19 and outstanding dues payable to GoN shall be incorporated in the books of NEA. NEA between GoN and NEA (b) NEA is entitled to receive NPR 3.98 BN from GoN, and GoN is entitled to receive NPR 14.84 BN from NEA. 9.1.6 Royalty shall be Royalty shall be calculated on the basis of selling price at generation point, DoED20 MoF, MoE and NEA calculated as per the which is in the range of NPR 3 per kWh, rather than the current practice of fixing 16 Ministry of Finance 17 Ministry of Energy 18 Ministry of Local Development 19 Ministry of Industries 20 Department of Electricity Development 59 Clause in Title Definition Implementing Agency Auxiliary Agencies Report provisions of Electricity selling price at NPR 5.41 per kWh Act 1992 9.1.7 Develop payment MoF shall deduct the amount equivalent to street light dues from the annual MoLD MoF, MoE, Municipalities mechanism for street grants provided to local bodies and the same shall be reimbursed to NEA & VDC21 light bills to minimize collection risk 9.1.8 Formation of Rural A Rural Electrification company shall be incorporated under the full ownership Council of Ministers MoF, MoE and NEA Electrification Company of GoN and existing infrastructure related to rural electrification, offices, employees, related assets and liabilities shall be transferred to such company 9.1.9 Formation of Electricity To form an Electricity Purchase Tariff Fixation Committee (ETFC) Council of Ministers MoE purchase tariff fixation committee 9.1.10 Operation of Multi-fuel (a) If diesel plants are to be operated continuously, GoN shall bear the cost Council of Ministers MoF, MoE and NEA and Diesel Plant above the average cost of generation for NEA plants (b) If the diesel plants are to be operated for voltage improvement, then the entire cost would be borne by NEA 9.1.11 Debentures Issue NEA is allowed to issue debentures guaranteed by the GoN for project financing NEA MoF, MoE 9.2 Managerial Reform 9.2.1 Reduction of (a) Competitive appointment of executive director on performance contract NEA Administrative (b) Greater control over recruitment and misuse of corporate resources Expenses (c) Greater reliance on contract labor to bring down staff costs 9.2.2 Establishment of Creation of retirement fund for employees benefits NEA Retirement Fund for employees benefits 9.3 Tariff adjustment To adjust electricity sales tariff as per revenue requirement ETFC MOF, MoE, NEA Source: Data provided by NEA 21 Village Development Committee 60 26. The 132 kV Kabeli Corridor Transmission Line Project, a proposed US $47.68 mln project that includes the Kabeli-Damak transmission line and four sub-stations has a project cost/MW-km of US $3800 for a capacity of 140MW. At a utilization of 73.5 MW, the project cost works out to US$7300/MW-km. The construction is expected to start in the last quarter of 2011 and enter into operation by end of FY 2013. 27. In the base case scenario, the project is assumed to have 73.5MW connected to it over 2015-2017. 28. The results of the financial analysis indicate that the project has a 25 year levelized transmission tariff of 1.428 US cents/kWh. Sensitivity tests indicate that the project is robust. Historical performance of NEA Financial Highlights 29. In 2009, NEA had total EBITDA, including provisions, of 378 MM NPR, which was insufficient to cover interest payments on existing loans (2,493 MM NPR). This also implies internal cash flows were not available to fund capital expenditure on capacity generation or transmission projects. 30. The significant gap between demand and generation capacity of NEA implies that NEA has had to rely increasingly on costlier sources of electricity: IPPs in Nepal and India, as well as purchases from private producers in India to meet additional demand after the 50MW available from PTC as per Power Exchange Agreement. This has led to significant increase in power purchase costs over the last few years. 31. Average Tariff Yields22 have gone down over the analyzed period while costs of generation, power purchase and transmission have grown, applying pressure on operating margins and affecting the ability of NEA to fund capital expenditure on capacity expansion as well as upkeep of existing plant and equipment. 32. NEA has been unable to pay interest payables and interest during construction fully in any of the years considered (FY2007-FY2009), with total Interest Payable at 22 BN NPR by 2009. In 2009, interest actually paid was NPR 565 MM against an interest payable of 2.5 BN NPR. 33. The liquidity position of NEA has also been deteriorating rapidly, with Net Working Capital at -22 BN NPR as of FY09 from -12.5 BN as of FY07. 22 Average Tariff Yields are defined as Revenues from sales of electricity/Total Units of electricity sold 61 Table 1: NEA Financials Snapshot ­ Income Statement FY06 to FY09 (All numbers are in NPR MM) FY 2006 FY2007 FY2008 FY2009 Generation NEA Hydro 1569 1747 1793 1840 NEA Thermal 16.1 13.31 9.17 9.06 Power from non-NEA IPPs (GWh) 930 962 958 926 Power Purchase from India (Under PEA) (GWh) 266 329 425 356 Available Energy (GWh) 2781 3052 3186 3131 Revenue Net Sales 13,332 14,450 15,041 14,406 Other Income 640 1,017 935 1602 Total 13,972 15,466 15,976 16,008 Operating Expenses Generation Costs 811 856 980 1120 Power Purchase Costs 6,392 6,968 7,437 7,691 Transmission Costs 232 241 275 328 Distribution & Electrification 1,704 1,834 2,110 2,575 General Admin Costs 898 480 684 652 Royalty Charges 420 970 839 796 Total Provisions 65 60 60 2,468 Total Operating Costs 10,521 11,409 12,385 15,629 EBITDA 3,451 4,058 3,591 378 Interest Payments 3,051 2,385 2,274 2,493 Depreciation 1,817 1,856 1,895 2,361 Street Light Dues Written Off 0 0 0 -863 PBT (1,565) 267 (1,171) (6,249) PAT (1,565) 193 (1,113) (6,151) Profit/Loss Transferred to Balance Sheet (6,096) (6,650) (7,632) (15,320) 34. The results in Table 1 show EBITDA in FY 2009 was NPR 378 MM against interest payments of NPR 2.5 BN. Assuming an across the board tariff hike of 30% and that collection percentages remain the same, EBITDA increases to NPR 4.7 BN. This implies that after interest and principal payments, NPR 1.63BN is available for investment in capital expenditure against CAPEX of NPR 9.3BN and additional investment in PPPs of NPR 520MM, which adds up to a total investment outlay of NPR 9.8BN in 2009 for capacity expansion and upkeep. Net Income after appropriation would remain negative at -1.65 BN NPR. 62 35. Table 1b provides a list of key ratios with their definitions appended as foot-notes. As shown, the DSCR has fallen to 0.95 by 2009 and self-financing ratio to -33%. The return on Net Fixed Assets has fallen to -6.7% from approx. 2% in 2006. The precipitous decline in terms of balance sheet integrity shows no indication of slowing without drastic reforms. Table 1b: Key Ratios for NEA Key Ratios FY 2007 FY 2008 FY 2009 Debt-Equity Ratio (D/D+E) 70% 70% 73% Self-Financing Ratio23 -57.13% -73.28% -33.30% Return on Average Net Fixed Assets24 2.06% 1.37% -6.66% 25 Debt-Service Coverage Ratio 1.16 0.95 0.95 Account Receivables 122 131 119 Account Payables 711 755 810 36. Trends in revenues from electricity sales. Total electricity sales for NEA were around 2,204 GWh in FY07, and remained at the same level (2205 GWh) in FY09. The corresponding revenue realized for electricity sales during the same period was slightly decreased by around 0.20% from NPR 14.77 billion in FY07 to NPR 14.74 billion in FY09. The average tariff yield has decreased over the period under consideration. The unit average price of electricity realized in FY09 was NPR 6.70/kWh. Table 2 provides details of electricity sales and revenue realized by NEA over a three year period from FY07 to FY09. Table 2: NEA Electricity sales and revenues, FY07 to FY09 FY07 FY08 FY09 Customers GWh MM NPR GWh MM NPR GWh MM NPR Domestic 893 6,021 931 6,298 909 6,101 Non-Commercial 101 940 110 982 99 901 Commercial 142 1,288 154 1,400 146 1,385 Industrial 849 5,301 901 5,545 845 5,264 23 Self-Financing Ratio is defined as Funds from Internal Sources/CAPEX; where Funds from Internal Sources is (Operating Revenue + net non-operating income) ­ (All Operational Expenses inc. taxes but excluding depreciation and other non-cash charges) ­ (All Debt Service excluding IDC) 24 Defined as the ratio of Operating Income and Average Net Fixed Assets in Operation, where Operating Income is the difference between (i) gross revenues related to NEA's services; and (ii) the operating and administration expenses (including taxes, if any), adequate maintenance and depreciation but excluding interest and other charges on debt; and Average Net Fixed Assets mean average of the historical net fixed assets of NEA in operation at the beginning and at the end of such Fiscal Year 25 Defined as Net Revenues/Total Debt Service Requirements, where Net Revenues implies Gross revenues from operations and net non-operating income less operational & administrative expenses including taxes, but excluding provisions for depreciation and debt-service requirements 63 FY07 FY08 FY09 Customers GWh MM NPR GWh MM NPR GWh MM NPR Water Supply & Irrigation 48 214 47 205 48 215 Street Light 67 455 70 467 68 446 Temporary Supply 1 17 1 11 1 12 Transport 6 32 6 34 5 27 Temple 5 26 5 26 5 25 Community Sales 16 54 25 64 32 70 Total (Internal Sales) 2,127 14,348 2,250 15,031 2,158 14,446 Bulk Supply (India) 77 429 60 361 47 295 Grand Total 2,204 14,777 2,310 15,392 2,205 14,742 Source: Data provided by NEA 37. Trends in operating costs. Table 3 shows the operating costs incurred by NEA during FY07 to FY09. Table 3: NEA operating costs, FY07 to FY09, in NPR million Units FY 07 FY 08 FY 09 Cost of Generation MM NPR 856 980 1,120 Units Generated GWh 1,761 1,802 1,849 Unit Cost of Generation NPR/kWh 0.49 0.54 0.61 Cost of Power Purchase MM NPR 6,968 7,437 7,691 Units Purchased GWh 1,291 1,384 1,282 Unit cost of power purchased NPR/kWh 5.40 5.37 6.00 Cost of Transmission MM NPR 241 275 328 Units transmitted GWh 2,204 2,310 2,205 Unit cost of transmission NPR/kWh 0.11 0.12 0.15 Royalty MM NPR 970 839 796 Distribution Expenses MM NPR 1,834 2,110 2,575 Units transmitted GWh 2,204 2,310 2,205 Unit cost of distribution NPR/kWh 0.83 0.91 1.17 Administrative Expenses MM NPR 480 684 652 Total Operating expenses MM NPR 11,349 12,325 13,162 Source: Data provided by NEA 64 38. Major operating expenses include cost of power purchase (49% of total operating costs in FY09) and distribution expenses (16% of total operating costs in FY09). These two cost heads accounted for around 65% of the total operating costs in FY09. 39. Power purchase expenses include cost of power purchased from Nepal IPPs owned and operated by the private sector and cost of power imported from India. Generation cost includes cost of power generated from NEA owned plants. Unit operating cost for generation for NEA was 0.61 NPR/kWh, while per unit generation cost for NEA was 2.46 NPR. Unit cost of purchased power from IPPs in Nepal was 6.68 NPR/kWh, and 4.65 NPR/kWh for power purchased from India under purchase agreement. Overall unit cost of purchased power was 6.00 NPR/kWh (Power purchased from IPPs in Nepal amounted to 926 Gwh at NPR 6279 million in 2009). NEA generated around 59% of its total power requirements in FY09 and the rest 41% was purchased. It should be noted though that the generation costs presented as part of operating costs include only O&M expenses incurred by NEA for operating its power plants. 40. Although sales have remained at around the same level from FY07 to FY09, operating costs increased by 15.97% over the same period. The increase is driven by the corresponding rise in unit electricity costs. 41. Generation cost per unit increased by 30.84% Based on breakdown of generation costs provided in financial statements, the major drivers are: a. Repairs & Maintenance, which increased by 48% and contribute to 39% of total costs, and have more than doubled over the last 5 years. According to the NEA, this can be attributed to a major overhauling program of powerhouses like Kulekhani in 2009 and increases in cost of service and material b. Staff costs, which increased by 38% and contribute to around 28% of total costs. According the NEA, hikes in employee remunerations required by the GON and annual increment of grades for employees are major causes. They were unable to provide staffing data, but stated that generation-related staff count increased over the period in question. c. Spare-parts and Operations, which increased by 46%, contribute to 10% of total costs and have increased three-fold in the past 5 years. NEA suggests that the reasons are the same as for Repairs and Maintenance. 42. Power purchase costs increased by 10.38% over the same 3 year period. 43. Distribution expenses per unit electricity sold have risen by around 40% in the same 3- year period. Based on breakdown of distribution expenses provided in financial statements, major drivers are: a. Staff costs and terminal benefits, which together constitute around 60% of total costs and have increased by 46% over the past two years. According to NEA, this can be attributed to government mandated salary hikes. b. Repair & Maintenance which constitutes 23% of total costs has increased by 36%. According to the NEA, this can be attributed to the capitalization of distribution lines and increase in cost of material. Together these three expenses account for around 86% of the total operating expenses. 65 44. Royalty payments are paid by NEA to Government of Nepal (GON) for power generated from its hydro power plants, and in part to the affected DDCs and VDCs. The payments are currently made one year following the year in which the payments are charged. Royalty Charges are composed to two elements, an installed capacity based capacity charge and an actual production based energy charge. They are computed as follows: (a) Capacity charges (On the basis of Installed capacity of Hydro Plants) Commercial date of Operation (CoD) Capacity Charge <15 yrs Rs 100 per kW >15 Yrs Rs 1,000 per kW (b) Energy charges (On the basis of actual units electricity sold) Commercial date of Operation (CoD) Capacity Charge <15 yrs 2% of the energy sold price at generating point >15 Yrs 10% of the energy sold price at generating point Energy sold price is currently fixed at Rs 5.41 per kWh while real prices at point of generation are lesser. 45. Operating Margins. Operating margin which is an indicator of operating efficiency & adequacy of pricing has dropped from around 23.7% in FY07 to 20.39% in FY08, and -8.49% in FY09, implying that cost of operations have been exerting greater pressure on revenues, resulting in less cash being available for debt service, equity returns and capital investment programs. Table 4: Operating margin for NEA, FY07 to FY09 In MM NPR FY07 FY08 FY09 Revenues 14,450 15,041 14,406 Total operating expenses 11,409 12,385 15,629 Operating surplus/(gap) 3,428 3,067 -1223 Operating margin (Operating Surplus/Revenues) 23.7% 20.39% -8.49% Source: Data provided by NEA 46. Collections. Table 5 presents the collections (amount received as percentage of total amount invoiced for each customer category). 47. The average number of receivable days for each customer category based on historical data for the past three years is presented in Table 5. Overall receivables as of FY09 were 5,385 MM NPR. Out of these total receivables, 549 MM NPR were provisioned as bad debt. As per information received from NEA, a major component of these provisions (around 70%) is allocated to Domestic customers while the rest is allocated to Industrial customers. 66 Table 5: Collections for each customer category for FY09 Customers Collections (%) Average Receivable Days (measured historically) in days Domestic 95 146 Non-Commercial 97 14026 Commercial 99 30 Industrial 98 55 Water Supply & Irrigation 98 143 27 Street Light 746 Temporary Supply 100 30 Transport 100 30 Temple 5 3915 Community Sales 80 79 Total (Internal Sales) Sales: 14,742 MM NPR Outstanding: 5,385 MM NPR Source: Data provided by NEA 48. The total street light dues as of end of FY10 were approximately 1340 MM NPR. Within the past 5 years, there have been two major write-offs in the street light dues account. Details on the same have been presented below: a. Total street light dues in FY09 were 2,735 MM NPR. Out of these total receivables, 1,840 MM NPR was due from municipality street light account and 895 MM NPR was due from the Village Development Committee (VDC) street light account. Based on an agreement between the NEA and GON, NEA waived off 47% (861 MM NPR) of the balance outstanding in the municipality street light account and GON paid up the remaining 53% (980 MM NPR). The resulting outstanding street light dues as of FY09 after this agreement were 895 MM NPR. b. The reasons for the 264 MM NPR write-off in FY05 have not yet been made available. 49. Liabilities. Interest Payable to GON accounted for around 76% of the total current liabilities of 29,221 MM NPR as of FY09. The outstanding payables consisted of 12,993 MM NPR of interest payments due and 9,112 MM NPR of IDC (interest during construction) due. The amount of interest payable is significant and equals approximately 17 times the operating profit in FY09. 50. As per a restructuring plan currently pending with the Ministry of Finance, the total interest payable amount including IDC and any future interest payments due are expected to be structured as a separate interest free loan and repaid over a 20 year period. 26 Composed largely of GON office outstanding 27 GON paid 980 MM NPR and 863 MM NPR was written off in 2009 out of sales of 440 MM NPR. The dues for municipalities for up to FY 2009 were cleared but the outstanding of Village Development Council (VDC) of approx. 900 MM NPR remains in 2009 67 51. Almost all loans to NEA including foreign loans are taken on GON's books. GON then on-lends the corresponding loan amount in local currency to NEA. Thus any loss on foreign loans due to devaluation of the local currency is borne by GON. As of FY09, NEA had two foreign currency tranches on its books, both in Yen (Kulekhani Disaster Prevention Tranches), totaling 3.45 MM NPR out of total secured loans of 54.03 MM NPR on its books. Kabeli Corridor 132 kV Transmission Line Project 52. Project Costs. The Kabeli Corridor 132 kV Transmission Line Project envisages the creation of transmission corridor in the eastern part of Nepal in order to evacuate power generated in the region and bring down system-wide transmission losses, while also incentivizing IPP-driven HEP projects in the region. Major components of the proposed project include the Kabeli-Damak transmission line as well as the substations at Ilam, Phidim, Kabeli and Damak, substations where the transmission corridor line will be connected to the existing grid. The 90 km transmission line from Kabeli to Damak is expected to have 73.5 MW available for transmission by 2017. 53. In the first year of operation of the transmission line, 53 MW is expected to be available for transmission, which is expected to grow to 73.5 MW by 2017 (the base case scenario) and remains constant thereafter. The low utilization of the transmission line implies higher levelized transmission tariff for the project over the project lifetime. 54. The Project Costs, excluding IDC and other financing charges, but including physical contingencies (5%) and price contingencies (5%) is estimated at US $43.95 MM. Table 6 provides a high-level description of the cost estimates for the project. A summary of the cost estimate, including a detailed breakdown of the EPC costs for the project organized by key project components including transmission line and substations are provided in Table 6. The projections indicate a CAPEX/MW-km of approx. US $3800. Table 6: Capital Expenditure (All Figures are in US $ `000) CAPITAL EXPENDITURE COST Land Acquisition for Substation and R & R Compensation 3,000.00 Compensation and Consulting for Transmission Lines i) Environmental Mitigation & Monitoring 900.00 ii) Technical Assistance 1,681.00 Civil Works i) Infrastructure for substations 468.00 Equipment (Supply & Erection) Cost a) Transmission Lines, OLTE & OPGW 12,653.00 b) Sub-Stations 13,278.00 c) Rural Electrification Grid Extension Component 5208.00 d) Rural Enhanced Energy Services Component 1200.00 Sub total 38,466.00 Maintenance during construction 68 CAPITAL EXPENDITURE COST Taxes & Duties 993.00 Project development cost @ 3.00% 1036.98 Physical & Price Contingencies @ 10.00% 3456.60 Total excluding IDC 43,952.58 IDC and Financing Charges 2,606.90 Total Capital Cost 46,559.48 Financial Projections 55. The results of the financial analysis indicate that the project is financially viable, with the projected equity IRR of 22.2% exceeding the Weighted Average Cost of Capital. The 25 years Levelized Tariff of US 1.428 cents/kWh (NPR1.071/kWh) is lower than comparable tariff for the cross-border transmission line project. The levelized tariff, computed at a relatively low utilization (peak power transmitted of 73.5 MW), can be further improved in case projects planned for the region come online on schedule. Table 7 summarizes the outcomes of the financial analysis. Table 7: Summary Description of Financial Analysis results Results Summary Description Financial IRR (FIRR) 25 Years 22.2% NPR/kWh 1.071 25 Years Levelized Tariff US c/kWh 1.428 Minimum IRR 1.33 Average IRR 1.77 56. The key assumptions used for the financial analysis are summarized in Tables 8 and 9. The detailed list of assumptions is available in the Assumptions Book of the Financial Model designed for the project. As shown in the key uses and sources of funds in Table 24 and key debt terms are provided in Table 25, the project is assumed to be financed by 70% long-term debt with 20 years tenor and 9% p.a fixed interest rate. Equity investment is expected from NEA and the GON. O&M Costs are assumed to be a levelized 2% of capital expenditure over the projection period. Tax and Depreciation assumptions are selected as per relevant Nepal laws and standards. Table 8: Key sources and uses of funds Uses of Funds NPR Crores USD MM Hard Costs 329.64 43.95 Financing Costs 19.55 2.61 Total 349.20 46.56 Sources of Funds Share Capital Equity 104.72 13.96 Debt 244.48 32.60 Total Sources of Funds 349.20 46.56 69 Table 9: Key Debt Assumptions Debt Terms Tranche Upfront fee % 2% Commitment fee % 0.60% Interest rate % p.a 9% Facility used US $ MM 32.6 Repayment tenor Years 20 Moratorium Years 5 57. Tariff was computed using the cost-plus methodology, and overall tariff is composed of O&M Charge, Interest cost on long-term loans, depreciation, interest on working capital and a 16% pre-tax return on equity. The 25 year levelized tariff computed is NPR 1.071 per kWh (US 1.428 cents per kWh). 70 Annex 10: Safeguard Policy Issues NEPAL: Kabeli Transmission Project Social Impact Assessment and Resettlement Action Plan 1. Located in Nepal's Eastern Development Region, the proposed Kabeli Corridor Transmission Line passes through Terathum, Panchthar, Ilam and Jhapa districts. The transmission line corridor is approximately 90 km in length and passes through 25 VDCs of the four districts. The key physical components of the project that lead to direct physical impacts are: construction of substations; erection of 342 towers; stringing of transmission lines; camps and storage. NEA has carried out a Social Impact Assessment (SIA), and developed a resettlement action plan (RAP) for the towers at angle points, the siting of which has been fixed at this stage of planning, and a Social Management Framework (SMF) for the rest of the project activities whose final assignment and siting can be determined only later during the project implementation. 2. SIA. The SIA was carried out during October-November 2010 in VDCs along the alignment of the transmission line. It benefitted from early social screening and survey work done as part of the environmental impact assessment. The methodology included literature review; 54 focus group discussions with women, ethnic minority and Dalit groups; and a census survey of the directly affected households. The SIA team shared available project information with local communities and carried out extensive consultations. Following are the key findings of the SIA: Agriculture and animal husbandry are the most common livelihood activities and remittances from external labor and foreign military service are important income sources. Representatives of an estimated 70 caste and subcaste groups live in the project area. Ten janajati groups are resident in the four districts. Eight of them are hill groups and two are lowland (Terai) groups. The more populous groups are the Limbu, Rai, Tamang and Magar. The majority of the local population knows of the project and has a positive attitude to the project. They expect to benefit from the project through improved access to electricity, employment, skills training as well as improvement in education and health facilities. Compensation payment is expected to be delivered to those losing land and structures to the project. 3. Resettlement and ethnic minority groups. The project will require 2.8 ha of private land which will impact a total population of 203 in 34 households. An RAP was prepared to address the impacts associated with the construction of towers at angle points. The social planning team carried out an inventory survey of the project impacts and a census of the affected 71 population. A profile was established for every affected household that records their household demographic profiles, land holdings, livelihood and income sources and losses under the project. 4. In line with relevant domestic and World Bank policies, the project formulated an entitlement policy and a set of planning principles to guide the RAP preparation. These included impact minimization, compensation at replacement cost, entitlement eligibility for non-affected non-titleholders, adequate financing and consultation. The livelihood rehabilitation package consists of cash compensation at replacement cost and livelihood assistance. The livelihood assistance consists of vocational training, extension services, employment opportunities during construction and other income-generating activities to be agreed in consultation with the affected households during implementation. The total RAP cost is estimated at NRs. 16.84 million, including NRs. 4.61 million for capacity-building in R&R management and income generation. 5. The RAP specifies the grievance redress mechanism to address the complaints of local people. A project Grievance Redress Committee (GRC) will be established under the project. The implementing staff members of NEA will be working with the affected households and help them to file their grievances. The GRC will meet every month and review all grievances. All grievances will be addressed or responded to within 15 days of receiving the complaints. The affected households can always file their grievances in court if they are not satisfied with the GRC decisions. 6. NEA will be responsible for the implementation of the RAP. A separate Unit with dedicated staff members has been proposed to be set up within the Project to implement the social safeguard activities in coordination with project's physical works. Regular internal monitoring will be carried out by project staff for effective project implementation. An independent agency will be engaged to undertake half yearly external monitoring for the RAP implementation. 7. The SIA has identified ten ethnic groups in the project districts. The team carried out extensive consultations with them and held separate focus group discussions with each of these groups over their attitudes towards the project, their concerns and expectations from the project. The majority of them are supportive of the project and they are expecting to benefit from the project. The SIA also indicates that the 34 affected households belong to eight ethnic groups, despite the ethnicity difference, these affected households share a lot in common in their access to natural resources and economic livelihood activities, and a common approach is sufficient to address the land loss impact and assist them in livelihood rehabilitation. 8. SMF. Under the project engineering design, the location and impact boundaries of some of the proposed activities can only be determined during the course of the project implementation. The key activities among them are the transmission line corridor and line towers. This SMF is developed to guide the planning to address any adverse impacts under these activities. 9. The SMF is prepared in line with the relevant national and World Bank policies on land acquisition, involuntary resettlement and ethnic minority population. It describes the legal and policy framework, basic principles and entitlement policy to be followed in the planning of the mentioned project activities. It also prescribes the procedures and requirements on public 72 consultation as well as the monitoring process. The SMF lays out the planning steps, review and approval process as well as the institutional setup and responsibilities for managing and monitoring the planning and implementation of any action plans. Environmental Impact Assessment and Environmental Management Plan 10. Environmental factors and potential environmental impacts were taken into account as part of the determination of the alignment of the transmission line. In November 2010, NEA completed an Initial Environmental Examination (IEE) of the transmission line and substations. There are no protected areas or known conservation sites in and around the project area including the transmission line alignment and substation sites. 11. The main adverse environmental impacts apparent from the IEE include: (i) impacts on forest and wildlife as 33 km out of the approximately 90 km of the transmission line passes through community, government and private forests at several stretches (although the length of the transmission line through a single forest is generally less than one-half kilometer; the longest length through a forest is about 2 km); The IEE estimates the total forest area affected by the project at about 59 hectares, out of which around 24 hectares belongs to 17 community forests at different places. The project will permanently occupy less than one hectare of the community forest; whereas approximately 23 hectares of community forests are affected due to restrictions on the height of trees and bushes in the right of way. The project will work with the forest users in implementing the mitigation measures summarized below; (ii) increase in soil erosion and slope instability/landslides due to vegetation clearance and excavation activities, particularly in the fragile Siwalik hills and steep sections of the Mid-hills; about 12 % of the transmission line passes through the Siwalik hills which are physically fragile and susceptible to erosion and mass wasting, including gully erosion, debris flow and landslides; (iii) workers' Occupational Health and Safety (OHS) while working on the tower, cable stringing, excavation on difficult hilly terrains, and electric shock; (iv) health and safety of communities possibly resulting from workers' poor sanitation practices, HIV risks from outside workers, and disposal of hazardous wastes; and (v) impacts resulting from the sub-stations and hazardous wastes generated by them. 12. The identified environmental risks are limited to the vicinity of the transmission line and substations and can be mitigated through simple mitigation measures that are already identified. As the overall environmental impact of the project is expected to be moderate the project has been assigned environmental Category B. 13. The IEE identified mitigation measures for construction and operational phases including, for example, limiting clear-cutting of vegetation to less than 5 m wide (as may be necessary for cable stringing); limiting clearance to trimmings of the tall standing trees as required for safety of the cable (only lopping and topping of the high growing trees and plants to the height less than 5 m below stringing cable along the RoW beyond 5-m width for cable stringing); no ground clearance of herbs and shrubs; compensatory plantation (25 saplings for the loss of one common or protected tree species above 10 cm DBH); providing alternative fuel to workers; banning workers from wildlife hunting; use of bio-engineering and other appropriate soil erosion/ landslide/ gully protection measures around towers; maintaining ground vegetation in the cleared areas (NTFP etc); proper management of excavated spoils; collection and safe disposal of hazardous wastes (spent machine lubricants, engine oils and other chemicals); 73 provision of necessary occupational health and safety items/ facilities to workers, etc. In addition to these measures, the EMP included in the IEE provides environmental standards to be followed, roles and responsibilities and institutional arrangements for environmental management in the project. The IEE has been approved by Ministry of Energy and is binding on NEA. 14. For the implementation and monitoring of the environmental mitigation measures, an Environmental and Social Unit (ESMU) will be created under the Kabeli Project Unit. The ESMU will draw on NEA staff resources such as ESSD and will also engage consultants. The EMSU will be responsible for the implementation of the EMP, safeguard provisions of the Project Implementation Plan, SIA, RAP, and SMF as well as for regular monitoring and reporting of contractor compliance every two months, implementing environmental mitigations that are beyond the contractor's responsibility, and facilitating and coordinating safeguard activities. In addition, NEA will engage consultants to carry out independent review and monitoring of the implementation of environmental and social managements plan and safeguard measures every six months including for the mid-term and project completion reviews 15. NEA, building on the IEE recommendations and EMP included in the IEE, has initiated preparation of Sample Site-Specific Environmental Mitigation Implementation Plan (Sample SS- EMIP). The EMP contained in the IEE addresses the main expected adverse impacts of the proposed transmission line and substations; for implementation, the identified mitigation needs to be detailed and customized for each site's specific conditions. As a large number of tower locations will be fixed only during the early stage of construction, site-specific mitigations can best be detailed during the construction survey. NEA, therefore, has taken a pragmatic approach in detailing site-specific mitigation measures: (i) NEA has initiated preparation of Sample SS- EMIP building on the recommendations of the IEE and EMP; and (ii) NEA will prepare SS- EMIP for the entire length of the transmission line and sub-stations as soon as locations are firmly defined. The sample SS-EMIP will help in initiating early and timely implementation of site-specific mitigation works. The sample SS-EMIP will: (i) identify/propose potential sample sites for compensatory plantation as known at this stage with a plan and program for the plantation; (ii) prepare site-specific mitigation plan for landslide/erosion impacts for already known sample spots of high landslide/erosion risks and a guidance note for the remaining towers, (iii) define minimum standards for workers' Occupational Healthy and Safety depending on the type of works they are involved in and minimum standards for the labor camp including sanitation as well as elaboration of the ways to protect community health from the project or project-induced activities, and (iv) detail the mitigation measures for the sub-stations and hubs impacts. 16. The environmental mitigations activities of the contractor, envisaged by the EMP, are included in the Standard Bidding Documents. The IEE estimates cost of environmental enhancement (training, bio-diversity awareness, support for NTFP and CF establishment) at about US$127,000 and that of biological impact mitigation measures at about US$ 279,000. These costs are internalized within the project. The cost of monitoring/management and physical impact mitigations are assumed to be internalized within project management costs and civil works costs respectively. 74 17. For the Rural Enhanced Energy Services Component, depending on the nature of the investment selected by the community, AEPC will follow the (i) AEPC Environment Assessment Guidelines for Community-owned and Managed Micro Hydro Schemes" dated March 2003 (in use under the ongoing PDP); and (ii) Environmental Management and Mitigation Plan dated September 2010 prepared for biogas schemes. The guidelines for micro hydro schemes provide checklists of potential environmental issues related to the siting of plants, construction and operation activities together with potential mitigation measures as well as a sample matrix for environmental assessment and a sample checklist for environment assessment covering such wide-ranging issues as climate, physiography, hydrology, space/land/soil, flora and fauna, demography, economy, culture and public health. The guidelines also suggest consideration of alternatives, corrective and preventive measures for avoiding/reducing adverse impacts, and mitigation measures for remaining impacts. Common preventive measures recommended are tree plantation and public awareness programs. Pre-investment environmental assessments (EAs) carried out to date have generally been satisfactory and have covered wider environmental management issues in villages than required by World Bank's safeguard operational policies. An EA is one of the three documents (viz; Technical Feasibility, EA and VCDP) that constitute the Detailed Project Report of a micro hydropower scheme. The EA recommends that mitigation measures that are directly related to the micro-hydropower scheme's safety, such as landslides protection works around scheme components, be internalized within the scheme costs and Bills of Quantity to ensure that they are fully funded. Partnership with other agencies is sought for implementation of the wider environmental management activities, including watershed conservation, plantation, awareness and training. 18. Detailed site investigations that will be carried out in the implementation stage will determine whether grid extension or off-grid electrification is the optimal form of electrification for rural settlements in the project area. The potential negative environmental impacts of the distribution lines are expected to be similar to that of the transmission line (described below), however with reduced scale and severity. NEA has several years of experience implementing rural electrification by grid extension and has established standard criteria to avoid or minimize the environmental impacts of the placement of the distribution lines and associated distribution transformers (through avoidance of forests, houses and other structures used by people, etc). The following measures have been agreed to identify and manage the potential environmental impacts of the community-based rural electrification grid extension investments: (i) the Environmental Screening Criteria and Procedures, developed for the Community-based Rural Electrification Grid-Extension Component as part of NEA's Project Implementation Plan, will be used during planning, route/site selection, design and construction of each package, (ii) each community-based rural electrification proposal will be screened for potential environmental impacts; (iii) site-specific Environmental Mitigation Implementation Plans, if required, will be prepared; and (iv) compliance monitoring will be carried out for these activities as for the transmission line component. 75 Annex 11: Governance Framework NEPAL: Kabeli Transmission Project 1. The governance framework for the proposed project was evaluated in keeping with the nature and implementation challenges of the proposed investments and the experience of the ongoing Power Development Project-Additional Financing (PDP-AF) for which a Governance and Accountability Action Plan (GAAP) is under implementation at NEA and AEPC. In keeping with the wide range of support provided under the PDP, in the course of agreeing the GAAP for the PDP-AF an extensive review was carried out at NEA and AEPC of: organizational governance structures; financial management; procurement; monitoring and evaluation; aspects of transparency, disclosure and communications; social oversight and participation; and, where appropriate, grievance redress mechanisms.28 2. Progress in the implementation of the current GAAP under the PDP-AP ­ and more generally, in addressing the core issues reflected in the GAAP ­ is mixed. At NEA, there has been recent good progress in addressing institutional capacity for financial management and procurement (facilitated in part by the scaling up of Bank support to power sector development in Nepal, which includes the NIETTP and the proposed project). An international consulting firm has been engaged to help build NEA's capacity for financial management and will provide support over 2011-2012. NEA has recently engaged an international procurement consultant to assist NEA with procurement for IDA-funded contracts. NEA staff have also participated in a two-week training course in Bank-funded procurement. 3. NEA is in the process of engaging an Owner's Engineer which will be a reputable international firm of transmission project design and construction capability. The scope of services of this consultant will include the proposed NIETTP, the proposed project and will include on-the-job training to NEA staff in project management. Technical assistance that will be provided under the proposed NIETTP will build capacity for NEA's transmission business. These efforts will be enhanced by a twinning arrangement with Statnett, Norway's grid company, that was recently signed by Government of Nepal and Government of Norway. 4. AEPC has made good progress in implementing a study of the long-term sustainability of microhydro schemes. This study, the first comprehensive assessment of microhydro schemes that have been functioning for at least five years, will yield recommendations to: (i) enhance the sustainability of these systems (encompassing technical, financial and institutional dimensions), (ii) reduce the costs of new systems; and (iii) increase the capacity factors of the reviewed systems in support of local economic development. AEPC has established a mechanism for publicly disseminating the information on community grants for micro-hydro plants through display boards in beneficiary communities. 5. With respect to the specific actions agreed in the GAAP at both organizations there is scope for improvement in disclosure and communications, and for basing management of community relations on an understanding of underlying social dynamics at the local level. There is also a need for enhanced monitoring of the implementation on-the-ground of mitigation measures agreed in the context of the social and environmental management plans. 28 PDP-AF Project Paper, Report No. 48516-NP 76 6. Key project-specific governance issues and how they will be addressed under the proposed project are described below. It is important to stress that in some cases the specific activity is not included in the GAAP for the proposed project (because it is treated elsewhere) but it is expected nonetheless to impact positively on the governance of the proposed project. 7. Contract management. There is always uncertainty in the implementation of contracts emanating from a variety of risks. Recent experience with the implementation of transmission line contracts in Nepal indicates that a particular area of concern is NEA's decision-making capacity to review and respond to contractor's claims for variations. The engagement of an Owner's Engineer will supplement NEA's ability to supervise the transmission line contract. The international procurement advisor who is already on board will advise NEA on responding to contractual aspects of variations that may arise in the implementation of the transmission line contract. 8. Communications, consultations and disclosure. The inclusion of the rural electrification components in the project design is a response to the desire of people in the project area for access to electricity that was frequently stated during consultations. While this measure is in itself an important risk-mitigation tool, it is possible that it will create a subsidiary risk, namely, possible dissatisfaction of those communities which for reasons of economic and technical feasibility fall outside the zone to be electrified. Alternatively, even communities that are planned for electrification may wish the process to happen sooner than is possible. How the implementing agencies respond to the communications and consultations challenges of implementation will likely have a significant bearing on the overall success of the project. The implementing agencies will post project-related information on their Web sites (including the EIA/EMP; SIA/RAP/SMF; procurement plan; procurement complaints mechanism; trimesterly implementation progress reports (approved versions); Invitations for Expressions of Interest, Bid Documents, Request for Proposals, Minutes of Pre-bid Conferences, Contract Awards; and Annual Audited Financial Statements. NEA will post a Public Relations officer who will be based at site and oversee information-sharing activities with key stakeholders. NEA will also create a Project Information Center at Ilam which will house all relevant project documents and will carry out ongoing communications and disclosure measures as detailed in the GAAP. 9. Environmental monitoring. Recent project implementation experience has demonstrated that there is a need to improve monitoring of the environmental management plans that are approved for investment projects. In addition, NEA will engage an independent consultant to review environmental monitoring as part of the Mid-Term Review. 77 Governance and Accountability Action Plan (GAAP) Note: this GAAP is specific to the proposed project. It does not reflect measures that are under implementation in the GAAP for the PDP-AF and for the proposed NIETTP. But it is expected that the totality of these measures will contribute to improved governance in the implementation of the proposed project. Issues Identified Proposed Mitigation Measures Milestones Indicative For Monitoring Timeline Components 1 and 2 (implemented by the Nepal Electricity Authority) Communications Posting of a Public Relations 1. Preparation of TOR 1. April 2011 Officer at site 2. Recruitment process 2. May 2011 3. Post officer at site 3. September 2011 Create Project Information Center (Dependent on posting of Public September 2011 at Ilam regional office. Relations Officer) Ongoing disclosure through: Ongoing PIC at Regional Office All relevant documents to be posted on NEA website Disclosure walls at village-level for rural electrification component carrying details of costs, implementation schedules, contact details for project manager etc. Similar information boards at angle-points and other key locations of transmission line. Sharing of information on project with DDCs and VDCs. Monitoring of NEA to engage Independent 1. Preparation of TOR 1. June 2011 EMP Monitor for monitoring of EMP. 2. Launch of RFP 2. August 2011 3. Award contract 3. February 2012 4. Contractor mobillization 4. March 2012 Component 3 (implemented by AEPC) Communications Update AEPC Website with 1. Create project link on AEPC Continuous project-related documents Website with project-related updating documents. Create Project Information Center June 2011 at DEES, Panchthar District Disclosure Formal disclosure of relevant Ongoing documents and progress reports to DDCs and VDCs Accountability Public audits to be carried out in June 2013 ­ project area January 2014 78 Annex 12: Operational Risk Assessment Framework NEPAL: Kabeli Transmission Project Project Development Objectives The project development objectives are: (i) to support the addition of transmission capacity to the Integrated Nepal Power System; and (ii) to provide access to electricity to communities in the area of the Kabeli 132 kV transmission line. PDO Level Results 1. Increased transmission capacity in the Integrated Nepal Power System. Indicators: 2. Number of communities that have received access to enhanced off-grid energy services under the project. Risk Category Risk Risk Description Proposed Mitigation Measures Rating (i) Conscious selection of the project as a national Project Stakeholder Risks High Political and political economy transmission project that will bring additional power considerations for consumption by the domestic economy. (ii) Careful attention to social aspects of project preparation including benefits-sharing. (iii) Incorporation of rural electrification component in project to address local demands for electrification and to help overcome any possible local opposition to the project. (iv) Carry out study of the political economy surrounding the project. (v) Design and carry out a communications strategy that will include the following elements: (a) targeted comms strategy for project area; (b) national consultations on Bank's energy strategy for Nepal; (c) continued engagement by CD and, as appropriate, 79 Risk Category Risk Risk Description Proposed Mitigation Measures Rating team members, with political parties and members of the Constituent Assembly to explain Bank's program of support to Nepal, including to energy sector development. Implementing Agency Risks Capacity High Implementing agencies have several (i) Regular interactions by CD and other staff, projects underway currently, which could including energy team, at senior levels of government, stretch their resources. including with the Minister and Secretary of Energy, Minister and Secretary of Finance and others, providing good platform to address delays that may emanate from NEA Board and senior management level. (ii) Most of team based in Kathmandu, allowing for close support and capacity-building for the new client to come up to speed on Bank procedures, reducing the impact of any capacity risk. (iii) Strengthening of NEA's capacity is being supported under the on-going Power Development Project and the cross-border transmission line that is under preparation. Procurement of the services of an international procurement advisor is nearing completion and plans are being made for strengthening of the transmission business function in particular at NEA. 80 Risk Category Risk Risk Description Proposed Mitigation Measures Rating Governance (i) Regular interactions by CD and other staff, Medium-L Limited capacity, protracted decision- including energy team, at senior levels of government, making process. including with the Minister and Secretary of Energy, Minister and Secretary of Finance and others, providing good platform to engage on sector governance. (ii) TA to strengthen FM at NEA is being provided under the on-going PDP. Fraud & Corruption (i) Ensure adequate procurement and FM support to Medium-I Risks inherent to any large capital- project preparation and supervision. intensive infrastructural project; mitigated (ii) Application of Bank audit requirements to the by existence of robust competitive project. international market for power sector contracts. Project Risks Design Low Technical risks characteristic of (i) Transmission route and distribution line planning to transmission line development in a hilly take into account the microterrain. area. (ii) For the transmission line, the contractor's team will include a civil engineer and NEA will engage a geo-technical advisor for the construction phase. Social and (i) New environmental and social impact assessments Environmental Medium-I Risks of improper handling of will be carried out during preparation; the Bank team environmental or social impacts which will work closely with NEA in this regard. could negatively impact the local area, the (ii) Bank team to help strengthen NEA's safeguards affected population or the river system. capacity through occasional training. The first 81 Risk Category Risk Risk Description Proposed Mitigation Measures Rating training was offered April 1-2, 2010. Program and Donor Low In view of the low probability of this risk no mitigation measures are anticipated. Delivery Quality Medium-L Risks emanating from the inadequate The most effective measure to mitigate this risk will coordination of construction schedules of be adequate support by the Bank to NEA during the other related projects, the two components preparation phase, which will send a positive signal to of this project, etc. other developers to advance projects in the expectation that transmission capacity is expected to be will be available by 2015. Given the very high value of additional units of electricity in Nepal, the economic rate of return remains robust even in credible delay scenarios. Overall Risk Rating at Overall Risk Rating During Comments Preparation Implementation Medium-L Medium-I 82 Annex 13: Project Preparation and Supervision NEPAL: Kabeli Transmission Project Planned Actual PCN review 04-05-2010 04-05-2010 Initial PID to PIC 04-28-2010 04-28-2010 Initial ISDS to PIC 04-30-2010 04-30-2010 Appraisal 02-28-2011 02-10-2011 Negotiations 04-04-2011 04-08-2011 Board/RVP approval 05-31-2011 05-12-2011 Planned date of effectiveness 07-01-2011 Planned date of mid-term review 08-30-2013 Planned closing date 06-30-2015 Bank staff and consultants who worked on the project included: Name Title Unit Michael Haney Sr. Energy Specialist and Task Team Leader SASDE Bigyan B. Pradhan Sr. Financial Management Specialist SARFM Kiran R. Baral Sr. Procurement Specialist SARPS Drona Raj Ghimire Environmental Specialist SASDI Chaohua Zhang Sr. Social Sector Specialist SASDS Mudit Narain Operations Analyst SASDE Aman Sachdeva Financial Analyst (Consultant) SASDE Mei Wang Sr. Counsel LEGES Sunita Gurung Program Specialist SASDO Shaukat Javed Program Specialist SASDO Ayse Cansiz Sr. Power Engineer (Consultant) SASDE Kavita Saraswat Sr. Power Engineer SASDE Junxue Chu Sr. Finance Officer CTRFC Rabin Shrestha Sr. Energy Specialist SASDE Shambhu Uprety Procurement Specialist SARPS Sudeshna Banerjee Sr. Economist SASDE Ishwor Neupane Social Safeguards (Consultant) SASDE Christopher Rytel Power Engineer (Consultant) SASDE Sona Thakur Communications Officer SAREX Bank funds expended to date on project preparation: 1. Bank resources: $235,963 2. Trust funds: - 3. Total: $235,963 Estimated Supervision costs: 1. Estimated average annual supervision cost: $100,000 83 Annex 14: Documents in the Project File NEPAL: Kabeli Transmission Project 1. Project Concept Note (PCN) 2. Project Information Document (PID) 3. Integrated Safeguard Date Sheet (ISDS) 4. NEA. Feasibility Report. Kabeli Corridor 132 kV Transmission Line. June 2010. 5. NEA. Kabeli Corridor Transmission System Development Feasibility Study. January 2009. 6. Social Impact Assessment of the Kabeli Corridor 132 kV Transmission Project. [December 2010] 7. Resettlement Action Plan for Angle Towers of the Kabeli Corridor 132 kV Transmission Project. [December 2010] 8. Social Management & Entitlement Framework of the Kabeli Corridor 132 kV Transmission Project. [December 2010] 84 Annex 15: Statement of Loans and Credits NEPAL: Kabeli Transmission Project Difference between expected and actual Original Amount in US$ Millions disbursements Project ID FY Purpose IBRD IDA SF GEF Cancel. Undisb. Orig. Frm. Rev'd P117417 2010 Second HNP and HIV/AIDS Project 0.00 129.15 0.00 0.00 0.00 130.63 5.33 0.00 P113441 2010 School Sector Reform Program 0.00 130.00 0.00 0.00 0.00 108.31 5.50 0.00 P113002 2009 NP Social Safety Nets Project 0.00 64.47 0.00 0.00 0.00 17.36 -26.65 -5.14 P087140 2009 Agriculture Commercialization and Trade 0.00 20.00 0.00 0.00 0.00 18.63 2.29 0.00 P110762 2008 Peace Support Project 0.00 50.00 0.00 0.00 0.00 25.85 27.34 6.01 P105860 2008 PAF II 0.00 100.00 0.00 0.00 0.03 1.02 -8.15 0.00 P099296 2008 Irrig & Water Res Mgmt Proj 0.00 64.30 0.00 0.00 0.00 49.29 15.55 9.97 P095977 2008 Road Sector Development Project 0.00 117.60 0.00 0.00 0.00 86.18 -14.08 2.70 P100342 2007 Avian Flu 0.00 18.20 0.00 0.00 2.24 2.53 4.28 2.00 P090967 2007 Second Higher Education Project 0.00 60.00 0.00 0.00 0.00 41.03 5.42 0.00 P083923 2005 Rural Access Improve. & Decentralization 0.00 77.00 0.00 0.00 0.00 47.44 2.22 1.85 P071285 2004 Rural Water Supply & Sanitation Project 0.00 52.30 0.00 0.00 0.00 8.49 -17.32 0.00 P071291 2003 NP Financial Sector Technical Assistance 0.00 16.00 0.00 0.00 6.52 1.72 5.33 0.00 P043311 2003 POWER DEVELOPMENT PROJECT 0.00 164.80 0.00 0.00 0.76 128.61 25.32 54.72 Total: 0.00 1,063.82 0.00 0.00 9.55 667.09 32.38 72.11 NEPAL 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. 1996 Bhote Koshi 13.21 2.95 0.00 17.41 13.21 2.95 0.00 17.41 1998 Bhote Koshi 1.64 0.00 0.00 0.00 1.64 0.00 0.00 0.00 1994 Himal Power 18.17 0.00 2.54 0.00 18.17 0.00 2.25 0.00 2001 ILFC - Nepal 0.00 0.10 0.00 0.00 0.00 0.10 0.00 0.00 1998 Jomsom Resort 4.00 0.00 0.00 0.00 4.00 0.00 0.00 0.00 Total portfolio: 37.02 3.05 2.54 17.41 37.02 3.05 2.25 17.41 Approvals Pending Commitment FY Approval Company Loan Equity Quasi Partic. Total pending commitment: 0.00 0.00 0.00 0.00 85 Annex 16: Country at a Glance NEPAL: Kabeli Transmission Project Nepal at a glance 12/9/09 P O V E R T Y a nd S O C IA L S o ut h Lo w- Development diamond* N e pa l A s ia inc o m e 2008 P o pulatio n, mid-year (millio ns) 28.8 1,543 973 Life expectancy GNI per capita (A tlas metho d, US$ ) 400 986 524 GNI (A tlas metho d, US$ billio ns) 1 1 .5 1,522 510 A v e ra ge a nnua l gro wt h, 2 0 0 2 - 0 8 P o pulatio n (%) 2.0 1.5 2.1 Labo r fo rce (%) 3.5 2.2 2.7 GNI Gross per primary M o s t re c e nt e s t im a t e ( la t e s t ye a r a v a ila ble , 2 0 0 2 - 0 8 ) capita enrollment P o verty (% o f po pulatio n belo w natio nal po verty line) 31 .. .. Urban po pulatio n (% o f to tal po pulatio n) 16 30 29 Life expectancy at birth (years) 67 65 59 Infant mo rtality (per 1,000 live births) 41 59 78 Child malnutritio n (% o f children under 5) 39 41 28 Access to improved water source A ccess to an impro ved water so urce (% o f po pulatio n) 89 87 67 Literacy (% o f po pulatio n age 1 5+) 57 63 64 Gro ss primary enro llment (% o f scho o l-age po pulatio n) 121 108 98 Nepal Low-income group M ale 120 1 11 102 Female 121 104 95 KE Y E C O N O M IC R A T IO S a nd LO N G - T E R M T R E N D S 19 8 8 19 9 8 2007 2008 Economic ratios* GDP (US$ billio ns) 3.5 4.9 10.3 12.6 Gro ss capital fo rmatio n/GDP 22.3 24.8 28.1 31 .8 Expo rts o f go o ds and services/GDP 1 .4 1 22.8 13.0 12.1 Trade Gro ss do mestic savings/GDP 1 1 .4 13.8 9.9 1 1 .2 Gro ss natio nal savings/GDP 15.2 23.0 28.7 29.5 Current acco unt balance/GDP -6.5 -1.0 -0.1 2.9 Interest payments/GDP 0.7 0.6 0.3 0.3 Domestic Capital savings formation To tal debt/GDP 33.4 55.0 35.0 29.2 To tal debt service/expo rts 12.1 5.8 5.0 4.1 P resent value o f debt/GDP .. .. 19.5 17.7 P resent value o f debt/expo rts .. .. 67.7 57.2 Indebtedness 19 8 8 - 9 8 19 9 8 - 0 8 2007 2008 2 0 0 8 - 12 (average annual gro wth) GDP 5.0 3.7 3.3 5.3 .. Nepal Low-income group GDP per capita 2.4 1.5 1.4 3.4 .. Expo rts o f go o ds and services .. -1.8 0.5 -3.4 .. S T R UC T UR E o f t he E C O N O M Y 19 8 8 19 9 8 2007 2008 Growth of capital and GDP (%) (% o f GDP ) 30 A griculture 50.9 39.9 33.5 33.7 20 Industry 16.2 22.5 17.1 16.7 10 M anufacturing 6.4 9.6 7.7 7.4 0 Services 32.9 37.6 49.4 49.6 -10 03 04 05 06 07 08 Ho useho ld final co nsumptio n expenditure 79.7 76.9 80.9 78.8 -20 General go v't final co nsumptio n expenditure 9.0 9.3 9.2 10.0 GCF GDP Impo rts o f go o ds and services 22.4 33.9 31.3 32.7 19 8 8 - 9 8 19 9 8 - 0 8 2007 2008 Growth of exports and imports (%) (average annual gro wth) A griculture 2.6 3.4 1.0 4.7 20 Industry 7.8 3.3 3.9 1.9 10 0 M anufacturing 10.6 1.6 2.6 0.2 -10 03 04 05 06 07 08 Services 6.3 3.9 3.8 7.1 -20 Ho useho ld final co nsumptio n expenditure .. 3.5 3.2 3.3 -30 General go v't final co nsumptio n expenditure .. 5.6 7.0 6.8 Gro ss capital fo rmatio n .. 7.0 1.5 20.4 Exports Imports Impo rts o f go o ds and services .. 3.3 1.1 7.5 No te: 2008 data are preliminary estimates. This table was pro duced fro m the Develo pment Eco no mics LDB database. * The diamo nds sho w fo ur key indicato rs in the co untry (in bo ld) co mpared with its inco me-gro up average. If data are missing, the diamo nd will be inco mplete. 86 Nepal P R IC E S a nd G O V E R N M E N T F IN A N C E 19 8 8 19 9 8 2007 2008 Inflation (%) D o m e s t ic pric e s 15 (% change) 12 Co nsumer prices 10.9 8.3 6.4 7.7 9 Implicit GDP deflato r 1 1 .8 4.1 7.7 6.7 6 G o v e rnm e nt f ina nc e 3 (% o f GDP , includes current grants) 0 Current revenue 9.6 12.3 14.1 15.8 03 04 05 06 07 08 Current budget balance -1.1 3.1 3.3 3.9 GDP deflator CPI Overall surplus/deficit -8.8 -4.4 -1.4 -2.8 TRADE 19 8 8 19 9 8 2007 2008 Export and import levels (US$ mill.) (US$ millio ns) To tal expo rts (fo b) 185 856 842 913 4,000 Fo o d .. 51 100 202 P ulses .. 35 63 32 3,000 M anufactures .. 188 601 613 2,000 To tal impo rts (cif) 626 1,551 2,762 3,414 Fo o d 92 79 183 244 1,000 Fuel and energy 47 259 383 413 Capital go o ds 187 270 333 370 0 Expo rt price index (2000=100) .. .. .. .. 02 03 04 05 06 07 08 Impo rt price index (2000=100) .. .. .. .. Exports Imports Terms o f trade (2000=1 00) .. .. .. .. B A LA N C E o f P A Y M E N T S 19 8 8 19 9 8 2007 2008 Current account balance to GDP (%) (US$ millio ns) Expo rts o f go o ds and services 397 1 ,261 1,327 1,603 5 Impo rts o f go o ds and services 741 1,760 3,276 4,234 4 Reso urce balance -344 -499 -1,948 -2,631 3 Net inco me -17 7 106 122 2 Net current transfers 136 443 1,830 2,812 1 Current acco unt balance -226 -49 -13 364 0 Financing items (net) 326 222 97 92 -1 02 03 04 05 06 07 08 Changes in net reserves -100 -172 -84 -456 M emo : Reserves including go ld (US$ millio ns) 226 719 2,008 2,143 Co nversio n rate (DEC, lo cal/US$ ) 22.1 62.0 70.8 64.9 E X T E R N A L D E B T a nd R E S O UR C E F LO WS 19 8 8 19 9 8 2007 2008 Composition of 2008 debt (US$ mill.) (US$ millio ns) To tal debt o utstanding and disbursed ,1 1 65 2,671 3,602 3,685 IB RD 0 0 0 0 F: 4 E: 360 G: 57 IDA 466 ,1 1 31 1,524 1,507 To tal debt service 48 89 147 162 IB RD 0 0 0 0 IDA 6 19 46 50 B: 1,507 Co mpo sitio n o f net reso urce flo ws Official grants 157 171 437 710 Official credito rs 138 135 29 -23 P rivate credito rs 46 -1 3 0 -1 D: 1,680 Fo reign direct investment (net inflo ws) 1 12 6 1 C: 77 P o rtfo lio equity (net inflo ws) 0 0 0 0 Wo rld B ank pro gram Co mmitments 68 0 0 17 Disbursements 84 63 35 31 A - IBRD E - Bilateral P rincipal repayments 2 11 34 39 B - IDA D - Other multilateral F - Private C - IMF G - Short-term Net flo ws 83 52 0 -8 Interest payments 5 8 11 12 Net transfers 78 44 -11 -20 No te: This table was pro duced fro m the Develo pment Eco no mics LDB database. 12/9/09 87 80° 82° 84° 86° 88° 30° SELECTED TOWNS AND VILLAGES 30° Darchula DISTRICT HEADQUARTERS (MECHI) N E PA L NATIONAL CAPITAL FAR Chainpur Saifaidi WESTERN DISTRICT BOUNDARIES (MECHI) KABELI TRANSMISSION Dadeldhura C ZONE BOUNDARY (MECHI) PROJECT Dipayal Jumla H DEVELOPMENT REGION BOUNDARIES Achham MID I INTERNATIONAL BOUNDARIES Mahendranagar N Ataria Dhangadhi WESTERN A MECHI ZONE Birendranagar Jajarkot Kailali Chisapani Salyan Libang Baglung WESTERN Kohalpur Pokhara Besishahar Gulariya Tulsipur Pyuthan Tamghas Dhunche Mt. Everest 28° PROPOSED TRANSMISSION LINES 28° Nepalganj Gorkha Tribhuuvannagar Sandikharka Kodari Mugling Bidur Tansen KATHMANDU Barhabise SELECTED CITIES AND TOWNS Koilabas Butwal Bharatpur Naubise Jiri TAPLEJUNG Dhulikhel Taulihawa Bhaira- Lalitpur Bhaktapur Area of map DISTRICT HEADQUARTERS M M M hawa Parasi Hetauda Num Bhimphedi Taplejung Bhikhathori Ramechhap INDIA HIGHWAYS E E E CENTRAL Sindhulimadi EASTERN Phidim THA R I N D I A Birganj Kalaiya Bhaduare Bhojpur CH PA N Ilam FEEDER ROADS C C C Dhankuta Malangwa Dholkebar Raxaul H 0 40 80 120 160 KILOMETERS Janakpur Gaighat Dharan ILAM Siliguri DISTRICT ROADS Gaur Siraha Lahan Inaruwa Damak Jaleswar I Rajbiraj Chandragadhi OTHER ROADS 0 20 40 60 80 100 MILES Jaynagar Biratnagar JHAPA Bhadrapur 80° 82° 84° 86° Jogbani 88° BAN. VILLAGE DEVELOPMENT COMMITTEE BOUNDARIES 87°30' 87°45' 88°00' DISTRICT BOUNDARIES ZONE BOUNDARIES TAPLEJUNG INTERNATIONAL BOUNDARIES Lelep Papung 27°30' ELEVATION: 27°30' 4500 meters Sanwa Ekhabu Tapethok Nalbu 3500 Khejenim Yamfudin 2500 Thukima Linkhim Liwang Sawadin Mamangkhe 1500 Lingtep Thinglabu Phurumbu 1000 li Kabe Khola Khokling Khamlung Khewang 500 Phakumba Santhakra Hangdeva Pedang Sikaicha Tellok Surunkhim 0 Dhungesaghu Change Taplejung Mehele Tiringe Hangpang Dokhu Ambegudin Sangu Nankholyang Dummrise Sinam Thechambu Ankhop Phulbari Thumbedin Sawalakhu Sadewa Chaksibote Nidhuradin Falaicha Kabeli Tharpu Nagi Oyam 27°15' Ambarpur 27°15' Panchami Sumang NC PA N C H TH A R 88°15' Khunga Ekteen Memeng Luwamfu Bharpa Yangnam Parangbung TERHATHUM Phidim Salleri Nangeen Sidin Ranitar Chokmagu Lungrupa Myanglung Phidim NEPAL Rani Gaun Maimajhuwa Syangrumba Yasok Nawamidanda Embung Pouwa Mabu Phaktep Sartap Mangjabung Chilingdin Puwamajwa Jamuna Sarangdanda Chameta 27°00' Phakphok Pyang Aangna Olane Sakhejung Jogmai Mauwa Sumbek Naya Gorkhe Amchok Barbote Bazar Hangum Ektappa Mangalbare Pashupatinagar Soyang Phuyatappa Rabi Namsaling Aarubote Lumbe Ghuseni Ilam N.P. DHANKUTA Durdimba Kurumba Gajurmukhi Sangrumba Ilam Panchakanya Linba Khandrung Emang Jitpur ILAM Goduk Sri Antu Kanyam Samalp Laxmipura Bajho Siddhithumka Soyak Sakfara Shantipur Chisapani Kolbung Jirmale Erotar Danabari 26°45' Shantinagar 26°45' Mahamai Khudnabari Budhabare Bahundan INDIA Arjundhara Dhaijan MORANG Damak N.P. Satasidham Surunga Sanischare Dhulabari Lakhanpur Kakadvidta Duhagadhi Dharmpur Charpani Anarmani Jyamirgadhi Garamani Topgachchi J H A P A Chandragadhi Gourandana Shivaganj Maharanijhora Haldibari 0 5 10 15 20 Km. Panchganchi Golchhap Bhadrapur N.P. Kohabara Chakchaki Sharanamati 26°30' Juropani Mahabhara Maheshpur Rajghadh Prithivinagar 26°30' Gauriganj Kumarkhod Khajurgachhi Balubari Baniyani This map was produced by the Dharmapur Korabari Pathariya Map Design Unit of The World Bank. Gherabari The boundaries, colors, Pathabnari denominations and any other information shown on this map do not imply, on the part of The World Bank JANUARY 2011 IBRD 37641R Group, any judgment on the legal INDIA Kechana status of any territory, or any endorsement or acceptance of such boundaries. 87°30' 87°45' 88°00' 88°15'