Pad Data Sheet

Document of The World Bank

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Report No: 59893-NP

PROJECT APPRAISAL DOCUMENT

ON A

PROPOSED CREDIT

IN THE AMOUNT OF Public Disclosure Authorized SDR 53.8 MILLION (US$84 MILLION EQUIVALENT)

AND A

PROPOSED GRANT

IN THE AMOUNT OF SDR 9.7 MILLION (US$15 MILLION EQUIVALENT)

Public Disclosure Authorized NEPAL

FOR A

NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

May 27, 2011

Sustainable Development Department South Asia Region

Public Disclosure Authorized

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

AAA Analytical and Advisory Activities HVDC High-voltage Direct Current ADB Asian Development Bank ICR Implementation Completion Report AEPC Alternative Energy Promotion Center IDA International Development Association APL Adaptable Program Loan IDC Interest During Construction BIMSTEC Bay of Bengal Initiative for Multi-Sectoral IEE Initial Environmental Examination Technical and Economic Cooperation BtB Back-to-Back IFC International Finance Corporation CARC The Central Asia Regional Economic IL&FS Infrastructure Leasing and Finance Services Cooperation Ltd. CAS Country Assistance Strategy IMCC Inter Ministerial Coordination Committee CEA Central Electricity Authority IMF International Monetary Fund CERC Central Electricity Regulatory INPS Integrated Nepal Power System Commission CMU Country Management Unit IPP Independent Power Producer CPTC Cross-border Power Transmission ISN Interim Strategy Note Company DfID Department for International Development ISO International Organization for Standardization D-M Dhalkebar-Muzaffarpur Transmission ITSA Implementation and Transmission Service Line Agreement DOED Department of Electricity Development JICA Japan International Cooperation Agency ECO Economic Cooperation Organization kWh Kilowatt hour EIRR Economic Internal Rate of Return MDG(s) Millennium Development Goal(s) EMP Environmental Mitigation Plan MEA Ministry of External Affairs ESIA Environmental and Social Impact MoE Ministry of Energy Assessment ESMAP Energy Sector Management Assistance MoF Ministry of Finance Program ESPP Environment and Social Policies and MoP Ministry of Power Procedures ETFC Electricity Tariff Fixation Commission MOU Memorandum of Understanding MW Megawatts FY Fiscal Year NEA Nepal Electricity Authority GAAP Governance and Accountability Action NLTA Non-Lending Technical Assistance Plan GDP Gross Domestic Product NPC National Planning Commission GEF Global Environment Facility NRETTP Northeast Regional Electricity Transmission and Trade Program GoB Government of Bangladesh OAG Office of the Auditor General GoN Government of Nepal OECD Organization for Economic Cooperation GWh GigaWatthours (1 million kWh) and Development

H-D-D Hetauda-Dhalkebar-Duhabi Transmission OTC Over the counter Line PAF Poverty Alleviation Fund SIMF Social Impact Management Framework PDP Power Development Project SJVNL Sutlej Jal Vidyut Nigam Ltd. POWERGRID POWERGRID Corporation of India Ltd. SPV Special Purpose Vehicle PMO Project Management Office SREP Scaling-up Renewable Energy Program PPA Power Purchase Agreement SWAp(s) Sector wide Approach(es) PSA Power Sales Agreement TA Technical Assistance PSDP Power Sector Development Project TSO Transmission System Operator PTC Power Trading Corporation UI Unscheduled Interchange PTCN Power Transmission Company Nepal UK United Kingdom RAP Resettlement Action Plan UNDP United Nations Development Program RoW Right of Way USA United States of America SAARC South Asia Association for Regional VDC Village Development Committee Cooperation SAR South Asia Region VPDF Vulnerable People Development Framework SAWI South Asia Water Initiative VPDP Vulnerable People Development Plan SDAP Social Action Development Plan WBG World Bank Group SIA Social Impact Assessment WECS Water and Energy Commission Secretariat SIL Specific Investment Loan

Regional Vice President : Isabel Guerrero Director, Regional Integration : Salman Zaheer Country Director : Susan Goldmark Sector Director : John Henry Stein Sector Manager (Acting) : Malcolm Cosgrove-Davies Task Team Leader : Raghuveer Sharma

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NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

Table of Contents

I. Strategic Context ...... 1 A. Regional Context ...... 1 B. Energy in Nepal ...... 3 C. Regional Sectoral and Institutional Context ...... 9 II. South Asia Northeast Regional Electricity Transmission and Trade Program (NRETTP) .. 12 A. Higher Level Objectives to which the Project Contributes ...... 14 B. Project Development Objectives...... 15 1. Project Beneficiaries ...... 15 2. PDO Level Results Indicators ...... 15 III. Project Description ...... 15 A. Project components ...... 15 B. Project Financing ...... 17 1. Lending Instrument ...... 17 2. Project Cost and Financing ...... 17 C. Lessons Learned and Reflected in the Project Design ...... 18 IV. Implementation ...... 20 A. Institutional and Implementation Arrangements ...... 20 B. Results Monitoring and Evaluation ...... 23 C. Sustainability...... 24 V. Key Risks and Mitigation Measures ...... 24 VI. Appraisal Summary ...... 26 A. Economic and Financial Analysis ...... 26 B. Technical ...... 29 C. Financial Management ...... 31 D. Procurement ...... 32 E. Safeguards ...... 32 Annex 1: Results Framework and Monitoring...... 38 Annex 2: Detailed Project Description ...... 40 Annex 3: Implementation Arrangements ...... 52 Annex 4: Operational Risk Assessment Framework (ORAF) ...... 81

Annex 5: Implementation Support Plan ...... 84 Annex 6: Team Composition ...... 87 Annex 7: Institutional Aspects of NEA ...... 88 Annex 8: Financial Analysis ...... 92 Annex 9: Economic Analysis...... 96 Annex 10: Governance Framework ...... 101 Annex 11: Maps ...... 106

PAD DATA SHEET

Country Name: Nepal Project Name: Nepal-India Electricity Transmission and Trade Project

PROJECT APPRAISAL DOCUMENT

Region: South Asia Sector Unit: SASDE

Date: May 27, 2011 Sector(s): Power; Energy Director, Regional Integration: Salman Zaheer Theme(s): Regional Integration Country Director: Susan Goldmark EA Category: B Sector Director: John H. Stein Sector Manager (Acting): Malcolm Cosgrove-Davies Team Leader: Raghuveer Sharma Project ID: P115767 Lending Instrument: SIL Project Financing Data: Proposed terms: [ ] Loan [ X ] Credit [ X ] Grant [ ] Guarantee [ ] Other: Source Total Amount (US$M) Total Project Cost: 202.3 Cofinancing: 73.3* Borrower: 30.0 Total Bank Financing: IBRD - IDA - New 99.0 Recommitted *including US$20 million IDA from ongoing Power Development Project (Cr.4637-NP; Grant H506-NP) Borrower: Government of Nepal Responsible Agency: Nepal Electricity Authority (NEA) Durbar Marga, P.O Box 10020 Kathmandu, Nepal Contact Person: Dr. Jivendra Jha, Managing Director Telephone No.: +977 1 415 3007 Fax No.: +977 1 415 3009 Email: [email protected]

Estimated Disbursements (Bank FY/US$ m) FY 12 13 14 15 Annual 16 33 37 13 Cumulative 16 49 86 99

Project Implementation Period: 5 years Expected effectiveness date: September 30, 2011 Expected closing date: December 2016 Does the project depart from the CAS in content ○ Yes X No or other significant respects?

If yes, please explain:

Does the project require any exceptions from X Yes ○ No Bank policies? Have these been approved/endorsed (as X Yes ○ No appropriate by Bank management? Is approval for any policy exception sought from ○ Yes X No the Board? 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 meet the Regional criteria for X Yes ○ No readiness for implementation? If no, please explain:

Project Development objective: The development objectives of the proposed Project are to: (a) establish cross-border transmission capacity between India and Nepal of about 1000 MW to facilitate electricity trade between the two countries; and, (b) increase the supply of electricity in Nepal by the sustainable import of at least 100 MW.

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Project description:  Part A: Design, construction and operation of 400 kV transmission lines between Muzaffarpur (India) and Dhalkebar (Nepal);  Part B: Design, construction and operation of Hetauda-Dhalkebar-Duhabi 400 kV transmission line (in Nepal) with concomitant substations, and Synchronization of the Nepal and India Grids;  Part C: Technical Assistance for: (a) Owners’ Engineer; (b) Transmission System Master Plan preparation; (c) Lenders’ Engineer; and (d) Capacity Development for NEA and Ministry of Energy. Safeguard policies triggered?

Environmental Assessment (OP/BP 4.01) X Yes ○ No Natural Habitats (OP/BP 4.04) X Yes ○ No Forests (OP/BP 4.36) X Yes ○ No Pest Management (OP 4.09) ○ Yes X No Physical Cultural Resources (OP/BP 4.11) X Yes ○ No Indigenous Peoples (OP/BP 4.10) X Yes ○ No Involuntary Resettlement (OP/BP 4.12) X Yes ○ No Safety of Dams (OP/BP 4.37) ○ Yes X No Projects on International Waterways (OP/BP 7.50) ○ Yes X No Projects in Disputed Areas (OP/BP 7.60) ○ Yes X No

Conditions and Legal Covenants:

Financing Agreement Description of Date Due Reference Condition/Covenant Article 5.01. Condition Subsidiary Agreement has been 90 days after of Effectiveness executed on behalf of the Signing of the Recipient and the Project Financing Implementing Entity. Agreement Article 5.02 Additional Subsidiary Agreement has been Legal Matter duly authorized or ratified by the Recipient and the Project Implementing Entity and is legally binding upon the Recipient and the Project Implementing Entity in accordance with its terms.

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Article IV Remedies of (b) a situation has arisen which the Association shall, in the opinion of the Association, make it improbable that Part A of the Project can be carried out; and (c) the PSA, the ITSA-CPTC or the ITSA-PTCN has been amended, suspended, abrogated or waived, in whole or in part, without the prior written consent of the Association. Schedule 2, Section I. The Recipient shall ensure that D. 4 Ministry of Forests and Soil Conservation shall carry out the Reforestation Program in an acceptable manner. Section IV. B1. No withdrawal shall be made for Withdrawal Conditions payments: (i) made prior to the date of this Agreement; (ii) under Category (1), unless (A) the PSA between NEA and PTC has been signed, in form and substance satisfactory to the Association; (B) the ITSA-CPTC has been signed, in form and substance satisfactory to the Association; and (C) the ITSA- PTCN has been signed, in form and substance satisfactory to the Association Project Agreement, NEA shall, no later than 6 Schedule, Section 1, months after the effectiveness of A.6 the PSA, the ITSA-CPTC and ITSA-PTCN, enter into Back-to- Back PSA and Back-to-Back TSA with respective parties

Project Agreement, NEA shall ensure that the ITSA- Schedule, Section 1, PTCN shall provide for the C.7 obligation of PTCN to carry out Part A.2 of the Project in accordance with the Safeguards Requirements, and to periodically provide NEA with all pertinent data, information and reports necessary for NEA to fulfill its obligations to the Association under the provisions of paragraph C.6 of Section I of this Schedule.

I. Strategic Context

A. Regional Context

1. South Asia has enjoyed robust economic growth, averaging an annual 6 percent over the last 20 years. After a short, steep decline in 2008 (mainly in India) due to the global financial crisis, growth in the region has rebounded and is expected to soon reach and exceed pre-crisis levels. There are significant variations between countries, and also within countries. India leads the rebound with growth estimated at 8.5 percent for 2010, followed by Sri Lanka 7.5 percent, Bangladesh 5.8 percent, Nepal 4.6 percent and Pakistan at around 2.5 percent. Despite this impressive economic growth, poverty in the region remains high with more than 1 billion people living on less than US$2/day. Hence, maintaining growth and expanding economic development opportunities remains a key development priority in the region.

2. At the same time, insufficient access to and the high cost of energy are major constraints to achieving growth and economic development objectives. The energy situation in the South Asia Region (SAR) is characterized by poor consumer access to modern energy sources (especially electricity), high dependence on imported oil and petroleum products, slow development of energy sources and supply infrastructure (relative to demand), weak financial condition of distribution utilities, varying levels of institutional development, and almost no energy trade between the countries. Businesses in the region report that the inadequate, costly and poor quality of grid electricity is the biggest constraint to private investment1 . Non- commercial biomass remains the dominant source of energy for a large fraction of the population2, and per capita electricity consumption in the region is lowest after Africa – annual consumption ranges from 19 and 70 kilowatt hours (kWh) per capita in Afghanistan and Nepal, respectively, to about 540 kWh and 733 kWh in Pakistan and India, respectively (compared with about 1000 kWh in China). Inadequate development of energy resources and supply infrastructure means that even people fortunate enough to have an electricity connection experience poor service and must resort to costly coping mechanisms.

3. Dependence on fossil fuel for power generation is growing and CO2 emissions will continue to grow. India leads the region in coal dependence. Coal-fired power plants comprise about 54 percent of India’s total grid-connected generation capacity and the power sector is responsible for 50 percent of the country’s CO2 emissions. India’s CO2 emissions will continue to grow (albeit from a low per capita base) until at least 2040 under most reasonable scenarios. Significantly lowering carbon emissions in India, as envisaged under the country’s National Action Plan on Climate Change, will require aggressive efforts. Under India’s 11th Five-Year Plan which ends in March 2012, the country expects to add about 62,374 MW of generation capacity to the grid (compared with the Plan target of 78,700 MW). Of this Plan target, thermal (mainly coal-based) generation and hydropower are expected to constitute 76 percent and 20 percent, respectively. India, Pakistan, Bangladesh and Sri Lanka have sector strategies which include an increased reliance on coal to meet their energy requirements over the medium and

1 For example, 50-60 percent of firms in India rely on captive generation to meet their power requirements compared with less than 20 percent in China. 2 More than 80 percent of the energy mix in Afghanistan and Nepal; 60 percent in Sri Lanka and Bangladesh; and about 30 percent in India and Pakistan. 1

longer term. In the shorter term, given the limited choices available, several countries (Afghanistan, Pakistan, and Bangladesh) are contracting oil-based rental or other smaller power plants to alleviate shortages. Nepal is rehabilitating its diesel-based generation plants while consumers must resort to expensive diesel-based generation to meet their own needs. These measures are proving to be both insufficient to close the demand-supply gap, and unaffordable for consumers and governments.

4. Renewable energy development is progressing slowly. The region has made some progress in developing its renewable energy potential – for example, hydropower in Sri Lanka and wind and hydropower in India – but a large untapped potential remains. Known available resources from a cost-competitive point of view include small and larger hydropower (Afghanistan, Bhutan, India, Nepal and Pakistan), wind (Sri Lanka, India and possibly Pakistan), and solar (including potential for larger grid-connected solar power in India). There is also significant potential for moderating demand growth rates through energy efficiency measures, especially in consumer segments which have been less influenced by pricing and energy rationing policies.

5. There is virtually no energy trade between countries in the region other than between Bhutan and India. Several countries in South Asia (Bhutan, Nepal) and its vicinity (Myanmar, Iran, Kyrgyz Republic, Tajikistan, Turkmenistan, Uzbekistan) have potential energy resources far in excess of their own needs even under high growth scenarios. The remaining countries in South Asia (Afghanistan, Bangladesh, India, Maldives, Pakistan, and Sri Lanka) already have energy demand in excess of domestic supply, with demand-supply gaps – especially at peak demand periods – projected to widen. Based on such endowments and their complementarity in mitigating shortages, the overall prospect for energy trade in the eastern energy market was analyzed under the study, “Potential and Prospects for Regional Energy Trade in the South Asia Region” (2008), funded by the Energy Sector Management Action Plan (ESMAP). These are updated and summarized in Table 1.

Table 1: Summary of Trade Prospects in the Eastern Energy Market Importing Exporting Countries Countries India Bhutan Nepal Bangladesh Myanmar India Significant Significant Transit of power Significant gas quantities of hydropower from India’s and power X hydropower export northeast, gas & supply possible possible power from Myanmar, and gas from Bangladesh (with some resource uncertainty) Bhutan Dry season Unlikely; Small amounts of Unlikely (far support similarity of thermal power and off; too small X resources and gas; connection via market) seasonal India shortages Nepal Thermal power Unlikely. Small amounts of Unlikely support. Dry Similarity of thermal power season support resources and X seasonal

Importing Exporting Countries Countries India Bhutan Nepal Bangladesh Myanmar shortages. Bangladesh Electricity swaps Hydropower via Hydropower Unlikely and sharing of India via India (although some generation X potential in reserves; power hydropower) from Northeastern states Myanmar Joint Little Scope Little Scope Little Scope development of X hydropower Source: Updated from “Potential and Prospects for Regional Energy Trade in the South Asia Region” (2008).

B. Energy in Nepal

6. Nepal’s energy-sector development is low by global and South Asia regional standards. An estimated 88 percent of the country’s total primary energy demand is met by traditional (non-commercial) forms of energy, reflecting the overwhelmingly rural distribution of the 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. About 46 percent of the population in Nepal is believed to have access to electricity (grid and off-grid), with a significant disparity between access levels in urban Nepal (around 90 percent) and rural Nepal (around 30 percent).3 Therefore, increasing access to reliable electricity in a timely and cost-effective manner is one of the most significant development challenges facing Nepal today.

7. Electricity consumption levels in Nepal are low. Nepal’s total grid-connected generation capacity amounts to a meager 698 MW although the actual available capacity at any moment is generally less for a variety of reasons such as low water flows (in the hydropower plants) and poor condition of infrastructure. As a result, actual consumption of electricity remains very low, even for urban Nepalese, leading to a perpetual “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, and reaches 16 hours a day during the dry season months. The supply-demand gap has grown sharply in recent years, with a peak demand of about 885 MW (in the dry season of 2009/10). With insufficient electricity provided by the grid, industry and households increasing rely on captive diesel-based power generators or lighting solutions, which are both expensive and polluting.

3 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

8. Nepal’s significant hydropower potential is well-known, as are the many challenges to developing this potential.4 Installed capacity represents less than two percent of the estimated economically viable potential despite the fact that the 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 including first and foremost the overarching factors of conflict and transition that have characterized the last 15 years in Nepal; difficult terrain and limited infrastructure to access project sites; local suspicion of foreign developers; 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; the high financing costs faced by developers of generation projects and the difficulty of coming to financial closure; uncertainty in the process of negotiating Power Purchase Agreements (PPAs) between private power producers and NEA; NEA’s weak financial condition, and; time-consuming processes of review and clearance by Government ministries and agencies. 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 challenging and long-term process.

9. NEA’s financial weakness is a key constraint to energy sector development. Protracted civil strife, rising costs, the absence of adjustments to tariffs since 2001 and operational inefficiency have eroded NEA’s financial condition over the last decade. NEA today is loss-making and heavily indebted (see Annex 8). 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 kWh of electricity it sells, which provides a disincentive to increase supply of electricity at a time of acute deficit. Meanwhile, resistance to tariff increases is high given the track record of poor service and load-shedding, weak public confidence, and that current tariffs are among the highest in South Asia. A Cabinet- appointed task force drafted a financial restructuring plan in 2010 but it has not been adopted or even sufficiently reviewed. The large scale of this problem suggests that its resolution will take some time and will need to be appropriately sequenced, especially with regard to tariff adjustments (to align power prices with current costs). In the short-term, there is a greater willingness to proceed on measures to lower costs through efficiency improvements and the contracting of lower-cost generation, including imports.

10. The Government declared a “national energy crisis” in December 2008 in response to the dramatic worsening of electricity supply that took place in 2008. The 38-Point National Electricity Crisis Management Plan (Action Plan) was approved and is currently under implementation (with support from IDA for some specific investments). This Action Plan includes demand- and supply-side investments aimed at alleviating load-shedding in the short and medium terms. Notably, the Action Plan includes development of the Dhalkebar- Muzaffarpur cross-border transmission link with India (a key element of the proposed Project) which would initially enable import of power to Nepal from India to meet the current debilitating

4 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 the possibility of open access to the deregulated power markets in India suggest that the actual hydropower potential could be much higher. 4

electricity shortages. In addition, the Action Plan includes plans for the development of large hydropower generation projects by the private sector (Table 5). The current government has confirmed its resolve to address the energy crisis, including through the construction of 400 kV transmission links with India to import power to help meet the deficits.

11. The World Bank Group (IDA and IFC) is supporting Nepal’s energy sector development through lending and non-lending activities. The ongoing IDA-funded Power Development Project (PDP) includes support to new transmission and distribution system strengthening; the microhydro-based village electrification program; rehabilitation of existing generation capacity; and technical assistance for the Ministry of Energy and for institutional strengthening of NEA. Non-lending support, in part funded by ESMAP and the multi-donor funded South Asia Water Initiative (SAWI), has helped in assessing the effectiveness of the microhydro program and the barriers to hydropower development. The proposed Project supports efforts already underway between India and Nepal to establish high-capacity cross-border transmission links to facilitate power trade. In parallel, IDA is considering financing the development of the Kabeli Transmission Corridor to facilitate hydropower development in the Kabeli river basin (including the 37 MW Kabeli A project), and the preparation – in partnership with the ADB and IFC – of Nepal’s small hydropower development through the Scaling-Up Renewable Energy Program (SREP) for which Nepal is one of six pilot countries. IFC has investments in two private hydropower projects and is expanding its portfolio of investments in hydropower in Nepal.

12. Other 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 (JICA), the ADB is considering for financing the Upper Seti HEP, 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 SREP. India and Nepal continue bilateral cooperation, among others, in the areas of power generation and power exchange/trade. Through Indian assistance, about 10 percent of Nepal’s installed hydropower capacity (through three small projects) has been realized. Existing government-to-government agreements allow for power exchange of up to 150 MW (effectively imports of power from India into Nepal) but the actual exchange has been far less due to transmission constraints. India is currently providing assistance to Nepal to realize the following projects: rehabilitation of the Devighat HEP; implementation of the 250 MW Naumure Storage Power Project; development of the 27 MW Rahughat HEP; and implementation of the 400 kV Dhalkebar-Muzzafarpur cross-border transmission line (part of the proposed Project). The People's Republic of China has also begun providing assistance to Nepal's energy sector. Current projects under development include the 30 MW Trishuli Hydropower Project and concomitant transmission links, and the development of the Nalsyagu Gad HEP (400 MW).

13. 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 an agreement for 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.

Energy in India

14. The Indian system as a whole has capacity and supply shortages. As of December 31, 2010, India had a total installed capacity of nearly 170,000 MW (54.4 percent coal-based, 10.3 percent gas-based, 22 percent hydro, 9.9 percent alternative and renewable energy, 2.7 percent nuclear and 0.7 percent diesel sets) besides captive generating units with a total estimated capacity of 19,500 MW. Of the total generating capacity, 48 percent is owned by the states, 31 percent by the central government and 21 percent by the private sector. In FY 2010, annual generation amounted to 747 TWh compared to a demand of 831 TWh. Peak demand during FY 2010 was 119,166 MW. The Central Electricity Authority’s (CEA) analysis of the sub-regional situation during FY 2010 is given in Table 2.

Table 2: Region wise Peak Demand and Energy Situation (April 2009-March 2010) Region Energy Needs Energy Deficit Peak Demand Peak Deficit TWh (%) (‘000 MW) (%) North 254.2 11.6 37.2 15.4 West 258.5 13.7 39.6 17.7 South 220.6 6.4 32.2 9.7 East 87.9 4.4 13.2 6.3 North- East 9.3 11.1 1.8 17.9 All India 830.5 10.1 119.2 12.7

15. India has added 50,000 MW in a five-year period, from 120,000 MW in January 2006 to 170,000 MW in January 2011. This represents a 134 percent increase over the 37,300 MW that was added during the entire decade previous to this period (1995 to 2005). The highest annual capacity addition ever recorded was 9,585 MW in 2009-2010. This number has already been surpassed in 2010-2011 with the addition of 10,200 MW. This significant expansion has contributed to a relative easing of the demand-supply gap, as evident from the reduction in the average trading price from up to 20 US cents/kWh to 8-10 cents/kWh over the last year. NTPC, the single largest generation utility, has reported backdown of base load stations during traditional non peak months this year, a scenario that could not have been envisaged just a few years ago.

16. The Indian power system consists of a number of state-owned and -operated grids that are grouped into five regional grids (north, south, east, west and north-east), each with its own Regional Load Dispatch Center. The five regions are interlinked by the National Grid 6

handled by the National Load Dispatch Center. The National Grid had 81,457 circuit km of mostly 400 kV lines, 133 extra-high-voltage substations with a total capacity of 91,630 MVA, and an inter-regional transfer capacity of 22,400 MW as of January 31, 2011 (and this capacity is rapidly increasing). The National Grid is an open access system and is regulated by the Central Electricity Regulatory Commission (CERC). In FY 2010 the inter-regional power exchange amounted to 52 TWh. Four of the five regions operate in synchronous mode whereas the Southern Region is connected with other regions through high-voltage direct current (HVDC) links. More than 95 percent of interstate and inter-regional electric power transmission (that constitutes the National Grid) is operated by POWERGRID Corporation of India Ltd. (POWERGRID) which is recognized as one of the largest and best-run transmission utilities in the world (see below). POWERGRID is owned substantially by the Government of India but a notable part of its equity has been privatized through public offerings.

17. Within this system, daily and seasonal shortages and surpluses occur at various points, creating a good scope for trading. There are a number of registered and regulated electricity traders (including PTC India, formerly Power Trading Corporation of India) who handle long-term, medium-term and short-term contracts. There is an active trade in the national market both in terms of the spot market, and the Unscheduled Interchange (UI) market (the price movements of which are governed by variations of system frequency from the 50 Hz norm), and in terms of contracts for short-, medium- and long-term power. Given the integrated nature of the regional and national grids, there is the potential for power trade with neighboring countries which would ultimately follow the evolving trading conditions across India.

18. POWERGRID Corporation of India Ltd. As India’s Central Transmission Utility with a mission to establish and operate national and regional electricity transmission grids with reliability, security and efficiency, and in accordance with sound commercial principles, POWERGRID is playing a key technical role in the implementation of the proposed Project on the India side and in the Government of India’s broader efforts to facilitate electricity trade with its neighbors. The company constructs and maintains one of the world’s largest extra high voltage (EHV) transmission systems and also provides support to the Government in the planning of the national and regional grids, and the operation of the regional load dispatch centers with state-of-the-art communication facilities through a wholly-owned subsidiary company namely Power System Operation Corporation (POSOCO). Network expansion, operations and financial performance of POWERGRID has been impressive (see table below), underpinned by governance and management structures and policies which serve as a role model for other public sector enterprises in India and globally. In recognition of its sound governance practices and contribution to India’s power sector, in May 2008 the GoI conferred the coveted “Navratna” status on POWERGRID which comes with enhanced delegations/powers for the company’s Board of Directors and Management. POWERGRID first entered the capital market in FY 2007-08 with an Initial Public Offering (IPO) of 10 percent of fresh equity and a disinvestment of 5 percent of GoI’s shareholdings. Subsequently, in November 2010, it had a Follow-on Public Offer (FPO) comprising a fresh issue of 10 percent of paid-up capital along with disinvestment of 10 percent of GoI shareholding. Both the IPO and the FPO received overwhelming response, resulting now in GoI ownerhip of 69.4 percent with the balance being held by the public.

Table 3: POWERGRID’s Performance – A Snapshot

Year Cumulative Inter-Regional Grid Disturbances Turnover Net Profit Transmission Power Exchange Major Minor (US$ (US$ Network (MU) (Number) (Number) Million) Million) (circuit km) 2002-03 46,245 12,600 4 53 567 143 2003-04 47,757 22,800 0 7 623 166 2004-05 50,745 30,800 0 2 629 175 2005-06 55,121 34,800 0 1 790 224 2006-07 59,461 38,000 0 0 910 273 2007-08 66,807 43,000 0 0 1,129 322 2008-09 71,447 46,027 0 0 1,562* 376* 2009-10 75,291 52,000 0 0 1,668* 453* *At the exchange rate of US$ 1= INR 45

19. The World Bank Group has maintained a steady and successful partnership with POWERGRID since its inception in 1989, financing its investment programs, supporting its ongoing efforts to achieve world-class operations and management, and helping leverage private participation (including with IFC financing of the Bhutan/India Tala transmission system). Under a series of Power Sector Development Projects (PSDP), the Bank has provided six direct loans to POWERGRID to date: PSDP I (1993), PSDP II (2001), PSDP III (2006), PSDP IV + Additional Financing (2008), and PSDP V (2009). These loans, together with loans transferred to POWERGRID from its parent entities at the time of inception, amount to about US$4.1 billion. IEG ratings of the outcomes for PSDP I and II were Satisfactory and Highly Satisfactory, respectively. In addition, PDO ratings for the ongoing PSDP-III, PSDP- IV and Additional Financing are Highly Satisfactory, and Satisfactory for the ongoing PSDP-V. Implementation ratings for PSDP III, PSDP- IV and Additional Financing, and PSDP-V projects are Satisfactory.

20. POWERGRID is expected to play a dominant role in overseeing the implementation of the India section of the proposed Project (see Section IV of the PAD). This expectation is based on its shareholding in the Cross-border Power Transmission Company (CPTC, 26 percent), discussions between CPTC and POWERGRID, and POWERGRID’s strong desire to safeguard its reputation. Table 4 lists other joint venture projects in which POWERGRID plays a significant role.

Table 4: Details on POWERGRID’s Joint Ventures

SN Name of the JV JV Partner and Equity Structure5 Associated Generation Project 1 Powerlinks Transmission POWERGRID (49 percent) 1020 MW Tala Hydro Electric Ltd Tata Power Ltd (51 percent) Power (HEP) Project 2 Parbati-Koldam POWERGRID (26 percent) 800 MW Parbati II HEP and 800 Transmission Co. Ltd Reliance Energy Ltd (74 percent) MW Koldam HEP 3 Torrent POWERGRID POWERGRID (26 percent) 1100 MW Sugen generation plant Ltd Torrent Power Transmission Private Ltd (74 percent) 4 Jaypee POWERGRID Ltd POWERGRID (26 percent) 1000 MW Karcham-Wangtoo HEP Jaiprakash Hydropower Ltd (74 percent)

5 Based on the debt equity ratio of 70:30 8

SN Name of the JV JV Partner and Equity Structure5 Associated Generation Project 5 Teestavalley Power POWERGRID (26 percent) 1200 MW Teesta III HEP Transmission Ltd Teesta Urja Ltd (74 percent) 6 IL&FS POWERGRID POWERGRID (50 percent) Development of Intra-state Private Ltd IL&FS (50 percent) Transmission and Sub- transmission lines within the country and outside India 7 North East Transmission ONGC Tripura Power Company 740 MW gas based project in Company Ltd Private Limited (35 percent) Tripura POWERGRID (26 percent) Four Northeast States (39 percent) 8 National High power Test POWERGRID, NTPC, NHPC & DVC - Laboratory Private Ltd – 25 percent each 9 Energy Efficiency POWERGRID, NTPC, PFC & REC – - Services Ltd 25 percent each

C. Regional Sectoral and Institutional Context

21. Cross-border energy cooperation can lower costs in each country, improve supply reliability, and help lower carbon emissions compared with business-as-usual. The development of hydropower in Nepal, Bhutan and Myanmar could alleviate the serious peak power and energy shortages plaguing Bangladesh, India and Pakistan. Also, since peak demand occurs at different periods in different countries, even a country that has a supply deficit during periods of peak demand could export during non-peak periods, when its system could be in surplus. With appropriate project structuring, both energy-deficit and energy-surplus economies can benefit from energy trade. For countries with a surplus or potential surplus, development of hydropower for export can make a significant contribution to the budget, as in Bhutan6. Comparable lessons can also be drawn from other countries, for example hydropower export from Laos to Thailand (including from the recently-commissioned and Bank-supported 1080 MW Nam Theun 2 hydropower plant).

22. Recent developments are setting the stage for electricity trade between India and Bangladesh and between Nepal and India. On the demand-side, electricity shortages have reached crisis levels in Nepal, Bangladesh and parts of India. There is also a heightened awareness of the financial and economic costs of inadequate supply, and that demand will only increase with economic growth and as more people are connected to the grid. Furthermore, power sector reforms in India, catalyzed by the Electricity Act of 2003, have advanced the commercialization of the electricity market and the ability of power producers and traders to compete in the market (at the moment at the wholesale level). While each of the countries has national programs to address sector development needs, India’s offer to supply power to Bangladesh and Nepal as soon as physical connectivity of the grids is established has raised the importance of transmission inter-connectivity. Through commercial and/or state-to-state arrangements, India has made available the supply of 500 MW of power to Bangladesh and 150 MW to Nepal. These amounts can make a significant difference in alleviating power shortages in Bangladesh (with peak shortage of about 2,000 MW) and Nepal (with a peak shortage of about

6 Bhutan’s electricity exports now account for 50 percent of the country’s overall exports, comprise a significant portion of the GDP, and contribute about 60 percent of state revenues. 9

400 MW). Talks have also begun between India, Bangladesh and Bhutan to enable the transmission to Bangladesh of any power that Bangladesh contracts from power producers in Bhutan. These arrangements could potentially be further extended to Nepal.

23. At the political level, a Prime Ministerial level agreement in January 2010 between Bangladesh and India has raised substantially the scope and commitment for cooperation between the two countries. The agreement envisages improving road, rail and water transport and connectivity; reducing trade barriers at border posts; developing the Chittagong and Mongla ports in Bangladesh;7 and connecting the two electricity grids.

24. Separately, private investors and NEA are seeking to develop about 5,000 MW of hydropower potential in Nepal (Table 5). If these developers are able to secure financing and meet all the conditions required for moving these projects ahead, production from these plants will augment the 698 MW of existing generating capacity in the country and relieve the prevailing crippling power shortages. Furthermore, state revenues will also be boosted by the policy and contractual obligations for export-oriented power producers to provide a minimum of 10 percent of the generated power free to Nepal. This synergistic development of Nepal’s hydropower resources for its own needs and to export any surpluses offers the country an opportunity to build the capacity to develop its water resources in a sustainable manner, negotiate fair terms of trade, and enhance the inclusivity of economic growth through an equitable sharing of benefits.

Table 5: Proposed Nepal Hydro Projects No. Project Name Capacity Developer Status (MW)* 1 Upper Tamakoshi 456 NEA Construction started; Expected 2014/15 2 Likhu – IV 120 Bhilwara Preparation completed 3 Upper Marsyangdi 600 GMR Under preparation, seeking financing 4 Kali Gandaki Gorge 275 Hydrosolutions Under preparation, seeking financing 5 Upper Trishuli 110 NEA Under preparation, seeking financing 6 Kirne 67 SN Power Under preparation, seeking financing 7 Balephi 50 Bhilwara Under preparation, seeking financing 8 Lower Arun 400 Braspower Under preparation, seeking financing 9 Arun III 900 SJVNL Under preparation, seeking financing 10 Upper Karnali 900 GMR Under preparation, seeking financing 11 Tamakoshi-3 880 SN Power & Under preparation, seeking financing 12 Upper Seti 127 NEA Under preparation, seeking financing Total: 4,885 * In some cases capacities may be reduced depending on availability of financing

7 Mongla to better serve Bangladesh’s Southwest (complementing the construction of the Padma Bridge) and also improve Nepal and Bhutan’s port connectivity, and Chittagong to improve the port connectivity of India’s northeast. 10

25. The Northeast Electricity Transmission Grid. Opportunities to build the transmission infrastructure to boost electricity trade in the northeastern sub-region are emerging as a consequence of the evolving political and commercial/contractual conditions between Nepal- India and India-Bangladesh, adding to the already established relations between Bhutan and India. These interconnection opportunities are bilateral in nature, consistent with demand-driven patterns (consisting of sound economics, commercial contractual arrangements between electricity suppliers and buyers, and political support). The growing number of bilateral transmission interconnections will form the nucleus of regional energy market. This is also consistent with commitments to grid connectivity under the SAARC (South Asia Association for Regional Cooperation) framework; and with international experience towards regional electricity markets as discussed below.

26. The institutional arrangements to enhance cooperation in energy in the region are being pursued under multilateral approaches. Progress under SAARC includes the establishment in 2005 of an Energy Center in Islamabad and, over the last two to three years, commitments made by the region’s energy ministers to, among other things, grid connectivity, integrated resource development, and energy efficiency and energy conservation. In addition to SAARC, South Asian countries are members of other regional groupings which are also promoting regional energy cooperation. Afghanistan and Pakistan are members of CAREC (the Central Asia Regional Economic Cooperation) and of ECO (Economic Cooperation Organization) which extends further west (including Azerbaijan, Iran and Turkey). Towards the east, South Asian countries (other than Afghanistan and Pakistan) are also members of BIMSTEC (Bay of Bengal Initiative for Multisectoral Technical and Economic Cooperation) which includes Myanmar and Thailand. Energy cooperation remains a key pillar of the agenda of this cooperation. Thus, such multilateral platforms are used to agree on region-wide strategies and priorities for energy trade.

27. In addition, countries are making bilateral institutional arrangements for the establishment of physical links for energy trade under what can be called the Northeast Regional Electricity Transmission and Trade Program (the Program). This Program forms the foundation of the Bank’s support and is described in the next section. Accordingly, India and Bhutan are already connected; the first of a series of India-Nepal high-capacity interconnections is under financing consideration (this proposed Project); the first high-capacity India-Bangladesh interconnection has already received funding from ADB and major contracts have recently been awarded; and an undersea link to connect India and Sri Lanka is in the planning stages. An agreement to facilitate cross-border power exchanges between India and Nepal has been in place since the late 1990s and is now being revised to take into account the large volumes and commercial nature of this trade. The planned SAARC grid is likely to emerge through a series of bilateral transmission infrastructure linkages.

28. South Asian countries are on the path towards development of a regional market. From a review of international experience (e.g., Nordpool, UCTE, Southern Africa Power Pool), carried out recently under the ESMAP-funded report “Trading Arrangements and Risk Management in International Electricity Trade, 2008”, it is evident that the movement towards an integrated market is an evolutionary process and the institutional arrangements of existing regional energy markets has shown a pattern of development that is described in Figure 1. In the

first stage, bilateral trade between neighbors occurs, usually state-to-state utility transfers followed by dedicated trade from new facilities. Trade would take place among synchronized national power systems in the next stage; and then multilateral trade with a regional pool mechanism would happen in the final stage. These multi-country regional pools have taken many years to develop in Europe and the US. Different models are possible and each would allow participating countries to benefit from energy trade.

Figure 1: Institutional Arrangements for Integration of Power Markets

INCREASED INTEGRATION Market Type

Bilateral Regional Long-term PPAs OTC contracts Single market exchanges exchange

Institutional Regional Power Single Market exchange with n/a n/a National MOs Market/Power National Market operator(MO) Exchange Operator

National National National National regulators National regulator? Regulator regulators regulators regulators

Commercial

Standard Standard contracts / Negotiated long- Negotiated long- No contracts contracts / short- Short-term Contracts term contracts term contracts term contracts contracts

Regional PX price Opportunity Negotiated PPA Negotiated Single regional / national prices Pricing exchanges price contract price price diverge

Operational

National Planning / National National Linked national Regional scheduling using scheduling scheduling scheduling scheduling scheduling notified contracts Source: “Trading Arrangements and Risk Management in International Electricity Trade” (2008).

II. South Asia Northeast Regional Electricity Transmission and Trade Program (NRETTP)

29. The proposed Project is one of several projects that comprise the regional transmission program that can be called the South Asia Northeast Regional Electricity Transmission and Trade Program (the Program). The Program seeks to implement evolving agreements between the Governments of Bangladesh, India and Nepal by financing electricity transmission projects which will enable power trade between the countries (Table 6). The Program will reduce related barriers to the development of Nepal’s 40,000+ MW hydropower potential and could facilitate electricity trade and easier connectivity between India’s northeast 12

(with about 60,000 MW of hydropower potential), Bangladesh, and the rest of India. Identified transmission projects in the Program are listed below together with their approximate costs and status (also see Maps in Annex 11).

Table 6: On-Going and Proposed Projects under the South Asia Northeast Regional Electricity Transmission and Trade Program (NRETTP) Countries No Project Likely Project Financing by Status Involved Cost (US$m) 1. Bheramara (NW 160 POWERGRID, ADB has Bangladesh)-Baharampur GoB and ADB approved a (India) HVDC Back-to- loan of Back converter and US$100m Bangladesh corresponding 400 kV line India 2. Various additional Tbd Bilateral opportunities discussions on-going 3. Dhalkebar (Nepal)- 180 NEA, GoN, GoI, Proposed Muzaffarpur (Bihar, India) POWERGRID, Project 400 kV line and SJVNL IL&FS Hetauda-Dhalkebar- and IDA Duhabi 400 kV line in (proposed) Nepal Nepal-India 4. Butwal (Nepal)- 200 Feasibility Gorakhpur (UP, India) Study Nepal-India 400 kV line underway 5. Duhabi (Nepal)-Purnea 150 Under (West Bengal, India) 400 planning kV line 6. Lamki (Nepal)-Bareilly 180 Under (UP, India) 400 kV line planning 7. Siliguri (West Bengal, 120 Under India)- Duhabi (Nepal) Planning 400 kV TOTAL PROGRAM COSTS (indicative) 990

30. The projects are planned to be implemented over the next ten years. While the Governments have yet to formulate their financing strategies for several of the projects, it is expected that at least Nepal and Bangladesh will seek financing support from the International Financial Institutions (World Bank Group including IFC, Asian Development Bank) in addition to bilateral and private/commercial sources.

31. Realization of these transmission lines and establishment of commercial agreements for electricity trade would enable the development of additional transmission and generation projects and expansion of electricity trade and regional cooperation. In particular:

 The preparation of the proposed Dhalkebar-Muzaffarpur line and corresponding negotiations of the commercial agreements have provided encouragement to hydropower

developers in Nepal (Table 5). The World Bank Group has already been requested to help guide some of these projects in their preparatory phase.

 In view of the fact that 100 percent foreign direct investment in power generation is allowed in India, the Government of Bangladesh has expressed preliminary interest in investing in hydro capacity planned to be developed in India’s northeast, where some 60,000 MW of hydropower potential exists. The idea is to bring some hydropower to Bangladesh especially to address current and future power needs.

32. Phasing of the Program. The first project in the Program is the Bangladesh-India Bheramara-Bahrampur HVDC transmission interconnection (500 MW, 125 km, 400 kV double circuit line with back-to-back 400 kV HVDC convertor station at Bheramara in Bangladesh). Financing on the Bangladesh side has been provided by ADB (August 2010) and on the India side by POWERGRID. This line could be expanded to 1000 MW in the future. The details of this project are available in the ADB’s Project Appraisal Document.8 The second project in the Program is the proposed Project, which would finance the Nepal-India, Dhalkebar-Muzaffarpur transmission interconnection and corresponding transmission links within Nepal (Hetauda- Dhalkebar-Duhabi).

A. Higher Level Objectives to which the Project Contributes

33. The proposed Project has the potential to be transformational for Nepal and for the South Asia Region. Its higher level objective is to contribute to the economic growth of Nepal and India by promoting electricity trade which will help overcome power shortages and improve access to lower-cost and reliable electricity in both countries. Industries and households would benefit from the additional electricity to be delivered from the proposed Project, which in turn will promote growth and help achieve social objectives. Nepal would address urgent domestic electricity shortages in the short-term and, in the longer-term, improve state revenues and power sector finances from export earnings and charges for transmission services. The Project would also help strengthen Nepal’s capacity to plan, negotiate and execute further expansion of its electricity transmission system for improving electricity supply within Nepal and for export. In the longer-term, consumers in India and other countries in the South Asia Region can potentially access clean hydropower from Nepal, providing them with an additional option to mitigate their carbon emissions.

34. Rationale for Bank Involvement. The Program and the proposed Project are fully consistent with the strategy of the Government of Nepal (GoN) to address electricity shortages in Nepal in the short-term and to enable economic growth through electricity exports in the longer term. The proposed Project is also fully consistent with the Bank’s Interim Strategy (2009-2011) for Nepal which emphasizes Bank support for cross-border electricity interconnections to facilitate economic development; and with the Bank’s South Asia Regional Strategy Updates (2010 and 2011) which seek to strengthen regional cooperation in trade/transport, water, and electricity.

8 Asian Development Bank: Report and Recommendation of the President to the Board of Directors on a Proposed Loan to Peoples’ Republic of Bangladesh for a Bangladesh-India Electrical Grid Interconnection Project, Project # 44192, August 2010. The ADB is not financing nor supervising the India side of this line. 14

35. The Bank’s support for the Program and proposed Project would also enable the Bank to bring financing instruments that have not been widely used in the South Asia Region. Bangladesh and Nepal would be able to access IDA funds allocated specifically for regional projects, allowing them to leverage their country IDA allocations. More broadly, the World Bank Group, through the IFC, is considering private investment in hydropower generation in Nepal which would be facilitated by the proposed Project.

B. Project Development Objectives

36. The development objectives of the proposed Project are to: (a) establish cross-border transmission capacity between India and Nepal of about 1000 MW to facilitate electricity trade between the two countries; and (b) increase the supply of electricity in Nepal by the sustainable import of at least 100 MW.

1. Project Beneficiaries

37. Project beneficiaries comprise: (i) the electricity consumers in Nepal who would see an increase in power supply from the electricity imports from India; (ii) the IPP developers, most of them private investors, who would use the Project’s transmission infrastructure to sell power domestically in Nepal and to export any surplus power to India; and, (iii) in the longer-term, the electricity consumers in India who will benefit when clean hydropower from Nepal supplied during the energy-surplus wet season contributes to meeting India’s peak power needs.

2. PDO Level Results Indicators

38. The key indicators for the proposed Project include: (a) cross-border transmission capacity; and (b) quantity of electricity imported from India to Nepal (in energy, i.e. kWh terms) under the terms of the Power Sales Agreement.

III. Project Description

A. Project components

39. The proposed Project includes investments financed by IDA (Components B and C) as well as linked investments not financed by IDA (Component A):

Company (CPTC) without World Bank financing or oversight. It will be subject to Indian laws and regulations (See Implementation Arrangements).9  Component A2: Dhalkebar–Bhittamod 400 kV Transmission Line (non-IDA financed). Design, construction and operation of approximately 40 km of 400 kV double circuit transmission line between Bhittamod, on the Nepal border with India, and Dhalkebar in Nepal.

Part B: Hetauda-Dhalkebar-Duhabi (H-D-D) Transmission Line and Grid Synchronization  Component B1: Hetauda-Dhalkebar-Duhabi Transmission Line and Substations. Design, construction and operation of approximately 285 km of 400 kV double circuit transmission line for the Hetauda-Dhalkebar-Duhabi segment, together with concomitant substations in Nepal.  Component B2: Synchronization of Operation of the Nepal and Indian Grids. Installation of properly tuned power system stabilizers in the major power generating stations and other measures in Nepal in order to synchronize its power system with that of India.

Part C: Technical Advisory Services  Component C1: Owners’ Engineer. Provision of technical advisory services, through an Owners’ Engineer for NEA, for overseeing Part B of the Project.  Component C2: Transmission System Master Plan. Provision of technical advisory services to NEA for the preparation of a transmission system master plan for future transmission system development in Nepal and for development of additional cross- border interconnections.  Component C3: Lenders’ Engineer. Provision of technical advisory services, through a Lenders’ Engineer, for enabling results monitoring, highlighting obstacles to achieving results in a timely manner, and ensuring the development and implementation of appropriate corrective actions by NEA, Government of Nepal and the Bank.  Component C4: Capacity Development. Provision of technical advisory services to: (i) NEA to strengthen the institutional capacity of its transmission business, including, inter alia, to increase cross-border transmission links; and, (ii) the Ministry of Energy and NEA to develop understanding of the concepts of benefit-sharing in export-oriented hydroelectric projects, and to strengthen their institutional capability to oversee the Project and further the regional power trade agenda from Nepal’s perspective.

9 The ADB is also not financing nor supervising the India side of the Bangladesh-India Bheramara-Bahrampur HVDC transmission interconnection, the first project of the Northeast Regional ElectricityTransmission and Trade Program. 16

B. Project Financing

1. Lending Instrument

40. The Bank’s support to the regional Program will be through a Specific Investment Loan (SIL) for the proposed Project, for which GoN seeks financing of US$99 million from IDA. The proposed Project qualifies for regional IDA as it is a key project in the regional Program which comprises the participation of three countries. India is financing its participation through commercial sources. ADB and Government of Bangladesh are financing Bangladesh’s participation; and GoN, IDA, Government of India (GoI) and private investors are financing Nepal’s participation.

2. Project Cost and Financing

41. Project Costs. Project costs and financing are summarized in Tables 7 and 8, respectively, while the detailed cost and financing plans are further elaborated in Annex 2.

Table 7: Project Costs Table 8: Financing Plan Project Cost by Component US$ Financing Plan US$ million million Part A: D-M Line - Component A1: Muzaffarpur – Sursand 29.7 Government of Nepal 30.0 Transmission Line - Component A2: Dhalkebar – Bhittamod 17.9 Nepal Electricity Authority 6.0 Transmission Line

Part B: H-D-D Line and Grid IDA (Proposed Credit and 99.0 Synchronization Grant) - Component B1: Hetauda – Dhalkebar – 108.6 Duhabi Transmission Line and Substations - Component B2: Measures for 10.0 IDA Co-financing (on-going 20.0 synchronized operation of the Nepal grid Power Development Project) with the Indian grid Part C: Technical Advisory Services 11.0 Co-financing (Other 11.1 Shareholders than NEA Equity) Total Baseline Costs 177.3 Contingencies 15.0 Government of India Credit 13.2 Line Total Project Costs 192.3 Commercial Borrowing (India 23.0 portion - unidentified) Interest During Construction 10.0

Total Financing Required 202.3 Total Financing 202.3

42. The D-M line components (Part A) will be financed through a combination of debt and equity on a 70:30 debt:equity structure. Shareholders other than NEA would finance US$11.1 million equivalent as equity. The Government of Nepal intends to utilize about US$13.2 million from a Line of Credit from the Government of India to finance the Nepal portion of this line. The source(s) for debt financing of about US$23 million for the India portion of this line is still unidentified but the developer (Infrastructure Leasing and Finance Services or IL&FS) is in discussions with potential financiers, including the IFC, who are considering financing the India portion of the Project. In view of the fact that shareholders of the SPV that would build, own and operate the Indian portion of the line include well resourced firms such as POWERGRID, SJVNL and IL&FS, combined with the interest being shown by IFC, Power Finance Corporation, etc., raising the debt portion of the financing for CPTC is not seen as problematic. GoN has committed to financing about US$30 million from its budget for: (a) NEA’s equity contribution in the two SPVs; (b) the debt financing gap on the Nepal portion of the D-M Line; and, (c) land acquisition, re-forestation, and social compensation costs of the H-D-D line and the Nepal portion of the D-M Line. GoN would provide these funds to NEA’s Balance Sheet partly as equity and partly as low interest loan to further strengthen NEA’s financial position. NEA would meet the costs of about US$6 million for IDC (Interest During Construction) as it accrues.

43. The remaining finance is proposed to come from IDA. US$99 million of this would be the proposed IDA financing and the remaining US$20 million would be from the on-going IDA- financed Power Development Project. The US$99 million equivalent of IDA financing to GoN would be part grant and part credit, according to current country parameters; and all funds would be disbursed only against eligible expenditures. In turn, GoN would on-lend the credit portion of the IDA financing, and provide the grant portion as equity to NEA. This would serve to reduce the financial burden of the proposed Project on NEA. The on-lending terms would be specified in a subsidiary loan agreement; the GoN has agreed to on-lend IDA funds to NEA at an interest rate of 5 percent per annum with a repayment period of 20 years, including 5 years’ grace period.

C. Lessons Learned and Reflected in the Project Design

44. The design of the proposed Project draws on lessons learned from: (i) the Bank’s experience with the implementation of regional power projects; and, (ii) the Bank’s experience implementing energy projects in Nepal.

45. Lessons from Regional Projects. The Bank has approved several regional projects since 2003. These projects are currently under implementation and impart the following lessons of relevance to the proposed Projects:  Simplification. Regional projects are complex simply from involving multiple countries and stakeholders. They also take longer to prepare and implement. For these reasons, simplicity and flexibility should be built into the project design to help ensure successful implementation.  Procurement and Implementation Capacity. All three existing Bank-funded power pool projects have experienced implementation delays and cost increases and have had to seek closing date extensions and additional financing. Implementation delays can be attributed to inadequate implementation capacity on the part of the Bank and the Clients. For the

Bank, having staff based in the country to ensure close supervision and fast response is key while procurement, financial management and project management skills are critical success factors for the Client’s project management teams. While part of the cost increases for the existing power pool projects can be attributed to global price inflation for equipment, consulting and construction services, they are also closely linked to the reasons discussed above for implementation delays.  PPA Readiness. Negotiating Power Purchase Agreements (PPAs) or Power Sales Agreements (PSAs) can take more time than anticipated and can delay project implementation.

46. Lessons from Energy Projects in Nepal. NEA’s recent experience with the Power Development Program (PDP) in Nepal imparts similar lessons regarding procurement and implementation capacity.

 Procurement Capacity. Lessons from the successful implementation by NEA of the Khimti-Dhalkebar 220 kV transmission line is partly attributable to measures taken to ensure that NEA has adequate procurement and implementation capacity for the proposed Project. Measures deployed under the proposed Project include the engagement of an Owners’ Engineer to manage contract implementation and an international Procurement Advisor to provide assistance in the execution of the remaining contracts.  Implementation Capacity. The environment in Nepal today for implementation of large- scale energy projects 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 specific aspects of safeguard policies. Experience from the ongoing PDP 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 and fiduciary experts are essential, for developers as well as for the Bank.

47. In view of the above lessons and considering Nepal’s weak institutional capacity to design and manage projects, the following measures have been taken to ensure implementation success for the proposed Project:

 Significant assistance has been provided to NEA in the preparation of the project with funds from the ongoing PDP as well as from AusAID and DfID to negotiate viable commercial agreements with Indian counterparts, prepare the feasibility study including preliminary design of the H-D-D line, and prepare the Environmental and Social Impact Assessment (ESIA).  NEA’s capacity is being enhanced with the appointment of an Owners’ Engineer who will help with: the bidding process for major contracts, construction supervision, project financial management, and implementation of Safeguards management frameworks (environment, forests and social).

 To strengthen the Project’s governance framework, a Lenders’ Engineer will be appointed to report to the lender(s).  The Procurement Plan has been simplified to include a few large contracts under the Design, Supply and Install approach where contractor(s) have the responsibility for detailed design of the line/substations.  Moreover, an experienced Procurement Advisor is already in place and procurement activities, including preparation of bidding documents, are at an advanced stage.  The Project includes funds for engineering and supervision services to assist NEA in the implementation of the Project.  The PPA and other commercial agreements for the Project are being negotiated. The Bank is following these negotiations closely, and their signature is proposed as a condition of Disbursement of IDA financing against Part B of the Project.

IV. Implementation

A. Institutional and Implementation Arrangements

Partnership Arrangements

48. The three physical components of the project will be constructed and owned by three entities - two of them special purpose vehicles (SPV) in which NEA would be a shareholder.

 The Indian portion of the project would be owned by an SPV called “Crossborder Power Transmission Company Private Limited” (CPTC). This is a joint-venture comprising POWERGRID (26%); Sutlej Jal Vidyut Nigam Ltd (SJVNL) (26%); and IL&FS (48%). A recent shareholders meeting endorsed a 10% share for NEA (with a concomitant reduction in IL&FS’ shareholding). This SPV has been incorporated and is beginning to function.  The SPV to own the Nepal portion of the cross-border transmission line is called “Power Transmission Company Nepal Limited” (PTCN) and is also a joint-venture. The current shareholders are NEA (50%); and IL&FS (50%). POWERGRID has received its Board’s authorization to take up to 26 percent equity in PTCN (with a concomitant reduction in IL&FS’ shareholding10). This SPV is also established and is beginning to function.  The Hetauda-Dhalkebar-Duhabi (H-D-D) line will be built and owned by NEA.

49. For operations, CPTC would have responsibility for operating the Indian portion of the D-M line; PTCN for the Nepal portion of the D-M line; and NEA for the H-D-D lines. With the establishment of this major high voltage link, the Indian and Nepal power grids will be operated synchronously, i.e., essentially as a single system.

10 Shareholders have agreed that in PTCN, eventually IL&FS will hold no more than the level of NEA’s equity in CPTC. Since NEA is likely to hold 10% of equity in CPTC, IL&FS would also reduce its equity in PTCN to 10%, the balance to be picked up by NEA. 20

Commercial/Legal Arrangements

50. The project is being developed on a commercial basis and therefore the legal framework will comprise the following agreements:  A Power Sales Agreement (PSA) between NEA and PTC India (formerly Power Trading Corporation, India);  An Implementation and Transmission Service Agreement (ITSA) between CPTC India and NEA (ITSA-CPTC);  An Implementation and Transmission Service Agreement (ITSA) between PTCN and NEA (ITSA-PTCN).

51. These documents have been drafted and are being negotiated between the Indian parties led by IL&FS (the main developer of this project) and NEA for the ITSAs; and between PTC and NEA for the PSA. These agreements are expected to be signed by July 2011. Signature of these agreements is proposed as a condition of disbursement of the IDA financing against Part B of the proposed Project.

52. These institutional and commercial structures described above are consistent with industry practices for cross-border infrastructure projects with private sector involvement, and were put in place by the developers (IL&FS) and agreed to by the authorities in Nepal before the Bank became involved with the Project.

53. In addition, to mitigate the risks that NEA would face in terms of having to pay the transmission service charge for the D-M transmission line, NEA is planning to enter into Back- to-Back Transmission Service Agreements with expected users of the cross-border line (and the associated internal lines). The users would be mainly IPPs that are developing generation projects to export power to India. The active IPP developers in Nepal and NEA have entered into a Memorandum of Understanding (MoU) whereby the IPPs have indicated their willingness to pay the transmission service fee (essentially capacity charge) to NEA, from the time that the line is commissioned. Moreover, NEA has also begun discussions with industrial consumers to enter into Back-to-Back Power Sales Agreements for the internal sale of power to be imported from India. These Back-to-Back sales agreements would pass on the obligations of NEA on to the industrial consumers. NEA would be required to enter into the Back-to-Back PSAs and Back-to- Back TSAs within six months of the effectiveness of the PSA and ITSA-CPTC/ITSA-PTCN.

54. With funding from the on-going PDP, NEA has engaged international and local advisors with financial, technical and legal expertise to help it negotiate and finalize the commercial/legal agreements with the Indian counterparts and the Back-to-Back agreements with prospective Nepal-based users of the transmission infrastructure.

Institutional Arrangements for Implementation

55. The implementation arrangements for the various components of the project are as follows:

 Component A1 - i.e., the design, construction and operation of approximately 90 km of 400 kV double-circuit transmission line between Muzaffarpur and Sursand in India – will be implemented by CPTC, the SPV incorporated under Indian laws and regulations. CPTC will follow Indian laws and regulations in the construction and operation of this line. IDA is not financing this linked investment and it will have no supervision rights for this component.11 As costs of this component will be recovered from NEA through transmission charges, implementation arrangements (including joint supervision and adherence to environmental and social safeguards policies which are in line with POWERGRID’s ESPP) will be addressed in the ITSA to be entered into between NEA and CPTC.  Component A2 – i.e. the design, construction and operation of approximately 40 km of 400 kV double-circuit transmission line between Bhittamod and Dhalkebar in Nepal – will be implemented by PTCN, the SPV incorporated in Nepal in which NEA holds a 50 percent shareholding and which will follow Nepalese laws and regulations. Even though IDA is not financing this component, it will be subject to IDA safeguards policies, with IDA monitoring through NEA. As with Component A1, implementation arrangements for this component will be addressed in the ITSA to be entered into between NEA and PTCN.  Parts B and C – i.e. the design, construction and operation of the approximately 285 km of 400 kV double-circuit transmission line between Hetauda-Dhalkebar-Duhabi, associated sub-stations, Synchronization, and Technical Advisory Services, - will be implemented by NEA. This component will be subject to IDA safeguards policies and oversight.

56. CPTC and PTCN have indicated their intention to jointly appoint an experienced an internationally reputable grid construction and operation company as the project manager, designer and construction supervisor for Components A1 and A2. Such Project Manager could be POWERGRID (as per discussions between CPTC and POWERGRID) or other entity with similar capability, including in the Safeguards area (see paragraph 88). POWERGRID, in the event it is not appointed Project Manager, as a shareholder in both SPVs, would ensure the adherence to its technical and safeguards standards. Furthermore, recognizing the need to improve the institutional and implementation capacity of NEA, the Project’s design has incorporated specific measures to ensure adequate implementation, governance, and monitoring and reporting capabilities. The implementation arrangements are detailed in Annex 3A and summarized below.  To obtain GoN input in a streamlined manner, an Inter-Ministerial Coordination Committee (IMCC) has been established, headed by the Secretary, Ministry of Energy and comprising representation from the National Planning Commission, ministries of Finance, Foreign Affairs, Forest, Environment, Land Reform and Management, Office of Prime Minister and Council of Ministers, and Nepal Electricity Authority (Managing Director or General Manager of Grid Development). The IMCC will provide overall

11 The ADB is also not financing nor supervising the India side of the Bangladesh-India Bheramara-Bahrampur HVDC transmission interconnection, the first project of the Northeast Regional ElectricityTransmission and Trade Program. It is, instead, relying on POWERGRID’s capabilities, policies and procedures. 22

guidance, policy advice, coordination of the project activities, and address the inter- agency issues.  A Project Steering Committee (PSC) headed by the General Manager, Grid Development has been established to ensure oversight and coordination by NEA’s senior management.  A Project Management Office (PMO) dedicated to preparation and implementation of the proposed Project is already in place and is functioning, under the General Manager, Grid Development.  To address the delays encountered in procurement actions, including getting the necessary clearances from the Bank, an experienced Procurement Advisor is already in place and tender documents for all the major components are at an advanced stage of preparation.  To address weaknesses in the supervision of contracts and safeguards compliance, and project financial management and reporting, an Owners’ Engineer is being appointed to assist the PMO in particular and NEA in general. The services of the Owners’ Engineer (see Annex 2 for details of Scope of Services) are crucial as the contractors are responsible for the detailed designs of the H-D-D line and substations and it is the PMO’s role to oversee the contractor.  To ensure that the Safeguards aspects are properly complied with during implementation, the PMO will have a sub-unit focusing on safeguards, and as mentioned above, would be assisted by the Owners’ Engineer.  To ensure additional accountability and proper governance of all aspects of the Project, a Lenders’ Engineer would be appointed by NEA to report to GoN and the Bank. The Lenders’ Engineer’s mandate would be limited to identifying lapses in quality or speed of project implementation, facilitating early resolution of these lapses, and reporting on a periodic basis to GoN and the Bank.

B. Results Monitoring and Evaluation

57. The PMO will include dedicated personnel for Monitoring and Evaluation. The PMO would submit trimesterly reports in an agreed format to the GoN, Project Steering Committee and the Bank no later than 45 days after the end of each trimester. The trimesterly report would cover the progress and expected completion dates for works and equipment supply contracts, progress on institutional components, implementation of Safeguards Instruments (IEE, EMP, RAP, etc.) and Environmental Mitigation Plan (EMP), Governance and Accountability Action Plan (GAAP), relevant intermediate results indicators, training and studies, and activities of the PMO’s engineering, procurement and financial consultants. The reports would also cover: (a) comparison of actual physical and financial outputs and updated six-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.

58. The PMO will also prepare annual reports by no later than July 15 of each year of project implementation. The report will cover: (a) the progress of each component, implementation of key features of the Safeguards Instruments (IEE, EMP, SIMF, RAP, VPDP and VPDF); key

performance indicators including actions agreed in the GAAP and results framework 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 co-financier, an updated disbursement profile, planned actions for mitigating negative effects during construction, and target indicators for the coming year. A mid-term review of the Project would be undertaken by December 31, 2013. An Implementation Completion Report (ICR) would be submitted to the Bank no later than six months after the closing date.

59. In addition, the presence of the Lenders’ Engineer would enable provision of timely independent feedback to GoN and the Bank. The combination of the Project Steering Committee, Project Management Office, Owners’ Engineer and Lenders’ Engineer would provide the necessary support for regular monitoring and evaluation of the Project’s impact, including the implementation and monitoring of the Safeguard Instruments and enable corrective actions to be undertaken in a timely manner as needed.

60. Project Implementation Period. With these arrangements, a project implementation period of 54 months is planned, starting from the expected date of effectiveness of September 30, 2011 and with a planned construction period of 36 months. The target date for completion of construction is December, 2015. The Credit Closing Date will be December 31, 2016. The Project Implementation schedule is described in Annex 3A.

C. Sustainability

61. Synchronized technical operations with the Indian power grid and timely payment for imported power are key to the sustainability of the Project’s benefits. From a technical and operational point of view, the Project – in fact the entire Nepal grid – would need to operate synchronously with the Indian grid. Accordingly, the technical operational standards and procedures will have to be common between the two grids and the Project would enable the measures to be implemented for such synchronous operation. From a commercial and financial point of view, recognizing NEA’s weak financial condition (see Appraisal Summary and Annex 8), measures are being designed and will be put in place to minimize the project-associated financial risks to NEA. These measures include Back-to-Back Power Sales Agreements between NEA and key industrial customers and Back-to-Back Transmission Service Agreements between NEA and IPPs.

V. Key Risks and Mitigation Measures

62. The detailed Operational Risk Assessment Framework (ORAF) matrix is provided in Annex 4. Key risks and their mitigation strategies are summarized below.  Political risks are a reality, especially in the context of the current political transition in Nepal which could take some time to stabilize, and the complexities of managing political relations across borders. The new Government that came into power in mid- February 2011 has identified resolution of the energy crisis as a top priority and has issued a comprehensive policy statement to this effect. This policy statement re- emphasizes the priority for the proposed Project which is also part of the “38-Point

National Electricity Crisis Management Plan” which was adopted by the Government in 2008. In addition, the leadership of the major political parties has confirmed their support for the Project. Sustainability Risks stem mainly from NEA’s financial situation (discussed in the sustainability discussion above, the Financial Analysis in the Appraisal Summary, as well as the discussion in Annex 8). There is also a risk that the planned new generation by IPPs may not be realized in a timely manner. However, the project remains economically viable even if only 100 MW of the agreed 150 MW import contracted from India materializes.  NEA’s weak implementation capability constitutes a major implementation risk. The Project has been designed to mitigate this risk. Specific measures include an IMCC at the Government level; a high level Project Steering Committee within NEA; an internationally-experienced Procurement Advisor who is already in place; and an Owners’ Engineer which will be recruited to support all aspects of project implementation. Moreover, the Procurement Plan is simplified and procurement actions are already underway.  Another risk is associated with the implementation of Component A1, the linked investment in the Muzaffarpur-Sursand transmission line within India that IDA is not financing and will not supervise. While this does represent a risk to satisfactory project implementation (in terms of Bank’s ability to identify and help remedy any lapses), this risk is modest in scope because: a. The investment footprint is limited - the length of the proposed Muzaffarpur to Sursand line is about 90 kilometers compared to the 325 km of line to be constructed on the Nepal side; and construction of the India portion of the line is well within the capabilities of India’s power sector, as it is small compared to the approximately 5000+ kilometers of high voltage transmission lines installed annually by POWERGRID and others; and India has a good track record for such projects; b. CPTC’s shareholders have decided to adopt an environmental and social policy which is in line with that of POWERGRID’s Environmental and Social Policies and Procedures (ESPP). The Bank has helped shape POWERGRID’s ESPP over its 15+ year lending relationship with the company and such ESPP have previously been reviewed and approved by the Bank under the provisions of OP/BP 4.00 Piloting the Use of Borrower Systems to Address Environmental and Social Safeguard Issues in Bank-Supported Projects for use in the Bank-financed Fifth Power Sector Development Project (PSDP-V, Ln. 7787) in India, approved in 2009. POWERGRID applies ESPP for all its investments, regardless of financing source, and regular project supervision by the Bank, including during a mission in December 2010, has confirmed POWERGRID’s satisfactory adherence to its ESPP; c. The proposed line alignment would traverse an area without significant safeguard risks and with sufficient scope for mitigating social and environmental impacts. World Bank safeguards experts have conducted a site visit of the proposed transmission line alignment in India and noted that the majority of the land is

agricultural and does not present significant safeguard risks as discussed in detail in the Appraisal Summary, Safeguards section. d. Operational risks related with the Muzaffarpur-Sursand Transmission Line in India are well within the capacity of CPTC and its shareholders to manage. Specific risks which can result in transmission line failures include damage due to floods and high winds, while general risks are typically due to inadequate operation and maintenance practices. Although this is not known to be an earthquake prone area, the risk of earthquakes cannot be ruled out. While CPTC has yet to decide on an operator for the Muzaffarpur-Sursand transmission line, management of these risks are well within the managerial, technical and financial capabilities of CPTC's owners which include POWERGRID. POWERGRID, which is expected to play a dominant role in overseeing CPTC’s operations, has a demonstrated track record and capability to build and operate transmission infrastructure under similar conditions in accordance with world class practices. For example, POWERGRID maintains an Emergency Restoration System (ERS) which it has deployed effectively to restore emergency power services after several natural disasters (such as the Gujarat earthquake, etc.). The ERS essentially consists of light weight towers that can be transported to site quickly and set up in a short time frame to restore power flows. Since the area is generally flat and easily accessible, CPTC should be able to respond quickly, especially since its transmission service fees under the Implementation and Transmission Service Agreement with NEA will be linked to line availability. Furthermore, POWERGRID’s oversight of CPTC’s operations and maintenance (O&M) practices - on account of POWERGRID’s ownership and reputational stake in the joint-venture - is expected to ensure that CPTC achieves the operating benchmarks set by POWERGRID, such as not having experienced a major grid disturbance over the last 8 years, having maintained system availability in excess of 99 percent for the last few years, and having achieved a record 99.77 percent system availability in 2009-10 and 99.90 percent in 2010-11.

VI. Appraisal Summary

A. Economic and Financial Analysis

Economic

63. Nepal is currently facing severe shortages of electricity supply and has not been able to meet the growing demand for electricity in the country. The problem is more serious during the dry season months when river flows are at the minimum and electricity demand is at the maximum. Even when plants are generating at full capacity (wet season months), transmission constraints inhibit the adequate flow of electricity to the demand centers. Furthermore, there is insufficient cross-border transmission capacity to trade electricity with India to relieve the domestic shortages. The lack of sufficient transmission capacity has also constrained the development of export-oriented hydropower projects, which Nepal could develop to its advantage for both domestic consumption and export earnings.

64. Supply Demand Analysis. Peak demand in Nepal grew at an annual rate of 9.5 percent over the period FY 2001-FY 2010 while supply grew only at an annual rate of 7.9 percent. However, the grid-connected installed generation capacity has stagnated around 640 MW of which a notable portion is not available for generation on account of old age and the need for rehabilitation. Moreover, because of seasonal river flow variations, generation capacity drops substantially during the dry season. For example, on the highest demand day in FY 2010 (January 19, 2010), load-shedding was more than 400 MW. During the dry season, daily supplies were limited to 12 hours only and the total energy not supplied during the year amounted to 678 GWh.

65. Load forecasts are made by NEA based on econometric modeling, making use of income elasticity and price elasticity concepts but without any analysis of energy end uses. According to NEA’s latest forecast, peak demand is expected to grow from 967 MW in FY 2011 to 3679 MW in FY 2028 at an annual growth rate of 8.2 percent. The annual growth is expected to be at a faster rate of 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 during the 17-year time-frame from 4,431 GWh in FY 2011 to 17,404 GWh by FY 2028 at an annual growth rate of 8.4 percent.

66. Without the proposed Project it is fairly certain that the current deficits, already severe, will worsen. This is because:  Even though NEA has under construction four new hydropower projects totaling 500 MW, all of these are run-of-river schemes and will not be able to meet any part of the incremental winter demand;  While the IPPs are planning to build significant new capacities (See Table 5), all these projects will only be realized if cross-border transmission capacity will be made available as these are all export-oriented hydropower projects;  The transmission system bottlenecks and congestion will continue and will result in increased system losses.

67. With the proposed Project:  Nepal would be able to get at least 100 MW of year-round power from India at a cost that is lower than the costs being incurred to generate diesel-based power; and perhaps lower than what Nepal is now paying in short-term trade with India;  Much of the currently agreed (government-to-government) power import of roughly 100 MW of power (which is not being fully delivered to Nepal due to transmission constraints) will be transferred to the proposed new line, with increased reliability and reduced losses;  The proposed new line would give NEA the option of seeking additional power from the Indian market to meet additional demand on a short-term basis;  The proposed Project would bolster the confidence of the IPP developers and help them to realize their projects, which would benefit Nepal;

 The proposed Project would reduce transmission system losses;  The proposed Project will develop capacity in Nepal to plan, build and operate cross- border interconnections and internal transmission links at higher voltage levels and on a commercial basis.

68. Cost-Benefit Analysis. The proposed Project’s economic viability was assessed using standard cost-benefit analysis. The analysis was applied in two parts: (a) the benefits to consumers in Nepal derived from the imported power from India and the improved efficiency (lower losses) of the Nepal transmission system; and, (b) the benefits to India from hydro exports from Nepal.

69. Economic Returns. While the PSA would provide for 150 MW of contracted power, the committed power under the agreement is 85 percent of that amount, or 127.5 MW. For the economic analysis, a more conservative assumption of 100 MW was used. The Project Economic Internal Rate of Return and Net Present Value are presented for Nepal and India separately (Table 9). Considering only the import of 100 MW to Nepal, the project returns an EIRR of 21 percent. Including benefits to India, the total project EIRR is a healthy 40 percent. The NPV of the project is US$548 million.

Table 9: EIRR and NPV for the Project – Base Case Base Case Net Benefits to Net Benefits to Total Net Nepal India Benefits EIRR (%) 21.22 26.17 39.76 NPV @ 12% (US$ million) 79.6 317 547.5

70. Sensitivity analysis confirms the robustness of the Project to risks of cost overruns and reductions in benefits; the EIRR remains attractive in all the cases analyzed.

Financial

71. Financial Assessment. With a high proportion of fixed costs, transmission tariffs per unit of electricity are especially sensitive to capacity utilization and the amount of electricity being transmitted. Assuming a conservative base level of 100 MW (energy equivalent), the 25-year levelized transmission tariff of the India portion of the line would be 0.44 USc/kWh), the Dhalkebar-Bhittamod portion would have a tariff of 0.29 USc/kWh; and the Hetauda-Dhalkebar- Duhabi section would have had a levelized tariff of 1.44 USc/kWh. This implies a consolidated 25-year levelized tariff of 2.11 US cents per kWh. The results of the financial analysis indicate that the lower bound of FIRR for the Nepal portion of the Project is 13 percent, and for the India portion is 12.7 percent.

72. NEA Corporate Financial Assessment. As detailed in Annex 8, NEA’s financial position remains very weak. 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 increased 16 percent (at 7.7 percent CAGR) during FY 2007-2009, with distribution and power purchase costs - accounting for 20 percent and 58 percent of total costs, respectively - growing at

a compound rate of 18.5 percent and 5 percent, respectively. The cost of generation of NEA grew at 14.4 percent in the same period.

73. GoN and NEA realize the gravity of the situation. To address the problem, a comprehensive Financial Recovery Plan (FRP) was prepared by a special Task Force set up for this purpose as required by the 38-Point National Electricity Crisis Management Plan. The key recommendations of the FRP are: (a) recapitalization of NEA by (i) increasing authorized capital of NEA from NRs 30 billion to NRs 100 billion; (ii) converting accumulated losses into equity; (iii) converting IDC on projects and interest arrears to government by NEA into equity; (b) separate the rural electrification responsibility, operations, assets and liabilities from NEA and transfer them to a new rural electrification company; (c) Government to settle immediately accounts receivables of NRs 3 billion due from the Government; (d) revise the cost of bilaterally- funded grant-financed projects on the basis of market costs or 50 percent of the actual project costs; (e) reduce the interest rate on government loans to NEA to 5 percent p.a; (f) calculate royalty at the point of generation and not at the point of sale; (g) provide government subsidy to cover the escalation in the power purchase costs of NEA; (h) permit NEA to issue government guaranteed debentures (or convertible notes) for hydropower development; (i) ensure prompt payment of dues by local governments for street lighting charges; and (j) raise tariffs by a minimum of 30 percent. This FRP is yet to be discussed and endorsed by the new Government. GoN is expected to take forward the process for adopting and implementing the FRP as the political situation stabilizes.

74. NEA's financial recovery is an important aspect for the sustainability of the sector. However, realization of financial recovery will take time. The Bank, working with other stakeholders such as ADB and others would provide advisory assistance to GoN and NEA to revise and adopt viability enhancement measures both under this Project and other interventions. The proposed Project is critical to the financial recovery of NEA as it would enable additional power at lower costs to be supplied to its consumers; and would enable generation of additional revenues through transmission service charges. In addition, the following measures will be instituted to ensure that this project will not worsen the financial condition of NEA: (a) The obligations that NEA will take on as part of the PSA and ITSA will be passed on to end- consumers through back-to-back PSAs and back-to-back TSAs, respectively; (b) GoN would on- lend the credit portion of IDA financing at a lower rate (5 percent instead of 8 percent), and provide the grant portion of IDA financing as equity to NEA. In addition, the GoN contribution to the financing of the proposed Project will be reflected in the balance sheet of NEA. GoN and NEA have agreed to report, on a semi-annual basis, commencing July 15, 2011, to the Bank on: (a) progress achieved in the process leading to the adoption of the FRP, and, once GoN and NEA have adopted the FRP (after having considered the Bank’s views), (b) implementation progress of the FRP.

B. Technical

75. NEA would be constructing a 400 kV transmission line for the first time, but the components of the proposed Project are not very complex and many 400 kV systems are built and are operating in the world, including a significant number in India. The Bank team directly and through the GoN (under the on-going PDP) has provided significant assistance and capacity building to help NEA prepare the feasibility study of the Project, including the load flow studies,

route alignment survey, establishment of design criteria, preparation of preliminary designs, and preparation of bidding documents. To ease implementation challenges, the Procurement Plan has been simplified to consist of just two goods and works contracts, and two supply contracts. Procurement actions are already underway.

76. POWERGRID’s technical expertise and extensive experience in the design, construction, operation and maintenance of one of the largest transmission networks in the world, and its key role in the implementation of Component A1 through its stake in CPTC (and likely role in Component A2 through its expected stake in PTCN) will contribute to the technical soundness and sustainability of the cross-border transmission line. As mentioned in paragraph 62, POWERGRID achieved a record 99.77 percent system availability in 2009-10. In the same year, it also approved investment projects worth US$3 billion and commissioned projects worth about US$800 million. Over the last several years, POWERGRID has been able to maintain system availability consistently above 99 percent and has not experienced a major disturbance for the last 8 years. POWERGRID uses sophisticated techniques and state-of-the-art technology in operation and maintenance of its assets. Its maintenance activities are International Organization for Standardization (ISO) certified, and systems and procedures are revised periodically to keep up with the latest technology.

77. The transmission links under the Project are designed to cater to current demand and to part of the anticipated future demand in both Nepal and India, which is consistent with good practice in transmission planning Power demand, is growing at close to 10 percent per annum in the region, and transmission links need to be built to accommodate this growth. Moreover, obtaining rights-of-way and land rights for construction is becoming the biggest challenge for transmission line construction, and therefore it is better to design lines for anticipated future growth. Accordingly, in addition to choosing the 400 kV voltage level, the H-D-D line in particular, which will form the backbone of the future 400 kV grid in Nepal, is being designed to carry 3000 MW in the future, with just a change of conductor. An Owners’ Engineer will be appointed to help NEA manage the project implementation and provide the much needed supervisory role in construction. Operationally, the system needs to operate synchronously with the Indian grid, and synchronization/stabilization measures are included as part of the Project.

Institutional Aspects of NEA

78. NEA has been able to keep the power system functioning under difficult conditions. However, NEA faces several key challenges. The first and foremost is the growing gap between supply and demand of power. While there is growing interest from Nepalese and foreign investors to develop Nepal’s hydro capacity, both to meet domestic demand and for export, investors will be obliged to proceed cautiously owing to country risks, the financial condition of Nepal’s power sector, and the absence of transmission infrastructure to the larger Indian power market (which could mitigate some of the risks associated with the Nepal power market). Accelerated and comprehensive development of the country’s transmission system is an important element of Nepal’s energy sector development. NEA, with support from the GoN and its development partners, is placing an increased focus on the strengthening of its transmission system planning and development capacity.

79. Strengthening NEA’s Transmission Grid Development and System Operations. The Grid Development and System Operations business of NEA carry out key functions such as system operation, main grid planning and construction, and grid operations. Grid Development is responsible for the design, construction, operation and maintenance of the 66 kV and higher transmission system of the national grid and for the operation of the Integrated Nepal Power System (INPS).

80. The following measures are needed to strengthen NEA’s Grid Development and System Operations: (a) Improved system utilization; (b) Improved Grid Planning and Project Implementation; (c) Cooperation with neighboring countries in the area of power grid construction and operation; (d) Business Plan for NEA Grid Development, including development of the wheeling and transmission service charges policies; and (e) Capacity for realizing additional cross-border interconnections. To address these capacity needs, technical assistance will be offered by the Bank under the proposed Project and is being considered by other development partners.

C. Financial Management

81. Financial Management and Disbursement (see Annex 3B for details). The FM capability assessment of NEA has been done in the context of the ongoing PDP. The overall project financial management (FM) is less than satisfactory due to concerns over the institutional capability as well as 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.

82. To address the qualified observations of the auditors and other systemic issues, NEA has begun the implementation of an Action Plan, which IDA finds satisfactory. As part of this Action Plan, NEA has recently contracted a well-known international consulting firm under the PDP, which mobilized in December 2010 and has the following main tasks: (a) introduce reform in NEA’s accounting framework; (b) develop and implement a new Financial Accounting System; (c) revise the accounting policy and manual based on International Accounting Standards; (d) provide training to NEA staff; (e) assist in clearing the backlog of audit irregularities; (f) prepare job descriptions of Finance and Accounts staff; and, (g) implement computerization of the financial management system in NEA. Implementation of these measures is expected to strengthen NEA’s financial management capability and will be monitored during project implementation.

83. Audit Arrangements. 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 year 2009/10, a private auditor has been appointed by NEA, with OAG concurrence, to audit the financial accounts, while OAG is to audit the project accounts. This audit is delayed and is expected to be received in June, 2011. To avoid such delays in the future, GoN and NEA would appoint, with the agreement of OAG, 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 the project accounts. The auditor would be appointed before the end of the current financial year.

D. Procurement

84. Procurement Arrangements (see Annex 3C for details). Procurement of the D-M line (Component A1, non-IDA financed) will follow industry practices and the Indian portion will comply with CERC regulatory requirements. Only Indian companies would be eligible to compete for the part of the line on Nepal territory which is funded under the GoI’s Line of Credit. As regards the IDA-financed H-D-D Line within Nepal (including the 400kV substation at Dhalkebar and the substations at Hetauda and Duhabi), a Design, Supply and Install Contract approach is being adopted for the transmission line and substations, with the selected contractor also being responsible for the detailed design. However, the conductor (for transmission line) including earthwire and OPGW and transformers (for substations) would be procured as supply contracts. Appropriate approaches, in accordance with Bank Guidelines, will be developed for the remaining smaller packages including equipment and services for Power System Stability and synchronization, and consulting services.

85. The PMO is responsible for preparing the procurement plans, procurement of consultant services and overall project implementation. The PMO has been the coordinating unit for the preparation of the Project and has gained knowledge of working according to the Bank’s procurement rules. Continued engagement of these staff members with the project will be pivotal in ensuring adequate procurement capacity of the PMO. The procurement function will be looked after by the Procurement and Contract Management Unit.

86. An assessment of the capacity of the implementing agency to implement procurement actions for the Project was carried out by Bank staff. The assessment reviewed the organizational structure for implementing the procurement under the project and the interaction between the Project’s staff responsible for procurement. The special measures for dealing with procurement risk are detailed in Annex 3C based on this review.

E. Safeguards

87. Scope of Environmental and Social Impact Assessment. The developers of the Nepalese sections of the proposed Project (components A2 and B1) and the Indian section (component A1) have used separate approaches and arrangements in addressing the social and environmental impacts of the transmission lines due to different financing, regulatory and institutional structures in the two countries. For the Nepalese sections of the transmission line (components A2 and B1), an independent environmental and social impact assessment has been completed that is consistent with the World Bank’s Safeguards policies, as well as with the local regulatory requirements in Nepal. The Indian portion (component A1) will follow a framework approach consistent with Indian requirements as the exact alignment of the transmission line and the exact locations of the towers will only be finalized during implementation (explained below). The proposed Project is expected to contribute overall positively to the local economies through improved power supply. The local populations are also expected to benefit through enhanced employment opportunities, training, and extension services planned under the Project.

88. Environmental and Social Management Framework for the Indian section of transmission line. The Muzaffarpur-Sursand line (component A1), i.e. the Indian portion of the line, will be implemented by CPTC (see paragraph 48), including the environmental and social

mitigation measures. This line goes into Indian territory for a limited distance of only about 90 km (from Sursand on the Nepal border to the existing sub-station at Muzaffarpur in India). CPTC shareholders have decided to adopt an environmental and social policy for the Indian portion which is in line with POWERGRID’s Environmental and Social Policies and Procedures that have previously been reviewed and approved by the Bank under the provisions of OP/BP 4.00 Piloting the Use of Borrower Systems to Address Environmental and Social Safeguard Issues in Bank-Supported Projects for use in the Bank-financed Fifth Power Sector Development Project (PSDP-V, Ln. 7787) in India approved in 2009.12 The line will pass through the Muzaffarpur and Sitamarhi districts of Bihar,13 where Sursand is located at the India-Nepal border. Three alternative routes (of length 86.4 km, 85.7 km and 101.7 km) for the transmission line were assessed by the shareholders through a consulting firm, during a walkover survey. Considering the route length, vicinity of industrial belts and growing cities, accessibility by roads for construction and maintenance and operation, the first alternative route (or Alternative 1) of 86.4 km route was chosen. A preliminary assessment based on the Forest Atlas, topographical sheets, Google maps and the walkover survey of the area by Bank safeguard specialists indicate that about 0.75 ha of forest land will be needed under the proposed (Alternative 1) transmission line route. The route alignment was carefully selected to avoid any villages or habitations. The line would also not pass through any tribal areas. In addition, the needed expansion of the Muzaffarpur substation can be accommodated within the existing substation premises. For the transmission line route, only the right of way is to be acquired (i.e., not the land), and the line routing will pass through agricultural land, and no people would need to be resettled. Keeping the requirements of the Forest (Conservation) Act in mind, the alignment was selected to avoid major forest areas. As the exact location and alignment of line and towers will be finalized during implementation, in line with POWERGRID’s ESPP, an Environmental Assessment and Resettlement Action Plan (RAP) will be prepared during implementation for this line.

89. Social Assessment and Impacts for the Nepalese sections. The total length of transmission lines in the Nepalese section is about 325 km (Hetauda-Dhalkebar-Duhabi 285 km + Dhalkebar–Bhittamod 40 km). NEA has carried out a Social Impact Assessment (SIA) for the entire length. In accordance with OP 4.12, involuntary resettlement has been avoided where possible; and where it would not be possible to avoid, a Resettlement Action Plan has been prepared through which affected persons would be assisted to improve their livelihoods and standards of living. While preventive planning approaches have been integrated into the Project using alternative engineering design options, appropriate mitigation measures have been planned to address residual adverse impacts. The SIA provides the socioeconomic and demographic profile in the Project districts, identifies potential positive and adverse impacts resulting from the Project’s interventions, and screens the indigenous communities in the Project areas. In accordance with OP 4.10 Indigenous Peoples, the SIA team carried out extensive consultations with local communities and governments to identify Project-related impacts and possible mitigation, as well as recorded their expectations and recommendations for the Project. The SIA has confirmed the presence of indigenous communities in the Project areas and a process of free,

12 A current desk review by the Bank team and the findings of a December 2010 supervision mission of ESPP performance under PSDP V indicates a satisfactory implementation and monitoring of key environment and social mitigation measures. 13 From “Preliminary and Detailed Survey of 400 kV Double Circuit Muzaffarpur-Sursand Route for Indo-Nepal Transmission Project, Detailed Project Report, February 2008. 33

prior and informed consultations has confirmed their support for the Project. A Vulnerable People Development Framework (VPDF) has been prepared that will guide proactive interventions to minimize potential impacts on the indigenous communities. The exact nature of impacts and interventions will be identified consultatively during finalization of the exact alignment and location of the transmission line, towers and substations. A RAP has been developed to resettle and rehabilitate people who will be affected due to the known specific locations of transmission line, towers and substations, while a Social Impact Management Framework (SIMF) has been developed to address the transmission lines, towers and substations whose alignment and specific locations are expected to be finalized only during implementation (described below). Additionally, in compliance with OP 4.11 Physical Culture Resources, during preparation, some minimal impacts on physical cultural resources have been identified, and in consultations with the communities, mitigation measures have been included to be implemented under the Project.

90. Resettlement Action Plan for transmission line, towers and substations for the Nepalese sections whose locations are known. The RAP (details in Annex) was developed based on data from a household survey of socio-economic status and impacts. It indicates that the affected population belongs to 29 different caste/ethnic groups scattered along the transmission line. Extensive consultations with the affected households were carried out to record their concerns and to inform them about Project impacts, and to develop mitigation measures. Overall, the towers and substations will require 21 hectares (ha) of land; relocation of nine private structures belonging to six households; and affect 133 households comprising 873 people. The RAP describes in detail the impacts; compensation policy and entitlements; compensation payment and relocation arrangements for the private structures, one primary school and three temples; and institutional setup and monitoring arrangements.

91. Social Impact Management Framework is to be applied within Nepal where exact locations are currently unknown. The SIMF will be applied to those sections of transmission line and suspension towers whose alignment and specific locations will only be finalized during project implementation. The procedures described in the SIMF have been designed to comply with the relevant local regulations and the World Bank’s Safeguards policies. The SIMF contains a framework with procedures and guidelines to identify, evaluate and prepare plans to address involuntary resettlement; issues concerning vulnerable communities including Indigenous Peoples; and consultation and participation and grievance redress mechanisms. The SIMF also describes policy objectives and principles, planning approach and requirements, review and approval procedures, and institutional responsibilities and implementation arrangements. During implementation, a site-specific RAP and Vulnerable People Development Plan (VPDP) will be prepared as soon as the exact location of the transmission line and suspension towers is established prior to finalization of the engineering designs. The site specific RAP and the VPDP will be reviewed, monitored and supervised by the independent environmental and social management unit of the NEA, supported by the Owners’ Engineer and the Bank’s Safeguards team. The ITSA-PTCN will include the necessary provisions for the application of appropriate Safeguards policies.

92. Environmental assessment and impacts for Nepalese Sections. In accordance with OP 4.01, an Environmental Assessment, as part of the Initial Environmental Examination (IEE) was

undertaken for both the Dhalkebar-Bhittamod section of transmission line in Nepal (component A2), as well as the Hetauda-Dhalkebar-Duhabi section of transmission line in Nepal (component B1). The assessment included developing baseline environmental and social conditions along the anticipated ROW as well as identification and evaluation of impact resulting from proposed intervention. The assessment indicates that environmental and social impacts associated with the project activities are not direct, irreversible or significant in nature. Hence the project is rated Environmental Category B. Also in compliance with OP 4.04 Natural Habitats, the Project avoids critical natural habitats; and includes mitigation measures for those non-critical areas that the Project would affect. Additionally, as part of the environmental assessment, in compliance with OP 4.36, the use of such forest land has been minimized - only a part of the HDD line would pass through some forest land - and to the extent of forest land and trees affected, mitigation measures in accordance with Nepalese law and regulations are included to be implemented under the Project. The findings are summarized below:  Dhalkebar-Bhittamod Section (Component A2): The proposed 40 km stretch of transmission line is located in Dhanusha and Mahottari district of Janakpur zone in Eastern Nepal. The project area does not lie in any national park, wildlife reserve, buffer zone, conservation area, wetlands, historically and archaeologically important sites or environmentally sensitive or fragile areas. The proposed alignment does not pass through forest land. The beneficial impacts include: employment of up to 400 people, increase in economic opportunity, enhancement of technical skills, increase in power exchange facilities and rural electrification. Potential adverse impacts typically associated with transmission lines, such as changes in land use pattern, water pollution, waste disposal and land degradation, are not expected to be significant or irreversible. The biological impacts during construction and operation phase include loss of 728 private trees, loss of 500 bamboo grooves on private property; and potential risk in some locations of birds striking the transmission line. The project-affected people would receive monetary compensation for the losses of trees and bamboo groves. To mitigate the impact on birds, proven methods for minimizing collisions with lines will be used. An Environmental Management Plan (EMP) has been prepared to mitigate and monitor the impacts during the construction and operations phases. These include land use restrictions, loss of agricultural production, land fragmentation and farming hindrance, withdrawal of economic opportunity, occupational safety and livelihood. Overall the environmental assessment shows that adverse impacts on physical, biological as well as socioeconomic and cultural heritage due to implementation and operation of the Dhalkebar-Bhittamod component of the project are limited and can be mitigated.  Hetauda-Dhalkebar-Duhabi section of transmission line in Nepal (component B1). The proposed 285 km 400 kV H-D-D transmission line (the largest component of the proposed Project) mostly runs parallel to existing infrastructure in already human-impacted areas. The proposed alignment often co-shares the Right of Way of the existing 132 kV transmission line and the Mahendra Highway, especially in sections where it passes through the core forest area. The IEE indicates that the proposed line does not go through any national park, wildlife reserve, buffer zone, conservation area, wetlands, or historically and archaeologically important sites. While the proposed transmission line alignment was chosen to completely avoid going through Koshi Tappu Reserve and Parsa Wildlife Reserve, its buffer zone which is approximately 10 km from the proposed Right of Way is known to

contain sensitive flora and fauna, habitats for migratory birds and migration routes of the wild Asian Elephant. The anticipated direct impacts on these sensitive locations by the construction and operation of the H-D-D transmission line, however, are not expected to be significant. Any direct and indirect adverse impact on an area significantly broader than the immediate RoW or on facilities subject to physical work, will be mitigated, closely monitored and supervised. According to the IEE, the existing RoW of the 132 kV transmission line is not reported to have caused adverse impacts on the migration of birds or the wild Asian Elephant that continues to migrate over the highway and under the 132 kV line. The proposed 400 kV line which for the most part will run parallel to the existing 132 kV line will have a greater vertical ground clearance than the 132 kV line, and elephants (which are actually attracted by the crops and their traversing by elephants happens close to the harvesting season) can continue to pass through unhindered under the new line. The NEA environmental team supported by the Owners’ Engineer and the Bank’s Safeguards team will closely monitor and supervise the construction and implementation phase of the Hetouda- Dhalkebar-Duhabi transmission line.

93. Environmental and Social Mitigation, Monitoring and Supervision. As mentioned earlier (paragraphs 20 and 55), for the Muzaffarpur-Sursand line in India (Component A1), CPTC shareholders will address the joint supervision arrangements among themselves in the ITSA-CPTC; and IDA will have no supervision rights for this component. Similar joint supervision arrangements would be entered into in the ITSA-PTCN for the Dhalkebar-Bittamod line in Nepal, which is also not financed by IDA. However, IDA would be able to monitor, through NEA the implementation of this component, including adherence to the Safeguards aspects satisfactory to the Bank. IDA would of course supervise the HDD line and concomitant substations, which it would be financing. CPTC shareholders have decided to have joint project monitoring through the formation of a Coordination Committee which would meet at least once every three months.

94. While the NEA’s capacity is being strengthened for safeguards management through other ongoing engagements in the power sector in Nepal as well as through this project, a two- level monitoring and supervision framework is proposed for the implementation of the H-D-D line. The PMO will have a specialized Safeguards Monitoring Unit (SMU); and the construction Contractor’s team will be required to have a trained environmental and social development specialist on their team to assist during implementation. An Owners’ Engineer will assist the NEA to oversee the work of the Contractor. In addition, a Lenders’ Engineer with sufficient expertise on the environmental management aspects of transmission line construction will also be hired to help with safeguards monitoring and supervision. For the Dhalkebar-Bhittamod line, PTCN will prepare similar suitable site specific plans to address environmental management measures specified in the IEE and share them with NEA. PTCN will also share required information with NEA so that NEA can report to the Bank on compliance with these requirements each trimester.

95. The total estimated environmental and social management cost for the Nepalese portion of the proposed Project is approximately US$15 million. This includes: costs of compensation and livelihood assistance; compensatory reforestation and biodiversity-related mitigation measures; relocation of a primary school and three temples; environmental monitoring during

pre-construction, construction and operation phases of the Project; provision of a communications/outreach centre; supervision and monitoring of implementation; and capacity building of NEA staff on environmental management and social issues.

F. Safeguards Policies triggered

Safeguard Policies Triggered by the Project Yes No TBD Environmental Assessment (OP/BP 4.01) X Natural Habitats (OP/BP 4.04) X Pest Management (OP 4.09) X Physical Cultural Resources (OP/BP 4.11) X Involuntary Resettlement (OP/BP 4.12) X Indigenous Peoples ( OP/BP 4.10) X Forests (OP/BP 4.36) X Safety of Dams (OP/BP 4.37) X Projects in Disputed Areas (OP/BP 7.60)* X Projects on International Waterways (OP/BP 7.50) X

* By supporting the proposed Project, the Bank does not intend to prejudice the final determination of the parties' claims on the disputed areas 37

Annex 1: Results Framework and Monitoring NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

Project Development Objective (PDO): (a) establish cross-border transmission capacity between India and Nepal of about 1000 MW to facilitate electricity trade between the two countries; and (b) increase the supply of electricity in Nepal by the sustainable import of at least 100 MW. Cumulative Target Values** Data Responsi Description PDO Level Results Unit of Source/ bility for (indicator Baseline Frequency Indicators* Core Measure YR 1 YR 2 YR3 YR 4 YR5 Metho Data definition dology Collection etc.) Indicator One: Cross- NEA Transmissio Border transmission MW 0 0 0 0 0 1000 Annual Report NEA n capacity in capacity s MW Indicator Two: Traded quantity of electricity GWh NEA Electricity imported from India per 0 0 0 0 0 744 Annual Report NEA under the into Nepal under the year s PSA in PSA GWh

INTERMEDIATE RESULTS Intermediate Result (Component One): Design, construction and operation of 400 kV transmission line between (a) Muzaffarpur (India) and Dhalkebar (Nepal); and (b) Hetauda- Dhalkebar-Duhabi with concomitant sub-stations. Intermediate Result Number of indicator One: T/L tower T/L line 400 kV Vario T/L tower foundation Line Construction Progress 0 0 stringing Trimester NEA transmission us foundation 40% 100%, Tower Operational erection 40% complete line towers constructed Intermediate Result Number of indicator Two: T/L tower T/L line 400 kV Vario T/L tower foundation Line Construction Progress 0 0 stringing Trimester NEA transmission us foundation 40% 100%, Tower Operational erection 40% complete line towers constructed

Cumulative Target Values** Data Responsi Description PDO Level Results Unit of Source/ bility for (indicator Baseline Frequency Indicators* Core Measure YR 1 YR 2 YR3 YR 4 YR5 Metho Data definition dology Collection etc.) Intermediate Result Number of indicator Three: T/L tower T/L line 400 kV Vario T/L tower foundation 90%, Construction Progress 0 0 stringing Line Trimester NEA transmission us foundation 40% Tower erection 30% complete Operational line towers constructed Intermediate Result Power Steps indicator Four: System Actio required to Synchronization of Stabilizers n Power System achieve Nepal grid and India No No No Scope installed Steps Stabilizers Annual NEA synchronizat grid synchron synchronization synchronization finalized and Requi ordered ion between ization Systems red the two Synchroniz grids ed Intermediate Result (Component Two): Consulting assistance to NEA for: (a) Owners’ Engineer; (b) Transmission System Master Plan preparation; (c) Lenders’ Engineer; and (d) Capacity Building Intermediate Result Draft Final Trimester Steps indicator Five: Transmission Transmission required to Transmission System System Master System Master develop the

Master Plan Plan prepared Plan Transmissio Developed n System Master Plan

Annex 2: Detailed Project Description NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

Project Genesis

1. Nepal has a long common border sharing on its south with India from east to west touching the states of West Bengal, Bihar, Uttar Pradesh and Uttaranchal. With its huge hydro potential and power deficits in the region coupled with hardening energy prices, there is immense scope for closer cooperation on power interchange between the two countries for mutual benefits.

2. The current power deficit of Nepal is partly met (to the tune of 50-100 MW) by imports from India using a number of small capacity interconnections (presently there are 21 interconnections, four 132 kV, others mostly 33 kV or 11 kV links between India and Nepal). However, the deficit is increasing over the next 5-7 years is estimated to increase to about 600 MW which Nepal intends to meet by import from India and commissioning additional generation projects. According to the present projected load generation scenario for Nepal, at least in the initial 5 years i.e., up to 2014-15, during dry season the load flow is envisaged from India to Nepal and vice versa during monsoon season.

3. Taking into consideration commissioning of on-going and new small and medium sized hydro projects totaling around 2,000 MW, Nepal Electricity Authority has estimated that after 5 to 7 years with the commissioning of small and medium sized hydro projects Nepal would have surplus power and after meeting their demand they would be able to export at least 300 MW to India, without even taking into account the large sized hydro projects, which are also under development.

4. Therefore there is a need to develop a robust and viable transmission interconnection, which has been under discussion for quite some time. The Indo-Nepal Power Exchange Committee had initially identified the following four transmission corridors that if operating at appropriate high voltage level could be developed between the two countries: Butwal- Anandnagar, Dhalkhebar-Sitamari, Duhabi-Purnea and Anarmani-Siliguri.

5. Considering the above scenario IL&FS, NEA and PTC with support from the Ministry of Power, Ministry of External Affairs (MEA), GoI, and Indian Embassy in Nepal commenced taking initiatives in mid-2006 to facilitate the development of transmission interconnections between India and Nepal for mutual interest of both countries. The Ministry of External Affairs and Ministry of Power (MoP) of GoI further discussed the cross-border transmission links in May 2007 and consequently entrusted POWERGRID Corporation of India to undertake the transmission system study with NEA.

6. Pursuant to above, an interconnection study was carried out by POWERGRID jointly with NEA. In September 2007, in a meeting between the Nepalese delegation led by NEA and Indian delegation led by Ministry of Power, Government of India, the corridor and modality of interconnections were finalized - it was agreed that a single point AC interconnection of 400 kV

level be taken up in the first phase. This was necessary due to issues of loop flows resulting from parallel paths created by multiple interconnections, which may burden the Nepalese grid unless it is also strengthened. Since the synchronous connection would result in the Nepal Grid being connected to the Indian Grid, in much the same way as the Indian states are connected, it was decided that the point of interconnection most suitable at present would be between Muzaffarpur in India and Dhalkebar in Nepal through a 400 kV double circuit line and would be implemented in the first phase with the interconnection being in synchronous mode. Accordingly, IL&FS as the ‘lead developer’ of the Project initiated and completed the Detailed Project Reports (Feasibility Studies) of the Dhalkebar-Muzaffarpur (D-M) line, including environmental and social assessments through POWERGRID. In addition, the project was to be developed and operated under a commercial framework with special purpose vehicles established and commercial agreements signed for the construction and operation of the Project.

7. The Bank joined these efforts in September 2009 to help with the realization of the cross- border high voltage interconnection. It was recognized that the line between Dhalkebar (Nepal) andMuzaffarpur (India) is necessary but not sufficient to derive the benefits from this line. This is because there are no load centers at Dhalkebar. Therefore, the construction of the Butwal- Dhalkebar-Duhabi transmission links is also needed along with the construction of the D-M line. Fortunately, parts of this additional line, Hetauda-Bharatpur (70 km) section; and Bharatpur- Bardghat (70 km) are already under implementation with World Bank financing under the Power Development Project. Therefore, the construction of the Hetauda-Dhalkebar-Duhabi line was agreed to be taken up as part of the proposed Project. In addition, it was decided to make this link a 400 kV link, thus creating the beginning of the east-west transmission backbone of Nepal, which will be able to evacuate the energy from the medium-large hydro projects being developed in Nepal with a view of exporting the excess production to India in the long-term.

Project components

8. The proposed Project would comprise the following components:

Part A: Dhalkebar-Muzaffarpur (D-M) Transmission Line  Component A1: Muzaffarpur-Sursand 400 kV Transmission Line (non-IDA financed). Design, construction and operation of approximately 90 km of 400 kV double circuit transmission line between Muzaffarpur and Sursand on the Indian border with Nepal.  Component A2: Dhalkebar–Bhittamod 400 kV Transmission Line (non-IDA financed). Design, construction and operation of approximately 40 km of 400 kV double circuit transmission line between Dhalkebar and Bhittamod on the Nepal border with India.

double circuit transmission line for the Hetauda-Dhalkebar-Duhabi segment, together with concomitant substations in Nepal;  Component B2: Synchronization of Operation of the Nepal and Indian Grids. Installation of properly tuned power system stabilizers in the major power generating stations and other measures in Nepal in order to synchronize its power system with that of India.

Part C: Technical Advisory Services  Component C1: Owners’ Engineer. Provision of technical advisory services, through an Owners’ Engineer for NEA, for overseeing Part B of the Project.  Component C2: Transmission System Master Plan. Provision of technical advisory services to NEA for the preparation of a transmission system master plan for future transmission system development in Nepal and for development of additional cross-border interconnections.  Component C3: Lenders’ Engineer. Provision of technical advisory services, through a Lenders’ Engineer, for enabling results monitoring, highlighting obstacles to achieving results in a timely manner, and ensuring the development and implementation of appropriate corrective actions by NEA, Government of Nepal and the Bank.  Component C4: Capacity Development. Provision of technical advisory services to: (i) NEA to strengthen the institutional capacity of its transmission business, including, inter alia, to increase cross-border transmission links; and, (ii) the Ministry of Energy and NEA to develop understanding of the concepts of benefit-sharing in export-oriented hydroelectric projects, and to strengthen their institutional capability to oversee the Project and further the regional power trade agenda from Nepal’s perspective.

Detailed Description

Part A

9. Component A1: Muzaffarpur-Sursand Transmission Line. The project is located in the Muzaffarpur and Sitamarhi districts of the state of Bihar in India, where Sursand is located at the India-Nepal border.

10. Transmission Line Route. Three alternative routes (of length 86.430 km, 85.679 km and 101.666 km) for transmission line were studied during a walkover survey. Considering the route length, vicinity of industrial belts and growing cities, accessibility by roads for construction and maintenance and operation, the first alternative route (or Alternative 1) of 86.43 km route was chosen. The proposed transmission line alignment starts from POWERGRID’s Muzaffarpur substation and passes through Muzaffarpur and Sitamarhi districts of Bihar. After emanating from POWERGRID’s 400 kV substation at Kafain it connects to the Dhalkebar-Bhittamod line at the India-Nepal border at Sursand. A preliminary assessment based on Forest Atlas, topographical sheets, Google map and walkover survey of the area indicate that about 0.75 ha of

forest land will be needed in the proposed (Alternative 1) transmission line route. The route alignment was carefully selected to avoid any villages or habitations or forest areas. Around 100 percent of the line traverses through plain terrain with about 300 meters of route length infringing upon road and canal-side social forest. There are two major river crossings: Burigandak River with a span of less than 468 meters and Bagmati River with a span of 804 meters. The line is mostly adjacent to road and from visual observation of soil strata passes through mostly sandy silt with some portions having sandy soil belts for which shallow foundation provision will be necessary. The route can be approached mostly by all-weather roads all along the length which will make construction and operation activity easier.

11. Project Features. The proposed 400 kV transmission line will be approximately 90 km in length, and double-circuit comprising of duplex overhead conductors. The vertical double- circuit configuration tower will have an average height of 45 meters and the standard tower base dimensions will be 15 meters by 15 meters from centre to centre of each tower leg foundation/ footing. The design span between tower structures is approximately 400 meters. The RoW of the proposed transmission line is 23 meters on each side from the centerline of the overhead transmission line. The transmission line design features are given in Table A2.1.

Table A2.1 Muzaffarpur - Sursand 400 kV D/C Transmission Line Design Features

S.No. Item Name 1 Total Length 86.43 km 2 Bee Line 75.365km 3 Total no. of Tower 239 nos. 4 Total no. of Suspension Tower 160 nos 5 Total no. of Angle Tower 79 nos. 6 Forest Length (Social forest) 0.748 ha 7 National Highway X-ING 4nos. NH - 28, NH - 57, NH - 77, NH – 104 8 State Highway X-ING 1 no., SH – 52 9 Power Line X-ING:- 66 KV Nil 10 Power Line X-ING:- 132 KV Nil 11 Power Line X-ING:- 220 KV 2 12 Power Line X-ING:- 400 KV S/C Nil 13 River X-ING Major River 2nos. Burigandak (350m), Bagmati (700m) 14 Railway X-ING 3 nos. under North Eastern Railways

12. Component A2: Dhalkebar–Bhittamod 400 kV Transmission Line. The proposed line is located in Dhanusha and Mahottari districts of the Janakpur zone of the Central Development Region in the Tarai area of Nepal. The transmission line route is accessible through district and feeder roads.

13. Transmission Line Route. The proposed transmission line alignment starts from Substation tole (Bijuli tole) of the Dhalkebar VDC ward-4 located just outside of the existing substation and passes mainly through the cultivated land of Dhanusha and Mahottari district and finally terminates at the India-Nepal border (the inter-connection point) located at ward-6 of Bathnaha VDC. While selecting the transmission line alignment, due consideration was given to

43 avoid the settlement areas, in-built structures, religious places, schools and other community infrastructures all along its route from Dhalkebar to the India-Nepal border as far as possible.

14. Project Features. The proposed 400 kV transmission line will be approximately 40 km in length, and double-circuit comprising of duplex overhead conductors. The vertical double- circuit configuration tower will have an average height of 45 meters and the standard tower base dimensions will be 15 meters by 15 meters from centre to centre of each tower leg foundation/ footing. The design span between tower structures is approximately 400 meters.

15. The Right of Way of the proposed transmission line is 23 meters on each side from the centerline of the overhead transmission line. The transmission line design features are given in Table A2.2.

Table A2.2 Dhalkebar-Bhittamod Transmission Line Design Features

General Number of major road crossing 3 Number of major river crossings 3 Number of 33 kV line crossings 3 Design Features Line length 39 km Right-of-way width 46 m (23 m on either side of centerline) Number of angle points 13 Average span between towers 400 m Standard tower height 45 m Number of towers 100 (estimated) Voltage level 400 Kv Circuit Double circuit

Part B 16. Component B1: Hetauda-Dhalkebar-Duhabi Transmission Line and Substations. The proposed line is located in the Central and Eastern Development Region of Nepal. Physiographically, the line is located in the Siwaliks and Tarai areas of Nepal. East-West Highway is the main access to the Project area while Dhulikhel-Sindhuli-Bhittamod Road, Mirchaiya-Katari-Gaighat Road and Kadamchok-Bhediyatar Road provide alternative access routes. The transmission line is accessible through feeder roads and foot trails from these roads. Simara, Biratnagar and Janakpur are the nearest airports to the site.

17. Transmission Line Route. The proposed 400 kV transmission line is approximately 285 km in length, commencing at the Hetauda substation (which is under construction for the Hetauda-Bardghat 220 kV Project) located at Hetauda Municipality Ward No 1 of Makwanpur District and terminating at the new Duhabi Substation located at Ward No 7 Bhokraha tole (Hanif tole) of Bhokraha VDC in Sunsari District. The initial 18.6 km stretch of the transmission line passes through a hilly section (Hetauda-Hurnamadi) and after that 23.4 km section is hill to Terai (Hurnamadi-Nijgadh). The remaining 240.5 km (Nijgadh-New Duhabi) passes through flat plain of Tarai almost parallel to the north side of East-West Highway. While selecting the

transmission line alignment, due consideration was given to avoid the settlement areas, in-built structures, religious places, schools and other community infrastructures as far as possible.

18. Project Features. The transmission towers of the proposed transmission line will be capable of carrying a double-circuit ‘quad-Moose’ configuration conductor, but initially will carry a double-circuit ‘twin-Moose’ conductor. Each line circuit will have three phases, each phase comprising two separate aluminum steel-reinforced conductors. The vertical double-circuit configuration tower will have an average height of 45 meters and the standard tower base dimensions will be 15 meters by 15 meters from centre to centre of each tower leg foundation/ footing. Steel tower leg and body extensions will be utilized to reduce foundation excavation on slopes and provide greater tower foundation structural security. The design span between the tower structures is 400 meters. The right of way of the proposed transmission line is 23 meters on each side from the centerline of the overhead transmission line as per the Electricity Regulation, 2050 (1993). The transmission line design features are given in Table A2.3.

Table A2.3 Hetauda-Dhalkebar-Duhabi Transmission Line - Design features

Features Description General Initial point New Hetauda Substation , Hetauda Municipality Makwanpur Terminal point New Duhabi Substation, Bhokraha VDC, Sunsari district Number of major road crossing 5 Number of major river crossings 6 Number of 33 kV line crossings 2 Number of 66 kV line crossings 1 Number of 132 kV line crossings 1 Design features Line length 282.51 km Number of angle points 117 Number of towers 485 Average span between towers 400 m Right-of-way width 46 m (23 m on either side of centerline) Voltage level 400 kV Standard tower height 45 m Circuit Double

Substations

19. Dhalkebar Substation. Dhalkebar Substation will be able to receive imported power from cross-border transmission from India and transmit it to load centers elsewhere. Also, when there will be excess power in Nepal’s power system, electric power from various IPPs will flow to this substation via the proposed Hetauda–Dhalkebar–New Duhabi line. This substation will also serve to provide required power for the existing 132 and 33 kV networks in this area. For this purpose, there will be 400, 220, 132 and 33 kV voltage level buses. The project will acquire 6.77 ha of private cultivated land nearby the existing Dhalkebar Substation for the construction of new buses. 45

Substation Particulars Dhalkebar 400/220 kV, 9 X 100 MVA single phase auto transformers (to form 3 bays of 300 MVA transformer), 220/132 kV, 2x160 MVA transformers 220 kV air insulated switchyard with: 5 nos. of transformer bays, 6 nos. of line bays, 1 bus coupler bay; 400 kV gas insulated switchgear with: 3 nos. of transformer bays, 2 nos. of line bays, 2 nos. of shunt reactors SCADA, protection and telecommunications Land, control building and fence

20. New Duhabi Substation. The New Duhabi Substation is proposed in Hanif tole of Bhokraha VDC. The Koshi Corridor transmission line will be connected to this substation at 220 kV and the existing 132 kV line will be looped in and out in this substation. The existing Duhabi Substation is at around 17 km from this location. The existing Duhabi Substation is now surrounded by settlement and there is a problem of constructing a new transmission line in this area. Therefore this option was rejected and the Bhokraha/Inoruwa area, which is a comparatively open area, was chosen. The Koshi corridor has significant capacity and will be connected to this substation at 220 kV in the initial stage. Thus, in the initial stage this substation will have 220, 132 and 33 kV voltage level buses. In future, a 400 kV bus will also be required and an additional cross-border transmission line will be constructed in this area. The project will acquire 9.48 ha of private cultivated land for the construction of the new substation.

Inaruwa (Duhabi) 220/132 kV, 2x100 MVA transformers 220/33 kV, 2X50 MVA transformers 220, 132 & 33 kV air insulated switchyard with: 2 nos. transformer bays at 220 kV, 4 nos. of transformer bays at 132 kV, 2 nos. of transformer bays at 33 kV, 2 line bays at 220 kV, 4 line bays at 132 kV, 2 line bays at 220 kV, 1 bus coupler bay at 220 & 132 kV each SCADA upgradation

21. New Hetauda Substation. NEA is constructing a new substation at Hetauda Municipality Ward-1. The 220 kV transmission line from this substation to Bharatpur is under construction and there is a further plan to extend this line to Bardghat. Under this project, a 220 kV bus will be added and 2 X 150 MVA, 220/132 kV transformers will be installed. The proposed expansion work will be conducted within the boundary of the substation and no additional land will be acquired.

Hetauda 220/132 kV, 2x100 MVA transformers 220 kV air insulated switchyard with: 2 transformer bays at 220 kV, 2 transformer bays at 132 kV, 2 Line bays at 220 kV, 1 bus coupler bay at 220 kV. SCADA Upgradation

22. Component B2: Measures for Synchronized Operation of the Nepal Grid with the Indian Grid. After construction of 400 kV cross-border links between Nepal and India, it is also necessary to install properly tuned Power System Stabilizers (PSS) in the major power generating stations in Nepal in order to synchronize Nepal’s system with that of India. The initial Dynamic Studies have been done to identify the measures. Further studies would be required and these measures will be initiated after the construction of the transmission links.

Part C: Technical Advisory Services

23. Component C1: Owners’ Engineer. This assistance is mainly for NEA, particularly for the H-D-D line and substation contracting and construction. The Scope of Work of the Owners’ Engineer, which will be a reputable international firm of transmission project design and construction capability, would include: (a) overseeing the procurement and contracting phases of the H-D-D line and substations; (b) supervision of construction of the H-D-D line and substations; (c) supervision of compliance of the Safeguards policies by the contractors; (d) advising NEA, and other relevant bodies through NEA, on the observance of Safeguards policies; and (e) project financial management, including preparation and periodic progress reports and financial management reports; (f) advising and assisting NEA, including undertaking additional studies as needed on the measures to synchronize the Nepal grid with the Indian grid; and, (g) on-the-job training to NEA staff in Project Management Aspects.

24. Component C2: Preparation of a Transmission System Master Plan for Nepal. With the developments of the power sector becoming more dynamic in the last few years – a very high demand growth rate, multiple cross-border links planned with India, several medium to large hydro projects under development for meeting Nepal’s needs as well as future export of power – there is an urgent need to prepare a master plan for the development of the transmission system in Nepal to cater to these needs in the coming two decades. A professional firm of consulting engineers would be appointed to carry out the necessary studies and prepare the Transmission System Master Plan.

25. Component C3: Lenders’ Engineer. This is to ensure that the technical, environmental, social, and other safeguards aspects, as well as fiduciary aspects (procurement and disbursement) are being observed as designed under the Project. It is expected that a professional firm will be appointed to perform this task and report to the lenders – including the Government of Nepal and IDA – on the performance of the Project. The scope of work is the same as that of the Owners’ Engineer, but the level of effort is smaller – about 20 percent of that of the Owners’ Engineer.

26. Component C4: Capacity Development. This component would strengthen NEA’s Transmission Grid Development and System Operation Business Unit in the areas of: (a) Improved system utilization; (b) Improved grid planning and project implementation; (c) Cooperation with India in the area of power grid construction and operation; (d) Business Planning for Grid Development and System Operations, including the development of the wheeling and transmission service charges policies; and (e) Capacity for realizing additional cross-border interconnections.

27. It would also include technical assistance to Ministry of Energy and NEA to establish and coordinate the activities of IMCC, including establishing a secretariat for the IMCC (which would include office facilities, office technology equipment, and other logistics support); Assisting Ministry of Energy with review and adoption of appropriate policy and regulatory aspects of establishing multiple cross-border high capacity inter-connections with neighboring countries; Assisting Ministry of Energy to understand the principles and concepts of benefit- sharing in export-oriented hydro-electric projects; Assisting Ministry of Energy in the faster realization of hydropower projects; and Assisting Ministry of Energy to participate in the relevant regional forums such as SAARC and BIMSTEC, especially in their Energy subcommittees; and analyzing the implications for Nepal of the decisions made at these forums.

Project Cost and Financing

28. Project Costs. The cost estimates are summarized in Table A2.4. The cost estimates for the D-M line are derived from the Feasibility Study carried out by POWERGRID and finalized in a Business Plan prepared by IL&FS, except for the Safeguards management and mitigation costs for the Nepal portion of the D-M Line (which is from an IEE prepared by NEA). The costs for the H-D-D line are from the Feasibility Study prepared by NEA with help from international and local consultants/advisors. The basis of the cost estimates are: (a) recent tenders of similar equipment under World Bank financing for the transmission line (conductors and towers) as well as substations; (b) Nepalese regulation and recent norms for the environmental and social mitigation/compensation costs in Nepal; and, (c) Cost estimates based on recent experience in the region for project management costs. The estimates are prepared in Indian and Nepali Rupees and converted to US$ for assessment purposes. Contingencies are based on experience of transmission line construction projects in the region, and price contingencies are based on Manufacturers’ Unit Value (MUV) Index maintained by the Bank.

Table A2.4: PROJECT COSTS IN US$ Million Project Cost Components Muzaffarpur- Dhalkebar- Hetauda- Total Sursand line Bhittamod Dhalkebar- (India line (Nepal Duhabi Portion of D- Portion of line M line) D-M line) Preliminary Survey & Soil Investigation 1.24 1.23 3.41 5.87 Cost of Compensation for Transmission Lines a) Environmental Management and Mitigation 0.32 0.74 7.36 8.42 b) Social Impact Management and Mitigation 0.02 0.63 5.89 6.54 Civil Works - Infrastructure for substations 0.05 0.27 0.89 1.21 Equipment (Supply & Erection) Cost a) Trans. Lines 23.25 11.57 57.20 92.02 b) Sub-Stations 1.08 0.00 31.02 32.10 India-Nepal Grid Synchronization Measures 10.00 10.00 Consulting Services 2.92 2.63 11.00 16.55 Sub total 28.86 17.08 126.76 172.70 Project Management Costs Engineering & Administration 0.52 0.51 1.98 3.01 Losses on Stock 0.06 0.06 0.15 0.28 Project development costs 0.26 0.25 0.69 1.21 Contingencies 0.78 0.91 13.33 15.02 Total excluding IDC 30.49 18.81 142.92 192.22 Interest During Construction (IDC) & Financing 2.34 1.90 5.83 10.06 charges Total Project Cost 32.82 20.71 148.75 202.28

29. On the above basis, Project costs total US$192 million before IDC but including contingencies. The needed measures for synchronization of the India and Nepal grids cost about US$10 million. Contingencies are small in part because the components are familiar to the project sponsors and to Bank staff, as a significant amount of similar equipment is being financed in India (e.g., under the various POWERGRID projects). Also, the price contingencies are low since the construction time is relatively short. For the same reason Interest During Construction (IDC), which amounts to about US$6 million for the Bank financed H-D-D line, is also on the low side; since a lower interest rate of 5 percent has been applied. The total financing requirements, including IDC amount to US$202 million.

30. Financing Plan. The proposed Financing Plan is presented in Table A2.5, again separated by component, in view of the differing financing sources.

Table A2.5: FINANCING SOURCES IN US$ Million Financing Plan Muzaffarpur- Dhalkebar- Hetauda- Total Sursand line Bhittamod Dhalkebar- (India Portion line (Nepal Duhabi of D-M line) Portion of line D-M line) Equity Financing IL&FS 3.74 0.62 0.00 4.36 POWERGRID 2.56 1.62 0.00 4.18 NEA 0.98 3.98 29.75 34.71 Sutlej Jal Vidyut Nigam Ltd (SJVNL) 2.56 0.00 0.00 2.56 Others-Nepal FIs / Banks 0.00 0.00 0.00 0.00 Total Equity Financing 9.85 6.21 29.75 45.81 Debt Financing Commercial Borrowing 22.98 1.30 0.00 24.27 Line of Credit from Government of 0.00 13.20 0.00 13.20 India Proposed IDA Credit 0.00 0.00 99.00 99.00 On-Going Power Development Project 20.00 20.00 Total Debt Financing 22.98 14.50 119.00 156.47 Total Financing 32.82 20.71 148.75 202.28

31. The D-M line components (Part A) will be financed through a combination of debt and equity on a 70:30 debt: equity structure. The Government of Nepal intends to utilize about US$13.2 million from a Line of Credit from the Government of India to finance the Nepal portion of this line. The source(s) for debt financing of about US$23 million for the India portion of this line is still unidentified but the developer (Infrastructure Leasing and Finance Services or IL&FS) is in discussions with potential financiers, including the IFC, who are considering financing the India portion of the Project. In view of the fact that shareholders of the SPV that would build, own and operate the Indian portion of the line include very well resourced firms such as POWERGRID, SJVNL and IL&FS, combined with the interest being shown by IFC, Power Finance Corporation etc., raising the debt portion of the financing for CPTC is not seen as problematic. About US$30 million of the financing for: (a) NEA’s equity contribution in the two SPVs; (b) the debt financing gap on the Nepal portion of the D-M Line; and, (c) land acquisition, re-forestation, and social compensation costs of the H-D-D line and the Nepal portion of the D- M Line would come from GoN’s budget. GoN would provide these funds to NEA’s Balance Sheet to further strengthen NEA’s financial position partly as equity and partly as low interest loan. NEA would meet the costs of about US$6 million for IDC (Interest During Construction) as it accrues.

32. The remaining finance is proposed to come from IDA. US$99 million of this would be the proposed IDA financing and the remaining US$20 million would be from the on-going Power Development Project. The US$99 million equivalent of IDA financing to GoN would be part grant and part credit, according to current country parameters; and all funds would be disbursed only against eligible expenditures. In turn, GoN would on-lend the credit portion of IDA financing, and provide the grant portion of IDA financing as equity to NEA. This would

50 serve to reduce the financial burden of the proposed project on NEA. The on-lending terms would be specified in a subsidiary loan agreement, including an interest rate of 5 percent per annum; and a repayment period of 20 years including 5 years’ grace period.

Annex 3: Implementation Arrangements NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

A. Project institutional and implementation arrangements

1. Part A (Components A1 & A2): Dhalkebar-Muzzaffarpur (D-M) Cross-Border Transmission line. For the D-M Line components A1-A2, the CPTC and PTCN are planning to jointly appoint an experienced and internationally reputable grid construction and operation company as the project manager, designer and construction supervisor.

2. Parts B and C: Hetauda-Dhalkebar-Duhabi Transmission Line. For Parts B and C of the project, NEA will be responsible for implementation. NEA will have overall responsibility for project management, implementation and coordination. The implementation arrangements, shown in Figure 3.1 have been designed to take into account NEA’s current capacity weaknesses; and delays in decision-making.

Figure 3.1: Project Management Organization Chart

3. Inter-Ministerial Coordination Committee. A high-level Inter-Ministerial Coordination Committee (IMCC) would be established to address the delays in decision making in the sector as well as NEA. Accordingly, the IMCC would be chaired by the Secretary, Ministry of Energy and will comprise representatives of Ministries of Finance, Forests, Foreign Affairs Environment, and Planning Commission. The IMCC would provide the forum for overall

guidance, policy advice and coordination of project activities and resolution of inter-agency issues.

4. Project Implementation. Responsibility within NEA shall rest with the General Manager, Grid Development, who would head a Project Steering Committee (PSC) directly under the Managing Director of NEA. A Project Management Office (PMO) has been established headed by a Director, Projects, and would be supported by the Owners’ Engineer. The key units, functions and skills required for the PMO are:

(i) Project Administration and Financial Management Unit will be responsible for all management and operation of all project-related accounts including financial management, disbursement and financial reporting. This unit will also be responsible for general administration of the PMO. (ii) Engineering Unit will be responsible for design and construction supervision matters. Further, the unit will be responsible for the overall management of project construction. (iii) Procurement Contract Management and Reporting Unit will oversee the entire procurement process, monitor and evaluate project progress and performance, liaise with the Bank and be responsible for preparing annual programs and implementation reporting. For civil works contracts, the project manager will serve as the Employer, and the Owners’ Engineer will serve as the Engineer for construction supervision. (iv) Safeguards (Environmental, Social) Monitoring Unit will supervise compliance with the Safeguard Instruments (IEE including the Environmental Management Plan, RAP and SIMF including VPDF and VPDP. (v) Communications and Public Relations Unit will be responsible for implementing the communications strategy and managing relations with the public and media. (vi) Monitoring and Evaluation Unit will monitor the activities of the Project throughout its duration and evaluate the achievement of Project Development Objectives, Results Framework and Implementation Progress. (vii) D-M Line Coordination Unit will be responsible for ensuring observance of ITSAs for Nepal and for the India-side of the D-M line. The unit will also be responsible for progress monitoring of the D-M line. The unit will coordinate with the PTCN and CPTC. 5. In addition, an Owners’ Engineer, which will be a reputable international firm of transmission project design, construction capability, will support the PMO. A Lenders’ Engineer will also be appointed to ensure that the technical, environmental, social, other safeguards aspects, as well as fiduciary aspects (procurement and disbursement) are being observed as designed under the Project.

6. Project Implementation Period. The project will be implemented over a period of 54 months. The target date for completion of all construction is December, 2015 and the Credit Closing Date will be December 31, 2016. The Project implementation schedule is given in the

53 table below, which shows that the H-D-D line would be constructed in 36 months, and the remaining time would be needed for mobilization and synchronization.

7. Reporting, Monitoring and Evaluation of Outcome/Results. The PMO will include dedicated personnel for Monitoring and Evaluation. The PMO would submit trimesterly reports in an agreed format to the GoN, Project Steering Committee and the Bank no later than 45 days after the end of each trimester. The trimesterly report would cover the progress and expected completion dates for works and equipment supply contracts, progress on institutional components, implementation of Safeguards Instruments (IEE, EMP, RAP, etc.) and Environmental Mitigation Plan (EMP), Governance and Accountability Action Plan (GAAP), relevant intermediate results indicators, training and studies, and activities of the PMO’s engineering, procurement and financial consultants. The reports would also cover: (a) comparison of actual physical and financial outputs and updated six-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.

8. The PMO will also prepare annual reports by no later than July 15 of each year of project implementation. The report will cover: (a) the progress of each component, implementation of key features of the Safeguards Instruments (IEE, EMP, SIMF, RAP, VPDP and VPDF); key performance indicators including actions agreed in the GAAP and results framework 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 co-financier, 54

an updated disbursement profile, planned actions for mitigating negative effects during construction, and target indicators for the coming year. A mid-term review of the Project would be undertaken by December 31, 2013. An Implementation Completion Report (ICR) would be submitted to the Bank no later than six months after the closing date.

9. In addition, the presence of the Lenders’ Engineer would enable provision of timely independent feedback to GoN and the Bank. The combination of the Project Steering Committee, Project Management Office, Owners’ Engineer and Lenders’ Engineer would provide the necessary support for regular monitoring and evaluation of the Project’s impact, including the implementation and monitoring of the Safeguard Instruments and enable corrective actions to be undertaken in a timely manner as needed.

B. Financial Management and Disbursement Arrangements

Country Financial Management Environment

10. The Nepal Country Financial Accountability Assessment (CFAA) 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 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. The Public Financial Management (PFM) Review (May 2007) has 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 on the low end. Joint DfID and World Bank progress reviews carried out in September 2008 and later in February 2009 have revealed little progress on implementation of the PEFA Action Plan. Some of the prevailing country level risks include deteriorating control environment, insufficient monitoring, increasing threat of collusion, intimidation to bidders, weakening oversight agencies with the absence of institutional leaders which include the Auditor General and the Chief Commissioner of the CIAA. These have a wider impact on the country’s accountability environment including at the sectoral or project level.

11. While these challenges prevail, improving the 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. Some of the actions undertaken during the challenging transition period such as, 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, are examples of Government’s continued commitment. 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 of implementation with continuation of collaborative support from development partners.

Financial Management Assessment of Implementing Agency (NEA)

12. The World Bank is supporting energy sector development in Nepal through the ongoing 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 an Action Plan to address the issues; and the Bank has recently received written confirmation that the implementation of the Action Plan has begun. The Bank will closely monitor the implementation of the Action Plan.

13. NEA has recently recruited a consulting firm, Deloitte Touche and Tomahatsu to support strengthening of financial management. The consultant has begun work to 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 irregularities pointed out in the auditors’ reports; (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 PDP. 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 the auditor’s comments/objections are showing improvement.

14. At the project level, the implementation experience of the ongoing PDP indicates moderate risk. A few deficiencies observed at the project level by the IDA team that relate to the internal control system and the 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 Officer will be deployed.

15. Planning and Budgeting. The proposed operation will follow NEA procedures. 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 for 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.

16. Project Financial Accounting, Reporting and Internal Controls. In order to ensure that project financial statements are consolidated, NEA will ensure that separate books of accounts are maintained for the project and accounts are prepared on an accrual basis. NEA will prepare trimester Implementation Progress Reports (IPR) which will include the Financial Monitoring Report (FMR). Accounting information will be regularly updated to timely generate financial reports. NEA will maintain required ledgers including the Special Designated Accounts Ledger. The internal control process of the NEA will be applied to monitor the progress of the Project in accordance with sound accounting practices. The 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) maintenance of the asset register; (v) monthly closing and reconciliation of accounts and statements; and, (vi) the production of annual financial statements.

17. Financial Reporting. As part of Project progress reporting, NEA will 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 financial monitoring report will include: (a) transfers of funds to and from the special Designated Accounts; and, (b) expenditure statements against each budget head by detail classification according to the chart of accounts, as funded for the Project.

18. External Audit. The Office of the Auditor General (OAG) is responsible for auditing the accounts of NEA. Audit of the NEA will be carried out by a qualified and experienced private auditing firm appointed by the Office of the Auditor General. Audit reports for FY2009/10 were due on January 15, 2011. However, there is a delay in submission on this audit report, and the Bank discussed the action plan both with the NEA management and the auditors for submission of audit report by June, 2011. To avoid such delays in the future, GoN and NEA would, in agreement with OAG, appoint 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. The auditor should be appointed before the end of the current financial year.

19. Furthermore, to address the issue of delays in the submission of audit reports, it is recommended that both NEA proactively plan the audit process closely with the 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

NEA Project Financial Qualified and 6 months after the Statements Experienced Audit Firm end of each fiscal appointed by the OAG year NEA Entity (NEA) Qualified and 6 months after the Financial Statements Experienced Audit Firm end of each fiscal appointed by the OAG year

20. Disclosure of Information and Corporate Governance. Disclosure requirements under the proposed Project are expected to be transparent and all information readily available for public disclosure (refer Annex on Governance and Accountability Action Plan). Implementing agencies will post on their website all available guidelines, procedures, and other key information related to the Project in line with Nepal’s Right to Information laws. NEA has agreed to disclose the following through its website: Trimester Implementation Progress Reports (approved versions); and Annual Audited Financial Statements.

21. 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 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.

22. 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. It is expected that IDA funds will be disbursed over a period of 5 years. The Closing Date of the financing is December 31, 2016.

Allocation of Financing Proceeds

Category Amount Amount Percentage of Expenditures of the of the to be Financed Credit Grant Allocated Allocated (inclusive of Taxes) (expressed (expressed in SDR) in SDR)

(1) Goods and works under Part B 40,400,000 0 100% of the Project

(2) Consultants’ services, and 0 6,400,000 100% Training and Workshops (under Part C of the Project)

(3) Operating Costs (under Part C of 0 700,000 100% the Project)

(4) Unallocated 13,400,000 2,600,000

TOTAL AMOUNT 53,800,000 9,700,000

23. Disbursement Arrangements. Disbursements from IDA will be made based on full documentation for contracts above the Prior Review threshold or SOEs. To facilitate disbursements, a Designated Account will be established. Project Management and Incremental Operating Costs are implemented through contractual services with firms or individuals and hence payments will be made directly from the Designated Account. For large value contracts, the Direct Payment method for disbursements will be used. Incremental Operating Costs and Project Management costs will first be pre-financed by NEA, and once the accounts are consolidated and approved the funds will be transferred from the Designated Account to NEA’s accounts.

24. Use of Statement of Expenditures (SOEs). SOEs will be used for the following expenditures: (i) contracts for works costing less than US$1,000,000 equivalent per contract; (ii) contracts for goods costing less than US$400,000 equivalent per contract; (iii) contracts for services of consulting firms costing less than US$200,000 equivalent per contract; (iv) contracts for services of individual consultants costing less than US$100,000 equivalent per contract; (v) all training; and, (vi) all incremental operating costs. During supervision, the Bank 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.

25. Designated Accounts. A Designated Account in US Dollars will be established at the Nepal Rastra Bank for utilization of IDA’s share of project expenditures, on terms and conditions satisfactory to IDA. The authorized allocations for Designated Account will be US$5.0 million. The designated account will be operated under joint signatures of the Project Director and the Finance Manager in the PMO.

26. NEA will ensure that the bank/cash books are reconciled with bank statements every month. They will separately submit applications documenting the expenditures from the previous advance and requesting for additional advance based on cash forecast to be deposited in the Designated Accounts on a trimester basis. The withdrawal application will be accompanied by reconciled statements from the bank in which the account is maintained, showing Designated Account transactions. Supporting documentation will be maintained by NEA for at least one fiscal year after the year in which the last disbursement from the project took place, and will be available for review by IDA staff and independent auditors.

C. Procurement Arrangements

27. Procurement under the project would be carried out in accordance with the World Bank’s Guidelines: Procurement under IBRD Loans and IDA Credits of January 2011 and Guidelines for Selection and Employment of Consultants by World Bank Borrowers of January 2011. The Bank’s standard bidding documents for procurement under International Competitive Bidding (ICB), and sample bidding documents for procurement under National Competitive Bidding (NCB) which are already being used on other Bank-financed projects in Nepal, will be used for procurement of Goods and Works under the Project. The Bank’s Standard Request for Proposal (RFP) document will be used in the selection of consulting firms.

28. The procurement approach for the D-M line – Part A of the Project - will be largely according to industry practices, and under the Indian line of credit limited to Indian companies. These components would be built by two Special Purpose Vehicles (SPVs) one on the India side and one on the Nepal side (same principal shareholders in each). Also there would be commercial contracts governing both the power trade and transmission services between these SPVs and NEA. In fact, the agreement on the use of the Transmission System would be governed by the Implementation and Transmission Service Agreement (ITSA). The SPVs and NEA would agree on the price of transmission service beforehand. As such, the SPVs would be obligated to provide the transmission service at the agreed price. In addition, any delays in completing the line would be governed by penalty clauses. Signature of the ITSA is a condition of disbursement of IDA financing.

29. As regards the H-D-D Line (including the 400 kV substations at Dhalkebar and the substations at Hetauda and Duhabi) – Component B1 – the approach would be to ask the contractor to take on the design, supply and install responsibility under the contract. There may be other smaller equipment and services – such as Power System Stability and synchronization measures needed to operate synchronously with the India grid – and appropriate procurement approaches would be proposed. There are consulting services required and would be procured in accordance with the Bank’s guidelines .A key consulting assistance that is being provided is that of an experienced procurement advisor initially using the funds from the on-going Power Development Project and to be continued.

30. All expected procurement of goods, works and consultants’ services will be listed in the project’s General Procurement Notice (GPN), and Specific Procurement Notices (SPNs) shall be published for all ICBs and consulting services contracts costing more than US$200,000. Overall procurement arrangements with tentative amounts are given in Table C3.1.

31. Assessment of Agency’s Capacity to Implement Procurement. NEA has been preparing the cross-border transmission line project and has gained considerable knowledge of working according to the Bank’s procurement rules. Continued engagement of these staff members with the Project will be pivotal in ensuring adequate procurement capacity of NEA. The procurement function will be handled by the Procurement and Contract Monitoring Unit. The Bank will hold a procurement training session for procurement staff as soon all the relevant staff is recruited.

32. An assessment of the capacity of the implementing agency to implement procurement actions for the Project was carried out by the procurement specialist on the team. The assessment reviewed the organizational structure for implementing the procurement under the project and the interaction between the project’s staff responsible for procurement. The special measures for dealing with procurement risk proposed above are based on this review.

33. Special Measures for Dealing with Procurement Risks. Despite the promulgation of the National Procurement Law based on the UNCITRAL model law, the overall procurement environment still entails significant risk. The following table describes the procurement related risks and proposed mitigating measures.

34. The Project has a rating of “substantial risk” for procurement and contract management. Although procurement under the ongoing Power Development Project has been carried out well, the rating is assessed merely based on the size of the operation and the country environment. In order to minimize this risk, several measures are introduced for procurement in general and for management of consultancy contracts in particular. These measures include:  The Procurement Unit of the PMO supported by a procurement advisor shall be responsible for carrying out the procurement activities under the project for the consulting services, works and goods. Responsibilities of the Procurement Advisor would include the following activities to mitigate the current procurement risks: capacity building of PMO officials in procurement management; conducting review of procurement process; assuring efficiency and effectiveness in procurement planning; achieving transparent and competitive

bidding with wider participation by national and international bidders; and timely completion of procurement cycle.  NEA’s website would be used by the PMO to publicize the procurement plan, procurement notices, invitations to bid, and latest information on contract status. The website would be accessible to all bidders and interested persons equally and free of charge. The website should be operational as soon as competitive procurements for the Project commence.  A credible system of handling complaints would be put in place for national competitive bidding in line with the provisions of the Public Procurement Law. The PMO would develop the system as soon as possible and it would be reviewed by the Bank. For ICB/international selection of consultants, the Bank-prescribed complaint mechanism will apply.  Procurement training for the PMO staff for works, goods and services of the Project would be arranged periodically.  A procurement documentation system, filling system and a procurement database would be developed and maintained as outlined in the section below.  A procurement strategy for the Project shall be prepared as part of the PIP documenting the procurement processes and approval procedures for each agency responsible for procurement under the Project, circumscribing roles and responsibilities, and service delivery standards.

35. At this stage the procurement risk rating of the Project is maintained at “substantial”. However, the procurement process and implementation of the contracts would be reviewed every six months by the Project Steering Committee in collaboration with the Bank and adjustments and corrective actions would be taken as necessary.

36. Procurement of Works Most of the Project’s works would be implemented using International Competitive Bidding (ICB) procedure. The works may be divided in several contracts. There would be some NCB contracts for preparatory works to develop office and other residential facilities ahead of the project start. The PMO would be responsible for evaluation of bids and recommendation of the award for major contracts.

37. The works contracts estimated to cost up to US$1,000,000 equivalent would be procured through NCB Procedures while contract estimated to cost more than US$1,000,000 would be procured through ICB procedures. Minor works estimated to cost up to US$50,000 equivalent per contract may be procured through shopping procedures. The PMO would validate authenticity of the quotations provided by suppliers under this procedure. Force Account may be resorted to for procurement of small works, if necessitated by absence of private contractors in the particular area due to various reasons, provided it satisfies the provisions of the Guidelines with the concurrence of Bank on an exceptional basis

38. Procurement of Goods. Goods procured under this Project would include: power transformers and ACSR conductors, etc. ICB procedures shall be followed for each Goods contract estimated to cost more than US$400,000 equivalent. Domestic Preference will be

allowed to local manufacturers on ICB contracts. Goods estimated to cost up to US$400,000 per contract may be procured through NCB procedures acceptable to the Bank. Vehicles and small value off-the-shelf goods, etc. estimated to cost up to US$50,000 equivalent per contract may be procured following Shopping procedures in accordance with the Bank’s procurement guidelines. Direct Contracting for procurement of items which satisfy the provisions of GL may be carried out with the concurrence of Bank on an exceptional basis.

39. Procurement of Consulting Services. Contracts with consulting firms will be procured in accordance with Quality and Cost Based Selection procedures or other methods given in Section II of the Consultants’ Guidelines. For contracts with consulting firms estimated to cost less than US$100,000 equivalent per contract, the shortlist of consultants may comprise entirely of national consultants in accordance with the provisions of paragraphs 2.7 of the Consultant Guidelines. Other selection methods like Quality Based selection, Fixed Budget Selection, Selection based on Consultant Qualification, Least Cost Selection, Selection of Individual Consultants, and Selection through Sole Source can be considered with the concurrence of the Bank.

40. Incremental Operating Costs. The Project will support operational costs such as for operation and maintenance of vehicles, vehicle and office rentals, rentals for IT services such as internet connection, utilities, and office consumables required for the day-to-day running of the PMO.

41. In order to ensure economy, efficiency, transparency and broad consistency with the provisions of Section 1 of the Procurement Guidelines, the following exceptions to local procedures shall apply in the case of National Competitive Bidding: a. bid documents shall be made available, by mail or in person, to all who are willing to pay the required fee; b. foreign bidders shall not be precluded from bidding and no preference of any kind shall be given to national bidders; c. bids shall be opened in public in one place, immediately after the deadline for submission of bids; d. qualification criteria (in case pre-qualifications were not carried out) shall be stated in the bidding documents, and if a registration process is required, a foreign firm declared as the lowest evaluated bidder shall be given a reasonable opportunity of registering, without let or hindrance; e. evaluation of bids shall be made in strict adherence to the criteria disclosed in the bidding documents, in a format and specified period agreed with the Association and contracts shall be awarded to the lowest evaluated bidders; f. re-bidding shall not be carried out without the prior concurrence of the Association; Extension of bid validity shall not be allowed without the prior concurrence of the Association (A) for the first request for extension if it is longer than four weeks and (B) for all subsequent requests for extension irrespective of the period; g. there shall not be any restrictions on the means of delivery of the bids.

42. Procurement Planning. The Procurement Plan for the key contracts for goods, works and consultants’ services expected under the Project have been prepared by the PMO with assistance from the Bank. Whenever possible, procurement of works, goods and services would be packaged into large packages to attract good contractors. Bidding documents for the first year’s procurement have been prepared and submitted to the Bank. Procurement under the project will be carried out in accordance with the Procurement Plan. Procurement plans will be closely monitored and updated on a quarterly basis, or as required. No procurement, regardless of the value, will be done by the implementing agency unless it has been approved under the procurement plan by the Bank. Any change in the estimated cost of any contract will promptly be conveyed to the Bank for its approval. No changes will be accepted after bidding documents have been made available to bidders. The Procurement Plan will also be available on NEA’s website (www.e-nea.org.np) and in the Bank’s external website.

43. Disclosure of Information. NEA will publish /disclose Procurement-related information as per the details indicated in Appendix 1.

44. Prior Review. Works contracts estimated to cost the equivalent of US$1 million or more, and Goods contracts estimated to cost the equivalent of US$400,000 or more shall be subject to the Bank's Prior Review. All contracts with consultant firms with estimated value of US$200,000 or more, and contracts with individuals costing the equivalent of US$100,000 or more and all direct contracts shall be subject to the Bank's Prior Review. These thresholds would be reviewed in 18 months and adjustments upwards or downwards would be made based on implementation experience.

45. Post Review. All other contracts will be subject to Post Review by the Bank. The PMO will send to the Bank a list of all contracts for Post Review on a quarterly basis. Post Reviews as well as implementation reviews would be done quarterly for the first 18 months or until the Credit disbursements reach US$30 million and there after bi-annually. Such review of contracts below threshold will constitute a sample of about 15-20 percent of the contracts.

46. Frequency of Procurement Supervision. Bank supervision would be carried out every six months and more frequently in the early stages of Project implementation. In addition to the Prior Review, Bank supervision missions, including a Procurement Specialist, would carry out a Post Review of procurement actions.

Table 3C.1 Procurement Arrangements (US$ million)

Works and Goods

Consulting Services

Appendix 1 to Annex 3C

Procurement disclosure Requirements as per Bank’s Guidelines

1. Contract Awards for ICB and LIB: Within two weeks of receiving the Bank’s No Objection to the recommendation of the contract award, the Borrower shall publish in UNDB on- line and in dgMarket the results identifying the bid and lot numbers and the following information: (a) name of each bidder who submitted a bid; (b) bid prices as read out at bid opening; (c) name and evaluated prices of each bid that was evaluated; (d) name of bidders whose bids were rejected and the reasons for their rejection; and (e) name of the winning bidder, and the price it offered, as well as the duration and summary scope of the contract awarded.

In the publication of Contract Award referred above, the Borrower shall specify that any bidder who wishes to ascertain the grounds, on which its bid was not selected, should request an explanation from the Borrower. The Borrower shall promptly provide an explanation of why such bid was not selected, either in writing and / or in a debriefing meeting, at the option of the Borrower. The requesting bidder shall bear all the costs of attending such a debriefing.

If after publication of the results of evaluation, the Borrower receives protest or complaints from bidders, a copy of the complaint and a copy of the Borrower's response shall be sent to Bank for information. If as result of analysis of a protest the borrower changes its contract award recommendation, the reasons for such decision and a revised evaluation report shall be submitted to the Bank for no objection. The Borrower shall provide a re-publication of the contract award.

2. Contract awards for National Competitive Bidding: Publication of results of evaluation and of the award of contract consisting of the same information as mentioned above for ICB and LIB.

3. Contract Awards for Direct Contracting: After the contract signature, the Borrower shall publish in UNDB on-line and in dgMarket the: (a) name of the contractor; (b) price; (c) duration; and (d) summary scope of the contract. This publication may be done quarterly and in the format of a summarized table covering the previous period.

4. Contract Awards for Consultancies: After the award of contract, the borrower shall publish in UNDB on-line and in dgMarket the following information: (a) the names of all consultants who submitted proposals; (b) the technical points assigned to each consultant; (c) the evaluated prices of each consultant; (d) the final point ranking of the consultants; (e) the name of the winning consultant and the price, duration, and summary scope of the contract. The same information shall be sent to all consultants who have submitted proposals.

5. Contract Awards for Selection Based on the Consultants’ Qualifications (CQS) and Single Source Selection (SSS): The Borrower shall publish in UNDB on-line and in dgMarket the: (a) name of the consultant to which the contract was awarded; (b) the price; (c) duration, and (d) scope of the contract.

This publication may be done quarterly and in the format of a summarized table covering the previous period. 65

D. Environmental and Social

47. Scope of Environmental and Social Impact Assessment. The developers of the Nepalese sections of the proposed Project (components A2 and B1) and the Indian section (component A1) have used separate approaches and arrangements in addressing the social and environmental impacts of the transmission lines due to different financing, regulatory and institutional structures in the two countries. For the Nepalese sections of the transmission line (components A2 and B1), an independent environmental and social impact assessment has been completed that is consistent with the World Bank’s Safeguards policies, as well as with the local regulatory requirements in Nepal. The Indian portion (component A1) will follow a framework approach consistent with Indian requirements as the exact alignment of the transmission line and the exact locations of the towers will only be finalized during implementation (explained below). The proposed Project is expected to contribute overall positively to the local economies through improved power supply. The local populations are also expected to benefit through enhanced employment opportunities training, and extension services planned under the Project.

48. Environmental and Social Management Framework for the Indian section of transmission line. The 90 km Muzaffarpur-Sursand line (component A1), i.e. the Indian portion of the line, will be implemented by CPTC, including the environmental and social mitigation measures. CPTC shareholders have decided to adopt an environmental and social policy for the Indian portion which is in line with POWERGRID’s Environmental and Social Policies and Procedures that have previously been reviewed and approved by the Bank under the provisions of OP/BP 4.00 Piloting the Use of Borrower Systems to Address Environmental and Social Safeguard Issues in Bank-Supported Projects for use in the Bank-financed Fifth Power Sector Development Project (PSDP-V, Ln. 7787) in India approved in 2009.14 The line will pass through the Muzaffarpur and Sitamarhi districts of Bihar,15 where Sursand is located at the India- Nepal border. Three alternative routes (of length 86.430 km, 85.679 km and 101.666 km) for the transmission line were assessed by the shareholders through a consulting firm, during a walkover survey. Considering the route length, vicinity of industrial belts and growing cities, accessibility by roads for construction and maintenance and operation, the first alternative route (or Alternative 1) of 86.43 km route was chosen. A preliminary assessment based on the Forest Atlas, topographical sheets, Google maps and walkover survey of the area by Bank safeguard specialists indicate that about 0.75 ha of forest land will be needed under the proposed (Alternative 1) transmission line route. The route alignment was carefully selected to avoid any villages or habitations. The line would also not pass through any tribal areas. In addition, the needed expansion of the Muzaffarpur substation can be accommodated within the existing substation premises. For the transmission line route, only the right of way is to be acquired (i.e., not the land), and the line routing will pass through agricultural land, and no people would need to be resettled. Keeping the requirements of the Forest (Conservation) Act in mind, the alignment was selected to avoid major forest areas. As the exact location and alignment of line and towers will be finalized during implementation, in line with POWERGRID’s ESPP, an

14 A current desk review by the Bank team and the findings of a December 2010 supervision mission of ESPP performance under PSDP V indicates a satisfactory implementation and monitoring of key environment and social mitigation measures. 15 From “Preliminary and Detailed Survey of 400 kV Double Circuit Muzaffarpur-Sursand Route for Indo-Nepal Transmission Project, Detailed Project Report, February 2008. 66

Environmental Assessment and Resettlement Action Plan (RAP) will be prepared during implementation for this line.

Environmental and Social Impacts Assessment and Management of Nepal sections

49. Public Consultations and Disclosure of Documents. Notice with regards to Initial Environmental Examination Study was published in a national daily newspaper; and as per regulations, 15 days time was given to local people for providing written concerns/issues regarding the proposed Project. The copy of notice was displayed at the VDC office, local schools, villages, health post and other public places. The Muchulka of the notice display was prepared and presented. Local people mainly raised the issue of compensation of land and other assets at market rate and employment opportunity to local people in project works. The concerns of local people/institutions were incorporated in relevant section of IEE report. The recommendation letter of concerned VDCs were collected and presented in the report. Besides this household survey, group meetings, visits by the experts and interaction with local people were also the part of public involvement. The district and local level organizations such as the District Development Committees, Village Development Committees, health posts, non- governmental organizations (NGOs) and other related organizations were consulted during the study. The following documents have been disclosed to the public:

S.No. Report Title Disclosed locally Disclosed at (NEA Website) WB Infoshop 1. Initial Environmental Examination of 02/16/11 02/17/11 Dhalkebar-Bhittamod 400 kV Transmission Line Project 2. Initial Environmental Examination of 02/16/11 02/17/11 Hetauda-Dhalkebar-Duhabi 400 kV Transmission Line Project 3. Social Impact Management Framework 02/16/11 02/17/11 (SIMF) of Hetauda-Dhalkebar-Duhabi 400 kV and Dhalkebar-Bhittamod 400 kV Transmission Line Projects 4. Resettlement Action Plan (RAP) of 02/16/11 02/17/11 Hetauda-Dhalkebar-Duhabi 400 kV and Dhalkebar-Bhittamod 400 kV Transmission Line Projects

50. Social assessment and impacts for the Nepalese sections. The total length of transmission lines in Nepal is 325 km (Hetauda- Dhalkebar-Duhabi 285 km + Dhalkebar – Bhittamod 40 km). NEA has carried out a Social Impact Assessment (SIA) for the entire length during September-October 2010. The objective of the SIA is to i) provide a socioeconomic profile in the project areas; ii) assess possible adverse social impacts under the project; iii) disseminate project information in the project areas and carry out consultations with various stakeholders, especially, the affected population, over their perceptions of the project and impacts, as well as their expectations and suggestions for the project screen for indigenous communities in the project areas; and iv) recommend mitigation measures to implement the

project in an environmentally and socially sound manner following the prevailing legal requirements of GoN and the World Bank.

51. A mixture of methodologies was employed for the SIA, including: a literature review; socio-economic survey of affected households; participatory rural appraisal (97 sessions, one in each Village Development Committee (VDC)/municipality); focus group discussions (22 with occupational/ethnic groups, 25 with women groups); key informant interviews (194); a market survey of the area; and consultation with local and district level stakeholders.

52. Key finding on the socio-economic and cultural background in the Dhalkebar-Bhittamod line area are as follows:  The proposed line will lie in the Dhanusha and Mahottari district of Janakpur zone. The transmission line covers 20 VDCs, 5 in Dhanusha district and 15 in VDCs in Mahottari district.  The total population of the project area is 144,861 including male 74,939 (51.7 percent) and female 69,922 (48.3 percent) which is 11.8 percent of the total population of the project districts.  The total number of households is 24,763 with an average household size of 5.85. Altogether 42 castes/ethnic groups are found in the project area. Out of this, 14 castes are classified as indigenous group by the GoN. Koiri, Yadava, Muslim, Dhanuk and Dalit are the dominant castes of the project area.  The average literacy rate (6 years and above) of the project area is 31.6 percent. Agriculture is the major occupation followed by foreign employment, labor, service, small scale industries, business, etc.  The nearest airport to the site is Janakpur from where the nearest distance of the alignment is more than 25 km. An average of 4-5 flights occurs daily from Kathmandu to Janakpur. The location of the airport is in an east–west direction. The aircraft flying route is east - south.  The average family size of the Project Affected Families (PAFs) is 7.75 which are higher than the average family size (5.85) of the project VDCs. The literacy rate of the PAFs is 56.1 percent. About 27.4 percent households are small farmers whereas medium and large farmers are 14.5 and 1.1 percent respectively. The average land holding of the PAFs 0.99 ha.  The average annual income of the PAFs is NRs. 117,582 whereas the average annual expenditure is NRs. 103,126.

53. Key findings on the social economic and cultural background in the H-D-D line area are as follows:  A large part of the project area is located along the east-west Highway. Similarly, almost all VDCs in the project area are connected with roads (blacktopped, gravel and earthen road) and accessible by public transportation. Telecommunication facilities are available in all the areas through land line and wireless technology (CDMA, GSM). Drinking water facilities are available only in some areas through piped water.

 The transmission line crosses 10 districts, 95 VDCs and two municipalities of two development regions. The project area is inhabited by more than 50 different caste/ethnic groups of hill, Terai and mountain origin including Brahmin/Chhetri, Terai origin high caste/ethnic groups, indigenous and Dalits. The population of Janjati and Bramhin/Chhetri constitute about half population of the project area. Similarly, there is a significant proportion of Dalits and Muslim population in the project area.  Almost all the indigenous people of the project area are mixed with other caste/ethnic groups of the area. They share a common language, they have similarity in dress, follow culture and festivals of other caste/ethnic groups and others also follow their culture/festivals, share common resources and facilities, and have social harmony.  Agriculture, animal husbandry and wage employment are the main sources of livelihood for the people of the project area. Seasonal migration particularly to India (Delhi, Punjab, Haryana and bordering cities) is one of the main sources of livelihood for most of the landless and subsistence households of the project area.  Ownership of agricultural land is common in all the districts of the project area, with about 68.0 percent of households in most districts owning agricultural land, livestock and poultry. The land holding of most of the households in the project area is small and also of poor quality. Similarly, poor fertility, lack of irrigation and agriculture inputs and labor shortage has resulted in low productivity of food grains in the area.  Remittance, daily wage labor, off farm agricultural activities, business, salaried jobs and selling firewood and NTFP are the main coping strategies for food deficit households.  Similarly, there are about 22.0 percent landless households in the project area. The main livelihood activities of the landless households are wage employment, remittances, livestock and forest/forest based activities.  Gender differences in occupation, education and decision-making are common features of Nepal and the households of the project area are no exception. Women spend most of their time in household and agricultural activities such as collection of firewood and fodder, cooking, washing, cleaning house, taking care of children, sick, elderly and other family members, taking care of livestock, food processing, and seasonal agricultural activities.  The major issues for women in the project VDCs are illiteracy, early marriage, the dowry system, domestic and sexual violence, sexual harassment, lack of reproductive rights, gender discrimination, and economic dependency. The potential income generating activities for the women of the project area are animal husbandry, agriculture, horticulture, forest based activities (NTFP), cottage industries, petty business and skill training.  Poverty, unemployment, low agricultural production and a desire for improving quality of life are the main reasons for migration out of the area. Remittances are the prominent source of income for most landless, poor, and marginalized households of the project area.  Forest, rivers and ponds are the main natural resources of the area. The forest resources of the area are significantly contributing to the livelihood and economic development of

the local people particularly to the marginal and landless households. These households are largely dependent on forests for their subsistance.  The social relationship between different caste/ethnic groups is cordial in the project area. Different ethnic groups, Dalits and advanced cast/ethnic groups live together in the area with mutual understanding. However, some discrimination regarding economic status and caste hierarchy still exists in some rural societies due to poverty and illiteracy.  The general law and order situation is satisfactory in the project area. It was worst before 2-3 years due to several underground political and criminal groups. There are police posts in some VDCs in the project area. Local leaders and traditional village heads play important mediation roles for dispute management and in maintaining law and order in most parts of the project area.

54. Key findings on direct project impacts and affected households under the angle towers and substations:  Major adverse impacts include acquisition of 21.24 ha of cultivated land, removal of 591 private trees, relocation of 9 private houses/structures owned by 6 households, relocation of 3 temples and one primary school, and loss of standing crop.  The project will directly affect 133 households in seven districts in the project area. The total population of the 133 affected households is 873. They belong to 29 different caste/ethnic groups of hill and Terai origin.  Agriculture, service (salaried job), wage employment and business/small industry are the main sources of livelihoods of the affected households. The project area is a food deficit area. Only 37.6 percent of the surveyed households could grow enough food for their consumption in a year. Of the surveyed households, about 69.9 percent (93) have family debt for various reasons. The proportion of the households having family debt is more than 50 percent in all the districts.  The average land holding of the affected households is 1.78 ha. The per capita landholding is 2.71 ha with the lowest (0.051 ha) in Makawanpur and highest (0.051 ha) in Mahottari.  Paddy, sugarcane, wheat, maize and millet are the main crops cultivated by the surveyed households. Other crops include vegetables, potato and pulses. In terms of area coverage, paddy cultivation ranks first, sugarcane second, wheat third and maize fourth.  Livestock ownership is an integral part of agriculture for the surveyed households of the project area. Of the surveyed households, about 80 percent have livestock.

55. Key findings on people’s attitude, perceptions and expectations of the Project:  Of the affected households, 86 percent have positive attitude and 4 percent (5) have negative attitude regarding the project and its implementation  They are expecting employment, good compensation, local development, and electrification from the project. Of the surveyed households, 38 percent are expecting

employment, 30 percent are expecting good compensation 9 percent expecting local development and 14 percent are expecting electrification from the project.  Concerns/issues raised by the local people and other stakeholders during community consultation are compensation, livelihood support, alignment of the transmission line, community support programs, and community participation in the project activities.

Summary of the RAP for Angle Towers for Components A2 and B1 (Nepal sections)

56. The Nepalese sections of the proposed Project are located in the Central and Eastern Development Regions of Nepal. Key project works include establishment of a transmission line corridor of 23 meters on each side, three substations, 136 angle towers, and 585 suspension towers. The RAP was developed to address the impacts under the angle towers and three substations whose locations are already known.

57. Impacts. An impact inventory survey was carried out over the project area. The angle towers and three substations would require acquisition of 22 ha of private land, relocation of nine structures; and acquisition of 591 trees. Seven of the structures are used for residential purposes, including six temporary ones, and two are cow sheds. Of the households losing land, over 60 percent are losing less than 10 percent.

Percentage Loss of Land from the Total Land of the Affected HHs Affected Categories of Angle Points Substation Total HHs and Land Loss (%) No. (%) No. (%) No. (%) 1. Marginally (<10%) 81 92.05 4 8.89 85 63.91 a. (10 – 50%) 7 7.95 18 40.00 25 18.80 2. Severely b. (> 50%) - - 23 51.11 23 17.29 Total 88 100 45 100 133 100

58. The Project will also require relocation of one elementary school and three small temples. In total this will affect 133 households of 873 people. A detailed socioeconomic survey was carried out to assess their social economic status, perceptions and recommendations with respect to project impacts and mitigation measures. These are summarized above and considered in the RAP formulation.

59. Objective and principles. In line with relevant Nepali and World Bank policies, the following principles are adhered to in the resettlement planning process to ensure that the affected households will restore and improve their livelihoods:  Acquisition of land will be minimized, attempting to avoid the resettlement of people as much as possible.  Compensation for the affected structures and associated structures shall be paid at replacement value.

 Local stakeholders will be systematically informed and properly consulted to identify the possible alternative subproject engineering and operational solutions to avoid or minimize the adverse impacts of land acquisition.  Lack of formal legal rights to the assets lost will not prevent PAFs from receiving compensation, entitlement and rehabilitation measures;  Relocated PAFs will be provided with some assistance to maintain, or improve their pre- project living standards, income earning capacity, production levels and employment opportunities;  Special assistance measures will be incorporated in the resettlement implementation process to protect the socially and economically vulnerable groups that will be affected;  An effective mechanism for arbitration of complaints and grievances will be provided during resettlement implementation;  Physical works will not commence on any portion of land before compensation and assistance have been provided to the affected population in accordance with the policy framework.

60. Entitlements and R&R package. In line with the above principles, an entitlement policy has been developed. The entitlement package consists of the following,  Cash compensation at replacement cost for land, structures, crops and trees;  Production disturbance at the value of one crop for households which will lose land;  Allowance for relocating households, including dislocation, transportation and rental allowances;  Livelihood assistance in cash for households losing land, varying according to degree of land losses;  Occupational skill training (non-farm) for livelihood assistance;  Agricultural assistance in extension training and agricultural input;  Priority consideration in construction employment opportunities;  Special assistance to vulnerable households;  Compensation and assistance in re-establishing the school and temples;

61. Institutional Arrangement. NEA will have the responsibility for the implementation of the RAP. Within NEA, a Project Management Office has been established, under which a Safeguards Management and Monitoring Unit will be established. This unit will have a Land Acquisition and Rehabilitation Unit set up which will be specifically responsible to oversee the implementation of the RAP. In addition, an Environment and Social Management Unit will be established in the field to manage the actual implementation of the RAP. The Environmental and Social Studies Department (ESSD) of NEA will, on a contractual basis, provide people, technical support and advisory services to the project director and the Land Acquisition and Management Unit in monitoring and supervising the RAP implementation.

62. At the district level, several organizations will participate in the RAP implementation as well. These include the district administration, Compensation Determination Committee, Local Consultative Forums, as well as the district revenue, forestry and agricultural offices. A monitoring system will be established, including internal and external monitoring. An external monitor will be engaged for the RAP implementation.

63. Grievance redress. A grievance redress mechanism will be established to allow project affected persons/households (PAPs/HHs) to appeal any disagreeable decisions, practices and activities arising from compensation for land and assets. The PAPs/HHs will be made fully aware of their rights and the procedures. A grievance recording register will be maintained at the Environment and Social Management Unit established at site. The Project will also organize site and community hearings to collect grievances. A four-step procedure has been established for grievance filing and redress,  Stage 1: Complaints will be filed and settled verbally or in written form in a field based project office. The field office will carry out its necessary inquiry and verification. A response should be due in seven days.  Stage 2: If issue is not addressed within seven days or to the satisfaction of the complaining party, a written complaint will be field with the Environment and Social Management Unit. Local Consultative Forums will also be established in each district to facilitate grievances redress. The LCF will be led by locally respected persons and include people’s representatives.  Stage 3: If no understanding or amicable solution is reached or no response from the project office, appeals can be made to the CDC where decisions should be made within 15 days.  Stage 4: If unsatisfied with the decision, people may submit its case to the District Court.

Environmental Assessment (EA)

64. Environmental assessment and impacts for the Dhalkebar-Bhittamod section of transmission line in Nepal (component A2). The proposed 40 km stretch of transmission line is located in Dhanusha and Mahottari district in the Janakpur zone in Eastern Nepal. The project area does not lie in any national park, wildlife reserve, buffer zone, conservation area, wetlands, historically or archaeologically important sites or environmentally sensitive/ fragile areas. The proposed alignment does not pass through forest land. The beneficial/positive impacts include: employment of up to 400 people, increase in economic opportunity, enhancement of technical skill, increase in power exchange facilities and rural electrification. Potential adverse impact typically associated with the transmission lines, such as changes in land use pattern, water pollution, waste disposal and land degradation are not expected to be significant or irreversible. The biological impacts during the construction and operation phases include loss of 728 private trees, loss of 500 bamboo grooves and potential risk in some locations of birds striking the transmission line. The losses of trees and bamboo groves will be mitigated through compensatory afforestation plan using 25 times more saplings for each tree lost. Measures to mitigate potential issues with birds in selected locations will be finalized and use proven methods

to avoid or minimize collisions with lines. An Environmental Management Plan (EMP) has been prepared to mitigate and monitor the construction and operation phase impacts that include land use restrictions, loss of agricultural production, land fragmentation and farming hindrance, withdrawal of economic opportunity, occupational safety and livelihood,. Overall the IEE shows that adverse impacts on physical, biological as well as socioeconomic and cultural heritage due to implementation and operation of the Dhalkebar-Bhittamod component of the project are limited and can be mitigated.

65. Environmental assessment and impacts for H-D-D section of transmission line in Nepal (component B1). The Initial Environmental Examination or IEE shows that the proposed 285 km 400 KV H-D-D transmission line (the largest component of the proposed Project) mostly runs parallel to existing infrastructure in already anthropogenically impacted areas. The proposed alignment often co-shares the Right Of Way of the existing 132 kV transmission line and the Mahendra Highway, especially in sections where it passes through the core forest area. The proposed alignment has been selected to entirely avoid going through the critical natural habitat zones of Kosi Tappu Wildlife Reserve and the Parsa Wildlife reserve. The ESIA indicates that the proposed line does not go through any national park, wildlife reserve, buffer zone, conservation area, wetlands, or historically or archaeologically important sites. While the proposed transmission line alignment has completely avoided going through Koshi Tappu and Parsa Wildlife Reserve, its buffer zone approximately 10 km from the proposed of right of way is known to inhabit sensitive flora and fauna, habitats for migratory birds and migration routes of the wild Asian Elephant (sensitive areas). The anticipated direct impacts on these hotspots, however, are not expected to be significant due to construction and operation of the H-D-D transmission line. Any direct and indirect adverse affect on an area significantly broader than the immediate ROW or facilities subject to physical work will be mitigated, closely monitored and supervised. According to the ESIA the existing right of way of the 132 KV transmission line is not reported to have caused adverse impacts on the migration of birds or the Asian Wild Elephant that continues to migrate over the highway and under the 132 kV line. The proposed 400 kV line running parallel (for most part) will have a greater vertical ground clearance than a 132 kV line, and elephants (which are actually attracted by the crops and the traversing of elephants happens close to the harvesting season), can continue to pass through unhindered under the new line. The NEA environmental team supported by the Bank safeguards team will closely monitor and supervise the construction and implementation phase of H-D-D transmission line.

66. The ESIA contains measures and activities which would mitigate the direct negative impacts on these hotspots to acceptable and sustainable levels. These measures include the fencing of the towers in the Elephant migration corridors to prevent injuries to the animals or damage to the lines themselves. Felled trees will, in accordance with Nepal regulations, be replaced at a rate of 25 trees planted per tree cut as part of the re-forestation component under the project. NEA will also initiate and complete a biodiversity study focusing on the hotspots in more depth during the detailed design stage of the project. The findings of this study will inform the design, prior to its finalization, of appropriate and effective mitigation measures for specific situations/stretches.

67. Description of Hetauda Duhabi line. The proposed Project is located in the Central and Eastern Development Region of Nepal. The Hetauda-Duhabi line passes through the areas of 77

Village Development Committees (VDCs) and two municipalities in 10 districts. The Dhalkebar-Bhittamor north-south line traverses 20 VDCs in 2 districts. The East-West Highway is the main access to the project area. While selecting the transmission line alignment, due consideration was given to avoid the settlement areas, inbuilt structures, religious places, schools and other community infrastructures as far as possible. Of the 285 km of D-H 400kV line, the initial 18.6 km (Hetauda- Hurnamadi) stretch of transmission line passes through a hilly area. Over the next 23.4 kilometers (Hurnamadi- Nijgadh), the line route gradually changes from hills to Terai. The remaining 243.2 km (Nijgadh- New Duhabi) passes through flat plain of Terai and runs almost parallel to, and on the northern side of the East-West Highway. , Alignment of the D-H line has been proposed parallel to the existing 132 kV line to the extent possible. In this regard out of 285.2 km total length, 96.6 km is aligned close to existing 132 kV line. The north- south line, alignment passes almost entirely through flat Terai land both within India and Nepal with land use along the proposed alignment being predominantly agriculture. While significant forest stretches are encountered along the Hetauda-Duhabi line, the alignment of the north-south line within Nepal has reported no forests, and in India only 0.75 ha social Forest (along canal bank) has been identified. No other environmentally sensitive receptors are known along the current north-south alignment in India and Nepal. This foregoing description clearly identifies Hetauda Duhabi line as the environmentally most sensitive, the description that follows concentrates on it and other portions are described where relevant.

68. Analyses of Alternatives  Two alternative routes were analyzed for the environmental assessment. Alternative A was approximately 235 km long and passed through the Koshi Tappu Wildlife Reserve. Nearly 75 percent of the alignment passed through the forested area while only 25 percent was on the agricultural land and settlements. Alternative B had a total line length of 285.2 km. The forest area in this alternative is less than 40 percent of the alignment length. Though nearly 60 percent of the alternative passes through agricultural land and settlements, it has avoided Koshi Tappu Wildlife Reserve, the large settlements, historical sites of cultural and religious significance, and institutional areas.  Further, the second alternative passes along the border area of the forest avoiding dense forest and settlements. Apart from this, the alignment is set parallel to the existing 132 kV transmission line and the road, has opportunity to co-share the RoW with the transmission line to minimize the forestland take and eliminate to the extent possible the forest fragmentation and wildlife habitat disturbances. Despite a longer transmission line length by about 50 km the second alternative was selected as it not only avoids critical natural habitat areas of Kosi Tappu Wildlife Reserve but also has minimum disturbances to wildlife habitats in the forest areas outside the wildlife reserves.  In Muzaffarpur and Hetauda, where, there is sufficient land available in existing substations, these substations would be upgraded to meet the infrastructure requirements. In Dhalkebar, where available land areas is not sufficient to accommodate the required infrastructures, land augmentation would be made from adjacent land plots without impinging seriously on the natural and social environmental resources., . Moreover, in the Dhalkebar substation, the land requirement has been minimized by adopting GIS switchgear which is also safer, and more reliable, even though costs could be somewhat higher. In Duhabi (Inaruwa), since such opportunities to upgrade/expand existing

substations were not available, a new substation of adequate size has been identified. Basic criteria used for selection of the sites included avoidance measures such as: as far from settlements as possible, use of agricultural land with less economic opportunities, circumventing forest land, and choosing land devoid of standing trees.

69. Enhancement and Mitigation Measures

 The enhancement measures proposed during the construction phase include priority to the local employment, rural electrification in affected VDCs and implementation of a community support program. Although these programs are not directly related to the project development, it has indirect consequences with regards to project construction. Since large scale transmission line projects are planned to be implemented in their area, the local people have certain expectations regarding the assistance in some of the development works. These include a health post support program, a school support program, small scale drinking water and irrigation assistance and assistance for the renovation and development of religious and recreational places. The major religious places proposed for assistance are Kushmandap Sarobar - Chaudhaghare, Hetauda municipality, ward no 9 Nunthar Mahadev - Paurahi VDC, Rautahat. Kailashpuri Mahadev, Harion, Sarlahi and Harihar Chhetra, Karmaiya, Sarlahi. In addition, a capacity building program for local institution (VDCs, NGOs, CBOs and clubs) working in community will also be conducted.  The project proponent will implement the proposed mitigation measures as a prime responsibility. The adverse impacts that are not identified during the study, if later discovered during the construction and operation phases will be mitigated by the proponent at its own cost. The project will compensate for the loss of life and properties due to activities taken during construction and operation of the project.  Special foundation designs such as matt and pile foundation (or combined footing type of foundation) will be used for the towers located in flood plains and in geologically fragile areas. Such types of tower pads are proposed at AP 51 & AP52 and intermediate towers located in the flood plains of Koshi River which are prone to flash floods.  Revegetation and slope maintenance will be carried out in the disturbed areas of Siwaliks to avoid erosion and land degradation. The waste generated from mixing concrete will be disposed in pits and filled with soil. Such pits will be made in barren land at approximately 500 meter distance from the water bodies.  Wherever possible, low value land/ barren land will be used for temporary facilities on a rental basis and makeshift camps in forestland will be prohibited. The temporary land occupied for project facilities such as storage areas, temporary camps, etc. will be rehabilitated before handing over to the concerned land owner. Air and Water quality protection measures such as sprinkling of water in vulnerable sections to arrest fugitive dust, establishment of waste mangement systems at camps and construction sites with special focus on sanitation to control water and land pollution will be implemented.  To ensure that PCBs are not used in transformers a chemical certificate of the oil used will be provided by the supplier of the transformer prior to the installation of the

transformer from an internationally accredited laboratory. To avoid leakage of oil from the substation, an oil filter on the drainage outlet of the substation will be installed.  To minimise the loss of forest land, loss of trees and forest habitat, the the contractors are recommended to co-share the ROW of the existing 132 kV transmission line with the proposed line. There is ample of opportunity to share the ROW of the two transmission line from AP 14 located at Nijgadh to AP 18 at Chandranigahapur, AP 21 to AP 25 and AP 38 at Lalbandi to AP 49 at Mahottari. The RoW sharing will save 96.6 km forest length having an area of 43.53 ha. This will reduce 18,429 numbers of poles and trees to be felled.  The area equivalent to the forestland under ROW (477.94 ha) will be afforestated by planting 764,704 saplings of local species at the rate of 1600 sapling /ha forest land. Apart from this, an additional 1,396 ha of land will be afforested by planting 3,489,806 saplings of local species at the rate of 2,500 saplings/ha as per the Forest Guideline of the Government of Nepal. This compensatory afforestation is envisaged to increase the forest area by at least 3 fold and the tree population by at least 20 times the lost trees.  Apart from this selective felling of trees in the right of way of the transmission line will be done to minimize the forest loss. Similarly, the contractors will as much as possible avoid felling trees in gullies and vallies in the Siwalik section.  The project will provide kerosene to the project workers to minimize the loss of forest. For the construction of temporary camps pole size timber felled by the project will be used.  Training and other assistance programs will be provided to the community forest affected by the project. The program includes capacity building training, forest management training etc.  The project proponent will require the Contractor to prohibit project workers from collection of non-timber forest products. Informative and warning signs will be placed at each construction sites located in and around the forest area. Training for cultivation of Non Timber Forest Products especially medicinal aromatic plants and other herbs and condiments and agro forestry will be given to two members of each Community Forest User Group. After implementation of training approximately 67,000 saplings will be planted in the cleared RoW in the area of each community forest.  The project proponent will implement an awareness program to increase local awareness of forest user groups. Such programs will be implemented in 10 places of the project area, which include 1 in each district.  The plantation sites will be managed by the concerned Forest User Group in the community forest plantation area. Replacement planting will be conducted after one year based on the survival result and four years of operational cost for such sites will be borne by the Project.  Herbicides will not be used for vegetation clearance. Trees which are considered critical for the operation and maintenance of transmission line will be removed manually. Saplings more than 3 meters height will be trimmed for safe operation of the line.

Saplings below 3 meters will be kept intact since plants below such height will have no impact on operation and maintenance of line.  The total land area to be afforested is around 1873.4 ha. The actual loss of the forested land is 477.9 ha. This means forest habitat will be developed in more than 3 fold land area within 20 years. Hence the loss of habitat will be eventually reversed, provided the compensatory afforestation is executed well. Due emphasis will be given for the plantation work in elephant migration area. The towers sited in this area will be fenced. Measures to minimize bird injury and death associated with the transmission line will be recommended for line design. Markers such as colored balls will be attached to wires to improve line visibility for birds. Silhouettes of birds of prey will be attached to conductors to frighten birds. Such markers are proposed for stretches close to the Koshi River and reserve, Bagmati River and Kamala River crossings.  As far as possible construction work will be labor based. The project will be responsible to avoid unnecessary machinery disturbances and lighting. The project workers will be strictly instructed to refrain from hunting and poaching.  Awareness for wildlife conservation will be implemented to minimize the adverse impacts on local wild fauna. The conservation awareness training will be given to project labors and representatives of Community Forest Users Groups.

70. Implementation, Monitoring and Supervision Arrangements

 The Project Management Office (PMO) has been established under the organizational setup of NEA. The Project Manager will have overall responsibility regarding the implementation of Safeguards management and mitigation, including EMP. He will also be responsible for the overall coordination of the work and make final decisions on environmental, social and issues of public concern. A Safeguards Management and Monitoring Unit (SMMU) will be part of the PMO.  SMMU will be headed by the personnel from Environment and Social Studies Department (ESSD) of NEA. The SMMU will comprise two cells - Environmental Social Impact Mitigation Implementation Cell (ESIMIC) and Environmental and Social Monitoring Cell (ESMC). The personnel in the ESIMIC will be deputed from the ESSD and shall be responsible for implementation of environmental and social mitigation work which is not allocated to contractors The ESMC will be responsible for the monitoring stipulated in the EMP documents. Services of an Owners’ Engineer will also be available for the SMMU and its sub-units to carry out their work. A Lenders’ Engineer will also be appointed to help GoN and the Bank become aware of any problem issues, and find resolutions in time.  The Environmental monitoring plan would comprise, inter alia, measurable monitoring indicators for physical, biological, cultural and social enivironmental resources including actions to monitor the project environmental compliance as well as environmental impacts. The plan is to be arranged in an interactive matrix highlighting the environmental monitoring indicators, location of monitoring, monitoring method, person responsible for monitoring, timing of monitoring and the estimated costs if it requires instrumental monitoring.

 To ensure that the project environmental impacts are avoided or minimised and timely corrective actions are taken, a reporting and decision making framework has been devised as a part of the management plan. The section chief of ESMC would be responsible to prepare a bimonthly report to the project management with regard to compliance, and if any corrective actions are required. In addition, he will be responsible for flagging the compliance and impact issues verbally or in a written form at the active construction sites to the responsible stakeholders (Owners’ Engineer and the Contractor) to avoid the impacts of the project, if required so.  With respect to Bank Supervision and Monitoring of Safeguards Aspects, as mentioned earlier, CPTC will implement the Indian part (component A1) line in accordance with Indian laws and regulations, and the shareholders of CPTC have decided to implement the environmental and social aspects of the Indian portion in line with POWERGRID’s ESPP. Since IDA is not financing these linked investments, IDA would not have any supervision/monitoring rights of this component. As regards the Nepal parts, for the Dhalkebar-Bhittamod section (component A2), the Bank would be able to monitor the implementation, including the Safeguards aspects, through NEA. For the H-D-D section (component B1), the Bank’s Safeguards team will closely monitor and supervise the construction and implementation phase of the Hetouda-Dhalkebar-Duhabi transmission line.

Social and Environmental Management Cost

71. The total estimated social and environmental management cost for the proposed project is approximately NRs 1050 million (US$15m) for both lines on the Nepal side. These include costs of forest related mitigation measures, environmental monitoring during pre-construction, construction and operation phases of the project, provision of a communication /outreach centre, and capacity building of NEA staff on environmental management and social issues.

Table: Details of Social and Environmental Management Costs

S.No Mitigation Program* Amount in Million NRs. Million Constru Operat Total USD ction ion (1USD= Phase Phase 72NR)

1 Biological Environment

Costs of Tree cutting, and compensatory Plantation a including lease of Forest Land for 30 years 159.09 108.55 267.64 3.71

b Training and Conservation Awareness Programs 5 1 6 0.08 c Technical Support to District Forest Offices 1 0.5 1.5 0.02 Biodiversity Study Cost (included in Component C d separately) 0 0 0 0.00 2 Socio-Economic Environment a Asset compensation for angle towers 129 1.79 b R&R Assistance and Others for angle towers 33 0.46 c Compensation for ROW use restriction ** 263 3.65 d Asset compensation and R&R assistance **+ 185 2.57 3 Monitoring 23.59 0.33 23.92 0.33 Project Information Center/Communication/Local 4 Consultations 10 0 10 0.14 Institutional Strengthening on Environment and 5 Social Safeguard NEA-ESSD/Project Staff 35 0 35 0.49 Sub Total 954.06 13.25 Contingency 95.406 1.33 GRAND TOTAL 1049.47 14.58 * Costs bid in by Contractor are excluded here * *These are estimated costs for the transmission line and suspension towers. + Includes NRs 2 million for relocation of a school and 3 local temples

Annex 4: Operational Risk Assessment Framework (ORAF) NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

Project Development Objective(s) The development objectives of the proposed Project are to: (a) establish cross-border transmission capacity between India and Nepal of about 1000 MW to facilitate electricity trade between the two countries and (b) increase the supply of electricity in Nepal by the sustainable import of at least 100 MW.

Key 1. Cross-Border transmission capacity Results Indicators: 2. Quantity of electricity imported from India to Nepal under the PSA

NOTE: GON = Government of Nepal; NEA = Nepal Electricity Authority;

ORAF Risk Levels Risk Rating Risk Description Proposed Mitigation Measures

(i) No support from new governments and opposition by (i) Design and implement a communications strategy aimed at one or more of the political parties in Nepal (could affect creating an enabling environment for the Project and at timely provision of counterpart funds) conveying the benefits of the project as they apply to all stakeholder groups. The strategy will include: (a) ongoing (ii) A complication in the political relations between consultations with all stakeholder groups to understand India and Nepal with the new Government. India is a their concerns; (b) targeted communication initiatives to Stakeholder Risks MI stakeholder in the project and political developments/ address these concerns; (c) providing easy access to reactions in India could impact the project information about project; (d) effective grievance redress

mechanisms. (iii) Withdrawal of one or more of the sponsors – IL&FS (ii) Maintaining momentum on preparatory actions including and/or NEA the signing of the requisite project agreements and Local opposition based on a perceived inadequacy in reaching financial close. benefits-sharing and access to electricity. (iii) Careful attention to social aspects of project implementation, including benefits-sharing.

Capacity at NEA is low in project management, FM, and (i) The capacity development plan put in place and the procurement extensive oversight built into the project design Implementing Agency MI Risks The possibility of fraud and corruption exists (ii) The routine nature of the transmission investment and the existence of a robust competitive market for such ICB

ORAF Risk Levels Risk Rating Risk Description Proposed Mitigation Measures

The protracted decision-making process could delay tenders implementation

The complex project design – comprising NEA and two The regulatory and legal framework to be incorporated in a set SPVs for the Dhalkebar-Muzaffarpur project, multiple of agreements is fully developed and is being negotiated. sources of financing, and multiple agreements to create the policy, regulatory and legal framework presents Nepal and NEA are experienced in dealing with commercial Design Risk implementation risks. legal agreements for power purchase from IPPs and even MI import of power on a small scale.

Capacity development interventions have been built into the Project and in the ongoing Power Development Project.

Risks of inadequate assessment or improper handling of (i) Applicable elements from the Nepal Peace Filter will be Safeguards aspects could delay project preparation and examined for incorporating into the social safeguards. approval; and during implementation could negatively (ii) Bank support to NEA’s ESSD is strengthened by impact the local area and the affected population. Policies engagement in the ongoing Power Development Project. triggered include Environmental Assessment policy (OP (iii) The Lenders’ Engineer will monitor the implementation of Safeguard Risks 4.01), Policy on Involuntary Resettlement (OP4.12), Safeguards mitigation plans. MI Forests (OP 4.36), Indigenous Peoples (OP 4.12), Natural Sustained communications initiatives will be undertaken to Habitats (OP 4.04), and Physical and Cultural Resources inform the affected stakeholder groups about the possible (OP 4.11). impacts of the project and the mitigation measures taken to ILO 169 creates greater local demands for control over address these impacts. resources. (iv) Careful attention to social aspects of project preparation including benefits-sharing.

Commitment for the regional program could wane due to Intensive engagement by the Bank team will continue during changes in government in Nepal or to suspicions around a implementation. Program and Donor “fair deal” in the cross-border power trade. Risk MI Closely monitoring the evolving political economy of the project and calibrating responses in terms of implementation plans and stakeholder outreach

Delivery Quality Risk Risks of inadequate coordination of construction i) The advice and assistance provided by the hired (Contract ML schedules could result in the infrastructure not being consultants/advisors/supervising engineers will help to Management, ready to evacuate power from India and face NEA with minimize this risk.

ORAF Risk Levels Risk Rating Risk Description Proposed Mitigation Measures

Sustainability and “take or pay” penalties. (The D-M Line and at least one (ii) The capacity building plans will address capacity M&E Risks) limb (either Hetauda Dhalkebar or Dhalkebar-Duhabi) of constraints. the H-D-D line have to be essentially completed at the same time)

Weak project management and M&E capacity.

Overall Risk Rating at Overall Risk Rating During Comments Preparation Implementation Given the volatile nature of the socio-political situation in Nepal as well as risks specific to the sector the project faces a high level of risks that are only partially amenable MI MI to upfront mitigation. The Bank has put in measures to build the capacity of the implementation agency as well as intensive third-party monitoring and supervision to ensure implementation success.

Annex 5: Implementation Support Plan NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

1. Strategy and approach for Implementation Support: Recognizing that good preparation would pave the way for good implementation of the proposed Project, the Bank team has been providing significant help towards all aspects of the Project’s preparation including designing implementation arrangements. Specifically, the Bank team, using the resources from the on-going PDP, trust funds from AusAID; and more recently trust funds from UK DfID, has provided assistance to NEA and GoN towards: (a) re-drafting and negotiating the commercial agreements such as PPA and ITSA; (b) helping with the detailed techno-economic Feasibility Study for the Hetauda-Dhalkebar-Duhabi transmission line; (c) Safeguards assessments including the mitigation and management plans; and (e) financial analysis of NEA with a view to identify the critical steps for the financial recovery of NEA. In addition, assistance has been provided for the preparation of a Procurement Plan and importantly the bidding documents for all the proposed contracts (both goods and works and consulting services). Such assistance has been provided with a view to build up the capacity of NEA – for example the techno-economic feasibility study and the Safeguards assessments were done by NEA staff themselves under the guidance of the Bank team (including consultants). This would enable NEA to be more certain of what its needs are during implementation.

2. Nevertheless, additional implementation assistance is needed. NEA, for the first time, would be preparing Design-Build contracts for a transmission line and substations. Therefore, the services of a Procurement Advisor are already in place to assist with the procurement process. In addition, an Owners’ Engineer would be appointed to help evaluate the bids, contract management and supervision, as well as overseeing the safeguards; and reporting including on Project Financial Management. A high level steering committee would be established to guide the Project Management Office already in place under the Director, Transmission Line Construction and Cross-Border Projects.

3. In addition, with a view to be able to provide timely feedback to the Government and the Bank on the quality and speed aspects during project implementation, a Lenders’ Engineer would be appointed. This will facilitate a more frequent and independent feedback on the Project, but at lower costs.

4. In recent years, the Bank has significantly scaled up its in-country presence and capacity for project management. The IDA/IFC joint team in Nepal currently includes a Country Director, IFC Resident Representative, and about 80 full time staff, including two energy staff.

5. Implementation Support Plan. Nevertheless, significant level of implementation support would be needed, especially during the first 12-18 months of the project. The following areas are needed:

i. Overall project implementation particularly coordination between the various elements of the project – the components being built by the two SPVs, the observance of commercial agreements; the coordination between technical and safeguards issues; and a focus on financing flows to the project; and financial viability issues on NEA

ii. Supervision of the technical aspects including coordinating with the procurement actions and documentation, and with the hired consultants (Procurement Advisor Owners’ Engineer). iii. Safeguards aspects – especially the inclusion of the various mitigation frameworks in bidding documents; and in particular the reforestation efforts which would be the responsibility of the Forest Department of GoN. iv. Financial Management – especially the establishment of project financial management; and observance of the Action Plan already in place to improve NEA’s overall financial management Capability. v. Corporate Financial aspects – focus on the implementation of the Financial Recovery Plan for NEA.

6. The main focus of implementation support is described below:

Time Focus Skills Needed Resource Partner Estimate Role First 1. Overall 1. Team leader $60,000 twelve Implementation 2. Power Engineer $30,000 months Support 3. Environmental $35,000 2. Technical and Social Aspects Specialists 3. Safeguards 4. Corporate Finance $30,000 4. Corporate Specialist Finance 5. Procurement $15,000 5. Procurement Specialist 6. Financial 6. Financial $10,000 Management Management Specialist

13-48 Annual Req. months 1. Overall 7. Team leader $40,000 Implementation 8. Power Engineer $20,000 Support 9. Environmental and $20,000 2. Technical Aspects Social Specialists 3. Safeguards 10. Corporate Finance 4. Corporate Finance Specialist $20,000 5. Procurement 11. Procurement 6. Financial Specialist $10,000 Management 12. Financial Management $10,000 Specialist

II. Skills Mix Required

Skills Needed Number of Staff Weeks Number of Trips Comments 1. Team leader 20 4

2. Power Engineer 10 3

3. Environmental 15 3 and Social Specialists

4. Corporate Finance 10 3 Specialist

5. Procurement 8 3 Specialist

6. Financial 8 3 Management Specialist

Annex 6: Team Composition NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

World Bank staff and consultants who worked on the Project:

Name Title Unit Raghuveer Sharma Team Leader SASDE Pravin Karki Sr. Hydropower Specialist SASDE Chaohua Zhang Sr. Social Sector Specialist SASDI Kishor Uprety Senior Legal Counsel LEGES Bigyan Pradhan Sr. Financial Management SARFM Specialist Gaurav Joshi Environmental Specialist SASDI Rabin Shrestha Senior Energy Specialist, Project SASDE Economist Michael Haney Senior Energy Specialist SASDE Diep Nguyen-van Houtte Senior Operations Officer SARVP Sona Thakur Communications Officer SAREX Rajib Upadhya Senior External Affairs Officer SAREX Shaukat Javed Program Assistant SASDE Sunita Gurung Program Assistant, Kathmandu SASDE office Christopher Rytel Consultant/Power Engineer V. Krishnaswamy Consultant/Strategy and Policy Santhanam Krishnan Consultant/Sr. Procurement Specialist Ishwar Chandra Jaiswal Consultant/Technical_Institutional Toran Sharma Consultant/Environmental Ishwor Neupane Consultant/Social Safeguards Aman Sachdeva Consultant/Financial Advisor

Annex 7: Institutional Aspects of NEA NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

The role and organization of NEA

1. Nepal Electricity Authority (NEA) was created on August 16, 1985 (Bhadra 1, 2042) under the Nepal Electricity Authority Act., 1984, through the merger of the Department of Electricity of Ministry of Water Resources, Nepal Electricity Corporation and related Development Boards.

2. NEA is the main player in the Nepalese electricity sector. It is the largest generator of electricity (approximately 60 percent of the total output), it is responsible for system operation, and it is the largest transmission and distribution grid owner in Nepal. NEA also holds the role as the single buyer of bulk electricity in Nepal. The company is entirely owned by the State of Nepal. Its Board of Directors is chaired by The Minister of Energy and otherwise consists of one representative from Ministry of Energy, one from Ministry of Finance, one Consumer representative, Two Power sector experts from Non-government sector, and one representative from industry, commerce and financial sector. All eight Board of Director members including the CEO are nominated by GoN.

3. NEAs mission is to maximize contribution to the economic development of Nepal by providing quality, reliable and affordable electricity supply to the customers in a safe and environmentally friendly manner.

4. NEAs primary objective is to generate, transmit and distribute adequate, reliable and affordable power by planning, constructing, operating and maintaining all generation, transmission and distribution facilities in Nepal's power system both interconnected and isolated.

5. The NEA organization has a staff of around 9000 and is organized in five business groups and 4 corporate offices (Planning, monitoring and IT, Administration, Finance, and Internal Audit). The business unit groups are:

 Generation  Grid Development and System operation (TSO)  Distribution and Consumer services  Electrification  Engineering services.

Legal and Regulatory Framework

6. The electricity sector of Nepal is in its shaping period, with formation of its institutions and legal framework. “The Electricity Act of 1992” and “The Water Resources Act of 1992” are currently the two governing acts. These were made under the authority of the kingdom of Nepal, and there are efforts to reform the legal and regulatory framework of the electricity sector with the pronounced aim of attracting investments to the sector. Accordingly there is a draft of a new Electricity act “Act for Development and Management of the Electricity Sector” approved by the

Government and with the Parliament. This draft act will shape the future of the power sector. In addition to covering issues described in the Electricity and water resources act of 1992, this act also covers new issues directly related to the NEA organization. For example, under chapter 3, it is stated that the different functions of NEA shall be divided into separate corporate bodies and that a National Electricity Transmission Company shall be established. This act also describes the prescription of a “National Transmission Grid” to which Licensees shall be given grid access in a non-discriminatory manner.

7. There is also a draft act entitled “Establishment and Management of Nepal Electricity Regulatory Commission” (The NERC act). This act describes the capacity of the Regulator and its objectives. Its objectives are among others to enhance the safety, capacity and effectiveness of the electricity system, to ensure reliable electricity to consumers at a competitive price, and to adopt a least cost expansion of the INPS.

8. The establishment of a national Transmission System Operator (TSO), a national grid with non-discriminating third party access, and a regulator who is the responsible authority for technical, safety, market development and tariff issues in addition to giving licences are important policy aims contained in the draft Acts.

The Main Challenges

9. NEA faces several key challenges. The first and foremost is the growing gap between supply and demand of power. Fortunately, there has been a significant response by the private sector to develop Nepal’s hydro capacity but almost all the proposed capacity is oriented towards exports to India. NEA’s second key challenge is to provide the necessary transmission services both inside the country and cross-border. Also provision of cross-border transmission services would enable import of base load power from India to meet the deficits even earlier than the Nepal’s hydropower can be developed. The development of the transmission system would enable the expansion of the system within Nepal. Combined with the additional power expected to be available, development of the transmission system in turn will enable NEA to meet its third major challenge - of increasing access within Nepal. The building of the transmission system including cross-border links will enable the financial situation to improve. Therefore accelerated and comprehensive development of the country’s transmission system, i.e., its Transmission and System Operation (TSO) business unit, is key to Nepal’s energy sector development, on which NEA is placing increased focus, with the support of GON and support from multilateral and bilateral agencies.

Strengthening NEA’s Grid Development and System Operations

10. The Grid Development and System Operation business of NEA carries out key functions such as system operation, main grid planning and construction and grid operations. Accordingly, this business unit of NEA is responsible for the design, construction, operation and maintenance the 66 kV and above transmission system of the national grid and to perform system operation for INPS. The Grid Development and System Operation’s main assets today are 1,619 km of 132 kV transmission line, 361 km of 66 kV transmission line and 37 substations. The total transformer capacity is 1,595 MVA.

11. The Grid Development and System Operation Business unit is the smallest business unit of NEA. It has a staff of 590, out of which 78 percent have a technical background. The business unit is organized in 3 Departments and 2 Project units. The 3 departments are Transmission Line and substation construction department (TL&SS), System operation Department (SO) and Grid operation Department. The Grid Operation Departments is the largest within the Business Unit. It has a staff of about 500 and is organized in sub-units with limited geographical responsibility. The two project units are Power development project and cross-border 400 kV transmission line interconnector project. The first unit is responsible for implementing transmission and distribution project under World Bank loan/grant assistance and the second for developing three or more 400 kV cross border projects between Nepal and India.

12. The main challenges faced by the TSO, and options to meet those challenges in performing its role to the fullest are discussed below:  Improved system utilization. Given the situation of the power system in Nepal, it’s imperative to look for ways NEA’s TSO can better utilize the existing system. There are possible steps that TSO could take such as: (a) minor investments in reactive capacity (capacitor banks); (b) system protection schemes; and (c) increasing thermal capacity. These strategies both increase the available transmission capacity and the system reliability. The issue of frequency control and regulation will also need to be addressed by collecting data, conducting analysis and setting of turbine governors. In the generation part of the sector, there are possibilities to reduce spilling of water and to utilize the surplus that exists during the wet period. Surplus capacity may reduce domestic load shedding and cause less use of the Kulekhani storage plant during the summer and thus improve the situation during the rest of the year.  Improved Grid Planning and Project Implementation. A core responsibility for a TSO is to plan and develop the main grid in a socio-economic fashion; and in the current situation, to plan and develop multiple cross-border connections with India. (a) First there is an urgent need to prepare a comprehensive Transmission System Master Plan for Nepal, which would include the needed cross-border connectivity with India, and build the capacity for periodic updating of the Master Plan to suit evolving and changing circumstances. (b) Second there is also the challenge of ’projectizing’ the Master Plan, prioritizing the projects within the plan, and executing the projects. This requires upgrading the capabilities of the Transmission Line and Substation Construction Department of the TSO, as well as corresponding departments across NEA (e.g., Environmental and Social Assessments, financial/treasury departments, etc.).  Cooperation with India in the area of POWERGRID construction and operation. It has been decided to build multiple cross border transmission links with India and in a synchronous (Alternating Current or AC) mode. However, there are many issues that need to be addressed to realize more cross border capacity. NEA needs to have sufficient knowledge on several technical and economic aspects of interconnecting with India, and activities to provide more insight will be of priority. The key issues to address are: (a) what are the measures needed to ensure synchronous and stable operation of the Nepal grid with India’s grid; and (b) how to ensure sufficient security of supply in a future situation with both more power export and import. NEA should conduct their own system

analysis for a Nepalese-Indian system in order to assess what are alternative ways forward from a Nepalese point of view. There is a need to create an institutional framework such as a technical and coordination committee between NEA and POWERGRID Cooperation of India; while in parallel, NEA begins receiving technical assistance to address the issues.  Business Plan for NEA Grid Development and System Operation. There is an urgent need for preparation of a separate Business Plan for NEA’s TSO in view of the fact that the TSO would begin dealing on its own with outside agencies in the context of Transmission Service Agreements with IPPs in Nepal and cross-border suppliers. This should also include cost splitting of the different NEA business areas. The governing structure should also be assessed. Both making strategic plans and tools for governance and strategic control may be introduced within this element. As part of the Business Plan development, the principles, procedures and implementation aspects of calculating wheeling and transmission service charges would need to be put in place.  Capacity for Realizing Additional Cross-Border Interconnections. Since there are 3-5 interconnections planned with India, NEA’s TSO needs to continue to develop its capability to conceptualize, prepare jointly with the Indian partners, and implement these cross-border connections, on a commercial basis. Therefore there would be continued need for the on-going legal, technical and financial advisory assistance for the proposed new inter-connections that NEA is receiving currently for the proposed Project.

13. To implement these options to strengthen the Grid Development and System Operations business unit, technical assistance is being put in place by the Bank. In addition the Bank has allocated funds from the on-going PDP as well as the proposed Project. Other donors/financiers such as Norweigian aid agencies are also interested in providing capacity building assistance to NEA.

Annex 8: Financial Analysis NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

Background 1. Nepal Electricity Authority (NEA) was created on August 16, 1985 (Bhadra 1, 2042) under the Nepal Electricity Authority Act. 1984, through the merger of the Department of Electricity of Ministry of Water Resources, Nepal Electricity Corporation and related Development Boards. NEA is governed by a Board of Directors which is constituted as follows:

The Minister/State Minister of Energy or Person appointed by the GoN Chairman Secretary, Ministry of Energy Member Secretary, Ministry of Finance Member One prominent person from commerce, industry, or financial sector Member One person from consumers group Member Two prominent persons with experience in power sector from outside Member government Managing Director, NEA Member Secretary

2. NEA maintains its accounts in accordance with the Nepal Accounting Standards. The adopted policies include financial statement preparation on the basis of historical cost convention in accordance with the generally accepted accounting principles. NEA has adopted the presentational requirements of the Companies Act 2063. NEA’s corporate financial performance was driven by financial performance covenants agreed to, through the Government of Nepal, with multilateral financial institutions, primarily ADB and the Bank.

B. Financial Analysis of the NEA

3. 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. Without rapid implementation of reforms, the company would continue the downward spiral of increasing costs, decreasing revenues and chronic underinvestment.

4. NEA revenues from electricity sales have remained stagnant over the 2007-2009 periods at around NPR14.7BN with average tariff yields declining slightly (0.8 percent) over the same period. There has been no substantial tariff hikes in Nepal since 2001.

5. Operating costs have increased 16 percent (at 7.7 percent CAGR) over the same period, with distribution and power purchase costs - accounting for 20 percent and 58 percent of total costs, respectively - growing at 18.5 percent and 5 percent CAGR, respectively. Cost of NEA’s own generation grew at 14.4 percent over the 2007-2009 periods.

6. According to NEA, the significant increase in its own generation costs are attributable to increasing staff costs due to hikes in employee remunerations instituted by the Government of

Nepal (GoN), a 48 percent 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.

7. 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 time period under consideration. NEA had not been able to keep its accounts receivable and account payable within a 90-day limit.

8. NEA’s liquidity is precarious and its debt service coverage ratios have been below 1.0 when all the dues in terms of repayment of loans and interest are taken into account.

9. 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 percent to 9 percent 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.

Projected Financial Performance

10. The projections for NEA financials indicate that cash flow shortfalls are expected over the 2011-2013 period.

11. NEA has projected growth in generation capacity from current base of 428 MW to 1448 MW over the next decade, requiring capital infusion of approx. US$2 billion. In addition, NEA also has significant transmission capacity addition plans over the same time period. This expansion plan requires an investment of approx. US$212 million per annum for generation over the next decade, plus an average investment of US$97 million per annum for transmission projects.

12. Under the current circumstances, it is impossible for NEA, even with GoN support to implement such a huge capital expansion plan. There is an urgent need to implement a financial recovery/restructuring plan comprising cost curtailment, reduction of liabilities, control of investments (by focusing on transmission and distribution investments).

13. 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 in Table 8.1. 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 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 been fully discussed with local stakeholders.

Table 8.1: List of Proposed Reforms

Clause Title Definition Implementing Agency Auxiliary in Agencies Report 9.1 Corporate Financial Reform 9.11 Increase Share (a) Increase Authorized capital From NPR 30 BN to Council of Ministers MoF16, MoE17 and Capital and NPR 75 BN NEA 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 Council of Ministers MoF, MoE and Subsidiary Loan accounted NEA Agreement with (b) Projects funded through foreign grants shall be GoN and capitalized at 50% of such grants, which will be capitalization of accounted as loan instead of grant projects constructed from foreign grants 9.1.3 Reduce Interest (a) Reduce Interest Rate from 8% to 5% financing Council of Ministers MoF, MoE Rates through foreign source (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 (a) Capitalize NPR 6.67 BN out of the NPR 13.54 BN Council of Ministers MoF, MoE and Middle KFW grant NEA Marsyangdi (b) Capitalize NPR 4.75 BM as IDC and Foreign Hydro Electric exchange loss during construction Project 9.1.5 Settlement of (a) The outstanding dues between NEA and GoN shall MoF MoE, MoLD18, 19 outstanding dues be adjusted and net payable to GoN shall be MoI and NEA between GoN incorporated in the books of NEA. 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 DoED20 MoF, MoE and calculated as per generation point, which is in the range of NPR 3 per kWh, NEA the provisions of rather than the current practice of fixing selling price at Electricity Act NPR 5.41 per kWh 1992

16 Ministry of Finance 17 Ministry of Energy 18 Ministry of Local Development 19 Ministry of Industries 20 Department of Electricity Development 94

Clause Title Definition Implementing Agency Auxiliary in Agencies Report 9.1.7 Develop MoF shall deduct the amount equivalent to street light MoLD MoF, MoE, payment dues from the annual grants provided to local bodies and Municipalities & mechanism for the same shall be reimbursed to NEA VDC21 street light bills to minimize collection risk 9.1.8 Formation of A Rural Electrification company shall be incorporated Council of Ministers MoF, MoE and Rural under the full ownership of GoN and existing NEA Electrification infrastructure related to rural electrification, offices, Company employees, related assets and liabilities shall be transferred to such company 9.1.9 Formation of To form an Electricity Purchase Tariff Fixation Council of Ministers MoE Electricity Committee (ETFC) purchase tariff fixation committee 9.1.10 Operation of (a) If diesel plants are to be operated continuously, GoN Council of Ministers MoF, MoE and Multi-fuel and shall bear the cost above the average cost of NEA Diesel Plant 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 NEA is allowed to issue debentures guaranteed by the NEA MoF, MoE Issue GoN for project financing 9.2 Managerial Reform 9.2.1 Reduction of (a) Competitive appointment of executive director on NEA Administrative performance contract Expenses (b) Greater control over recruitment and misuse of corporate resources (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 To adjust electricity sales tariff as per revenue ETFC MOF, MoE, NEA adjustment requirement Source: Data provided by NEA

14. It has been agreed that GoN/NEA shall report, on a semi-annual basis, commencing July 15, 2011, to the Bank on: (a) progress achieved in the process leading to the adoption of the FRP, and, once GoN and NEA shall have adopted the FRP after taking into account the Bank’s views thereon, (b) the implementation thereof.

21 Village Development Committee 95

Annex 9: Economic Analysis NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

Supply Demand Analysis

1. Peak demand in Nepal grew at an annual rate of 9.5 percent over the period FY 2001-FY 2010 while energy available for supply grew only at an annual rate of 7.9 percent (Table 9.1). However the grid connected installed generation capacity has stagnated around 640 MW of which a notable portion is not available for generation on account of old age and the need for rehabilitation. Further on account of seasonal river flow variations the capacity drops substantially during the dry season. Thus for example on the peak demand day of FY 2010 (January 19, 2010) load shedding was more than 400 MW. During the dry season daily supplies were limited to 12 hours only and the total energy not supplied thus during the year amounted to 678 GWh.

Table 9.1: Peak Demand Growth and Energy Availability in Nepal

Particulars 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010* Peak Demand (MW) 391 426 470.33 515.24 557.53 603.28 648.39 721.73 812.5 885.28 Available Energy (GWh) 1868.42 2066.45 2261.13 2380.89 2642.75 2780.92 3051.82 3185.95 3130.79 3689.27 NEA Hydro 1113.36 1113.13 1478.04 1345.46 1522.9 1568.55 1747.42 1793.14 1839.53 2104.52 NEA Thermal 27.14 17.01 4.4 9.92 13.669 16.1 13.31 9.17 9.06 13.12 Purchase (Total) 727.93 936.31 778.69 1025.519 1106.184 1196.27 1291.09 1383.64 1282.2 1571.63 India (Purchase) 226.54 238.29 149.88 186.675 241.389 266.23 328.83 425.22 356.46 612.58 Nepal (IPP) 501.38 698.02 628.81 838.844 864.795 930.04 962.26 958.42 925.74 959.05 Source: NEA Annual Report 2010. The data relating to 2010 are provisional.

2. The monthly variations of supply during FY 2010 given in Table 9.2 indicate the amplitude of the variations and the scarcity of power during the dry season.

Table 9.2: Monthly variations in supply from the generation units in Nepal (GWh) FY 2009/10 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Total NEA Thermal 0 1 1 1 1 1 1 2 2 1 0 1 13 NEA Hydro 204 205 201 194 197 159 125 115 137 159 200 198 2093 IPP Hydro 113 111 113 110 89 69 59 53 57 69 102 110 1055 Imports India 613

3. Load Forecasts are made by NEA based on econometric modeling also making use of income elasticity and price elasticity concepts (but without any anlaysis of energy end use). According to its latest forecast, the peak demand is expected to grow from 967 MW in FY 2011 to 3679 MW in FY 2028 at an annual rate of 8.2 percent. The annual growth is expected to be faster 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 during the 17 year time frame from 4,431 GWh in FY 2011 to 17404 GWh by FY 2028 at an annual rate of 8.4 percent.

Table 9.3: Load Forecast for the NEA power system

Fiscal Year Energy (GWh) System Peak 2010-11 4,430.70 967.10 2011-12 4,851.30 1,056.90 2012-13 5,349.60 1,163.20 2013-14 5,859.90 1,271.70 2014-15 6,403.80 1,387.20 2015-16 6,984.10 1,510.00 2016-17 7,603.70 1,640.80 2017-18 8,218.80 1,770.20 2018-19 8,870.20 1,906.90 2019-20 9,562.90 2,052.00 2020-21 10,300.10 2,206.00 2021-22 11,053.60 2,363.00 2022-23 11,929.10 2,545.40 2023-24 12,870.20 2,741.10 2024-25 13,882.40 2,951.10 2025-26 14,971.20 3,176.70 2026-27 16,142.70 3,418.90 2027-28 17,403.60 3,679.10

4. Without the proposed Project it is fairly certain that the current deficits, already severe, will worsen. This is because: a. Even though NEA has under construction four new hydropower projects totaling 500 MW all of these are run-of-river schemes and will not be able to meet any part of the incremental winter demand; b. While the IPPs are planning to build significant new capacities (See Table 5), all these projects will only be realized if cross-border transmission capacity will be made available – as these are all export oriented hydropower projects; c. The transmission system bottlenecks and congestion will continue and will result in increased system losses.

5. With the proposed Project: a. Nepal would be able to get at least 150 MW of year round power from India at a cost that is lower than the costs being incurred to generate diesel based power; and perhaps lower than what Nepal is now getting in short term trade with India; b. Much of the currently agreed (government-to-government) power import roughly 100 MW of power (which is not being fully delivered to Nepal due to transmission constraints) will be transferred to the proposed new line, with increased reliability and reduced losses; c. The proposed new line would give NEA the option of seeking additional power from the Indian market to meet additional demand on a short-term basis;

d. The project would bolster the confidence of the IPP developers and help them to realize their projects, which would benefit Nepal. Furthermore, the proposed Project is expected to reduce system losses; e. The project will develop capacity in Nepal to plan, build and operate cross border interconnections and internal transmission links at higher voltage levels and on a commercial basis.

Cost Benefit Analysis 6. The proposed project’s economic viability was assessed using standard cost-benefit analysis approaches. The analysis is applied in two parts – (a) the benefits to the Nepal consumers of the imported power from India; and (b) benefits to India from hydro exports from Nepal.

Cost Benefit Analysis of the Transmission Links 7. Power Flow on the proposed links. The Project will enable three types of electricity flows: (i) 100 MW of committed import from PTC India on the basis of a PPA22; (ii) 150 MW of seasonal power trade (50 MW from spot markets and 100 MW based on existing intergovernmental agreements); and (iii) about 792 MW of electricity export by IPPs. The characteristic and time of trade during dry (6 months) and wet (6 months) season is shown in Table 9.4 below. In respect of the export oriented IPPs, which are all run-of-the-river type, the distribution of dry season and wet season capacity and energy is based on the detailed technical analysis carried out for one of the large IPPs in an advanced state of preparation. As can be seen from the table in the initial years there would be net import of electricity while after the commissioning of the export oriented IPP projects, there would be net export.

Table 9.4: Power Flows in DM line (MW)

Wet Season Power Flow (MW) Dry Season Power Flow (MW) Net Net Committed Seasonal Export Committed Seasonal IPP Export Year Import Export IPP Export Flow Import Import Export Flow 2014 100 0 0 -100 100 150 0 -250 2015 100 0 0 -100 100 150 0 -250 2016 100 150 0 50 100 150 0 -250 2017 100 150 792 842 100 150 150 --100 2018 100 150 792 842 100 150 150 -100 2019- 2048 100 150 792 842 100 150 150 -100

8. The energy flows have been calculated at a load factor of 49 percent. 100 MW would thus correspond to an energy flow of 429.2 GWh. The use of H-D-D line would be basically to transfer electricity throughout the country and to increase reliability. Through this line 100 MW of committed import and 150 MW of seasonal import/export would be fully absorbed in Nepal system.

22 It should be noted here that PSA is based on 150MW of electricity at 85% availability factor delivered in India, after considering the transmission losses in India the effective capacity available in Nepal would be about 100 MW. 98

9. Costs. Financial costs of the Project have been estimated including physical contingencies, price contingencies to the base costs, and taxes, duties, and interest during construction. The project base costs are estimated in December 2010 prices. Economic costs have been arrived at by removing from the financial cost estimates price contingencies, taxes and duties as well as IDC. Only the base costs and physical contingencies are included. The local currency component of the project costs has been adjusted by the standard conversion factor of 0.85 to adjust for the price distortions of the items like unskilled labor, and skilled labor.

10. Benefits. The quantifiable benefits from the project are (i) reduction in load shedding in Nepal; (ii) reduction in the transmission losses based on the use of higher voltage levels in Nepal. In addition, India will be able to meet its peak demand at a lower cost and the import of hydropower from Nepal would reduce CO2 emissions in India.

Valuation of Benefits

11. Valuation of benefits has been done based on the following:  Reduction in load shedding to the extent of 250 MW would be rendered possible by the project. The additional energy thus available to the Nepal is economically valued at the alternative generation costs namely costs based on using diesel oil fueled generators estimated by NEA at US cents 28/kWh minus the cost of imported electricity (and associated transmission costs) estimated at US cents 9.58/kWh (based on PPA including wheeling charges). Load shedding benefit is estimated assuming that 250 MW of imported electricity during the dry season would be able to reduce 6 hours of load shedding through the use of HD line from 2014-2018 and 4 hours from 2019 to 2023 and 2024-2028 2 hours and thereafter it will reduce by 1 hour. This assumption is based on the fact that NEA would have gradually increased its generation capacity over the years.  The use of higher voltages of transmission is expected to lead to a reduction of transmission losses by 2 percent. The electricity thus gained is conservatively estimated at the border price of electricity in Nepal estimated at US cents 7.58/kWh.  The benefits derived by India is terms of reduction in costs in meeting peak demand is calculated by the imports during the peak period by the difference between the average peak power cost in India in 2009 at US cents 12.73/kWh (CERC estimates) and the estimated levelized cost of supply by large Nepalese IPPs estimated at US cents 8.33/kWh.

 For calculating CO2 emission reduction benefits to India an emission factor of 1MW=0.82 ton of CO2 has been used. The reduced emission had been valued at the internationally traded price of $10/ton of carbon dioxide.

Other Assumptions

12. Other assumptions are: 1) The opportunity cost of capital is considered as 12%. 2) Average system load factor of NEA is assumed to be 50% 99

3) O&M has been assumed to be 1.5% of the investment costs - it refers to salaries, spare parts, etc. 4) Useful life of the project has been considered as 35 years 5) All costs and benefits are priced at 2010 prices and no increase is assumed, either in benefits or costs, over the period of analysis. 6) In order to convert the Indian rupees (INR) and Nepalese rupees (NPR) to equivalent US dollars (USD) the exchange rate of 1 USD = 45 INR = 72 NPR have been use.

Economic Rate of Return 13. The base case economic internal rate of return (EIRR) calculation takes into account: in Nepal load shedding reduction benefit, and transmission loss reduction benefit; and in India benefits of peak power cost savings and CO2 emission reductions. The resulting EIRR and NPV are summarized below (Table 9.5).

Table 9.5: The EIRR and NPV for the Project Case Net Benefits to Net Benefits to Total Net Benefits Nepal India EIRR (%) 21.22 26.17 39.76 NPV @ 12% (US$ million) 79.6 317 547.5

Sensitivity analysis

14. Sensitivity analysis has been carried out for cost overrun and delays in project revenues. The results are summarized below in Table 9.6. The EIRR remains healthy in these scenarios indicating clearly the robustness of the economic viability of the projects and benefits to both countries. Table 9.6: Sensitivity Analysis Cost Increase by EIRR NPV 25% 34.26% 509.8 50% 30.20% 472.1 100% 24.49% 396.6 Delays by 1 year 32.86% 471.0 2 year 28.27% 402.8 3 years 24.95% 341.9

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Annex 10: Governance Framework NEPAL-INDIA ELECTRICITY TRANSMISSION AND TRADE PROJECT

1. The governance framework for the proposed Project was evaluated in keeping with the nature of the proposed investments and the anticipated implementation challenges. The assessment of implementation challenges drew on: (i) close consultations with NEA staff (particularly in the senior management, transmission, financial management and safeguards functional units); (ii) the environmental and social impact assessments that were carried out for the proposed Project; and (iii) the experience of the ongoing Power Development Project (PDP), including the Governance and Accountability Action Plan (GAAP) that was agreed with NEA in the context of the Additional Financing of the PDP (PDP-AF) and is presently under implementation.

2. In keeping with the wide range of investments funded under the PDP, in the course of assessing the governance framework for the PDP-AF an extensive review was carried out at NEA of: organizational governance structures; financial management; procurement; monitoring and evaluation; aspects of transparency, disclosure and communications; social oversight and participation and grievance redress mechanisms.23

3. Progress in the implementation of the GAAP that is being implemented under the PDP- AF – and more generally, in addressing the core issues reflected in the GAAP – is mixed. There has been recent progress at NEA 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 proposed Project and the proposed Kabeli Transmission 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 has also participated in a two-week training course in Bank-funded procurement.

4. NEA is in the process of engaging an Owners’ Engineer which will be an international firm of transmission project design and construction capability. The scope of services of this consultant will include the proposed Project, and on-the-job training in project management for NEA staff. Technical assistance that will be provided under the proposed project will be directed at building capacity in NEA’s transmission business unit. These efforts will be enhanced by a proposed twinning arrangement with Statnett, Norway’s grid company that was recently signed by Government of Nepal and Government of Norway. The ADB is also playing role in supporting power sector development through provision of investment finance and technical assistance.

5. The experience to date of the implementation of the Power Development Project has brought to light the considerable challenges that NEA faces on the corporate level (including financial management, planning, decision-making processes particularly for contractual matters, and so on) as well as on the level of project planning and implementation. At the same time, it is equally clear that, despite these challenging conditions, the utility has retained some pockets of

23 PDP-AF Project Paper, Report No. 48516-NP 101

technical excellence, including its Grid Development and system planning and operations units, with which the Bank team has engaged intensely in the course of preparing the proposed Project and the proposed Kabeli Transmission Project. Some of the challenges that NEA faces are not entirely within the authority of the utility to address, while others are. In both cases, a sharper focus is called for by Government and by the NEA Board and senior management to address the company’s weak areas and to help position the utility for the considerable growth of the Integrated Nepal Power System that is being supported by IDA, the ADB, Norway and other donors.

6. In the course of preparing the PDP-AF, in mid-2009, NEA prepared an Action Plan for Financial Management Improvement. The target dates for most of the activities in this Action Plan have slipped and in December 2010, NEA proposed revised target dates for the outstanding activities. While the risk of continued slippage exists, the recent engagement of a well-known international consulting firm to help build NEA’s capacity for financial management offers the prospect of improvement in this area. The consultant will help NEA to: (i) introduce reform in the accounting framework of NEA, (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 for Finance and Accounts staff, and (viii) introduce computerization of financial management systems in NEA. The success of this important endeavor will depend on how seriously NEA treats this contract which is to be implemented over 2011-12.

7. On the level of project management, there is scope for improved contract management, social and environmental management and monitoring, communications (with project-affected communities as well as with the public at large) and disclosure.

8. 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.

9. 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 Owners’ 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.

10. Communications, consultations and disclosure. The proposed Project is of national significance. The transmission line will be constructed in the Terai, the densely populated lower portion of the country, and will pass many population points of varying sizes. Given the sensitivities often associated with cross-border issues and large-scale construction works in general, it will be important for NEA to communicate proactively on the project, both locally, in the project area, and on the national level.

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11. NEA will post project-related information on its Website (including the EIA/EMP; SIA/RAP; procurement plan; procurement complaints mechanism; implementation progress reports (approved versions); Invitations for Expressions of Interest, Procurement Notices; Contract Awards; and Annual Audited Financial Statements.) Disclosure walls/boards at work sites carrying details of budgets, timelines, contact details etc will be set up. NEA will post a Public Relations officer who will be based in the field and oversee information-sharing activities with key stakeholders. NEA will also create a sub-Project Information Centers at the substation locations which will house all relevant project documents and will carry out ongoing communications and disclosure measures as detailed in the GAAP.

12. Environmental monitoring. Recent project implementation experience has demonstrated the need for improved monitoring of the environmental management plans that are approved for investment projects. For the proposed Project, environmental monitoring will be carried out by the project’s Environmental Monitoring Cell (EMC), which will be staffed by consultants hired from the local consulting firms with experinece in similar monitoring works. The EMC will be responsible for the monitoring works as stipulated in the EMP, which provides an adequate for environmental monitoring. In addition, joint teams consisting of representatives of the District Forest Offices, District Development Committees, Village Development Committees and the Community Forest User Groups will monitor the project works on regular basis.

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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 Kabeli Transmission Project. It is expected that the totality of these measures will contribute to improved governance in the implementation of the proposed Project.

Issue Proposed Mitigation Milestones Indicative Measures Timeline Project NEA would have overall 1. Establishment of IMCC Achieved Management responsibility for project 2. Establishment of PSC Achieved management. An Inter- Ministerial Coordination Committee would provide the overall policy guidance, inter- agency coordination and monitoring. NEA has established a Project Steering Committee (PSC) headed by the General Manager Grid Development. The Project Management Office (PMO) would take day-to-day guidance from the PSC. The PMO would also be supported by Owners’ Engineer. Owners’ Engineer will help 3. Request Expressions of EoI already with the design, bidding Interest issued process, supervise 4. Issue RFP construction, implementation 5. Award Contract Procurement to of safeguards management begin May/June frameworks and project 2011 financial management. A Procurement Advisor will Progress on procurement of Procurement be recruited to help manage key packages Advisor already the procurement activities in in place. all the activities of NEA. Transmission Preparation of a Transmission 1. Request Expressions of See Procurement Planning System Master Plan including Interest Plan training of TSO staff 2. Issue RFP 3. Award Contract Communications Design and implement a Draft Communications communications strategy Strategy Prepared jointly by aimed at creating an enabling NEA and the Bank environment for the Project and at conveying the benefits of the project as they apply to all stakeholder groups. The strategy will include: (a) ongoing consultations with all stakeholder groups to

104

Issue Proposed Mitigation Milestones Indicative Measures Timeline understand their concerns; (b) targeted communication initiatives to address these concerns; (c) providing easy access to information about project; (d) effective grievance redress mechanisms. Posting of a Public Relations 1. Preparation of TOR Officer at site 2. Recruitment process 3. Post officer at site Establish Project Information (Dependent on posting of Center at Regional Office Public Relations Officer) Ongoing disclosure through: Ongoing  PIC at Regional Office  All relevant documents to be posted on NEA website  Disclosure walls at village-level 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. Monitoring of NEA to initiate organization of Safeguards Instruments Environmental joint teams consisting of (IEE, EMP, RAP, SIMF, Management representatives of the District VPDP, VPDF) Disclosed Plan Forest Offices, District Development Committees, Implementation plans being Village Development finalized Committees and the Community Forest User Groups will monitor the project works on regular basismonitoring of EMP and at Mid-term Review. Lenders’ Engineer to carry out 1. Preparation of TOR Procurement to environmental monitoring. 2. Launch of RFP begin May/June 3. Award contract 2011 4. Contract implementation

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IBRD 38300R 80° 82° 84° 86° 88°

NEPAL-INDIA ELECTRICITY TRANSMISSION 04080120 160 KILOMETERS AND TRADE PROJECT 0 20 40 60 80 100 MILES UNDER CHINA PROPOSED CONSTRUCTION PROJECT EXISTING Humla Karnali 30° HYDRO POWER STATIONS 30°

DIESEL/MULTIFUEL POWER STATIONS DHAULIG GRID SUB-STATIONS PITHORAGARH CHAMELIA 400 kV TRANSMISSION LINES* 220 kV TRANSMISSION LINES* Mugu Karnali 132 kV TRANSMISSION LINES BAITADI FAR 66 kV TRANSMISSION LINES

DADHELDHURA WEST SETI KARNALI 33 kV TRANSMISSION LINES DOTI WESTERN RIVERS MAHAKALI MID BUDAR SETI REGION BOUNDARIES MAHENDRANAGAR UPPER Mahakali KARNALI ZONE BOUNDARIES GADDACHAUKI INTERNATIONAL BOUNDARIES CHANDANI WESTERN ATTARIA Note: Slashes indicate the number of LAMKI parallel transmission lines of the same CHISAPANI DHANGADHI Bheri BHERI Marsyangdi capacity.

Kali TIKAPUR Budhi Gandaki DHAWALAGIRIRAHUGHAT Gandaki Babai SURKHET TATOPANI U. MODI GANDAKI GULARIYA RAPTI U. MARSYANGDI BAGLUNG SETI MODI MADI-SHANESWOR POKHARA TULSIPUR PHEWA UDIPUR LANGTANG

KOHALPUR UP-SETI (STO) Trisuli DARAMKHOLA CHILIME WESTERN M. MARSYANGDI BAGMATI NEPALGUNJ GHORAHI JHIMRUK DAMAULI Mt. Everest 28° SYANGJA 28° KALI- DUMRE TRISULI BHOTEKOSHI GANDAKI ANDHIKHOLA (STO) DEVIGHAT LAMAHI TAMGHAS MARSYANGDI DHADING INDRAWATI UP-TAMAKOSHI TANSEN GAJURI KALI-GANDAKI 2 BUDHI GANDAKI KATHMANDU LAMOSANGHU LUMBINI MUDHE U. ARUN Narayani BHARATPUR MECHI SHIVAPUR BUTWAL SUNKOSHI KAWASOTI KI-II KHIMTI-II AMUWA BARDGHAT KI-III Tama Koshi PANAUTI Arun KRISHNA-NAGARKRISHNA-NAGAR LUMBINI GNAGAOLIGNAGAOLI RAMNAGAR PARSA KI-I ARUN 3 TAULIHAWATAULIHAWA PARASI CENTRAL KHIMTI BHAIRAHAWABHAIRAHAWA HETAUDA KOSHI Rapti CHANAULI EASTERN GANDAK LIKHU KABELI ‘A’ AMLEKHGUNJ PATHLAIYA MANTHALI L. ARUN LUCKNOW (PG) SIMRA THULO DHUNGA PILUWAKHOLA NARAYANI SINDHULI INDIA NEPAL PARWANIPUR NIJGADH DUDHKOSHI BASANTAPUR TAMOR PARWANIPUR JANAKPUR POKHARIA BIRGANJ HARSA DHANKUTA HAM HARIPUR DHALKEBARDHALKEBAR CHATARA KALAIYA Koshi PUWA MALANGAWA JALJALE Sun KHOLA Gandak KATARI SAGARMATHA DHARAN Ghaghara INDIA GAUR KANKAI ITAHARI DAMAK GORAKHPUR (PG) JANAKPUR Sapta Koshi BHITTAMODBHITTAMOD LAHAN DUHABI ANARMANIANARMANI BISHNUPURBISHNUPUR RUPANI DUHABI SURSANDSURSAND RAJBIRAJ KUSAHA BULUCHOWK JALESWOR MULTIFUEL Bagmati BHARDAHABHARDAHA BIRATNAGAR BHADRAPURBHADRAPUR Rapti Kamala This map was produced by the Map Design Unit of The World Bank.

The boundaries, colors, denominations and any other information shown on this map do not imply, on the part of The World Bank Group, MUZAFFARPUR any judgment on the legal status of any territory, or any endorsement Mechi or acceptance of such boundaries. BANGLADESH 80° 82° 84° 86° PURNEA 88° 26° JUNE 2011

r IBRD 38301R B

30° 25°

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Aizawl

MYANMAR

Shillong PLANNED SUBSTATIONS PLANNED INTERCONNECTIONS CAPITALS NATIONAL BOUNDARIES INTERNATIONAL

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85° 85° i d MUZAFFARPUR a n a h ti a p M

Sambalpur Pokhara Ra NORTHEAST REGIONAL ELECTRICITY NORTHEAST

NEPAL TRANSMISSION AND TRADE PROGRAM

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Allahabad

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denominations and any

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80° on this map do not imply, on the part of The World Bank Group, on the part of The World on this map do not imply,

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Kanpur any judgment on the legal shown This map was produced by the Map Design Unit of The World Bank. This map was produced by the Map Design Unit of The World The boundaries, colors, or acceptance of such boundaries. BAREILLY

30° 25°

JUNE 2011