Completion Report

Project Number: 29471-013 Loan Number: 1732 December 2011

Nepal: Rural Electrification, Distribution, and Transmission Project

CURRENCY EQUIVALENTS

Currency Unit – Nepalese rupee/s (NRe/NRs)

At Appraisal At Project Completion 1 November 2003 30 December 2008

NRs1.00 = $0.0146 $0.0143 $1.00 = NRs68.70 NRs70.00

ABBREVIATIONS

ADB – Asian Development Bank DPC – district profit center EIRR – economic internal rate of return FIRR

IEE – –

financial internal rate of return initial environmental examination

NEA – Nepal Electricity Authority NFA – net fixed assets OFID – OPEC Fund for International Development SFR – self-financing ratio T&D – transmission and distribution WACC – weighted average cost of capital

WEIGHTS AND MEASURES kWh – kilowatt-hour (1,000 watt-hours) GWh – gigawatt-hour (1,000 megawatt-hours) kV – kilovolt (1,000 volts) kVA – kilovolt-ampere km – kilometer MVA – megavolt-ampere MW – megawatt (1,000 kilowatts)

NOTES

(i) The fiscal year (FY) of the government and the Nepal Electricity Authority ends on 15 July. FY before a calendar year denotes the year in which the fiscal year ends, e.g., FY2008 ends on 15 July 2008.

(ii) In this report, "$" refers to US dollars.

Vice-President X. Zhao, Operations 1 Director General S. Hafeez Rahman, South Asia Department (SARD) Director Y. Zhai, Director, South Asia Energy Division Team leader Team member

S. Janardanam, Finance Specialist (Energy), SARD C. Roque, Project Officer, SARD

In preparing any country program or strategy, financing any project, or by making any designation of or reference to a particular territory or geographic area in this document, the Asian Development Bank does not intend to make any judgments as to the legal or other status of any territory or area.

CONTENTS

Page BASIC DATA i

I. PROJECT DESCRIPTION 1 II. EVALUATION OF DESIGN AND IMPLEMENTATION 2

A. Relevance of Design and Formulation 2 B. Project Outputs 3 C. Project Costs 7 D. Disbursements 7 E. Project Schedule 7 F. Implementation Arrangements 8 G. Conditions and Covenants 8 H. Consultant Recruitment and Procurement 9 I. Performance of Consultants, Contractors, and Suppliers 10 J. Performance of the Borrower and the Executing Agency 10 K. Performance of the Asian Development Bank 10

III. EVALUATION OF PERFORMANCE 11 A. Relevance 11 B. Effectiveness in Achieving Outcome 11 C. Efficiency in Achieving Outcome and Outputs 11 D. Preliminary Assessment of Sustainability 12 E. Impact 12 F. Social Assessment 13

IV. OVERALL ASSESSMENT AND RECOMMENDATIONS 13 A. Overall Assessment 13 B. Lessons 13 C. Recommendations 14

APPENDIXES 1. Project Framework 15 2. Cost Breakdown by Project Components 17 3. Project Financing Plan 18 4. Projected and Actual Disbursements of Loan Proceeds 19 5. Implementation Schedule 20 6. Status of Compliance with Major Loan Covenants 21 7. Financial and Economic Evaluation 23

BASIC DATA

A. Loan Identification 1. Country Nepal 2. Loan Number ADB 1732-NEP(SF) OFID 825 P 3. Project Title Rural Electrification, Distribution, and

Transmission Project 4. Borrower Government of Nepal 5. Executing Agency Nepal Electricity Authority 6. Amount of Loan ADB SDR36,213,000 OFID $10 million 7. Project Completion Report Number 1290 B. Loan Data 1. Appraisal – Date Started 12 September 1999

– Date Completed 17 September 1999 2. Loan Negotiations

– Date Started 10 November 1999 – Date Completed 12 November 1999

3. Date of Board Approval 21 December 1999 4. Date of Loan Agreement 13 July 2000 5. Date of Loan Effectiveness – In Loan Agreement 12 October 2000 – Actual 14 March 2002 – Number of Extensions 2 6. Closing Date – In Loan Agreement 30 June 2005 – First Revision 30 June 2007 – Second Revision 31 December 2008 – Actual 19 December 2008 – Number of Extensions 2 Asian Development Bank Loan 7. Terms of Loan – Interest Rate 1.0% during grace period, 1.5% thereafter – Maturity (number of years) 32 years – Grace Period (number of years) 8 years 8. Terms of Relending – Interest Rates 8% for rural electrification and off-grid

distribution, 12% for all other components – Maturity (number of years) 25 years

– Grace Period (number of years) 8 years – Second-Step Borrower Nepal Electricity Authority

ii

OPEC Fund for International Development Loan

9. Terms of Loan – Interest Rate 1.0% – Maturity (number of years) 12 years – Grace Period (number of years) 5 years 10. Terms of Relending – Interest Rate 12% (Part D)

– Maturity (number of years) 25 years – Grace Period (number of years) 5 years – Second-Step Borrower Nepal Electricity Authority ADB = Asian Development Bank, OFID = OPEC Fund for International Development, SDR = special drawing right. 11. Disbursements a. Dates

Initial Disbursement 9 September 2003

Effective Date 14 March 2002

Final Disbursement 19 December 2008

Original Closing Date

30 June 2005

Time Interval

63 months

Time Interval 40 months

b. Amount (SDR’000)

Original Partial Last Revised Amount Undisbursed Allocation Cancellation Allocation Disbursed Balance

01A Equipment & materials for parts A,B, & C 20,884 (3,146) 17,794 17,565 229

01B Supplies for part E 695 (46) 2,282 1,737 545

01C Turnkey contracts for parts A & C 4,406 (395) 3,811 3,677 134

01D Turnkey contracts for part D 2,149 155 2,304 1,610 694

01E Subloans for Part B 724 (724) 0 0 0

02 Consulting Services 1,021 (223) 798 630 168

03 Interest Charge 724 0 724 318 406

04 Unallocated 5,610 (4,121) 0 0 0Total (SDR'000) 36,213 (8,500) 27,713 25,537 2,176 a

Total ($'000) 50,000 (12,125) 37,875 38,164 3,338

Category

a The undisbursed balance was cancelled at loan closing on 19 December 2008. C. Project Data 1. Project Cost ($’000)

Cost Actuala Foreign Exchange Cost Local Currency Cost

44.23 12.86

Total 57.09 a Foreign costs include the OPEC Fund for International Development loan of $6.07 million.

iii

2. Financing Plan ($ million) Cost Appraisal Estimate Actual Implementation Costs Borrower Financed 35.5 12.8 ADB Financed 37.5 37.7 Other External Financing 10.0 6.1 Total 82.0 56.6 IDC Costs Borrower Financed 0.0 0.0 ADB Financed 12.5 0.5 Other External Financing 0.0 0.0 Total 94.5 57.1 ADB = Asian Development Bank, IDC = interest during construction.

3. Cost Breakdown by Project Component ($ million) Appraisal Estimate Actual Project Costs Foreign Local Total Foreign Local Total Rural electrification 18.40 6.20 24.60 31.79 7.38 39.17 Distribution for isolated power projects

2.00 0.80 2.80 0.00 0.00 0.00

Distribution system reinforcement

15.50 3.40 18.90

Transmission development

11.30 6.20 17.50 8.55 4.61 13.15

Computerized billing systems

1.20 0.30 1.50 3.04 0.35 3.39

Other institutional strengthening

0.80 0.40 1.20 0.38 0.52 0.90

Taxes and duties 0.00 2.40 2.40 0.00 0.00 0.00 Subtotal Base Cost 49.30 19.70 69.00 42.76 12.86 56.61 Contingencies 1. Physical 4.90 2.00 6.90 0.00 0.00 0.00 2. Price 4.40 1.70 6.10 0.00 0.00 0.00 Subtotal 9.30 3.70 13.00 0.00 0.00 0.00 Interest During Construction

1.40 11.10 12.50 0.48 0.00 0.48

Total 60.00 34.50 94.50 44.23 12.86 57.09 a In actual costs, parts A and C are combined. 4. Project Schedule Item Appraisal

Estimate Actual

Date of Contract with Consultants Part D Part E Part F Completion of Engineering Designs Civil Works Contracts

Feb 2000 Sep 2000 Sept 2000 May 2001

Feb 2004 May 2003 June 2004

Nov 2003

Date of Award Dec 2000 Sept 2003

iv Completion of Work Dec 2003 June 2011 Equipment and Supplies Dates First Procurement Dec 2000 Feb 2004 Last Procurement Jan 2001 Aug 2006 Completion of tests and commissioning Dec 2003 June 2011

5. Project Performance Report Ratings

Ratings Implementation Period

Development Objectives

Implementation Progress

From 31 Mar 2002 to 31 Dec 2002 From 1 Jan 2003 to 31 Dec 2003 From 1 Jan 2004 to 31 Aug 2004 From 1 Sep 2004 to 31 Dec 2004 From 1 Jan 2005 to 31 Dec 2005

PS PS PS S S

S S S S S

From 1 Jan 2006 to 30 Apr 2006 S S From 1 May 2006 to 31 Dec 2006 PS S From 1 Jan 2007 to 31 Dec 2007 PS S From 1 Jan 2008 to 31 Dec 2008 PS S PS = partly satisfactory, S = satisfactory.

D. Data on Asian Development Bank Missions

Name of Mission

Date

No. of Persons

No. of Person-

Days

Specialization of Members

Project review 1 Project review 2

13–24 Nov 2000 30 Aug–4 Sept 2001

1 1

12 5

b b

Project review 3 24–28 Feb 2002 1 5 b Project review 4 19–21 June 2002 1 3 b Project review 5 (midterm) Project review 6

8–16 Apr 2003 1–9 Dec 2003

3 1

24 9

b, c, e b

Project review 7 Project review 8 Project review 9

3–9 March 2004 6 Aug–2 Sep 2004 9–15 March 2005

1 1 2

7 8

14

b b b

Project review 10 6–9 Sept 2005 3 12 b, c, e Project review 11 18–19 Jan 2006 1 2 b Project review 12 24–30 May 2006 2 14 b, f Project review 13 20–24 Nov 2006 3 15 c, e Project review 14 27–30 Mar 2007 2 8 e Project review 15 30 Jul–6 Aug 2008 1 8 b Project review 16 Project completion

20–26 Nov 2008 1–6 Sep 2011

1 2

7 12

b c, e

a = project specialist, b = energy specialist, c = financial specialist, d = project engineer, e = project analyst, f = consultant.

I. PROJECT DESCRIPTION

1. Years of underinvestment in electricity generation and its transmission and distribution (T&D) in Nepal left chronic shortages and network bottlenecks, prompting the government to initiate a comprehensive plan to improve sector efficiency, service quality, and governance. The government adopted its hydropower development policy to develop Nepal’s large hydropower potential and export energy to generate revenues. Its Ninth Five-Year Plan, 1997–2002 aimed to reduce economic and social inequality and expand electricity supply. 2. At appraisal in 1999, Nepal’s per capita electricity consumption of 48 kilowatt-hours per year was the second lowest in the region. The Nepal Electricity Authority (NEA), the vertically integrated power utility, produced only 314 megawatts (MW) against peak demand of 326 MW, with annual energy sales amounting to 1,053 gigawatt-hours (GWh). Only 14.6% of the population had access to electricity, mostly in towns and cities. T&D losses were estimated at 24.5% in 1999, caused by lack of investment and technical and commercial losses. Thus, power shortages, poor quality of supply, and frequent load shedding across the country undermined industrial competitiveness and agricultural potential. Demand growth was estimated at 8.5% per annum in 1999. Peak demand for electricity was estimated to be 3,679 MW by fiscal year 2027–2028 (FY2028),1 requiring that power generation and T&D facilities be augmented. 3. On 21 December 1999, the Asian Development Bank (ADB) approved the $50 million Rural Electrification, Distribution, and Transmission Project to expand rural electrification, reinforce distribution systems in existing service areas, expand transmission in the Kathmandu Valley, and connect with the grid in India. The project, covering the eastern, central, and western development regions of the country, was designed to promote economic growth and improve standards of living in rural areas by improving access to electricity and supporting the implementation of Nepal’s Agricultural Perspective Plan. The project aimed to develop the NEA’s T&D system, evacuate power from existing and upcoming hydropower plants, extend the NEA distribution system to more rural communities, accommodate increased loads and new consumers in existing service areas, reduce losses and improve the efficiency of NEA's operations, and develop a transmission system in the Kathmandu Valley. It further aimed to improve the NEA’s operational efficiency, shift it toward more commercial orientation, and lease some district distribution operations to independent operators. Agreement was reached to improve the NEA’s financial performance, including introducing a semiautomatic process for more frequent tariff revisions.2 4. The project loan3 was to assist the Government of Nepal and the NEA in improving the quantity and quality of power supply, meeting peak demand and reducing system losses. It included six components: (i) part A: expansion of NEA’s interconnected grid for rural electrification in the eastern, central and western regions; (ii) part B: electricity distribution system extensions for isolated power projects not connected to the integrated grid; (iii) part C: 1 Nepal Electricity Authority. 2010. A Year in Review—Fiscal Year 2009/10. Kathmandu. 2 The absence of tariff increases since 2001, coupled with poor power supply, prompted the government to

investigate in FY2005 the financial restructuring of the NEA to reduce its operating and financial costs. In 2010, a financial restructuring plan for the NEA was submitted for approval and included (i) a tariff increase, (ii) a write-off of accumulated receivables, (iii) capitalization of 50% for certain projects, and (iv) a reduction of the interest rate at which NEA reborrows from 8% to 5%.

3 ADB has implemented three technical assistance (TA) projects to prepare the feasibility studies relevant for the project. The power system Master Plan for Nepal (TA 2614-NEP), completed in August 1998, included preparing a transmission system master plan. The Rural Electrification and Distribution Improvement Project (TA 2911-NEP), completed in March 1999, prepared the detailed plan for those project components. And the transmission plan for the Kathmandu Valley was prepared under TA 3193-NEP completed in October 1999.

2

reinforcement of the NEA’s distribution system in existing service areas at 33 kilovolts (kV) and lower voltage levels in the eastern, central and western regions; (iv) part D: transmission system development in the Kathmandu Valley and a new transmission interconnection to India; (v) part E: nationwide implementation of computerized billing systems for the NEA; and (vi) part F: other institutional strengthening for the NEA, including assistance with revaluating fixed assets and formulating the detailed design of a plan to establish district profit centers (DPCs). The foreign costs of the project were funded by project loans from ADB and the OPEC Fund for International Development (OFID),4 and local costs were funded from the resources of the government and the NEA. During implementation, additional works to reinforce grid substations were included in part D under ADB and OFID funding, to use budget originally provided for part B, which was cancelled in March 2005 as no suitable subprojects for part B could be identified.

II. EVALUATION OF DESIGN AND IMPLEMENTATION

A. Relevance of Design and Formulation

5. The project was highly relevant to government sector strategies at both appraisal and completion. It was consistent with government policies to expand and diversify Nepal’s power system to provide power to more residents in both urban and rural areas, supply the affordable electricity required for economic growth, and improve standards of living and economic development in rural areas. The government’s hydropower development policy adopted in 1992 aimed to (i) promote private sector participation, (ii) expand T&D systems, (iii) improve the quality and reliability of power supply and reduce system losses, (iv) develop hydropower and district-level projects, and (v) rationalize tariffs. The Ninth Five-Year Plan, 1997–2002 prioritized rural electrification to improve equality in electricity distribution. A long-term goal of the government is to reorient the power sector from domestic supply to significant exports. The project was consistent with ADB’s strategy for NepaI’s energy sector, which at appraisal was to support the policy of improving governance and efficiency, expanding rural electrification to enhance the outcomes of rural development projects, and promoting a more commercial approach to power supply and increased participation by the private sector. Moreover, improving the performance and governance of the NEA has been an underlying objective of ADB operations in the sector. 6. The project was realistically and comprehensively designed to address key development needs in Nepal’s power sector. It was conceived at a time when, owing to stagnant and insufficient tariffs, NEA’s financial position was deteriorating quickly and prolonged underinvestment rendered the NEA unable to meet rising demand for power or stem declining power supply quality and reliability. The project was formulated in close coordination with, and with support from, the NEA, the government, and the then Ministry of Water Resources, covering part of an investment plan to be implemented over 5 years. It was highly relevant as it focused on (i) expanding T&D systems to accommodate increased generating capacity, (ii) expanding the availability of power in urban and rural areas, (iii) reducing NEA T&D losses, and (iv) improving sector efficiency. The project incorporated several covenants designed to strengthen the long-term sustainability of the sector in general and of the NEA in particular such as (i) strengthening the financial performance and self-financing of the NEA through improved tariffs and procedures; (ii) improving accounting, auditing, and the recording of fixed assets; (iii) helping establish DPCs and performance incentives; (iv) establishing computerized billing systems; (v) designing and implementing an action plan to reduce nontechnical losses; and (vi) enacting the Electricity Theft Control Act. These considerations remained equally relevant at

4 OFID’s funding was an untied loan administered by ADB.

3

project completion. ADB has encouraged the government to (i) improve governance and private sector participation, (ii) achieve improved efficiency and sustainability through commercialization, and (iii) electrify poor rural areas. By strengthening and expanding T&D systems, the project loan helped increase the national electrification ratio from 14.6% in 1999 to 42% in 2008 and 56% in 2011.

B. Project Outputs

7. The project loan (i) expanded electricity supply coverage in rural areas of the eastern, central, and western regions, (ii) strengthened the T&D system by constructing transmission lines and constructing and upgrading substations, (iii) improved efficiency by computerizing the billing and collection systems in half of the collection centers nationwide, (iv) institutionally strengthened the NEA by revaluating and physically verifying its fixed assets, and (v) developed a performance-based management system for DPCs. It also helped the NEA achieve institutional and financial reforms. 8. Appendix 1 compares project performance with the project framework in the report and recommendation of the President. The project largely succeeded in (i) improving service coverage, particularly in poor rural areas; (ii) contributing to an improved transmission network; (iii) improving the capacity of distribution systems, including in the Kathmandu Valley; and (iv) improving management efficiency and revenue collection. 9. After the ADB loan account closed in 2008, the NEA completed the remaining works using its own resources. By the end of FY2011, when all the remaining works were completed, an estimated 119,000 new consumers had been connected to the grid. Of 22 substations constructed or upgraded under the project, 4 have been further upgraded in response to high demand and 12 are running at full capacity. The remaining 6 substations are currently running at 70% of their installed capacity. 10. The original scope of part A: rural electrification was to expand the NEA’s rural grid in the eastern, central, and western regions. This consisted of (i) newly supplying rural areas in 22 districts with 13 rural electrification schemes in the plains and 9 in hill districts and (ii) constructing new 33 kV lines and substations. The rural electrification component served 240 village development committees; connected 154,000 rural households, or 860,000 residents of poor rural areas; and constructed 9 new 33/11 kV area substations, 694 11 kV/low voltage distribution transformers, 1,150 kilometers (km) of 11 kV lines, 117 km of 33 kV lines, and 1,314 km of low-voltage lines. The component was expected to increase the number of NEA customers by 22% and improve the electrification ratio from 14.6% to about 18.0%. 11. Part B extended electricity distribution systems for isolated power projects not connected to the integrated grid. In March 2005, this component was cancelled mainly for lack of suitable subprojects. The funding provided for this component was used instead to upgrade the capacity of transformers in three 132kV substations as follows: (i) One new 132/33 kV, 30 megavolt-ampere (MVA) 3-phase transformer and a control and protection panel were installed in Anarmani substation, including bay extension at 132 kV and 33 kV. Upon completion of this work, one 132/33 kV, 15 MVA 3-phase power transformer was relocated to another substation. (ii) One new 132/11 kV, 30 MVA 3-phase transformer was installed in Pokhara substation, including bay extension at 132 kV and the replacement of one section of six existing 11 kV switchgear panels. Upon completion, one 132/11 kV, 7.5 MVA 3-phase transformer was relocated to another substation. (iii) One set of new 132/66 kV, 3x12.6 MVA transformers (a

4

bank of three single-phase transformers), a control and protection panel, and 132 kV power cables were installed in Siuchatar substation, which included bay extension at 132 kV and 66 kV.

12. This subcomponent commenced on 21 June 2006 and was completed successfully and commissioned on 19 January 2008, with a delay of 8 months. The performance of the contractor was satisfactory. ADB partly administered the OFID loan.5 Special arrangements were made to use the commitment procedure for two project contracts cofinanced by OFID, in which ADB advanced payment of the OFID portion and was subsequently reimbursement by OFID. This component contributed to enhancing the quality and reliability of the sub-T&D system of Mechi zone in eastern Nepal, improved the 11kV distribution capacity of Pokhara substation, and increased the power transforming capacity of Siuchatar substation.

13. Part C comprised distribution system reinforcement at 33 kV and below in existing NEA service areas in the eastern, central, and western regions. This component was intended mainly to bring distribution systems up to a satisfactory standard to reduce losses, rehabilitate facilities, improve reliability, improve voltage control, and serve expected load growth over the next 5 years by upgrading or rehabilitating substations and distribution systems, thereby improving the efficiency of NEA operations. The component (i) built 9 new 33/11 kV area substations and upgraded 11 other area substations, (ii) built 74 km of new 33 kV lines and built or upgraded 998 km of 11 kV lines, (iii) installed a new or replaced 481 distribution transformers with a combined capacity of 63,200 kilovolt-amperes, and (v) built or replaced 545 km of low-voltage lines. The aim was to reinforce existing distribution systems for 28 schemes in 27 districts. 14. Detailed feasibility studies for the components on rural electrification and distribution system reinforcement were undertaken in 1998, and bids were invited in 2001. However, as loan covenants could not be complied with within the stipulated time, these two components could not be started until 2004. The NEA was compelled to carry out several activities in the interim, including increasing substation capacity as electricity loads had risen substantially in the selected areas. Thus, in March 2005, parts A and C were combined, and the scope for the rural electrification and distribution system reinforcement components revised to 24 schemes in 22 districts, 277 village development councils, 123,400 household connections, 8 new 33/11 kV area substations, 543 11/0.4 kV distribution transformers, and 2,522 km of lines comprising 107 km of 33 kV lines, 495 km of 11 kV lines, 495 km of composite lines, and 1,425 km of low-voltage lines. All these components were completed, and 119,000 new connections made. 15. The construction of new rural electrification and distribution system reinforcement substations has helped expand electricity supply to targeted households, as well as strengthen and enhance NEA’s distribution system in urban and rural areas. This contributed to system reliability and loss reduction. The components were highly successful in meeting demand growth in targeted areas. Of 22 substations constructed or upgraded under the project, 4 have already been further upgraded to meet high demand and 12 are running at full load. The remaining 6 substations are currently running at 70% of their installed capacity. 16. Part D strengthened transmission systems in the Kathmandu Valley and constructed an interconnecting transmission line to the Indian border. At appraisal, this component comprised (i) expanding existing 132 kV substations at Bhaktapur, Patan, Balaju, and New Chabel; (ii) constructing a 26 km 132 kV transmission line from Bhaktapur to Thankot, as well as a new

5 Under partial administration, ADB was responsible for (i) reviewing withdrawal applications and advising

OFID to make the requested payments and (ii) procuring supervision services. Upon receipt of clearance, OFID directly paid recipients and/or suppliers of goods and services.

5

substation at Harisiddhi and a new switching station at Thankot; and (iii) constructing a 23 km double-circuit 132 kV transmission line from Butwal substation to the Indian border. In March 2005, the scope was revised to (i) expand the existing substation at Patan and drop the New Chabel substation as it was already constructed using NEA’s funds; (ii) construct 28.5 km of 132 kV double-circuit and 4-circuit transmission line from Mathathirta in Thankot to Bhaktapur via Harisiddhi, a new switching station at Matathirta, and a new substation at Harisiddhi; and (iii) construct a connecting transmission line from Parwanipur to Birgunj in lieu of the double circuit 132 kV transmission line from Butwal substation to the Indian border, which had to be cancelled because of the India–Nepal Power Exchange Committee’s slow progress in reaching agreement to proceed with constructing the line.

17. The transmission line was originally designed to run through rural areas but, prior to loan effectiveness, was redesigned to go through urban areas to reduce cost. The following two packages were tendered for execution: (i) the construction of the 28.5 km 132kV transmission line from Matatirtha in Thankot to Bhaktapur substation and (ii) the expansion of the existing 132 kV substation at Balaju and construction of a new substation at Harisiddhi and a new switching station at Matatirtha. The transmission line package included constructing 300 meters of loop-in loop-out on the existing Kulekhani II–Siuchatar 132kV transmission line into Matatirtha switching station; constructing the 132 kV double-circuit transmission line from Matatirtha switching station to Katunje tap-off point at Bhakatpur via the proposed Harisiddhi substation; and constructing the 132 kV four-circuit transmission line from the Katunje tap-off point to the existing 132/66 kV Bhaktapur substation, replacing the existing double-circuit 66 kV transmission line. The supply and installation of optical ground wire from Siuchatar to Bhaktapur substation was included.

18. In response to opposition from residents of Lalitpur District, the transmission line could not be completed. Similarly, land issues raised by residents of Harisiddhi prevented the construction of the Harisiddhi substation, though the equipment had been delivered. The 132/11 kV, 18/22.5 MVA transformer and associated bay equipment intended for Harisiddhi substation was installed in Matatirtha substation, and two sets of 132kV line bay equipment remain unused.

19. The contractor commenced transmission line works on 31 January 2005. However, a dispute with the NEA caused the contractor to cease works from April 2008 to December 2010, resuming them from 5 January 2011 only to construct the loop-in loop-out works at Matatirtha. The contract for the substation component was signed on 31 April 2007 and completed on 31 December 2010 with a time extension. The works completed so far are the construction of 300 meters of loop-in loop-out on the existing Kulekhani II–Siuchatar 132kV transmission Line into Matatirtha switching station, enabling the charging of Matatirtha substation; the expansion of the existing 132 kV substation at Balaju and Bhaktapur; and the construction of Matatirtha substation. Of 96 towers to be constructed, only 56 have been constructed, and conductor stringing has not begun. Although the Thankot–Chapagaon transmission line could not be completed, enhanced substation capacity in the Kathmandu Valley has improved the quality and reliability of its 11kV distribution system.

20. Part E was to implement nationwide computerized billing systems for the NEA, providing the computer hardware, software, and consulting services required to computerize 15 of the NEA’s larger distribution branch offices in Kathmandu and throughout Nepal, which accounted for more than two-thirds of its revenue. The NEA decided to expand the coverage of this component to 20 distribution centers, accomplished by rearranging old areas and creating new areas in 15 distribution centers to make revenue management, including billing and collection, more efficient. There were two phases. In the first phase, consultants were to assist in preparing a strategy for the NEA’s development of a computerized accounting and financial management

6

information system and subsequently in selecting an appropriate Oracle-based billing system. The consultant was to help the NEA procure the computerized billing software and hardware for 20 large distribution systems and implement them in four pilot branches. In the second phase, the NEA was to implement the same software in an additional 24 distribution centers and associated sub-branches, including procuring hardware and software. In addition, handheld meter-reading devices and software were to be procured and implemented on a pilot basis in 26 centers, and an interactive voice-response system was to be procured and implemented in five offices.

21. This component was delayed and unable to adhere to the implementation schedule outlined above because of political instability and security issues; the lack of trained manpower and computer literacy; the time required to perform data and system analysis in various branches and reconcile customer bill-collection data and input it from ledgers; and the delayed procurement of hardware and software caused by amendments, retendering, and clarifications. Consultants commenced work on 4 June 2004 and extended it until 27 September 2007. At appraisal, the consultant inputs were estimated at $0.29 million, which was revised to $0.23 million at midterm. Consultant inputs for procuring billing software and installation it in four pilot distribution centers were extended because of delayed project implementation. Savings were used to cover an additional 24 branches and 20 sub-branches. The system helped improve revenue collection, the quality and accuracy of bills, nontechnical losses, consumer satisfaction, and the timely collection of management information. Handheld metering devices reduced human error in meter reading. This component enhanced the NEA’s ability to implement complex information technology projects. By FY2011, the computerized billing system had been implemented in 54 branches and sub-branches of the NEA that account for 67% of its revenue. Handheld meter-reading devices have been deployed at 26 locations across Nepal.

22. Part F assisted with revaluating fixed assets and detailed planning to establish distribution DPCs.

(i) Revaluating NEA fixed assets. Consulting services were provided to strengthen the NEA's institutional capacity to revalue fixed assets using a computerized database. Assistance helped the NEA (a) establish a computerized register of fixed assets, (b) improve accounting procedures to resolve issues raised by auditors relating to the revaluation of fixed assets, (c) design an appropriate interim formula for annually revaluing fixed assets, and (d) physically verify and revalue its fixed assets. Consultants worked with NEA counterpart staff during implementation. The physical verification of major assets was undertaken by the consultants, with the remaining assets verified and inspected by the NEA. Methodologies for revaluation were developed and NEA counterpart staff were trained. The computerized recording of fixed assets was developed but not implemented, leaving the NEA to record fixed assets manually. The consultants assisted the NEA to revalue its fixed assets, and built NEA capacity in regard to its system of valuating fixed assets. However, revaluation has not been incorporated into account books, which continue to be maintained on historical costs. Consultants commenced work on 7 November 2003 and were expected to finish in April 2005. Work was extended to December 2008 in response to the poor security situation, frequent changes in management, and the difficulty of reconciling the revalued assets with historical costs. The NEA has received the final revaluation report from the consultants.

7

(ii) Establishing district profit centers. Consultants helped (a) conduct an in-depth review and analysis of distribution system operations and management and prepare plans for each center; (b) determine performance indicators, targets, and benchmarks for each center; (c) review the NEA’s bulk transfer prices computed for each center; (d) improve the NEA’s and DPCs’ financial accounting system; (v) determine appropriate operational and management authority for DPC managers; (e) establish performance incentive schemes to improve efficiency at each branch; (f) review the NEA’s loss-reduction plan; and (g) develop performance monitoring and evaluation criteria for each DPC. Unfavorable political and security conditions delayed consulting work. Initially, the NEA implemented the scheme in only a limited number of DPCs. The scheme is now being revised and expanded, incorporating some of the consultants’ recommendations, and is proposed for a rollout across all the distribution centers. The NEA is confident that this will improve the efficiency of district center management, the quality of service delivery, and the handling of consumer grievances.

C. Project Costs

23. At appraisal, the cost of the project was estimated at $94.5 million equivalent, $60.0 million in foreign currency (63.5%) and $34.5 million equivalent in local currency (36.5%). At completion, project expenditure was $57.1 million, $44.2 million in foreign currency and $12.9 million in local currency provided by the NEA and the government. The ADB loan was $50 million,6 of which $38.2 million (76.3%) was used. The OFID loan was $10 million, of which $6.07 million (60.7%) was used. Appendix 2 compares estimated project costs with actual project costs. Appendix 3 compares projected and actual financing. ADB’s share of financing increased from 52.9% to 66.9%, and government funding decreased from $35.4 million to $12.9 million. 24. Foreign exchange cost savings of $16 million reflect (i) the deletion of part B and $2 million in ADB financing, (ii) cost savings in parts A and C thanks to bids being lower than expected, and (iii) savings from unused contingency funding of $13 million. These savings were used instead to cover the expanded scope of parts A, D, and E. The local currency cost decrease of $4 million equivalent reflects the deletion of the 27 km transmission line in part D. Part of the loan of $50.0 million was cancelled, with total disbursement amounting to $38.2 million. Similarly, $3.93 million of the OFID loan was cancelled at loan closing. At project completion, government and NEA funds were used to meet the costs of parts A, C, D, and E. D. Disbursements

25. ADB loan disbursements totaled $38.2 million, or 76.3% of the projected amount of $50.0 million. The initial disbursement under the loan was on 9 September 2003, and the final disbursement was on 19 December 2008, 63 months later. As disbursements were mainly for goods and consulting services, direct payment and letter of credit payment procedures were used. The NEA expressed satisfaction with ADB disbursement procedures. Projected and actual disbursements are in Appendix 4.

6 In December 2005, $12.12 million was cancelled from the ADB loan. In December 2008, $3.3 million was finally

cancelled at loan closure.

8

E. Project Schedule

26. The loan was approved on 21 December 1999 for implementation over 60 months to 31 December 2004, but it became effective only on 14 March 2002. The project suffered implementation delays of 3.5 years because of failure to meet loan effectiveness conditions, the slow recruitment of consultants and procurement, resistance from residents to the construction of a high-voltage transmission line, and political disturbances. Once the contracts were awarded, implementation generally proceeded smoothly, except that one component had difficulty acquiring land for a substation and distributing compensation for the transmission line right-of-way. It should be noted that, during most of the project period, the country was in political turmoil, adversely affecting all aspects of project implementation from fielding consultants to construction. 27. The original scope of the project to be funding with foreign exchange was completed in June 2008. The original schedule is compared with actual implementation in Appendix 5. The first contract under the transmission component, part A, was awarded in 11 May 2005, against the scheduled date in November 2004, as the NEA required time to prepare bid documents. In response to delays, the NEA requested two loan extensions, from 30 June 2005 to 30 June 2007 and again to 31 December 2008. Foreign costs under ADB and OFID financing were completed at loan closing, after which the NEA and the government financed the remaining work using their own resources. F. Implementation Arrangements

28. The NEA was the executing agency. Implementation arrangements were the same as envisaged at appraisal, and ADB found them to be adequate. The NEA set up a project coordination office headed by a project coordinator, who was assisted by a team of full-time project managers for each component. The managers also reported to their superiors in the NEA. In addition to coordination, the project coordination office was responsible for monitoring and reporting on day-to-day project implementation to the divisions concerned in the NEA. The office served as the main contact point for ADB. To the extent feasible, land acquisition and environmental clearances were planned and executed in advance to avoid delays. G. Conditions and Covenants

29. Compliance with four conditions was required for the loan agreement to become effective: (i) a rate of return of 6.0% per annum on revalued net fixed assets in service; (ii) an average self-financing ratio of 23% of 3 years of capital expenditure, (iii) a debt-service ratio of 1.2 times debt service, and (iv) accounts receivable at less than 3 months. Effectiveness was delayed until the NEA met the conditions, and ADB declared the loans effective on 14 March 2002. 30. No covenants were modified, suspended, or waived during implementation. The status of compliance with covenants is in Appendix 6. The NEA was unable to fulfill the financial covenants in general, though it complied with conducting a detailed revaluation of its fixed assets. The revaluation was not incorporated in the accounts. It has not been possible for the NEA to comply with the covenant on an annual rate of return of 6.0% on revalued assets, as the tariff remained unrevised for the entire duration of the project. The situation in the country made the covenant unrealistic, as there was very strong opposition to timely tariff revisions. The NEA was unable to comply as well with the covenant to bring down its T&D losses to 20.00% by FY2003, with losses still at 25.27% in FY2009.

9

31. The NEA has failed to comply with, or only partly complied with, all four financial covenants, as no tariff increases have been approved since FY2001, despite energy and other operating costs showing an increasing trend.7 At the end of FY2009, the NEA incurred a loss of NRs4.95 billion and had outstanding accounts receivable in excess of NRs5.39 billion, equal to 4 months’ invoicing. The last 5 years’ performance is in Table 1.

Table 1: Compliance with Key Financial Covenants Covenant Target 2005 2006 2007 2008 2009 Return on average NFA (%)

6.0 4.3 2.8 6.1a 1.3 (3.8)

Debt-service ratio 1.2 0.9 0.8 1.1 1.0 0.6 3-year average SFR (%)

23.0 26.3 18.7 47.4 12.4 18.8

Accounts receivable (months)

3.0 3.5 3.7 4.3 4.8 4.0

NFA = net fixed assets, SFR = self-financing ratio. a Includes revaluation of yen loans. If excluded, the return on average NFA is 5.1%. Source: Audited accounts of the Nepal Electricity Authority. 32. Covenants relating to project implementation and the operation and maintenance of project-supported facilities were met satisfactorily. There were some delays in the submission of unaudited and audited financial statements, which ADB pointed out to the NEA. They were caused by higher authorities’ delays in approving audited financial statements. H. Consultant Recruitment and Procurement

1. Consultants

33. At appraisal, $1.41 million was allocated to consulting services for project implementation. The project engaged international and domestic consultants for part D: transmission; part E: computerized billing; and part F: fixed asset revaluation and DPCs. At completion, the amount disbursed for consultant services was $0.94 million. The consultants were extended for part E to help the NEA complete implementation in four pilot branches. For part F, consultants were extended mainly because political disturbances affected the completion of work. The DPC component was carried out on a pilot basis by the NEA.

2. Procurement

34. In general, the NEA carried out the procurement of ADB-financed contract packages in accordance with ADB’s Procurement Guidelines (2010, as amended from time to time). The NEA was tasked with preparing detailed designs and bid documents for all packages covering parts A, C, and D during project implementation, with consultants preparing preliminary designs for part D. ADB helped the NEA achieve important milestones by expediting needed approvals. 7 Achieving a self-financing ratio of 23% has also proved difficult. The debt-service ratio of 1.2 was generally met until

2002. Since 2003, the NEA has been unable to meet this covenant. It has faced considerable difficulty maintaining accounts receivable at less than 3 months of sales, which increased to 4.8 months in FY2008. This is because many government agencies and municipalities do not pay. Eliminating street lighting arrears in FY2008 would bring accounts receivable down to 3.2 months of sales as of that date.

10

I. Performance of Consultants, Contractors, and Suppliers

35. Consultant recruitment was slow, contributing to early delays in accomplishing parts E and F. In total, 105 person-months of consultant services, 47 international and 58 domestic, were required for these components. The consultants were not fielded until 7 December 2003 and completed their assignment only in December 2008. Consultant selection was delayed by (i) failed bids because proposals had higher costs than estimated at appraisal, (ii) revisions to the terms of reference, (iii) procedural delays caused by the executing agency, and (iv) political disturbances and security issues during implementation. However, the consultants’ performance was generally satisfactory. No major issues arose regarding project design or the quality of service provided by consultants. To avoid delays, requests for proposals for consultants should be prepared before loan effectiveness.

36. The NEA reported that the performance of all contractors was generally satisfactory. All goods and services under the ADB-financed portion of the project were procured in accordance with ADB’s procurement guidelines. Bidding documents were prepared to ensure maximum competition under international competitive bidding, through which packages that cost $1 million or more were awarded. Some complex components under parts A, C, D, and E were procured on a design–build–turnkey basis. Contractor performance was generally satisfactory, except regarding one contractor that provided services for part D, mainly because of difficulty in getting the right-of-way for constructing transmission lines. Significant delays affecting civil works were caused by political disturbances, design modifications, right-of-way and resettlement issues, and insurgency.

J. Performance of the Borrower and the Executing Agency

37. The performance of the NEA as the executing agency was satisfactory. All parts of the project were completed successfully, though there was an overrun of 3.5 years in completing the ADB- and OFID-financed portion of the project, until December 2008, because of initial start-up delays caused by failure to comply with conditions for loan effectiveness and delays in completing construction. The project contributed to a substantially improved rate of electrification from 14.6% in 1999 to 42.0% in 2008. A major outcome of the project was expanded access to reliable electricity supply in 27 districts in the western, eastern, and central regions; improved revenue management using computerized billing systems; and the NEA’s improved financial management system. The NEA has satisfactorily demonstrated its capacity to formulate and carry out engineering, procurement, and construction according to approved standards and to the satisfaction of ADB. It performed the required tasks of detailed design, procurement, and the installation of goods and works with the support of consultants. These actions demonstrated its commitment and capability to undertake such projects. 38. The performance of government as the borrower was satisfactory. It completed institutional arrangements for project management including appointing key staff before the loan became effective. Although ADB’s insistence on compliance with conditions for loan effectiveness improved the NEA’s financial position, institutional arrangements for timely tariff revision through the Electricity Tariff Fixation Commission failed as the commission did not approve any tariff increases during the project.

K. Performance of the Asian Development Bank

39. ADB’s performance is rated satisfactory. It monitored the project closely and regularly and provided guidance on project management. ADB fielded review missions frequently and

11

visited project sites. It promptly acted on proposals to change project scope and for partial cancellation, reallocation, and extending the loan closing date. ADB’s performance in jointly administering the project with OFID was satisfactory. The steps taken by ADB toward starting and implementing the project were very encouraging. On the one hand, ADB's insistence on compliance with conditions for loan effectiveness helped initially improve the financial health of the NEA, but on the other hand this contributed to a substantial delay in project implementation. ADB's was effective as the fund administrator for OFID loan.

III. EVALUATION OF PERFORMANCE

A. Relevance

40. The design of the project was highly relevant to the sector objectives of the government and the NEA, as well as to ADB’s country and sector strategies for Nepal. Since the government initiated power sector reforms in the 1990s, policy reforms had been on its agenda. The power sector had deteriorated to such an extent that it seriously limited economic growth. Because of the country’s poor financial condition and regulatory environment, the NEA was unable to improve power supply. The government then embarked on policy reforms and physical investments in the sector to strengthen T&D, enhance energy efficiency, and develop the country’s hydropower potential. At completion, ADB’s strategy for the power sector in Nepal was in harmony with the Ninth Five-Year Plan aim to develop infrastructure toward economic growth and poverty reduction. ADB’s present strategy for the sector is to (i) promote clean and renewable energy, (ii) optimize T&D systems, (iii) support sector reforms, (iv) strengthen institutions, (v) promote private sector participation, (vi) encourage energy efficiency and rural electrification, and (vii) ensure environmental and social sustainability. Project outputs contributed to achieving these objectives. B. Effectiveness in Achieving Outcome

41. The project achieved its immediate objectives of (i) extending the NEA distribution system in rural areas to provide service to more rural communities and to improve their economic and living conditions, (ii) developing the T&D system of the NEA to accommodate increased loads and new consumers in existing service areas, and (iii) reorienting the NEA toward more commercial operations and improved revenue management by introducing computerized billing systems and handheld meter-reading devices for better consumer services. NEA has also established a limited number of district profit centers under the project. However, one of the expected outcomes, improving the financial and operational performance of the NEA, could not be achieved as no tariff increases were effected during the entire project, which adversely affected the NEA’s financial performance, and T&D losses could not be brought down to 20% by FY2003. 42. The NEA was able to (i) meet peak demand of 721 MW in 2008 (and 946 MW in 2011), more than double peak demand of 327 MW in 1999, and (ii) improve collection efficiency from 97% in 2004 to 105% in 2009 (more than 100% with the receipt of some arrears from the government).8 The project achieved most of the physical targets at appraisal using savings and increased government funding. The project is rated effective. All substations are already running at 70% of capacity or higher, with some already further upgraded to meet higher demand. This demonstrates that the investments are being fully utilized.

8 In 2010, collection efficiency was 93%, as the government had not paid other arrears to the NEA.

12

C. Efficiency in Achieving Outcome and Outputs

43. The milestones of the project were achieved close to the revised target dates. Some remaining works in transmission, rural electrification, and distribution system reinforcement were completed after loan closing. The project is rated efficient. It was implemented efficiently, and all its parts have operated from the date of commissioning. Of 22 substations constructed or upgraded under the project, four have already been further upgraded to meet high demand, and 12 are running at full load. The remaining 6 substations are currently running at 70% of their installed capacity. The NEA has rolled out computerized billing systems in additional revenue centers, which has enhanced its capability to implement complex information technology projects. 44. The financial internal rate of return of all project parts was well above the NEA’s weighted average cost of capital of 1.18% for the rural electrification component and 3.27% for all other components. The economic internal rate of return of all parts was reevaluated at more than 12%. The financial and economic analyses were made using the world price numeraire. Major assumptions used in the financial and economic evaluation and the detailed calculations of rates of return are in Appendix 7. D. Preliminary Assessment of Sustainability

45. A preliminary assessment of the project shows positive indications of its long-term sustainability. The design of all parts and the technology adopted were robust and suitable given the technical parameters and the requirements of Nepal’s power sector. Power demand in Nepal is projected to grow substantially, ensuring the full use of project investments. All outputs are expected to be used optimally. Project investments are likely sustainable. Important requirement for sustainability include concerted action by NEA to bring down T&D losses, and support from the Electricity Tariff Fixation Commission through regular tariff increases. E. Impact

46. The NEA has installed the computerized system developed by the project in 54 branches and sub-branches that account for 67% of its annual billing volume. It has found the system important for improving revenue management and is planning to roll it out across all its branches in due course. 47. The project aimed to contribute positively to Nepal’s economic development by ensuring sufficient electricity supply in rural areas. Electricity has displaced conventional sources of energy such as kerosene for lighting and diesel for small industry and irrigation. It became an important calculation in decisions to establish small industries in rural area and improve the rural quality of life. Most potential impacts on environment are considered beneficial, and no adverse impacts were identified. Adequate safety measures and periodic monitoring were in place. 48. In accordance with Ministry of Environment and Environment Act, 1997 guidelines on environmental clearance, power lines passing through ecologically sensitive areas require approval. The routes were finalized in consultation with authorities to ensure minimal damage to forests and wildlife. An environmental impact assessment was required only in one project area, in Kaski District’s Annapurna Conservation Area. This was approved by the ministry. 49. Transformers and other equipment used in the project are free of polychlorinated biphenyl. No transformer oil spill was allowed, and batteries and scrap were collected and

13

disposed of in compliance with the Environment Act, 1997 and with ministry rules and regulations. Most distribution lines under the project were constructed along roads with minimal infringement on agricultural land, pastures, and other green areas. F. Social Assessment

50. The project is gender neutral with regard to beneficiaries. All electricity consumers derive benefits from improved power reliability. Annual per capita consumption doubled from 48 kWh in 1999 to 100 kWh in 2008. Other benefits include job creation. 51. The NEA chose the routes of power lines to avoid human dwellings, threatening the survival of vulnerable communities, and common property resources. Of 15 new substations, the NEA already held land for 1 and leased barren land from the government for 2 others. Land for all other substations was purchased from the local people, who were compensated to their satisfaction. 52. Parts A and C displaced no people, so no resettlement plan was required. The resettlement plan for the transmission component, part D, identified 100 project-affected people who needed to be compensated for the right-of-way. Funds for acquiring land for towers and right-of-way compensation were processed in accordance with the prevailing legal requirements and deposited with the district administration concerned. Public consultations were carried out involving local officials, community leaders, and affected groups. As the compensation amount could not be mutually agreed in Lalitpur District, one portion of the transmission line, from Thankot to Chapagaon, could not be completed.

IV. OVERALL ASSESSMENT AND RECOMMENDATIONS

A. Overall Assessment

53. The project substantially achieved all its physical outputs despite its implementation being adversely affected throughout by political uncertainty and turmoil. However, the policy objective of ensuring the long-term financial sustainability of the NEA could not be achieved because of the failure, for the duration of the project, to revise tariffs and because of mounting T&D losses. Project design was consistent with ADB's country and sector strategy and with the NEA's objectives of developing a T&D system capable of providing power reliably. The performance of the NEA, government, and contractors was satisfactory. Project implementation was achieved with the full involvement of both the government and the NEA. The project is rated highly relevant, effective, efficient, and likely sustainable. It has generally met its objectives and is rated successful.

B. Lessons

54. The NEA has not been able to increase tariffs since 2001, which seriously constrains its operations. As its financial condition is particularly serious, addressing financial issues is key to successful reform. The lack of resources arising from a stagnant tariff has hampered the NEA’s ability to invest adequately in expanding and maintaining its generation and T&D network. Consequently, the NEA is caught in a vicious circle of high T&D losses (28.91% in FY2010) that exacerbate its poor financial position. Investments under future ADB projects should directly target reducing such losses, system strengthening, and developing institutions to ensure sustainability in the sector. Impractical and unrealistic loan effectiveness conditions should be

14

avoided. Environmental management and resettlement plans should be prepared, and project sites and the routing of transmission lines should be designed to avoid densely populated and ecologically sensitive areas. 55. Successful implementation amply demonstrates that, if appropriate institutional support is provided, the NEA can adequately carry out such a project. Most project works were completed without consultants. The NEA took advance action to acquire land and clear other statutory hurdles, which eased implementation. In earlier ADB-assisted power projects, land acquisition and environmental issues often caused delays. The NEA’s experience and familiarization with ADB procedures, timely support from ADB, and the NEA’s willingness to adopt recommended practices facilitated project implement. The NEA and the government fully supported the project. C. Recommendations

56. Future monitoring. Various steps taken by the government in implementing reforms were well received by all stakeholders. There is a consensus among stakeholders in Nepal on the need for sector reforms. ADB will continue to engage in dialogue with the government to facilitate the early implementation of the financial restructuring plan for the NEA, including regular tariff revision. The next loan (para. 60) has covenants toward this objective. The NEA has had a good track record in maintaining the system, so no further monitoring by ADB is required. 57. The NEA should continue to improve governance, accountability, and coordination for sustainability. A particular need is to develop efficient management systems in the NEA and strongly enforce existing monitoring mechanisms. Appropriate institutional and regulatory mechanisms should be established to effectively monitor the performance of the NEA. Targets should be set annually to improve sector performance and ensure periodic tariff adjustments. 58. Covenants. Most covenants were complied with, except for the financial covenants and the covenant on reducing T&D losses. ADB will continue to work closely with the NEA and the government to facilitate the achievement of these covenants. 59. Further action or follow-up. As all parts of the project were successfully implemented and disbursements have been completed, no follow-up is required. 60. Additional assistance. The government and the NEA have developed a sector investment program for 2009–2020 estimated at $2.2 billion. On 27 November 2009, ADB approved a $65 million loan9 to help the NEA provide reliable and energy-efficient power, expand access, and improve operational efficiency. Moreover, the new Electricity Transmission Expansion and Supply Improvement Project has been approved in 2011. 61. Timing of the project performance evaluation report. A mission may be undertaken at any time in 2012 or later to prepare a project performance evaluation report.

9 ADB. 2009. Report and Recommendation of the President to the Board of Directors: Proposed Loan to Nepal for the

Energy Access and Efficiency Improvement Project. Manila.

Appendix 1 15

PROJECT FRAMEWORK Design Summary

Performance Indicators/Targets

Monitoring Mechanisms

Assumptions and Risks

Actual Achievement

Goal

Promote economic growth and a higher standard of living in rural and urban areas through improved access to electricity.

Meet growing demand for electricity supply in existing service areas.

Improve the financial and operational performance of Nepal Electricity Authority (NEA) and its governance.

Increase the national electrification ratio from 14.6% to 18.0%.

Enable the NEA’s total sales to growth at 9% per year.

Ensure the NEA a regular annual tariff increase to achieve a 6% rate of return and 23% self-financing ratio.

Socioeconomic surveys at periodic times

NEA annual reports

Assumption

A satisfactory second stage tariff increase will be required as a condition for loan effectiveness.

The national electrification ratio increased from 14.6% in 1999 to 42.0% in 2008. The NEA’s total sales grew at an average of 12.8% from 1999 to 2008. The self-financing ratio decreased to 12.4% in 2008 from 23.0% in 1999.

Purpose

Expand and strengthen the NEA’s distribution and transmission systems.

Reduce NEA transmission and distribution T&D losses.

Support institutional strengthening in the NEA and its commercialization.

Strengthen distribution systems for load growth of about 145 MW over the next 4 years.

Reduce T&D losses to less than 20%.

Establish distribution district profit centers.

Project benefit monitoring and evaluation reports

Action plan and progress reports prepared to implement profit centers

Assumption

Consumers are able to pay for new connections and energy consumption.

Load growth reached 164 MW in 2009. T&D losses were 26.52% in 2008 Six pilot distribution profit centers were established; the concepts were implemented in all distribution centers nationwide.

Outputs Extend the distribution system in rural areas, both on grid and off.

Reinforce distribution in existing service areas.

Strengthen the transmission system.

Establish computerized customer billing centers.

Establish distribution district profit centers.

Make 154,000 new rural connections with a peak load of 35 MW.

Make 5,000 new distribution connections off grid.

Strengthen distribution strengthening with 1,070 kilometers of 33 kilovolt and 11 kilovolt lines.

Strengthen transmission in the Kathmandu Valley and build another interconnection to India.

Quarterly project progress reports

Loan review missions

Project completion report

Assumptions

Counterpart funds are available.

Rights-of-way are acquired for a 132 kilovolt transmission line in the Kathmandu Valley, with satisfactory compensation.

By 2011, 119,000 new rural connections were achieved, with 123,400 to be reached by 2012. The off-grid component was cancelled. By November 2010, 2,522 kilometers of 33 kilovolt and 11 kilovolt lines were installed. The transmission line from Thankot

16 Appendix 1

Design Summary

Performance Indicators/Targets

Monitoring Mechanisms

Assumptions and Risks

Actual Achievement

to Bhaktapur is under construction. The Matathirta switching station was constructed as a substation in 2008. Three substations, at Anarmani, Pokhara, and Siuchatar, were upgraded in January 2008.

Activities

Appoint consultants.

Do detailed planning and design.

Procure materials and equipment.

Construct physical assets.

Test and commission assets.

Quarterly progress reports

ADB review and approval of tender documents, contract awards, and disbursements

Review missions

Project completion report.

Risk

Main activities are delayed.

Assumptions

Counterpart funds are available.

NEA staff are adequate for detailed planning, design, and construction supervision

Consultants were contracted for parts D, E, and F who successfully completed the required assistance.

Inputs $60 million in foreign exchange and $29 million in local currency

Consulting services for four tasks, comprising 39 person-months of international services and 58 person-months of domestic

$44.5 million in foreign currency and $12.9 million in local currency 47 person-months of international consulting services and 58 person-months of national.

Appendix 2 17

COST BREAKDOWN BY PROJECT COMPONENTS ($ million)

FC LC Total FC LC Total FC LC Total FC LC Total FC LC Total I. Base CostsA&C. Rural Electrification and Distribution System Reinforcement33/11 kV substation 6.20 1.54 7.74 5.96 2.09 8.05 0.09 0.00 0.09 5.87 2.09 7.96 5.56 1.95 7.52Line construction (33 kV, 11 kV, 0.4 kV) 27.71 8.00 35.71 34.99 14.47 49.46 0.02 0.00 0.02 34.97 14.47 49.44 26.23 5.43 31.66Subtotal (A & C) 33.91 9.54 43.45 40.95 16.56 57.51 0.12 0.00 0.12 40.84 16.56 57.40 31.79 7.38 39.17B. Distribution for Isolated Power Projects 2.00 0.80 2.80 0.00 0.00 0.00 2.00 0.80 2.80 0.00 0.00 0.00 0.00 0.00 0.00D. Transmission Development132 kV transmission line, Bhaktapur–Thankot 2.34 4.58 6.92 0.00 0.00 0.00 0.00 0.00 0.00 2.34 4.58 6.92 1.51 0.90 2.41132 kV trasmission line, Social and Environmntal cost 2.49 2.49132 kV transmission substation in Harisiddhi 1.96 0.39 2.35 0.00 0.00 0.00 0.00 0.00 0.00 1.96 0.39 2.35 0.67 0.33 1.00132 kV transmission switching station in Thankot 1.65 0.41 2.06 0.00 0.00 0.00 0.00 0.00 0.00 1.65 0.41 2.06 0.84 0.28 1.12Other substations expansion in Kathmandu Valley 2.88 0.45 3.33 0.00 0.00 0.00 0.00 0.00 0.00 2.88 0.45 3.33 2.65 0.25 2.90Change of scope in switching station in Thankot 0.59 0.04 0.63132 kV transmission line, Butwal to Indian Border 2.19 0.39 2.58Consulting services 0.30 0.00 0.30 0.29 0.29Grid system reinforcement - 0.00 0.00 2.73 0.28 3.01 0.00 0.00 0.00 2.27 0.40 2.67 2.27 0.32 2.59Subtotal (D) 11.32 6.22 17.54 2.73 0.28 3.01 0.00 0.00 0.00 11.10 6.23 17.33 8.82 4.61 13.42E. Computerized Billing SystemsDesktop computers and printer 0.39 0.00 0.39 2.12 2.12 0.00 0.00 0.00 2.12 0.00 2.12 1.67 0.22 1.89Billing system software 0.30 0.00 0.30 0.34 0.34 0.00 0.00 0.00 0.34 0.00 0.34 0.25 0.01 0.26Consulting services 0.29 0.00 0.29 0.23 0.23 0.00 0.00 0.00 0.23 0.00 0.23 0.28 0.00 0.28Other miscellaneous 0.27 0.30 0.57 0.91 0.91 0.00 0.00 0.00 0.91 0.00 0.91 0.71 0.09 0.80Relational database management systerm - 0.00 0.00 0.13 0.13 0.00 0.00 0.00 0.13 0.00 0.13 0.13 0.03 0.16Subtotal (E) 1.25 0.30 1.55 3.73 0.00 3.73 0.00 0.00 0.00 3.73 0.00 3.73 3.04 0.35 3.39F. Other Institutional StrengtheningFixed Asset Revaluation 0.52 0.26 0.78 0.00 0.00 0.00 0.00 0.00 0.00 0.52 0.26 0.78 0.19 0.40 0.59Distribution profit center project 0.30 0.15 0.45 0.25 0.15 0.40 0.05 0.00 0.05 0.20 0.15 0.35 0.19 0.12 0.30Subtotal (F) 0.82 0.41 1.23 0.25 0.15 0.40 0.05 0.00 0.05 0.72 0.41 1.13 0.38 0.52 0.89Taxes and Duties - 2.40 2.40Total Base Cost 49.30 19.66 68.96 47.67 16.99 64.66 2.16 4.19 2.96 56.39 23.20 79.59 44.03 12.86 56.89II. ContingenciesPhysical 4.90 2.00 6.90Price escalation 4.40 1.70 6.10Interest during construction 1.40 11.10 12.50 0.20 0.20Total 60.00 34.46 94.46 47.67 16.99 64.66 2.16 4.19 2.96 56.39 23.20 79.59 44.23 12.86 57.09

Net Amount AvailableComponent Appraisal Last Revised Allocation Amount Canceled Actual

FC = foreign currency cost, kV = kilovolt, LC = local currency cost

18 Appendix 3

PROJECT FINANCING PLAN

($ million)

Item Appraisal Estimate Actual Source Foreign Local Total Foreign Local Total ADB 50.00 0.00 50.00 38.16 0.00 38.16 OFID 10.00 0.00 10.00 6.07 0.00 6.07 NEA retained earnings 0.00 25.90 25.90 0.00 12.86 12.86 Government 0.00 8.60 8.60 0.00 0.00 0.00 Total 60.00 34.50 94.50 44.23 12.86 57.09 ADB = Asian Development Bank, NEA = Nepal Electricity Authority, OFID = OPEC Fund for International Development.

Appendix 4 19

DISBURSEMENT

Table A.1: Projected and Actual Disbursements of Loan Proceeds ($ million)

Calendar Projecteda Actual Year For the year Cumulative For the Year Cumulative 2003 0.08 0.08 0.07 0.07 2004 2.47 2.55 2.21 2.28 2005 12.34 14.89 11.04 13.32 2006 14.58 29.47 13.05 26.37 2007 6.23 35.70 5.57 31.94 2008 6.96 42.65 6.22 38.16

aProjections are made in Asian Development Bank’s Loan Financial Information System (LFIS). Source: ADB’s LFIS.

Disbursement Details

051015202530354045

2003 2004 2005 2006 2007 2008Year

$ m

illio

n

Asian Development Bank projection Actual

20 Appendix 5

IMPLEMENTATION SCHEDULE 2004 2005 2006 2007 2008 2009 2010 2011

1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4Part A: Rural Electrification

Part C: Distribution System Reinforcement

Part D: Transmission Projects

Legend: Projected: 1: Jan...March

Revised: 2: Apr...June

Actual: 3: July...Sept.

Beyond Loan Closing Date: 4: Oct...Dec.

2003Project Components 2000 2001 2002

Construction of 132 kV and 66 kV substations

Planning and preliminary design

Procurement of line materials

Detailed design and construction mgmt.

Supply and construction of substations

Construction of 132 kV transmission line

Part F2: Distribution District Profit Centers

Grid system reinforcement

Part E: Computerised Billing Project

Part F1: Fixed Assets Revaluation

Appendix 6 21

STATUS OF COMPLIANCE WITH MAJOR LOAN COVENANTS

Loan 1732-NEP (SF) Covenant

Reference in Loan Documents

Status of Compliance

1. A rate of return of at least 6 percent on net revalued fixed assets in service every year commencing Fiscal Year 2001 and thereafter, a minimum self financing ratio of at least 23 percent every year commencing Fiscal Year 2001 and thereafter and debt-service coverage ratio of at least 1.2 times the maximum debt-service requirements in any year on all debt incurred by NEA.

Schedule 6, Clause C-11 Partially complied. Rate of Return is 4.01 in 2009/10

2. The average residential tariff shall be no less than the average retail tariff for sales in Nepal, the first line block for residential consumers shall be limited to 20 kWh/month and the lifeline tariff rate shall be at least 60% of the average residential tariff rate.

Schedule 6, Clause C-12 Not complied. Tariffs have been maintained at 2001 levels.

3. GON shall ensure and cause NEA to ensure that for timely execution of NEA's annual application to ETFC for an approved tariff adjustment, to be effective from the beginning of each fiscal year.

Schedule 6, Clause C-15 Not complied. Tariffs have been maintained at 2001 levels.

4. ETFC and NEA shall require, through the amendment to the ETFC rules (referred to in paragraph 6.01(c) of this Loan Agreement) to review tariffs every 6 months after the date of the last tariff adjustment and adjust tariffs on a semi-automatic interim basis, if necessary, based on a formula to be agreed between the Borrower, ETFC and the Bank.

Schedule 6, Clause C-16 Not complied, as tariffs have not been revised since 2001.

5. NEA shall conduct a detailed revaluation of its fixed assets approximately every five years. NEA shall appoint international consultants no later than 31 March 2000 to assist it with a detailed revaluation of its fixed assets in service.

Schedule 6, Clause D-17(a) Complied.

6. NEA shall also revalue its fixed assets annually, by a formula satisfactory to the Bank, in those years when no detailed asset revaluation is conducted.

Schedule 6, Clause D-17(b)

Not Complied. Assets continue to be accounted on historical cost basis.

7. GON and NEA shall ensure that all necessary action is taken so that NEA's total accounts receivable is maintained at a level that does not exceed the equivalent of three months sales revenue for any Fiscal year.

Schedule 6, Clause G-22

Not Complied. Accounts receivable is 4.0 as of FY 2009.

8. GON shall cause NEA to furnish the Bank for review and comment a draft NEA corporate plan covering the subsequent six years setting forth NEA's development plans and investment requirements including (i) NEA load forecast; (ii) NEA's development plans and investment requirement for generation, transmission and development;(iii) NEA's financial projections.

Schedule 6, Clause H-24 (a)

Complied.

9. NEA shall take necessary action to reduce transmission and distribution system losses, including NEA's self- consumption, to a level not exceeding 23 percent of total energy available in Fiscal Year 2000, and 22 percent in Fiscal Year 2001, and 21 percent in Fiscal Year 2002; and 20 percent in each subsequent Fiscal Year.

Schedule 6, Clause I-27 Not complied.

22 Appendix 6

Loan 1732-NEP (SF) Covenant

Reference in Loan Documents

Status of Compliance

10. NEA shall implement a commercialization action plan based on recommendations of a commercialization study report agreed with the bank. This commercialization action plan shall include establishment of distribution district profit centers with employee performance incentives in NEA's 15 largest branches.

Schedule 6, Clause J-28 Complied.

Appendix 7 23

Financial and Economic Evaluation 1. The major assumptions used in the financial and economic evaluation of the investment project are discussed in this appendix. A. Financial Evaluation

2. The financial evaluation of the investment project was carried out based on cost and benefit streams realized by each component. All costs and revenues are expressed in constant 2011 prices. Capital costs include goods, services, and interest charges during construction. 3. The cost of capital is calculated for the project as a whole. The project is financed by foreign debt in the form of loans from the Asian Development Bank (ADB) and the OPEC Fund for International Development (OFID). The Nepal Electricity Agency (NEA) received the ADB loan from the Government of Nepal at an interest rate of 8% for rural electrification and off-grid distribution and 12% for other components. The weighted average cost of capital (WACC) was calculated for the project and was compared with the project’s financial internal rates of return (FIRRs) to ascertain financial viability. Financial viability was examined by comparing the incremental costs and benefits of the scenarios with the investment and without it. The WACC was calculated based on the financing sources of the projects as follows: (i) the government’s equity contributions and foreign loans; (ii) the cost of equity calculated as the government’s long-term bond rate and a margin; (iii) the ADB loan passed on from the government to the NEA in Nepalese rupees, with the interest rate including allowance for the government’s foreign exchange premium; and (iv) the foreign inflation rate taken as 8% and the domestic inflation rate at 8%. Tables A7.1 and A7.2 show that the WACC is 1.18% for the rural electrification component and 3.27% for all other components.

Table A7.1: Weighted Average Cost of Capital for Rural Electrification

($ million)

Nominal Weighted Source Amount Cost (%) ADB Loan 17.24 8.0 81.8 Government equity 3.83 15.0 18.2 Weighted average cost of capital 1.18 ADB = Asian Development Bank. Source: Project completion report mission estimates.

Table A7.2: Weighted Average Cost of Capital for Parts C and D (Other Components) ($ million)

Nominal Weighted Source Amount Cost (%) ADB loan 44.51 10.5 77.6 Government equity 12.86 15.0 22.4 Weighted average cost of capital 3.27 ADB = Asian Development Bank. Source: Project completion report mission estimates.

24 Appendix 7

1. Capital Cost

4. All components have been completed and begun to yield benefits. No salvage value has been assumed at the end of the useful life of components. A total cost of $57.4 million is used.

2. Sales Revenue

5. Part A: rural electrification. A noticeable increase in revenue collection has occurred under the rural electrification component. The increase in revenue is attributable to expanded access and electricity connections in rural areas under the project. The number of consumers is expected to reach 123,400 households by 2015 from 68,500 in 2008, or an estimated 700,000 rural residents, as well as industrial and commercial consumers. 6. Parts C and D: distribution system reinforcement and transmission. Benefits that accrue to this component are expected to result from additional savings because of investments, the greater availability of input energy, higher sales volumes and loss reduction, and other improvements to system efficiency. At least 10% of the incremental benefits in the system are assumed to be attributable to ADB funding. For these components, incremental income is based on actual benefits (incremental revenues) accrued in supplying additional power with increased load in the system. It is assumed that electricity sales will increase by 9% annually during the projection years.

3. Tariff

7. Revenues corresponding to incremental power sales are computed assuming an actual average retail tariff from 2004 to 2009. For the projection years, the tariffs are assumed to remain constant in 2010–2030, pending the government’s decision to increase tariffs. The same set of tariffs is assumed for estimating the benefits under parts C and D.

4. Operating Cost

8. The annual operating cost has been assumed to be 1.5% of total capital costs for parts A, C, and D.

5. Financial Internal Rate of Return

9. For part A: rural electrification plus associated transmission and generation, the FIRR was estimated at appraisal as 2.71%, which was lower than the WACC of 3.4% in real terms. The FIRR at project completion is estimated to be 3.73%, which is higher than the revised WACC of 1.18% at project completion in real terms. For parts C and D: NEA power system development, the FIRR is estimated as 11.2% at completion, up from 7.1% at appraisal. The FIRR of parts C and D is 11.2% is higher than the WACC of 3.27% at project completion. A summary comparison of FIRRs at appraisal and project completion is in Table A7.3. Detailed financial evaluation of the 22 rural electrification schemes is in Table A7.5, and of the power system development program in Table A7.7.

Table A7.3: Financial Internal Rate of Return of Project Components

Project Component

FIRR at Appraisal (%)

FIRR at Project Completion (%)

Part A: rural electrification Parts C & D: NEA power system development

2.71

7.10

3.73

11.17 FIRR = financial internal rate of return, NEA = Nepal Electricity Authority. Source: Project completion report mission estimates.

Appendix 7 25

6. Economic Evaluation

10. The economic analysis was carried out on the basis of economic benefits of power consumption to end-users, represented by their willingness to pay as applicable. The economic analysis used the world price numeraire. Economic costs were derived from the financial costs, deducting taxes and duties. The costs were separated into foreign exchange and local currency costs. Local costs were further separated and a conversion factor of 0.95 was used for unskilled labor. Labor costs were assumed to be 10% of the local currency costs, and unskilled labor costs were assumed to be 35% of the labor costs. 11. The economic evaluation of residential consumers (part A) is based on the economic benefits arising from (i) the alternative economic costs of kerosene that would be used for lighting in the absence of electricity and (ii) valuing the additional energy consumption at the estimated average willingness to pay based on the weighted average of alternative kerosene costs and current tariffs. For industrial users, the economic benefits are estimated based on the cost of alternative diesel-fueled generation. For parts C and D, economic performance cannot be readily isolated for evaluation. An economic evaluation of the NEA’s total investment program was therefore carried out for additional power supply from 2004 to 2030. The economic internal rate of return (EIRR) for part A is estimated at 17.4%, against 13.9% at appraisal. For parts C and D: distribution system reinforcement and transmission, the EIRR is estimated at 23.4%, against 14.8% at appraisal. A summary of the comparison of EIRRs at appraisal and project completion is in Table A7.4. Detailed economic evaluation of the 22 rural electrification schemes is in Table A7.6, and of the power system development program in Table A7.8.

Table A7.4: Economic Internal Rate of Return of Project Components Project Component

EIRR at Appraisal (%)

EIRR at Project Completion (%)

Part A: rural electrification Parts C & D: distribution system reinforcement and transmission

13.9

14.8

17.4

23.4 EIRR = economic internal rate of return. Source: Project completion report mission estimates.

26 Appendix 7 Table A7.5: Financial Evaluation of 22 Rural Electrification Schemes of the Nepal Electricity Authority, 2004–2030

Capital Cost O&M Cost 33kV Supply Total CostResidential Industrial Commercial Irrigation Total ($) ($) Cost ($) ($)

2004 0 0 0 0 0 0 0 0 0 1,110,834 16,663 0 1,127,496 (1,127,496) 2005 0 0 0 0 0 0 0 0 6,598,440 115,639 0 6,714,079 (6,714,079) 2006 0 0 0 0 0 0 0 0 0 7,159,452 223,031 0 7,382,483 (7,382,483) 2007 6,942 2,346 431 622 10,341 12,277 977,505 26,400 26,400 2,869,549 266,074 626,104 3,761,727 (2,784,222) 2008 14,431 4,877 896 1,292 21,496 25,520 2,031,986 52,800 26,400 2,794,387 307,990 1,301,512 4,403,888 (2,371,903) 2009 18,423 6,226 1,144 1,650 27,443 32,580 2,594,164 66,000 13,200 265,802 311,977 1,661,593 2,239,372 354,791 2010 21,572 7,290 1,340 1,932 32,134 38,149 3,037,582 75,172 9,172 278,732 316,158 1,945,608 2,540,498 497,084 2011 24,982 8,442 1,552 2,237 37,213 44,179 3,517,695 84,696 9,524 0 316,158 2,253,126 2,569,284 948,411 2012 28,706 9,701 1,783 2,570 42,760 50,764 4,042,044 94,696 10,000 0 316,158 2,588,978 2,905,136 1,136,908 2013 32,612 11,021 2,026 2,920 48,578 57,672 4,592,072 104,696 10,000 0 316,158 2,941,278 3,257,436 1,334,636 2014 36,719 12,409 2,281 3,288 54,696 64,388 5,170,384 114,696 10,000 0 316,158 3,283,798 3,599,956 1,570,427 2015 39,488 13,344 2,453 3,536 58,821 69,244 5,560,317 123,346 8,650 0 316,158 3,531,452 3,847,610 1,712,707 2016 39,488 13,344 2,453 3,536 58,821 68,656 5,560,317 123,346 0 316,158 3,501,453 3,817,611 1,742,706 2017 39,488 13,344 2,453 3,536 58,821 68,068 5,560,317 123,346 0 0 316,158 3,471,454 3,787,612 1,772,705 2018 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2019 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2020 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2021 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2022 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2023 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2024 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2025 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2026 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2027 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2028 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2029 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304 2030 39,488 13,344 2,453 3,536 58,821 67,644 5,560,317 123,346 0 0 316,158 3,449,855 3,766,013 1,794,304

Input Data 43,064,846 FIRR 3.73%Average rural electrification tariffs ($0.10/kWh) Residential 10.28 Industrial 8.17 Commercial 9.63 Irrigation 4.92 Average tariff' 9.45 O&M Costs 1.50% Losses 24.70% Cost of 33 kV supply $0.051/kWh at 2.7% interest rate

Actual Connected Customers

Additional Customers Each Year

Annual Costs Net Annual Benefits ($)Year

Annual Energy Sales (MWh) Bulk Supply Required @ 33kV (MWh)

Total Annual Benefits ($)

FIRR = financial internal rate of return, GWh = gigawatt hour, kV = kilovolt, kWh = kilowatt-hour, MWh = megawatt-hour, O&M = operating and maintenance. Sources: Project completion report mission estimates.

Appendix 7 27

Table A7.6: Economic Evaluation of 22 Rural Electrification Schemes of the Nepal Electricity Authority, 2004–2030

Capital Cost O&M Cost 33kV Supply Total CostResidential Industrial Commercial Irrigation Total ($) ($) Cost ($) ($)

2004 0 0 0 0 0 0 0 0 0 1,044,184 16,663 0 1,060,846 (1,060,846) 2005 0 0 0 0 0 0 0 0 6,202,534 115,639 0 6,318,173 (6,318,173) 2006 0 0 0 0 0 0 0 0 0 6,729,885 223,031 0 6,952,916 (6,952,916) 2007 6,942 2,346 431 622 10,341 11,892 2,405,609 26,400 26,400 2,697,376 266,074 1,314,051 4,277,502 (1,871,893) 2008 14,431 4,877 896 1,292 21,496 24,720 5,000,655 52,800 26,400 2,626,724 307,990 2,731,581 5,666,295 (665,640) 2009 18,423 6,226 1,144 1,650 27,443 31,559 6,384,157 66,000 13,200 249,854 311,977 3,487,312 4,049,143 2,335,014 2010 21,572 7,290 1,340 1,932 32,134 36,954 7,475,397 75,172 9,172 262,008 316,158 4,083,396 4,661,561 2,813,835 2011 24,982 8,442 1,552 2,237 37,213 42,795 8,656,940 84,696 9,524 0 316,158 4,728,807 5,044,965 3,611,974 2012 28,706 9,701 1,783 2,570 42,760 49,174 9,947,346 94,696 10,000 0 316,158 5,433,685 5,749,843 4,197,503 2013 32,612 11,021 2,026 2,920 48,578 55,865 11,300,947 104,696 10,000 0 316,158 6,173,082 6,489,240 4,811,707 2014 36,719 12,409 2,281 3,288 54,696 62,900 12,724,155 114,696 10,000 0 316,158 6,950,502 7,266,660 5,457,495 2015 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 8,650 0 316,158 7,474,686 7,790,844 5,892,925 2016 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 316,158 7,474,686 7,790,844 5,892,925 2017 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2018 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2019 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2020 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2021 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2022 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2023 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2024 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2025 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2026 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2027 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2028 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2029 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925 2030 39,488 13,344 2,453 3,536 58,821 67,644 13,683,769 123,346 0 0 316,158 7,474,686 7,790,844 5,892,925

Input Data EIRR 17.39%Unit Economic Benefits (Usc/kWh) Residential 25.4 Industrial 18.8 Commercial 25.4 Irrigation 15.3 O&M Costs 1.50% Losses 24.70% Cost of 33 kV supply $0.1105/kWh at 13.9% interest rate

Actual Connected Customers

Additional Customers Each Year

Annual Costs Net Annual Benefits ($)Year

Annual Energy Sales (MWh) Bulk Supply Required @ 33kV(MWh)

Total Annual Benefits ($)

EIRR = economic internal rate of return, kV = kilovolt, kWh = kilowatt hour, MWh = megawatt hour, O&M = operating and maintenance. Sources: Project completion report mission estimates.

28 Appendix 7

Table A7.7: Financial Evaluation of the Power System Development Program of the Nepal Electricity Authority, 2008–2030

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021-28Generation and SalesPeak load (MW) 515 558 597 603 648 813 885 967 1057 1163 1272 1387 1510 1640 1770 1907 2052 23080Additonal load (MW) 44.87 42.33 39.47 6.28 45.11 164.11 72.78 81.72 90 106 109 115 123 130 130 137 145 1627Total energy generated 1355 1537 1585 1761 1802 1849 2119 2545 2786 3072 3365 3678 4011 4367 4720 5094 5492 62343Total energy available (GWh) 2381 2643 2781 3052 3186 3131 3689 4431 4851 5349 5860 6404 6984 7604 8219 8870 9563 108552Electricity sales in Nepal (GWh) 1654 1854 1936 2127 2250 2158 2603 2837 3093 3371 3674 4005 4365 4758 5187 5653 6162 74077Increase over FY2004 804 1004 1086 1277 1400 1308 1753 1987 2243 2521 2824 3155 3515 3908 4337 4803 5312 67277Tariff (NRs/kWh) 7.33 6.95 6.74 6.75 6.68 6.70 6.96 6.96 6.96 6.96 6.96 6.96 6.96 6.96 6.96 6.96 6.96 56Average tariff ($/kWh) 0.098 0.095 0.092 0.096 0.099 0.093 0.093 0.093 0.093 0.093 0.093 0.093 0.093 0.093 0.093 0.093 0.093 0.093Additional Revenue from Nepal sales ($ million) 78.5 95.0 99.7 122.9 139.0 121.7 162.7 184.5 208.2 234.0 262.1 292.8 326.3 362.8 402.5 445.8 493.1 6244Operating Expenses ($ million)Fuel 1.0 1.8 2.5 2.2 1.8 1.9 2.7 2.9 3.2 3.5 3.9 4.3 4.7 5.2 5.7 6.3 6.9 87Power purchases from IPPs 72.2 78.4 87.0 96.6 110.6 106.9 130.0 133.9 138.0 142.1 146.4 150.8 155.3 159.9 164.7 169.7 174.8 1601Salaries, wages & allowances 18.4 19.4 24.2 25.6 32.1 34.8 40.8 44.1 47.6 51.5 55.6 60.0 64.8 70.0 75.6 81.6 88.2 1013Operation and Administration 23.5 30.6 31.2 37.5 38.7 39.4 44.7 49.2 54.1 59.5 65.4 72.0 79.2 87.1 95.8 105.4 115.9 1458Less Electricity Exports to India (9.0) (8.3) (7.9) (6.9) (5.4) (4.1) (8.1) (8.9) (9.8) (10.7) (11.8) (13.0) (14.3) (15.7) (17.3) (19.0) (20.9) (263.3) Net Operating Costs 106.0 122.0 136.9 155.0 177.8 178.8 210.2 221.3 233.1 245.8 259.4 274.0 289.7 306.5 324.5 343.9 364.8 3895 Increase over FY1996 85.5 101.5 116.4 134.5 157.3 158.3 189.7 200.8 212.6 225.3 238.9 253.5 269.2 286.0 304.0 323.4 344.3 2754Capital Expenditures ($ million)Generation, transmission, and distribution (without 101.4 121.9 118.5 129.7 110.1 112.4 69.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0equity investment)REDTP 2.9 14.3 17.1 10.6 11.7 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtotal Capital Costs 104.3 136.1 135.5 140.3 121.8 112.9 69.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net Annual Financial Benefits ($ million) (111.4) (142.6) (152.2) (151.9) (140.1) (149.5) (96.1) (16.3) (4.5) 8.7 23.2 39.3 57.1 76.8 98.5 122.4 148.8 716.5Financial Rate of Return 11.17%Key Assumptions: 25 year projection period, 10% increase in fuel cost, 8 % increase in salaries, 3% increase in fuel prices, 10% increase in operating and administration, and 0% increase in tariffs.

Basis of Accounts Actual Projected

FIRR = financial internal rate of return, FY = fiscal year, GWh = gigawatt hour, IPP = independent power producer, kWh = kilowatt hour, MW = megawatt, NRs = Nepalese rupees, REDTP = Rural Electrification, Distribution, and Transmission Project. Sources: Project completion report mission estimates.

Appendix 7 29

Table A7.8: Economic Evaluation of the Power System Development Program of the Nepal Electricity Authority, 2008–2030

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021-28Generation and SalesPeak Load (MW) 515 558 597 603 648 813 885 967 1057 1163 1272 1387 1510 1640 1770 1907 2052 23080Additonal Load (MW) 45 42 39 6 45 164 73 82 90 106 109 115 123 130 130 137 145 1627Total Energy Generated 1355 1537 1585 1761 1802 1849 2119 2545 2786 3072 3365 3678 4011 4367 4720 5094 5492 62343Total Energy Available (GWh) 2381 2643 2781 3052 3186 3131 3689 4431 4851 5349 5860 6404 6984 7604 8219 8870 9563 108552Electricity sales in Nepal (GWh) 1654 1854 1936 2127 2250 2158 2603 2837 3093 3371 3674 4005 4365 4758 5187 5653 6162 74077Increase over FY2004 150 350 432 623 746 654 1099 1333 1589 1867 2170 2501 2861 3254 3683 4149 4658 62045Operating Expenses ($ million)Fuel 1.0 1.8 2.5 2.2 1.8 1.9 2.7 2.9 3.2 3.5 3.9 4.3 4.7 5.2 5.7 6.3 6.9 87Power purchases from IPPs 72.2 78.4 87.0 96.6 110.6 106.9 130.0 133.9 138.0 142.1 146.4 150.8 155.3 159.9 164.7 169.7 174.8 1601Salaries, wages, & allowances 16.5 17.5 21.8 23.1 28.9 31.3 36.8 39.7 42.9 46.3 50.0 54.0 58.3 63.0 68.0 73.5 79.4 912Operation and administration 21.2 27.5 28.0 33.8 34.9 35.5 40.2 44.2 48.7 53.5 58.9 64.8 71.2 78.4 86.2 94.8 104.3 1312Less Electricity Exports to India (9.0) (8.3) (7.9) (6.9) (5.4) (4.1) (8.1) (8.9) (9.8) (10.7) (11.8) (13.0) (14.3) (15.7) (17.3) (19.0) (20.9) (263.3) Net Operating Costs 101.8 117.0 131.4 148.7 170.7 171.4 201.6 211.9 222.9 234.7 247.3 260.8 275.3 290.8 307.4 325.2 344.4 3648 Increase over FY2004 91.8 107.0 121.4 138.7 160.7 161.4 191.6 201.9 212.9 224.7 237.3 250.8 265.3 280.8 297.4 315.2 334.4 3568Capital Expenditures ($ million)Generation, transmission, and distribution (without 101.4 121.9 118.5 129.7 110.1 112.4 69.1 0.0 0.0 0.0 0.0equity investment)REDTP 2.9 14.3 17.1 10.6 11.7 0.5 0.0 0.0 0.0 0.0 0.0 Subtotal Capital Costs 104.3 136.1 135.5 140.3 121.8 112.9 69.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net Annual Economic Benefits ($ million) (158.1) (154.3) (147.4) (121.0) (93.3) (108.5) 18.0 136.2 190.0 248.8 313.1 383.5 460.5 544.6 636.6 737.2 847.0 5194Economic Rate of Return 23.39%

cost.

Basis of Accounts Actual Projected

Based on Economic Benefit of $0.254/kWh at a discount rate of 12%, a standard conversion factor of 0.9, 10% increase in fuel cost, 8% increase in salaries, and 10% increase in operating and administration

EIRR = economic internal rate of return, GWh = gigawatt hour, IPP = independent power producer, kWh = kilowatt hour, MW = megawatt, REDTP = Rural Electrification, Distribution, and Transmission Project. Sources: Project completion report mission estimates.