ASIAN DEVELOPMENT BANK PCR:IND 20027

PROJECT COMPLETION REPORT

ON THE

UNCHAHAR THERMAL POWER PROJECT (Loan 907-IND)

IN

INDIA

September 2002

CURRENCY EQUIVALENTS

Currency Unit – rupee/s (Re/Rs)

At Appraisal

15 August 1988 At Project Completion 4 April 2001

Re1.00 = $0.07 $0.02 $1.00 = Rs14.20 Rs46.07

ABBREVIATIONS

ADB – Asian Development Bank AGM – additional general manager CEA – Central Electricity Authority DEA – Department of Economic Affairs EA – Executing Agency EIRR – economic internal rate of return FIRR – financial internal rate of return INRM – India Resident Mission MOEF – Ministry of Environment and Forests NTPC – National Thermal Power Corporation PLF – plant load factor RAP – rehabilitation action plan RRP – Report and Recommendation of the President SEB – State Electricity Board TA – technical assistance UPG – Uttar Pradesh government UPPCB – Uttar Pradesh Pollution Control Board UPRVUN – Uttar Pradesh Rajya Vidyut Utpadhan Nigam UPSEB – Uttar Pradesh State Electricity Board WACC – weighted average cost of capital

WEIGHTS AND MEASURES

V (volt) – unit of electrical pressure kV (kilovolt) – 1,000 volts W (watt) – unit of real power kW (kilowatt) – 1,000 watts MW (megawatt) – 1,000,000 watts GW (gigawatt) – 1,000 megawatts Wh (watt-hour) – unit of electrical energy kWh (kilowatt-hour) – 1,000 Wh GWh (gigawatt-hour) – 1,000,000 kWh TWh (terawatt-hour) – 1,000 GWh load factor – ratio of average power demand to maximum

powerdemand 1 ton of crude oil – 10,000,000 kilocaloriesequivalent (toe)

or 39,680,000 British thermal units

NOTES (i) The fiscal year of the Government and the National Thermal Power Corporation ends on

31 March. FY before a calendar year denotes the year in which the fiscal year ends, e.g. FY2001 ends on 31 March 2001.

(ii) In this report “$” refers to US dollars.

CONTENTS

Page BASIC DATA iii MAP ix I. PROJECT DESCRIPTION 1 II. EVALUATION OF DESIGN AND IMPLEMENTATION 2 A. Relevance of Design and Formulation 2

B. Project Outputs 2 C. Project Costs 3 D. Disbursements 4

E. Project Schedule 4 F. Implementation Arrangements 5 G. Conditions and Covenants 5 H. Consultant Recruitment and Procurement 5

I. Performance of Consultants, Contractors, and Suppliers 6 J. Performance of the Borrower and the Executing Agency 6 K. Performance of ADB 6 III. EVALUATION OF PERFORMANCE 7 A. Relevance 7 B. Efficacy in Achievement of Purpose 7

C. Efficiency in Achievement of Outputs and Purpose 8 D. Preliminary Assessment of Sustainability 9 E. Environmental, Social, and Other Impacts 9

IV. OVERALL ASSESSMENT AND RECOMMENDATIONS 10

A. Overall Assessment 10 B. Lessons Learned 11 C. Recommendations 11

APPENDIXES 1. Project Scope 13 2. Chronology of Main Events in Project Implementation 14 3. Cost Breakdown by Project Components 17 4. Project Costs and Summary of Contracts 18 5. Annual Average Exchange Rate for the Rupee and Dollar 20 6. Project Financing Plan 21 7. Projected and Actual Disbursements of Loan Proceeds 22 8. Implementation Schedule 23 9. Organization Chart and Project Implementation Structure 24 10. Status of Compliance with Major Loan Covenants 25 11. Economic and Financial Evaluation 28 12. Environmental Monitoring Data and Compliance for Environmental Clearance 35 13. Resettlement and Rehabilitation Measures 38 14. Unchahar Stage – 2 Plant Performance (Two Units) 39

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CONTENTS

Page SUPPLEMENTARY APPENDIXES (available upon request) A. NTPC Outstanding Dues as on 31 March 2002 40 B. Settlement of Dues of CPSUs Owed by State Electricity Boards 42 C. Balance Sheets 45 D. Income Statements 46 E. Cash Flow Statements 47 F. Ratio Analysis 48 G. Status of Reforms and Restructuring of State Electricity Boards 49

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BASIC DATA

A. Loan Identification

1. Country India 2. Loan Number 907-IND 3. Loan Title Unchahar Thermal Power Project 4. Borrower India 5. Executing Agency National Thermal Power Corporation (NTPC) 6. Amount of Loan (net of cancelation) $126.676 million First cancellation $15.00 million 30 July 1998 Second cancellation $5.00 million 8 February 1999 Third cancellation $5.00 million 28 December

1999 Fourth cancellation $7.00 million 3 October 2000 Fifth cancellation $1.32 million 4 April 2001 7. Project Completion Report Number PCR:IND 711

B. Loan Data 1. Appraisal

- Date Started 8 June 1988 - Date Completed 23 June 1988

2. Loan Negotiations

- Date Started 29 August 1988 - Date Completed 2 September 1988

3. Date of Board Approval 29 September 1988 4. Date of Loan Agreement 1 December 19881 5. Date of Loan Effectiveness

- In Loan Agreement 1 March 1989 - Actual 30 April 1989 - Number of Extensions 2

6. Closing Date

- In Loan Agreement 30 September 1995 - Actual 4 April 2001 - Number of Extensions 3

7. Terms of Loan - Interest Rate 6 months variable ordinary capital resources (OCR) rate - Maturity (number of years) 25 - Grace Period (number of years) 5

8. Terms of Relending - Interest Rate 6 months variable OCR rate - Maturity (number of years) 25 - Grace Period (number of years) 5

1 The subsidiary Loan Agreement was signed with NTPC on 9 September 1995 and became effective on 14

November 1995.

iv 9. Disbursements

a. Dates

Initial Disbursement Final Disbursement Time Interval

5 Dec 1995

4 Apr 2001 5 years, 4 months

Effective Date Original Closing Date Time Interval

30 Apr 1989 30 Sep 1995 6 years, 5 months

b. Amount ($ million)

Category

Original

Allocation

Last Revised

Allocation

Net Amount Disbursed

Undis- bursed Balance

1. Steam Boilers and

Auxiliaries 90.00 58.22 58.22 0.00

2. Turbine Generators and Auxiliaries

60.00 42.59 42.59 0.00

3. Local Handling Plant 0.00 13.58 13.58 0.00 4. Ash Handling Plant 0.00 5.77 5.77 0.00 5. Control and

Instrumentation 0.00 6.52 6.52 0.00

6. Unallocated 10.00 0.00 0.00 0.00 Total 160.00 126.68 126.68 0.00

10. Local Costs (Financed) 0

C. Project Data

1. Project Cost ($ million)

Cost Appraisal2

Estimate Actual

Foreign Exchange Cost 225.88 127.04 Local Currency Cost 339.03 173.67 Total 564.91 300.71

2 Amounts mentioned are revised cost estimates (November 1993), at the time of approval of change of executing

agency from Uttar Pradesh Rajya Vidyut Utpadhan Nigam (UPRUVN) to NTPC.

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2. Financing Plan ($ million)

Cost Appraisal Estimate3 Actual A. Implementation Costs

1. Borrower-Financed 322.00 144.82 2. ADB-Financed 150.004 126.68 3. Other External Financing

0.00 0.00

Subtotal (A)

472.00 271.50

B. IDC Costs 1. Borrower-Financed 92.91 29.21 2. ADB-Financed 0.00 0.00 3. Other External Financing 0.00 0.00

Subtotal (B)

92.91 29.21

Total 564.91 300.71 ADB = Asian Development Bank, IDC = interest during construction.

3. Cost Breakdown by Project Component ($ million)

Appraisal Estimate4 Actual

Component Foreign Local Total Foreign Local Total

A. Base Cost 1. Structural Steel 0.00 10.43 10.43 0.00 11.70 11.70 2. Civil Works 0.00 52.08 52.08 0.00 31.53 31.53 3. Steam Generator with Associated Auxiliaries

62.90 26.96 89.86 58.35 12.88 71.23

4. Turbine Generator with Associated Auxiliaries

49.15 21.05 70.20 42.82 4.76 47.58

5. Control and Instrumentation

10.38 4.45 14.83 6.52 1.22 7.74

6. Coal Handling System 12.81 5.49 18.30 13.58 11.57 25.15 7. Ash Handling System 5.31 2.28 7.59 5.77 5.35 11.11 8. Miscellaneous Mechanical Equipment

14.96 6.41 21.37 0.00 16.74 16.74

9. Transformers 2.45 1.05 3.50 0.00 4.15 4.15 10. Switchgears 3.96 1.70 5.66 0.00 5.63 5.63 11. Power Cables 3.03 1.30 4.33 0.00 4.34 4.34 12. Miscellaneous Electrical Equipment

4.76 2.04 6.80 0.00 6.94 6.94

13. Tools & Plants, Commissioning, Engineering and Administration

3.46 26.42 29.88 0.00 27.66 27.66

14. Taxes and Duties 0.00 41.50 41.50 0.00 Included above

Included above

Subtotal (A) 173.17 203.16 376.33 127.04 144.46 271.50

3 Amounts mentioned are revised cost estimates (November 1993), at the time of approval of change of executing

agency from UPRVUN to NTPC. 4 Excluding the unallocated $10 million out of the total loan of $160 million.

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Appraisal Estimate5 Actual

Component Foreign Local Total Foreign Local Total

B. Contingencies 1. Physical Contingencies 8.66 13.28 21.94 0.00 0.00 0.00

2. Price Escalation 21.73 51.99 73.73 0.00 0.00 0.00 Subtotal (B) 30.39 65.27 95.67 0.00 0.00 0.00

C. Interest During Construction

22.31 70.60 92.91 0.00 29.21 29.21

Subtotal (C) 22.31 70.60 92.91 0.00 29.21 29.21

Total 225.88 339.03 564.91 127.04 173.67 300.71

Source: Asian Development Bank estimates.

4. Project Schedule

Appraisal Estimate NTPC Estimate6 Actual

Item Start End Start End Start End

Land Acquisition Jan 1989 Jan 1989 Jan 19897

Civil Works Jul 1990 Jun 1994 Aug 1995 Oct 2000 May 1995 Dec 1999

Steam Generator & Auxiliary Jul 1989 Sep 1994 Aug 1995 Jun 2000 Jun 1995 Mar 2000

Turbine Generator & Auxiliary Jul 1989 Mar 1995 Aug 1995 Jun 2000 Jun 1995 Mar 2000

Control & Instrumentation System

Mar 1990 Sep 1994 Oct 1996 Apr 2000 Aug 1997 Dec 1999

Coal Handling System Mar 1990 Mar 1995 Apr 1996 Jun 2000 Oct 1996 Dec 1999

Mechanical Services Oct 1990 Sep 1994 Jul 1996 Mar 2000 Jul 1996 Jan 2000

Transformers Jul 1990 Sep 1994 Feb 1996 May 2000 Aug 1995 Oct 1999

Switchgears Oct 1990 Sep 1994 Aug 1996 May 2000 Jul 1996 Jul 1999

Switchyard Equipment Oct 1990 Sep 1994 Jul 1996 Jun 2000 Mar 1996 Jul 1999

Electrical Services Oct 1990 Sep 1994 Jul 1996 Jun 2000 Aug 1995 Dec 1999

5. Project Performance Report Ratings

Rating Implementation Period Development

Objectives Implementation

Progress From Mar 1990 to Nov 1998 A A From Dec 1998 to Aug 2000 PS HS From Sep 2000 to Oct 2000 PS S From Nov 2000 to Dec 2000 S S

A = highly satisfactory, PS = partly satisfactory, HS = highly satisfactory, S = satisfactory.

5 Amount mentioned are revised cost estimates (November 1993), at the time of approval of change of executing

agency from UPRVUN to NTPC. 6 Start and end dates are revised dates (November 1993) at the time of approval of change of executing agency

from UPRVUN to NTPC. 7 Land was already acquired during the first stage of the Unchahar Thermal Power Plant.

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D. Data on Asian Development Bank Missions

Name of Mission

Date

Number of

Persons

Number of Person-

Days

Specialization of Membersa

Fact –Finding 2–18 Feb 1988 4 68 a,b,c,d Appraisal 8–23 Jun 1988 6 84 a,b,c,g,h Inception 16–20 Oct 1989 2 10 a Special Loan Administration /Review 1

7–15 Mar 1990 2 18 a,b

Review 2 10–12,19 Nov 1990 2 8 a Review 3 12–22 Feb 1991 2 22 a,b Fact –Finding 24 Sep–3 Oct 1991 3 30 a Consultation 4–19 Feb 1992 3 32 a,b Review 4 7 Sep 1992 1 1 a Review 5 12–29 Jul 1993 2 18 a,b Review 6 25 Nov–5 Dec 1996 5 55 a,d,i,j Review 7 4–7,17,25 Mar 1998 1 6 a Review 8 11–15,25 Jan 1999 2 12 a Review 9 20–23 Oct 1999 2 8 a Review 10 17–19 Jul 2000 2 6 a Project Completion Review 11b

17–19 Apr 2002 2 6 a,i

a a = engineer, b = financial analyst, c = counsel, d = economist, e = procurement/consultant specialist, f = control officer, g = programs officer, h = environment specialist, i = loan administration staff, j = young

professional. b This report was prepared by V. R. Karbar, Project Implementation Officer (Energy), and R. Kapoor, Assistant Project Analyst, India Resident Mission (INRM). J. Srinivasan, Senior Control Officer, INRM helped calculate FIRRs and EIRRs.

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Map 1

I. PROJECT DESCRIPTION

1. India has large reserves of coal. To make productive use of these resources and to redress the worsening balance-of-payments situation resulting from the steep increase in imports of oil, in the 1980s the Government decided to set up a number of coal-based thermal power plants (Appraisal Report). The Unchahar Thermal Power Project of Uttar Pradesh Rajya Vidyut Utpadhan Nigam (UPRVUN), with a maximum capacity of 1,050 megawatts (MW), was developed as a component of the Government’s long-term National Power Development Program to meet the country’s energy needs and ease the country’s dependence on imports. To meet the Government’s long-term objectives, the Central Electricity Authority (CEA) prepared an investment plan for the power sector. The Project was part of CEA’s long-term, least-cost generation investment plan for the northern region. (Report and Recommendation of the President [RRP], para. 75). The Uttar Pradesh government (UPG) entrusted project implementation to UPRVUN. It commissioned the first 210 MW unit in August 1989, and the second, in June 1990. The present scope of additional generating capacity of 2 x 210 MW was taken up in the second stage of the Project. At appraisal in 1987, the Uttar Pradesh State Electricity Board (UPSEB), with a total installed capacity of 4,540 MW under the state sector and an additional 3,591 gigawatt-hours (GWh) from central power sector undertakings (CPSUs), met only 13,655 GWh of demand, with unmet demand at 15%. Peak demand shortage was about 22%. During financial year (FY) 1988, generation constraints caused regular load shedding of 1,326 MW. CEA forecasts1 up to 2000 indicated that load shedding would persist in spite of planned2 capacity expansion plans undertaken by the UPG and CPSUs (Appraisal Report), as projected demand for power was anticipated to exceed the planned capacity expansion. In September 1988, ADB approved a loan of $160 million, with UPRVUN as executing agency (EA), to help implement the second stage of the generating capacity expansion program—the Unchahar Thermal Power Extension Project—consisting of two 210 MW units to produce a net 2,575 GWh annually.

2. After the loan was approved in 1988, UPRVUN had serious financial and management problems, and project construction could not start. Since commissioning, the first two 210 MW units were owned and operated by UPRVUN. In February 1992, the National Thermal Power Corporation (NTPC) purchased the two units from UPRVUN in lieu of payment of dues by the UPG to NTPC. NTPC proposed to implement the second stage of the Project, and with Government support requested that the ADB project loan be re-lent by the Government to NTPC. In November 1993, ADB approved the request for change in EA, and NTPC became the EA. The appraised project cost estimates and implementation schedule and arrangements were revised in November 1993.

3. At appraisal, the Project’s primary objective was to mitigate the power shortage in Uttar Pradesh by providing an additional 420 MW of generating capacity to produce a net output of about 2,575 GWh. After NTPC became the EA, the project objective was redefined to mitigate the power shortage in the northern region, with anticipated net annual output of 2,280 GWh.

4. The Project comprised the following major components3 (Appendix 1): (i) civil works for site preparation, foundation, power station building, cooling water systems, and other facilities; (ii) two 700-ton/hour coal-fired steam boilers and auxiliaries; (iii) two 210 MW reheat steam 1 Thirteenth Electric Power Survey of India, December 1987 2 From 1988 to 1998, about 4,000 MW of new generation projects were ongoing and sanctioned by Government,

and about 1,100 MW cleared by CEA (including the Project) in Uttar Pradesh. 3 Components for consultancy service and training were taken out of the scope of the Project subsequent to

change in EA in November 1993.

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turbine generators and auxiliaries; (iv) instrumentation and control systems; (v) coal- and ash-handling systems; (vi) water treatment and chlorination plants; (vi) miscellaneous mechanical equipment and systems; (vii) precipitators, cooling towers, and air pollution sampling equipment; (ix) transformers, switchyard, and other miscellaneous electrical equipment; (x) consulting services; and (xi) training. The main components under ADB financing are (i) 2-ton/hour coal-fired steam boilers and auxiliaries; (ii) two 210 MW reheat steam turbine generators and auxiliaries; (iii) instrumentation and control systems; and (iv) coal- and ash-handling systems.

5. The Project was developed as a load center-based power plant using coal from Jharia and North Karanpura in Bihar state, about 600 kilometer east of the project site. The coal is transported by rail; lines and rolling stock are adequate.

II. EVALUATION OF DESIGN AND IMPLEMENTATION

6. The main events in project implementation are given chronologically in Appendix 2.

A. Relevance of Design and Formulation

7. The most serious energy issue is the power and oil shortage, which constrains economic development. At appraisal, power shortages were about 10% of demand for electricity and up to 30% of peak demand. Load shedding caused industrial production losses of about 3% or approximately $1 billion annually (Appraisal Report, para. 5). As oil consumption steadily increased, so did India’s dependence on imported oil, worsening the balance of payments. Oil imports, which comprised 35.1% of oil requirements in FY1987, were expected to rise to 50% by the mid-1990s. The latest figures indicate that oil imports meet about 70% of the total requirement. Still, growing consumption of traditional or noncommercial energy forms contributed to deforestation. Since the 1980s, therefore, India’s energy strategy has stressed development of indigenous energy, and formation of adequate supply and distribution systems. The Seventh Plan FY1986–1990 allotted about Rs548 billion ($42 billion) to energy or about 30% of total public outlay. The Eighth Plan allocated about Rs1,155 billion (about 26.6% of total public outlay), and the Ninth Plan, about Rs1,600 billion (about 31.4%). At appraisal, EA was envisaged to contribute up to 73% of the total project cost. At project completion, total EA contribution was about 62%. The Project was highly relevant to the Government’s sector strategy at appraisal and at completion.

8. At appraisal, ADB’s country operational strategy for India was to mitigate the constraints, caused by infrastructure bottlenecks, on industrial growth and effective utilization of existing industrial capacity. ADB’s assistance was to expand power-generating capacity by 420 MW for northern India and was highly relevant to ADB’s strategy. ADB support to develop the Project was equally relevant at appraisal as well as at completion, since infrastructure bottlenecks still hinder industrial growth. B. Project Outputs

9. At appraisal, the Project comprised the installation and commissioning of the following components to develop the second phase, consisting of two 210 MW units with anticipated annual output of 2,575 GWh: (i) civil works for site preparation, foundation, power station building, cooling water systems, and other facilities; (ii) two coal-fired steam boilers, with auxiliaries; (iii) two 210 MW reheat steam turbine generators, with auxiliaries; (iv) instrumentation and control systems; (v) coal- and ash-handling systems; (vi) water treatment and chlorination plants; (vii) miscellaneous mechanical equipment and systems; (viii)

3

precipitators, cooling towers and air pollution sampling equipment; and (ix) transformers, switchyard, and other miscellaneous electrical equipment. Consulting services and staff training were also proposed. However, when ADB approved replacing UPRVUN with NTPC as EA in November 1993, consulting services and staff training were excluded as NTPC had adequate trained personnel and experienced engineering staff.

10. As envisaged during appraisal, all the components have been installed and commissioned successfully without delay. The first unit was synchronized on 27 January 1999, the second, on 22 October 1999. NTPC’s effective and efficient operation of the power plants and prudent plant maintenance enabled the two units to generate about 3,069 GWh of energy during FY2002 against the appraised annual energy output of 2,280 GWh, exceeding the appraised output by about 34.6%.

C. Project Costs

11. At appraisal, the total project cost was estimated at $598 million equivalent comprising $297 million (49.7%) in foreign currency and $301 million (50.3%) in local currency. The cost estimates were revised in November 1993, when the change of EA was approved. The revised total project was estimated at $564.91 million equivalent (as per the prevailing prices in 1993) comprising $225.88 million (40%) in foreign currency and $339.03 (60%) in local currency. The ADB loan at appraisal was $160.00 million, of which only $126.68 million (79.2%) was utilized. Cost savings of $264.20 million equivalent (46.8%) comprised $98.84 million in foreign currency and $165.36 million in local currency. Appendix 3 compares estimated (revised in 1993) and actual project costs. The project costs and summary of contracts are in Appendix 4. Appendix 5 provides the average exchange rates used to convert local currency to the dollar equivalent.

12. When the change of EA was approved in November, NTPC’s contribution to the Project was estimated at $414.91 million (73.5%), with the balance of $150.00 million to be financed by ADB (26.6%), with an unallocated $10.00 million in ADB’s total loan amount of $160.00 million. At NTPC’s request, in September 1996, ADB reallocated the loan proceeds, including the unallocated portion. The allocation of loan proceeds at appraisal and as revised in September 1996 are in Tables 1 and 2.

Table 1: Allocation of Loan Proceeds at Appraisal

($ million)

Category Item Description Amount Allocated I II

Equipment A. Steam Boilers and Auxiliaries B. Turbine Generators and Auxiliaries Unallocated

90 60

10

Total 160

4

Table 2: Revised Allocation of Loan Proceeds ($ million)

Category Item Description Amount Allocated I II

Equipment A. Steam Boilers and Auxiliaries

1. Coal Handling Plant 2. Ash Handling Plant

B. Turbine Generators and Auxiliaries 1. Control & Instrumentation

Unallocated (transferred to A)

68.0 22.5 9.5 53.0 7.0

0.0

Total 160.0

13. Actual project cost estimates show NTPC’s contribution to be $174.03 million (57.9%), and borrowings from ADB, $126.68 million (42.1%). Appendix 6 compares the revised financing plan approved in November 1993 and actual financing plan. The share of ADB increased from 26.6% to 42.1% despite the decrease in the loan amount from $160.00 million to $126.68 million.

14. The foreign exchange cost savings are attributable to (i) lower-than-estimated costs incurred in equipment procurement ($46.13 million) due to competition in the market; (ii) savings in physical and price escalation ($30.40 million), which were not needed as the Project was completed as scheduled at the time of contract award; and (iii) savings in interest during construction ($22.31 million). Local currency savings in dollar terms are largely due to (i) savings in physical and price contingencies ($65.27 million); (ii) savings in interest during construction ($41.39 million); and (iii) lower-than-estimated costs incurred in equipment procurement and civil works ($58.70 million).

D. Disbursements

15. Disbursements totaled $126.68 million out of the original loan amount of $160.00 million; $33.32 million was canceled in four stages as loan savings. Initial disbursements under the loan started on 5 December 1995, and the final disbursement was on 4 April 2001, or 64 months later. No funds were disbursed during 1989-1994 as project implementation could start only in April 1995, with the award of contract for the main plant in May 1995. Actual disbursements picked up significantly and exceeded initial projections (Appendix 7). The imprest-fund procedure was used although the statement-of-expenditures (SOE) procedure provides for disbursements. NTPC did not utilize SOE facility and appreciated the resulting additional liquidity. NTPC informed ADB that the imprest fund facility enabled it to make foreign currency payments to contractors on time and expeditiously.

E. Project Schedule

16. The main events during project implementation are in Appendix 8. The Project was scheduled to start in July 1989. The first unit was to be commissioned in September 1994, the second, in March 1995, implemented over 72 months. These dates were delayed significantly as UPRVUN could not start implementing the Project as originally scheduled. In November 1993, ADB approved the replacement of UPRVUN with NTPC as EA and revised the implementation schedule and arrangements. The new schedule envisaged issue of tender documents in November 1993, award of the main contracts in August 1994, commissioning of

5

the first unit in July 1998 and the second in December 1998, and implementation over 52 months. Due to delay in obtaining the Government’s approval for the investment, implementation started in April 1995 and the main plant award was placed in May 1995, about 9 months behind schedule. The first unit was commissioned in January 1999, the second, in October 1999. The 16 stator bars of the first unit were damaged due to an earth fault that occurred on 27 July 1999. The generator was repaired at the supplier’s works and recommissioned in January 2001. NTPC could have implemented the Project in 53 months from the date of the main plant award.

F. Implementation Arrangements

17. The implementation arrangements were the same as envisaged when ADB approved the change in EA, and ADB found the implementation arrangements to be satisfactory. The general manager of Unchahar Station was in charge of the Project. He was assisted by two additional general managers (AGMs). The project AGM was responsible for construction and erection; the operations and maintenance AGM, for commissioning. The executive director for corporate contracts and materials handled all contract awards; and the executive director for corporate finance, project finances. Project progress was reviewed quarterly by the director of projects, who was responsible for all NTPC projects, during project review, contract review, and technical coordination meetings. The executive director for corporate planning was the overall coordinator with ADB. ADB considered the implementation arrangement to be adequate as overall coordination existed and a proper project management system was in place. The project implementation structure is in Appendix 9.

G. Conditions and Covenants

18. The status of compliance with key loan covenants is in Appendix 10. Most of the covenants, including that on timely submission of the audited accounts and financial statements, were complied with, except for that requiring NTPC to maintain its receivables at a level not exceeding an amount equivalent to the proceeds of power sales for the 2 preceding months. Due to the poor financial state of the state electricity boards (SEBs) and other power utilities, NTPC’s outstanding receivables were equivalent to 7.7 months billing as of 31 March 2002. The SEBs’ condition can be directly attributed to low revenue, which is usually nowhere near the actual cost of the power sold and due to (i) huge transmission and distribution losses (commercial and technical); (ii) irrational power tariffs; (iii) pilferage; (iv) very low agricultural tariff or free power to agriculture load; (v) subsidies; and (vi) inefficient operations and political interference in SEB management. SEBs thus failed to generate enough revenue to pay for the power from CPSUs such as NTPC and Power Grid, and defaulted on payments. The statement on NTPC’s outstanding dues as of 31 March 2002 is in Appendix A. A brief note on NTPC’s various measures to maintain receivables at a level not exceeding an amount equivalent to the proceeds of power sales for the 2 preceding months is in Appendix B. H. Consultant Recruitment and Procurement

1. Consultant Recruitment

19. Recruitment of a consultant for design and construction supervision was excluded from the project scope when ADB approved NTPC as EA, as it had experienced engineering staff who could execute the Project.

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2. Procurement

20. NTPC followed ADB’s Guidelines for Procurement for ADB-financed contracts. For other contracts NTPC followed its own tendering procedures. The revised implementation schedule envisaged issue of tender documents for contracts in November 1993; award of the main contracts in August 1994; and commissioning of the first unit in July 1998, and the second, in December 1998. However, implementation was delayed by slow government investment approval, which was obtained in April 1995. The first unit was to be completed in January 2000, the second, in July 2000. NTPC placed the main contract award in May 1995, after a 9-month delay. While no procedural problems were encountered, the control and instrumentation contract award was delayed by 10 months, the ash-handling plant, by 11 months, mainly due to prolonged clarifications sought by the bidders. However, the two packages were executed on time without affecting the commissioning of first and second units.

I. Performance of Consultants, Contractors, and Suppliers

21. NTPC reported that the performance of all the contractors and suppliers was generally satisfactory. All the goods complied with the required specifications and other parameters in the contracts, and the contracts were executed without difficulty.

J. Performance of the Borrower and Executing Agency

22. The Government was the Borrower, and UPRVUN and NTPC were the executing agencies (EAs). Performance of the Government and UPRVUN was unsatisfactory. The Government took an unusually long time to approve NTPC’s investment. UPRVUN could not implement the Project for almost 2 years since the loan was declared effective in April 1989—a fact that UPRVUN did not tell ADB. However, after obtaining Government investment approval in April 1995, NTPC performed satisfactorily during project implementation. Operation of the power station since its commissioning by NTPC was also satisfactory. Despite the 10-month delay in the award of the control and instrumentation package, and the 11-month delay in that of the ash-handling plant, both units were commissioned ahead of schedule due to NTPC’s prudent management and implementation practices. NTPC informed ADB that to offset any delays in contract awarding, NTPC follows the in-house revised-scheduling practice called the best-efforts schedule, which facilitated the implementation of the two packages.

K. Performance of ADB 23. ADB closely monitored project progress, regularly monitored the Project through review missions, and advised NTPC staff to familiarize them with ADB’s procurement guidelines and procedures. However, in the initial years of project implementation, ADB could have reviewed the reasons for implementation delay and taken them up with the Government.

24. The India Resident Mission also closely monitored project administration. ADB, NTPC, and Department of Economic Affairs officials held many tripartite meetings, which improved NTPC’s performance. Various timely corrective measures were suggested and implemented as a result of these reviews. Thus, ADB’s overall performance was satisfactory.

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III. EVALUATION OF PERFORMANCE

A. Relevance 25. At appraisal and completion, the Project was rated highly relevant to the Government and ADB power sector strategy (paras. 7 and 8). The Project’s primary objective at appraisal was to mitigate the power shortage in Uttar Pradesh, with project implementation entrusted to UPRVUN. However, the project objective was redefined when ADB approved NTPC as the new EA. The Project was to provide a net annual energy output of about 2,280 GWh to the northern power grid. The allocation of power from the Project to the various northern states is in Table 3.

Table 3: Allocation of Power to Northern States

State Allocation

(MW) Uttar Pradesh Haryana Jammu and Kashmir Himachal Pradesh Punjab Rajasthan Delhi Unallocated

144 23 30 12 60 38 47 66

Total 420 MW=megawatt

26. Although the Project provides 420 MW of generating capacity, the northern region still has power shortages and the resulting load shedding. The peak power and energy shortages for FY2002 are 1,854 MW (8%) and 7,973 GWh (5.3%) in spite of the region’s total installed capacity of 27,462 MW. The Government continues to pursue capacity expansion, unbundling of SEBs, distribution reforms, realistic tariff setting by independent regulators, reduction of transmission and distribution losses, and private sector participation. To provide power on demand by 2012, the Government has a program to expand capacity by 100,000 MW. Since the early 1990s, ADB’s power sector strategy has been to support comprehensive reform of the state institutional and regulatory frameworks within an appropriate national power policy by emphasizing (i) restructuring and commercialization of SEBs, (ii) rationalization of power tariffs, (iii) establishment of independent regulatory commissions, and (iv) improvement in demand-side management and efficiency.

B. Efficacy in Achievement of Purpose 27. The Project achieved its immediate objective of providing 420 MW to partly mitigate the power shortage in the northern region. The Project was designed to provide a net annual energy output of about 2,280 GWh. Due to NTPC’s effective and efficient operation of the power plant and prudent plant maintenance, the two units could generate about 3,069 GWh of net energy in FY2002, exceeding the appraised output by 34.6%.

28. The Project also achieved its long-term objective of supporting economic development by mitigating the power shortage in the northern region by supplying 3,069 GWh of energy in FY2002, reducing the power shortage to about 7,973 GWh. The Project is expected to generate

8

and supply 2,500–3,000 GWh to the northern region, which has the second-highest power deficit in the country.

C. Efficiency in Achievement of Outputs and Purpose 29. The Project is rated efficient.

1. Financial Internal Rate of Return 30. The financial evaluation of the Project was done incrementally using the sales data provided by NTPC and a plant load factor (PLF) of 85%, and considering the total actual project cost. The recalculated financial internal rate of return (FIRR) is 10.97% against a weighted average cost of capital (WACC) of 9.07%, which compares well with the appraisal estimate of 11.26% when WACC was estimated at 16.2%. The Central Electricity Regulatory Commission has yet to finalize the tariff for the new facilities. The tariffs, therefore, have been estimated based on the model that would usually be adopted by the commission, assuming that the PLF is 68.5%. Any increase or decrease in WACC would be automatically reflected in higher or lower tariffs as they are worked out on a cost-plus basis. The major assumptions used in the financial evaluation, and the detailed calculations for FIRR are in Appendix 11. Balance sheets, income statements, cash-flow statements, and ratio analysis of NTPC are in Appendixes C, D, E, and F, respectively.

2. Economic Internal Rate of Return 31. Current tariff levels represent consumers’ minimum willingness to pay, and the costs of alternative energy supply represent maximum willingness to pay for more electricity. The average of these two values is the average willingness to pay for more electricity. Some proportion of electricity supply from the Project will displace alternative energy sources that would otherwise be used with the Project. The significant difference between local financial and economic border prices arises due to the incidence of a substantial tax element included in local financial prices. The overall weighted economic value of electricity supplied by the Project is estimated to be Rs3.27 at border prices. 32. The economic evaluation of the Project was carried out incrementally, considering (i) actual generation in FY2001 and FY2002, and estimating a PLF of 85% for future years; (ii) economic costs of the Project (based on financial costs adjusted for duties and taxes); and (iii) border prices for fuels. The economic internal rate of return (EIRR) is estimated at 19.4%, significantly higher than the 13.6% estimated at appraisal. The higher EIRR is due to a substantially lower project cost, estimated at Rs16.1 billion in 2001 prices, as against the appraisal estimate of Rs27.6 billion in 2001 prices—a saving of 41.7%. The significant tax element on fuel, which is excluded in economic border prices, also contributed to the higher EIRR. The border prices of fuel are significantly lower than the financial prices due to a high tax element on diesel. The financial price of diesel is Rs17.50 per liter, while the border price of diesel is about Rs8.47 per liter. The EIRR indicates that the Project is expected to provide an adequate return to the economy. Major assumptions used in the economic evaluation and the detailed calculations for EIRR are in Appendix 11.

9

D. Preliminary Assessment of Sustainability 33. The technical sustainability of the Project is high for the following reasons:

(i) Northern India suffered power shortages of 6.5% in FY2000, 8.6% in FY2001, and 5.3% in FY2002. The demand supply gap is expected to continue and may even worsen. CEA forecasts that by the end of FY2007, the power shortage of 16.4% may deteriorate as assumed in CEA’s perspective plan study for 1997-2012. Demand for the project-generated power will be adequate.

(ii) Operation performance figures such as PLF, plant availability factor, and specific

fuel consumption of plant (Appendix 14) indicate that the unit cost of the project-generated power will be competitive and may be reasonably cheaper than that of power generated by newer plants.

(iii) NTPC has demonstrated that it can operate power plants at efficiency levels

comparable to those of well-run utilities abroad. The first coal-fired 200 MW unit of Singrauli Super Thermal Power Plant, commissioned in 1982 by NTPC, is one such facility.

34. As project tariffs are determined based on cost plus methodology, which ensure the recovery of costs incurred at a normative PLF of 68.5% and return on equity of 16.0%, with incentives for better-performing plants, the Project is expected to be financially sustainable. However, NTPC must expeditiously bring down its outstanding receivables position to the comfortable level of 2.0 months from the present 7.7 months billing, or else jeopardize the commercial sustainability of NTPC plants in general and the Unchahar Thermal Power Project in particular. As the FIRR exceeds the WACC, the Project is financially viable (para.30), and returns from it will contribute to NTPC’s overall financial health. 35. On 17 April 2002, the Government accepted the recommendations of the Ahluwalia Committee for one-time settlement of total dues from SEBs and full payment of current dues. The successful implementation of these recommendations is expected to bring the outstanding receivables position to a comfortable level. The Mission is also of the view that realizing the objectives of the reforms and SEB restructuring programs, such as achieving minimum 3% return on net fixed assets, would substantially improve SEBs’ financial condition by ensuring timely payment to NTPC for the power purchased from this Project, mitigating the commercial and financial project risks, and improving project sustainability. E. Environmental, Social, and Other Impacts 36. The power plant was designed to meet the environmental standards of the environmental clearance certificate issued by the Ministry of Environment and Forests (MOEF) and Uttar Pradesh Pollution Control Board (UPPCB). Environmental pollution-mitigating equipment installed are (i) a 220-meter multiflue chimney; (ii) electrostatic precipitators of 99.5% efficiency; (iii) a 264-hectare (ha) ash disposal area adequate for all four units for 10 years of operation (NTPC is developing an additional 80 ha ash disposal area adequate to cover the life span of the four units); (iv) effluent-monitoring equipment; (v) dust extraction and suppression systems; and (vi) ash water-recycling system. NTPC has planted more than 700,000 trees as a part of afforrestation and greenbelt development around the plant. NTPC spent about Rs1,261.7 million (about $26 million) on these measures. An environmental management group headed by

10

a senior manager at the power station monitors the quality of effluents and conducts regular tests specified in the environmental management plans. UPPCB also conducts its own tests. Details of test results and compliance with MOEF conditions are in Appendix 12. The Project fully complied with standards for ambient quality, stack emission, and liquid effluent. The Project is required to ensure 100% commercial utilization of dry fly ash. NTPC informed the Project Completion Report Mission that about 37% of ash produced is commercially utilized, part of it to manufacture bricks for in-house use and the rest supplied free to nearby cement manufacturers as per Government notification.

37. The site for the plant was developed and resettlement satisfactorily completed in stage 1 of the Project (para. 16 of Board-approved paper, India: Loan No. 907-IND: Unchahar Thermal Power Extension Project – Change in Executing Agency and Implementation Arrangments, 6 October 1993). Under the Indian Land Acquisition Act 1984, NTPC acquired about 100 ha more for the ash pond and ash pipeline corridor, affecting 541 persons. Rs13.1 million ($280,000) was paid to compensate private landowners. Although more than 90% of the affected people (492 out of 541) lost less than 4,000 square meters and were affected only marginally, NTPC prepared a rehabilitation action plan (RAP) as per NTPC’s 1993 resettlement and rehabilitation policy, which was approved by the Government and endorsed by the World Bank as conforming to its program implementation guidelines. The RAP has a budget of Rs33.68 million ($720,000) and is scheduled for completion by September 2003.

38. The RAP covers various infrastructure development activities such as construction of roads, drains, culverts, community centers, and school buildings; installation of hand pumps; training program for skill development; and self-employment schemes. Income-generating schemes have so far helped 121 people set up dairy, poultry, goat-keeping, and retail businesses. Another 60 people are being screened for eligibility to benefit from income-generating schemes. NTPC informed ADB that the RAP is being implemented in consultation with the Unchahar Block and District Rural Development Authority, UPG, and Raibarely. The details of various NTPC rehabilitation and resettlement measures are in Appendix 13.

IV. OVERALL ASSESSMENT AND RECOMMENDATIONS

A. Overall Assessment

39. In general, the Project is considered successful in view of the following:

(i) Although completion was considerably delayed, the Project has been implemented substantially as conceived at appraisal. The Project was estimated to be completed by 30 September 1994, over 72 months. It was completed in October 1999, delayed by about 61 months. The appraisal schedule was realistic and feasible compared to the implementation period required by other SEBs to set up power stations of similar size and capacity. The main causes for delay were the following: (a) although tenders for the Project were invited in 1989, UPRVUN did not award contracts until the end of 1991; (b) ADB decided to replace UPRVUN with NTPC as EA; and (c) Government approval of NTPC was delayed. After ADB approved the change of EA in November 1993, project implementation started in May 1995, when NTPC obtained Government approval. As per the implementation schedule agreed upon between the Government and NTPC, the first unit was to be commissioned in January 2000, the second, in July 2000. The units were commissioned in January and October 1999, respectively.

11

(ii) The project objective of partly mitigating the power shortage in the northern region, which is reeling under regular power shedding, was achieved. The Project generated and supplied about 3,069 GWh to the northern region in FY2002, or about 2% of the total requirement for FY2002.

(iii) NTPC achieved high power plant operational efficiencies (Appendix 14) and

project sustainability (paras. 33-35).

B. Lessons Learned

40. In addition to the merits of the project, ADB must also evaluate other issues such as the EA’s capability and past performance to execute the project within schedule and budget. 41. NTPC has demonstrated that it can turn around poorly performing power plants within a reasonable time. 42. The successful completion of infrastructure projects of this scale requires evaluation of the EA’s preparedness and commitment to start project implementation as envisaged. 43. The Mission is of the view that to curtail procurement delays, ADB may consider deputing a procurement specialist with sector-specific experience as a part of the inception mission or advise the EA to hire an experienced consultant to prepare and evaluate bid documents. Doing so may substantially improve the quality of bid documents and reduce the time needed to review and finalize bid documents and evaluation reports. 44. Regular discussions with Government on implementing assurances under the Project prompted the Government to increase the rate of return on NTPC’s equity from 12% to 16% and address the issue of balance-of-accounts receivables (Appendix B). C. Recommendations 1. Project Related

a. Future Monitoring

45. All project components have been successfully implemented and the two units are operating commercially. As NTPC has a long and successful track record of efficiently operating coal-fired generating plants, no future project monitoring by ADB is required. b. Covenants

46. Most of the covenants were complied with, except for that requiring NTPC to maintain its receivables at a level not exceeding an amount equivalent to the proceeds of power sales for the 2 preceding months. Due to the poor financial state of the SEBs and other power utilities, NTPC’s standing receivables were equivalent to 7.7 months billing as of 31 March 2002. NTPC said that, based on the Ahluwalia Committee’s recommendations for one-time settlement of total dues, it is encouraging state governments to sign tripartite agreements (Appendix B, paras. 1-4). The committee recommended securitization of total dues as of 30 September 2001, and full payment of current dues. The successful implementation of these recommendations should improve the outstanding receivables position to a comfortable level of 2 months and improve the financial sustainability of the Project and NTPC operations. NTPC also said that Andhra

12

Pradesh, which has signed a tripartite agreement, has been receiving current payments regularly and its outstanding current dues position is just 1 month (Appendix A). This is a positive development and the Mission expects that other states will follow in view of the fiscal benefits accruing through compliance with the recommendations.

c. Further Action or Follow-up

47. The Project does not require any specific future action. The reliability and future performance of the power plant are closely monitored by NTPC as well as by beneficiaries of the Project at the Northern Regional Electricity Board, which the Ministry of Power adjudged ninth-best performing power plant in FY2001, and fifth best in FY2002. However, ADB needs to monitor the implementation of the Ahluwalia Committee recommendations.

2. General

48. Since its creation in 1975, NTPC has become the largest electric utility in India, with 20,092 MW of installed capacity in operation as of March 2002. As NTPC’s share of total power generation has increased steadily to about 26%, so has the agency’s role and influence in the sector. NTPC has also demonstrated that a public sector utility can be operated as efficiently as well-run private utilities in India and abroad. NTPC’s investments in new generating capacity generally have been completed without time and cost overruns, reflecting the agency’s strong management capability. 49. NTPC’s capacity expansion program envisages development of 20,000 MW generating capacity by 2012. For the first time, supercritical technology is being adopted in India at NTPC's Sipat Power Project, with installed capacity of 3 x 660 MW. NTPC requires Rs1,100 billion ($22.5 billion) worth of investments in the next 10 years. ADB may consider supporting NTPC, particularly to develop supercritical technology power projects, as the capital cost per MW of these units is lower than that of the 500 MW units, lowering generating costs.4 50. As it has developed strong management and technical capabilities and is a major stakeholder in the power sector, NTPC may consider investing in distribution to make it commercially viable, beginning with a few state-level distribution circles. Any NTPC distribution initiatives may be considered for ADB support. 51. In addition to the merits of the project, ADB must also evaluate other issues such as the EA’s capability and past performance to execute the project within schedule and budget. 52. The successful completion of infrastructure projects of this scale requires evaluation of the EA’s preparedness and commitment to start project implementation as envisaged. Resident Mission staff should participate more in the early phases of the project cycle. 53. Since 1991, the central and state governments have taken various measures to reform and restructure the power sector (Appendix G).

4 As a result of adoption of supercritical technology units of 660 MW instead of 500 MW for the Sipat Power

Project, CEA estimated capital cost savings at $189 million.

Appendix 1 13

PROJECT SCOPE

The project scope as envisaged at appraisal in 1988, when Uttar Pradesh Rajya Vidyut Utpadan Nigam (UPRVUN) was to be the executing agency (EA), was as follows. The Project consisted of phase 2 (2 x 210 megawatt [MW]) of a three-phase program for the Unchahar Power Station. Phase 1 (2 x 210 MW), begun in 1982 and financed entirely from government resources, is completed, while phase 3 (1 x 210 MW) is being planned. The Project comprised the following components:

(i) civil works for site preparation, foundation, power station building, cooling water systems, and other facilities;

(ii) two coal-fired steam boilers, complete with auxiliaries;

(iii) two 210 MW reheat steam turbine-generators, complete with auxiliaries;

(iv) instrumentation and control systems;

(v) coal- and ash-handling systems;

(vi) water treatment and chlorination plants;

(vii) miscellaneous mechanical equipment and systems;

(viii) precipitators, cooling towers, and air pollution sampling equipment; (ix) transformers, switchyard, and other miscellaneous electrical equipment; (x) consulting services; and (xi) training for UPRVUN staff.

In 1993, UPRVUN was replaced by the National Thermal Power Corporation (NTPC) as

EA. The project scope remained the same, except that the training and consultant components were eliminated as NTPC had adequate trained personnel to operate the plant, and experienced engineering staff who could execute the Project.

14 Appendix 2

CHRONOLOGY OF MAIN EVENTS IN PROJECT IMPLEMENTATION

Date Event 1988 2–18 Feb Fact-finding (1)1 16 May Management review meeting 8–23 Jun Appraisal 9 Aug Staff review committee meeting 29 Aug–2 Sep Loan negotiations 29 Sep Board approval 1 Dec Signing of loan and guarantee agreements 1989 30 Apr Declaration of loan effectivity 16–20 Oct Inception mission 1990 7–15 Mar Special Loan Administration and Review Mission (1). The executing

agency (EA) asked for help in major procurement exercises. The mission also reviewed the financial status of Uttar Pradesh Rajya Vidyut Utpadan Nigam (UPRVUN), the project EA.

10–12,19 Nov Review Mission (2). 1991 12–22 Feb Review Mission (3). 24 Sep–3 Oct Fact-finding (2). A mission visited New Delhi, following a request from the

Government and a visit to ADB headquarters by a delegation from the National Thermal Power Corporation (NTPC) regarding the replacement of UPRVUN with NTPC as EA. The mission studied the status of NTPC’s proposed takeover of the Unchahar power plant and the possible transfer of the ADB loan from UPRVUN to NTPC.

1992 13 Feb The Unchahar power plant was sold to NTPC to enable UPSEB to pay off

its debt to NTPC. With Government support, NTPC requested that the ADB loan be re-lent by the Government to NTPC.

4–19 Feb A consultation mission visited India to discuss various issues related to the proposed change in EA.

7 Sep Review Mission (4). The mission met with government and NTPC officials in New Delhi to discuss the project.

1993 14–15 Jan Negotiations with the Government and NTPC were held at ADB

headquarters on amending the Loan Agreement and on a new project agreement.

10 Jun The Public Investment Board approved Unchahar II. 12–29 Jul Review Mission (5). The mission visited New Delhi to discuss with NTPC

officials the change of project scope and implementation details. 16 Nov ADB approved the Government’s request that NTPC become the project

EA beginning 27 October 1993. 1 The first Fact-finding mission visited India when the executing agency was UPRVUN and the second Fact-finding visited when it was proposed to change the executing agency to NTPC.

Appendix 2 15 1995 19 Apr The Cabinet Committee on Economic Affairs granted investment approval

for Unchahar II. As per Government approval, the first unit was to be commissioned in January 2000, the second, in July 2000.

31 May The contract was awarded to supply a steam generator for $2.414 million and turbine generator for $1.630 million.

Jul Before the revised Loan Agreement and Project Agreement were signed, the Government of India requested that NTPC be allowed to borrow directly from ADB. This major change required ADB Board approval. It was agreed that the Subsidiary Loan Agreement (SLA) would be amended to reflect the same.

28 Jul The Loan Agreement and Project Agreement were signed. 9 Sep The SLA was signed. 14 Nov The SLA became effective. 5 Dec The first disbursement under the Project was made. 1996 20 May NTPC requested ADB to finance packages for coal handling, ash

handling, and control and instrumentation as only the equipment cost of the steam generator and turbine generator packages were covered under the loan.

27 Sep A contract was awarded to supply the coal-handling plant for $775,000. 25 Nov–5 Dec Review Mission (6). 1997 29 Jul A contract was awarded to supply ash handling and disposal for $336,000.18 Aug A contract was awarded to supply control and instrumentation for

$330,000. Oct NTPC proposed that savings of $14.59 million be used to finance the

spare-generator package, and that the balance of savings be used to fund erection packages of ADB-funded supply contracts.

1998 4–7,17,25 Mar Review Mission (7). 12 Jun NTPC proposed cancelation of $15 million from the loan proceeds. 30 Jul $15 million of the loan was canceled, reducing the balance to $145 million. 1999 27 Jan Unit 1 of the Project was synchronized. 11–15,25 Jan Review Mission (8). 8 Feb $5 million of the loan was canceled, reducing the balance to $140 million. 15 Feb ADB approved extension of the loan closing date to 31 March 2000. 27 Jul Unit 1 of the Project tripped due to an earth fault. 22 Oct Unit 2 of the Project was synchronized. 20–23 Oct Review Mission (9). 28 Dec $5 million of the loan was canceled, reducing the balance to $135 million. 2000 28 Jan ADB approved extension of the loan closing date to 31 December 2000,

and cancelation of identified savings of $5 million effective 28 December 1999.

1 Mar Unit 2 was declared commercially operational. 17–19 Jul Review Mission (10). The mission met with NTPC officials in Uttar

Pradesh to review the Project. 3 Oct $7 million of the loan was canceled, reducing the balance to $128 million.

16 Appendix 2

23 Oct ADB approved cancelation of savings of $7 million effective 3 October 2000.

Nov Unit 1 was resynchronized. 2001 1 Jan Unit 1 was declared commercially operational. 31 Mar Loan closing date 4 Apr The final disbursement was made under the Project. 4 Apr $1.324 million of the loan was canceled, reducing the balance to $126.676

million. 2002 17–19 Apr The Project Completion Review Mission.

Appendix 3 17

COST BREAKDOWN BY PROJECT COMPONENT ($ million)

Appraisal Estimate4 Actual

Component Foreign Local Total Foreign Local Total

A. Base Cost 1. Structural Steel 0.00 10.43 10.43 0.00 11.70 11.70 2. Civil Works 0.00 52.08 52.08 0.00 31.53 31.53 3. Steam Generator with Associated Auxiliaries

62.90 26.96 89.86 58.35 12.88 71.23

4. Turbine Generator with Associated Auxiliaries

49.15 21.05 70.20 42.82 4.76 47.58

5. Control and Instrumentation

10.38 4.45 14.83 6.52 1.22 7.74

6. Coal Handling System 12.81 5.49 18.30 13.58 11.57 25.15 7. Ash Handling System 5.31 2.28 7.59 5.77 5.35 11.11 8. Miscellaneous Mechanical Equipment

14.96 6.41 21.37 0.00 16.74 16.74

9. Transformers 2.45 1.05 3.50 0.00 4.15 4.15 10. Switchgears 3.96 1.70 5.66 0.00 5.63 5.63 11. Power Cables 3.03 1.30 4.33 0.00 4.34 4.34 12. Miscellaneous Electrical Equipment

4.76 2.04 6.80 0.00 6.94 6.94

13. Tools and Plants, Commissioning, Engineering and Administration

3.46 26.42 29.88 0.00 27.66 27.66

14. Taxes and Duties 0.00 41.50 41.50 0.00 Included above

Included above

Subtotal (A) 173.17 203.16 376.33 127.04 144.46 271.50 B. Contingencies

1. Physical Contingencies 8.66 13.28 21.94 0.00 0.00 0.00 2. Price Escalation 21.73 51.99 73.73 0.00 0.00 0.00

Subtotal (B) 30.39 65.27 95.67 0.00 0.00 0.00

C. Interest During Construction

22.31 70.60 92.91 0.00 29.21 29.21

Subtotal (C) 22.31 70.60 92.91 0.00 29.21 29.21

Total 225.88 339.03 564.91 127.04 173.67 300.71

Source: Asian Development Bank estimates.

NTPC PCSS Contract Description Contractor/Supplier Date of Date bid Contract No. Currency Amount $ Equivalent NIT Documents

sent to ADB

Category 01A - Equipment - Steam Boilers and Auxilliaries

CC-1430-101-8 0001 Supply of Steam Generator Bharat Heavy Electricals Ltd. Rs 1,701,547,791 45,410,091 30 Nov 1993 30 Jun 1993$ 4,960,502 4,933,489 £ 807,216 1,304,359 DM 6,018,367 3,473,038 F 10,651,146 1,875,831 ¥ 141,563,453 1,218,440

Category 01B - Equipment - Turbine Generators and Auxilliaries

CC-1430-110-8 0002 Supply of Turbine Generators Bharat Heavy Electricals Ltd. Rs 975,678,361 25,862,800 30 Nov 1993 16 Jun 1993$ 2,773,009 2,773,009 DM 19,593,684 11,472,465 £ 987,378 1,614,254 ¥ 105,018,603 874,812

Category 02 - Coal-Handling Plant

CC-1430-156-8 0003 Supply of Coal-Handling Plant TRF Ltd. Rs 549,355,723 13,576,296 1 Jun 1995 14 Nov 1994

Category 03 - Ash-Handling Plant

CC-1430-162-8 0005 Supply of Ash-Handling and Mahindra Ashtech Ltd. Rs 226,252,570 5,559,501 8 Sep 1995 23 May 1995and Disposal Plant $ 212,175 212,175

Category 04 - Control and Instrumentation

CC-1430-405-8 0006 Supply of Control and Instrumentation Bharat Heavy Electricals Ltd. $ 1,135,045 1,135,045 3 Jul 1995 14 Nov 1994£ 138,130 223,275 DM 282,692 156,157 Rs 210,684,909 5,000,770

ADB = Asian Development Bank, LOA = letter of acceptance, NIT = notice inviting tender, NTPC = National Thermal Power Corporation, PCSS = procurement contract summary sheet.

ADB financing of Contract Amount

Project Costs and Summary of Contracts 18 Appendix 4

Date of ADB Date of ADBNTPC PCSS Contract Description Approval of Date of Sale Date of Date Bid Approval Date of Date LOAContract No. Bid of Bid Bid Opening Evaluation of Contract Award of sent to

Documents Documents sent to ADB Award Contract ADB

Category 01A - Equipment - Steam Boilers and Auxilliaries

CC-1430-101-8 0001 Supply of Steam Generator 15 Sep 1993 15 Dec 1993 29 Mar 1994 16 Dec 1994 31 May 1995 31 May 1995 16 Jun 1995

Category 01B - Equipment - Turbine Generators and Auxilliaries

CC-1430-110-8 0002 Supply of Turbine Generators 15 Sep 1993 15 Dec 1993 29 Mar 1994 16 Dec 1994 31 May 1995 31 May 1995 16 Jun 1995

Category 02 - Coal-Handling Plant

CC-1430-156-8 0003 Supply of Coal-Handling Plant 29 Mar 1995 01 Jun 1995 20 Sep 1995 23 Jul 1996 04 Sep 1996 27 Sep 1996 22 Nov 1996

Category 03 - Ash-Handling Plant

CC-1430-162-8 0005 Supply of Ash-Handling and 29 Aug 1995 08 Sep 1995 15 Jan 1996 19 Jul 1996 31 Oct 1996 30 Jul 1997 07 Aug 1997Disposal Plant

Category 04 - Control and Instrumentation

CC-1430-405-8 0006 Supply of Control and 19 Jun 1995 03 Jul 1995 10 Oct 1995 09 Jul 1997 15 Aug 1997 18 Aug 1997 24 Sep 1997Instrumentation

ADB = Asian Development Bank, LOA = letter of acceptance, NIT = notice inviting tender, NTPC = National Thermal Power Corporation, PCSS = procurement contract summary sheet.

Project Costs and Summary of Contracts

Appendix 4 19

20 Appendix 5

ANNUAL AVERAGE EXCHANGE RATE FOR THE RUPEE AND DOLLAR

Fiscal Year Rs per $a

1996 33.45

1997 35.50

1998 37.16

1999 42.07

2000 43.33

2001 46.50

a The annual average exchange rates are as per Reserve Bank of India published rates.

Appendix 6 21

PROJECT FINANCING PLAN

Cost Appraisal Estimatea Actual A. Implementation Costs

1. Borrower-Financed 322.00 144.82 2. ADB-Financed 150.00b 126.68 3. Other External Financing

0.00 0.00

Subtotal (A)

472.00 271.50

B. IDC Costs 1. Borrower-Financed 92.91 29.21 2. ADB-Financed 0.00 0.00 3. Other External Financing 0.00 0.00

Subtotal (B)

92.91 29.21

Total 564.91 300.71 ADB = Asian Development Bank, IDC = interest during construction.

a Amounts mentioned are revised cost estimates (November 1993), at the time of approval of change of executing

agency from UPRVUN to NTPC. b Excluding the unallocated $10 million out of the total loan of $160 million.

22 Appendix 7

Calendar Year Actual

1989 0.00 0.001990 6.00 0.001991 0.00 0.001992 0.00 0.001993 0.00 0.001994 6.90 0.001995 12.35 14.671996 9.30 14.781997 21.60 49.801998 27.80 32.701999 6.20 8.002000 8.00 2.202001 5.90 4.53

a Projections as made in the annual Loan Financial Information System (LFIS).Source: LFIS of Asian Development Bank.

($ million)

DisbursementsProjecteda

PROJECTED AND ACTUAL DISBURSEMENTS OF LOAN PROCEEDS

Activity I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III

Land Acquisition

Civil Works

Steam Generators

Turbine Generators

Control and Instrumentation

Coal-Handling System

Mechanical Services

Transformers

Switchgear

Switchyard Equipment

Electrical Services

Note: The land was acquired during the first stage of the Unchahar Thermal Power plant.

Appraisal Estimate

National Theramal Power Corporation Estimate

Actual

2000

IMPLEMENTATION SCHEDULE

1994 1995 1996 19971990 1991 1992 19931989 1998 1999

Appendix 8 23

ExecutiveDirector

(Engineering)

ExecutiveDirector

(Consulting & JV)

Executive Sr. ManagerDirector(Hydro) (Construction-I)

Executive Dy. General Sr. ManagerDirector Manager

(Corporate Planning) (Construction) (Construction-II)

Executive Sr. ManagerDirector (Control &

(Finance) (Instrumentation)

Executive Sr. ManagerDirector (Equipment Erection

(Commercial) Electrical)

Executive Additional Dy. General Sr. ManagerDirector General Manager (Turbine Generator

(Operations Services) (Project) (Erection) Erection)

Board Chairperson Executive General Additional Dy. General Sr. Managerof and Director Manager General Manager (Steam Generator

Directors Director (NR) (Unchahar) (O&M) (Commissioning) Erection)

Executive Sr. ManagerDirector

(Environment & R&R) (off-site)

ExecutiveDirector Sr. Manager Engineer (R&R)

(HR) Sociologist(R&R)

ExecutiveDirector

(Contracts & Materials)

ExecutiveDirector

(Corporate Communication)

ExecutiveDirector

(WR)

ExecutiveDirector

(SR)

ExecutiveDirector

(ER)

ExecutiveDirector(NCR)

Dy. = Deputy; ER = Eastern Region; HR = Human Resources; JV=Joint Venture; NCR = National Capital Region; NR = Northern Region; O&M = Operations and Maintenance; R&R = Rehabilitation and Resettlement; SR = Southern Region; Sr. = Senior; WR = Western Region

ORGANIZATION CHART - PROJECT IMPLEMENTATION STRUCTURE

24 Appendix 9

Appendix 10 25

STATUS OF COMPLIANCE WITH MAJOR LOAN COVENANTS Covenant Reference in

Loan Documents Remarks

The National Thermal Power Corporation (NTPC) will furnish to ADB quarterly reports on the execution of the projects and on the operation and management of the project facilities. Such reports will be submitted in such form and in such detail and within such a period as ADB will reasonably request, and will indicate among other things progress made and problems encountered during the quarter under review, steps taken or proposed to be taken to remedy these problems, and a proposed program of activities and expected progress during the following quarter.

Project Agreement (PA), Schedule 2.08 (b)

Complied with

Promptly after physical completion of the Project, but in any case not later than 3 months thereafter or such later date as ADB may agree for this purpose, NTPC will prepare and furnish to ADB a report in such a form and in such detail as ADB will reasonably request on the execution and initial operation of the Project, including its cost, the performance by NTPC of its obligation under this Project Agreement and the accomplishment of the purposes of the loan.

PA, Schedule 2.08 (c)

Complied with

Furnish to ADB promptly after their preparation but in any event not later than 6 months after the close of the fiscal year to which they relate, unaudited copies of such accounts and financial statements; and not later than 9 months after the close of the fiscal year to which they relate or such date as may be agreed by ADB, certified copies of such audited accounts and financial statements and the report of the auditors relating thereto, all in the English language.

PA, Schedule 2.09

Complied with (furnished until FY2001)

NTPC will take all necessary and timely action to acquire all additional land required for proper disposal of all coal ash to be generated by operation of the project facilities.

PA, Schedule 2.2 Complied with

Performance Monitoring. As part of its annual auditing exercise, NTPC will carry out a performance audit of the operations of the Unchahar Station, a copy of the result of which study will be furnished to ADB. Such performance audit will include, but not necessarily be limited to (i) plant availability and energy production; (ii) staffing levels; (iii) maintenance procedures; (iv) inventory levels, including spare parts and fuel; and (v) environmental monitoring procedures.

PA, Schedule 2.5 Complied with

26 Appendix 10 Covenant Reference in

Loan Documents Remarks

Project Benefit Monitoring and Evaluation. Within 6 months of the date of project completion and thereafter on yearly basis, NTPC will provide ADB a full range of information, as specified by ADB, on the operation of the Project and the revenues received by the Project, to enable ADB to evaluate the impact on, and benefits of, the project facilities.

PA, Schedule 2.6

Complied with

Accounts Receivables. NTPC will maintain its total current accounts receivables at a level not exceeding an amount equivalent to the proceeds of its sale of power for the 2 preceding months for the purpose of this covenant. NTPC’s total current account receivable (i) will not include the balance of accounts due from the state electricity boards to NTPC as of 31 May 1990 and of 31 May 1992 which were guaranteed by the Borrower, and (ii) will be measured from the date of issuance of the billing statements by NTPC.

PA, Schedule 2.7 Not complied with. Receivables as of March 2002 were equivalent to 7.7 months of billing. In an attempt to bail out the central public sector utilities, the Government in April 2002 approved a one-time settlement scheme based on the Ahluwalia Committee recommendations, for clearing outstanding dues and current payments from state electricity boards (SEBs) and other power utilities. To ensure prompt payment of current dues and settlement of the outstanding dues by the SEBs under this scheme, the Government has proposed a tripartite agreement to be signed between the central Government, state government, and the Reserve Bank of India. The Ahluwalia Committee’s recommendations provide for securitization of total dues as of 30 September 2001, including surcharge by issue of tax-free bonds by respective state governments with a coupon rate of 8.5% per annum. The recommendations also envisage provision of full payment of current dues (from 1 October 2001) by opening irrevocable letters of credit with SEBs and utilities for an amount equal to 105% of their average monthly billing for the preceding 12 months, and failure to open the requisite letters of credit will attract regulation of power supply to respective defaulters and suspension of government assistance to SEBs through the Accelerated Power Development Reforms Program. NTPC informed ADB that the Government and NTPC are vigorously encouraging state governments to sign tripartite agreements. Once they are signed, NTPC is expected to be able to comply with the covenant.

Appendix 10 27 Covenant Reference in

Loan Documents Remarks

Contracts for the Sale of Power from the Project. NTPC will, prior to the commencement of generation of power from the Project, conclude contracts for the sale of power from the Project with beneficiaries purchasing power from the Project. In case a particular beneficiary has owed more than 2 months of accounts payable to NTPC at the end of the preceding fiscal year, NTPC will ensure that the contract with that beneficiary provides for the establishment of an irrevocable letter of credit covering the anticipated value of power sales to that beneficiary. NTPC will also ensure that in the event of noncompliance of said provision, NTPC will reallocate the sale of power from the Project to other beneficiaries purchasing power from the project who have a record of satisfactory payment.

PA, Schedule 2.8

Complied with. With the beneficiaries, NTPC signed the Power Purchase Agreement (PPA) for power supply from Unchahar II, wherein the establishment of letters of credit for payment of monthly bills in full, with the provision to provide a back-up escrow account equivalent to 110% of 1 month billing at normative plant load factor of 68.5%, has been provided. The PPA also provides for state government guarantee that bulk power customers will regularly pay energy bills presented by NTPC from various power stations. To safeguard against nonpayment of bills and nonestablishment of letters of credit, escrow account, and government guarantee, the PPA gives NTPC the authority to discontinue and/or reduce power supply from Unchahar II and various other power stations of NTPC to defaulting bulk power customers under intimation to the concerned regional electricity board.

The Borrower will by the date the project facilities are commissioned ensure that all necessary prior transmission facilities are installed and in operating condition. The Borrower will also ensure that such power transmission facilities are adequate to carry and deliver the full electricity output to be generated by the project facilities.

PA, Schedule 4, para 2 (Amendments)

Complied with. Installed by Powergrid.

The Borrower will set NTPC’s tariffs for power supplied from the Project so as to achieve an annual rate of return of not less than 16% on NTPC’s equity investments in the Project.

PA, Schedule 4, para 3

Complied with

Except as ADB may otherwise agree, the Borrower will set NTPC’s tariff for power supplied from NTPC power plants other than these under the Project so as to achieve an annual rate of return as follows: (i) not less 16% on NTPC’s total equity investments for power plants approved for development by the Borrower on or after 1 April 1992, and (ii) not less than 12% on NTPC’s total equity investments for power plants so approved before 1 April 1992.

PA, Schedule 4, para 4

Complied with

28 Appendix 11

ECONOMIC AND FINANCIAL EVALUATION

A. Introduction 1. The Project was for the construction of two 210-megawatt (MW) units under the second stage of the Unchahar Thermal Power Station. The economic evaluation considers the Project in the context of the national economy, and the financial evaluation considers the Project from the perspective of the Executing Agency, the National Thermal Power Corporation (NTPC). Prices are at March 2001 values. For the financial analysis, the financial costs of the Project are compared with the revenues NTPC is expected to earn for electricity generated under the Project. 2. For the economic analysis, project costs plus an estimated investment for transmission and distribution costs are compared with the estimated economic benefits of consumption by end users. Economic costs are calculated by (i) adjusting financial values to exclude taxes and duties; (ii) expressing domestic values of nontradable items in the border values by applying a standard conversion factor of 0.8; and (iii) expressing the values of all tradable items in terms of their (free on board/cost including insurance and freight [FOB/CIF]) border equivalents (distribution and marketing margins are included as local costs). The economic benefits of power supply to end users are estimated on the basis of a weighted average of current prevailing tariff levels and the alternative costs of small generators or alternative energy sources. B. Project Costs 3. Capital Costs. The capital cost of the Project is estimated at $379.5 million in 2001 prices, as against an appraisal estimate of $398 million in 1993 prices. At 2001 prices, the appraisal cost estimate would have been $700.0 million, reflecting a net saving of $320.5 million or about 46%. Additional transmission and distribution investments at 43% of the generation cost have been estimated at $108 million, based on average investments in India. 4. Operations and Maintenance (O&M). Incremental O&M expenditure has been estimated at 2.5% per annum of the capital cost of generation, and 1.0% per annum of the capital cost of transmission and distribution assets. 5. Fuel cost includes coal and fuel oil (required as a supplement for start-up and as a support for coal). Fuel specifications are in Table A11.1.

Table A11.1: Fuel Specifications

Station Heat Rate 2,464 Kcal/kWh Heat Value Coal (Grade F) Fuel oil

3,400 Kcal/Kg 10,000 Kcal/l

Oil Consumption 0.92 ml/kWh Coal Consumption (including transit losses) 0.680 Kg/kWh Kcal = kilocalorie, kg = kilogram, kWh = kilowatt-hour, l = liter, ml = milliliter.

Appendix 11 29 6. The government sets coal prices on an administered basis. The consumer prices of coal include, in addition, excise duties, sales taxes and royalties, and transportation cost for about 600 kilometer on an average from the coal mines to the site. Local coal supply is nontradable given its low heating value and the high inland transportation costs of exporting it. Economic costs have been calculated as 80% of the pithead price as increased by the transportation cost, to adjust for the standard conversion factor. 7. The financial cost of fuel oil is Rs10 per liter, and the economic cost is estimated at Rs3.03 per liter, based on the international market price of $71 per ton. Fuel costs per kilowatt-hour (kWh) are in Table A11.2.

Table A11.2: Fuel Cost

Item Financial

Price Economic

Price Coal (0.680 kg) 0.92 0.69 Oil (0.92 ml) 0.09 – Total Fuel Cost (Rs/kWh) 1.01 0.69 Total Fuel Cost ($/kWh) 0.02 0.01

Kcal = kilocalorie, kg = kilogram, kWh = kilowatt-hour, l = liter, ml = milliliter, Rs = rupees.

C. Generation 8. Generation from the Project is based on actual generation data for the FY2001 and FY2002, and projected at an average plant load factor (PLF) of 85% from 2003 onward. A system auxiliary use of 9.5% is assumed to arrive at net generation available at bus bar. An average system loss of 26.8% of net available generation for the northern region has been adopted.

D. Economic Benefits

9. The economic value of power supply to end users is based on a weighted average of (i) economic costs of the project electricity displacing alternatives available to individual consumers; and (ii) the economic value to consumers of additional energy consumption due to the Project, which is estimated on the basis of average willingness to pay. Estimated willingness to pay, in turn, is based on the average of (i) the minimum willingness to pay for power, which is equal to the current retail tariff levels for each consumer category; and (ii) the maximum willingness to pay for public power supply, based on the estimated alternative financial costs of small private power generators or alternative energy sources for various consumer categories. 1. Current Average Tariffs 10. Generation from the Project is allocated to a number of northern state electricity boards, each with different retail tariffs. The average tariff level in 2001 to end users to be served by the Project in the northern region is Rs2.04 per kWh.

30 Appendix 11

Table A11.3: Electricity Use and Average Tariff In Northern Region

Sectoral Use of Generation Average Tariff (p/kWh)

2000/01 State

Allocation Domestic Agri/Irr Industry Comm

Other Domestic Agri Total

Haryana Himachal Pradesh Jammu & Kashmir Punjab Rajasthan Uttar Pradesh Delhi Weighted Average

6.0% 4.0% 8.0% 19.0% 11.0% 39.0% 13.0%

22.8% 19.6% 31.7% 18.9% 16.2% 30.5% 44.4% 27.7%

44.6% 0.4% 14.7% 30.8% 32.6% 34.0% 0.9% 26.7%

19.8% 41.7% 14.7% 37.8% 37.3% 19.4% 18.4% 25.3%

12.8% 38.2% 38.9% 12.6% 13.8% 16.2% 36.3% 20.4%

280.00 92.48 125.00 190.16 138.00 129.53 273.91 174.12

29.47 50.00 250.00

- 34.85 49.97 276.00 44.70

214.91 203.04 194.16 176.42 195.79 183.35 320.00 204.71

Agri = agriculture, Comm = commercial, Irr = irrigation, kWh = kilowatt-hour, p = paise Source: Annual Report on the Working of the State Electricity Boards and Electricity Departments, Planning Commission (Power and Energy Division), Government of India, June 2001. 2. Costs of Alternative Energy Sources 11. For the economic analysis, estimates were made of costs of alternative energy sources available to the northern domestic, industrial, agricultural, and commercial users, based on the costs of kerosene consumption by domestic consumers, autogeneration for industrial consumers, diesel pumping for agricultural consumers, and diesel generation for commercial and other consumers. The average consumer surplus is estimated to be half the difference between the financial tariff and the alternative cost of energy supply. 12. The cost of autogeneration for industry with medium-sized diesel generators is estimated at Rs4.83 per kWh in financial terms and Rs2.48 per kWh in economic border prices. For agricultural consumers, the equivalence is established at Rs8.18 per kWh in financial prices in comparison to the operation of diesel pumps. This works out to Rs4.23 per unit in economic border prices. For consumers in the commercial and other categories, the alternative source is assumed to be a mix of generators. The financial cost of such generation is Rs5.31 per unit and Rs2.81 at economic border prices. 13. For domestic consumers, maximum willingness to pay is determined by the cost saving arising from the substitution of kerosene lamps by incandescent lights. The cost of kerosene lighting is based on the use of efficient petromax lamps, which require 0.7 liters of kerosene to produce 1 kWh equivalent of electric lighting. At the kerosene price of Rs9.60 per liter, the maximum willingness to pay for domestic consumers is computed at Rs6.72 per kWh, which is Rs5.71 per kWh at economic border prices. Details are in Tables A11.4 and A11.5.

Appendix 11 31

Table A11.4: Cost of Autogeneration (Amounts in rupees)

Item 350 kW 5 kW Financial Capital Cost per kW 6,000 7,000 Plant Life 15 10 Average Plant Factor 30% 30% Discount Rate 12% 12% Capital Recovery Factor 0.147 0.177

Fixed Annual Cost (Financial) Capital Recovery 881 1239 O&M (5% of capital cost) 300 350 Total 1,181 1,589 Annual Operation (hours) 2,628 2,080 Equivalent Unit Cost (Financial terms) 0.45 0.76 Equivalent Unit Cost (Economic terms) 0.36 0.61 Fuel Cost (diesel) Financial Price Rs/liter 17.50 17.50 Specific Fuel Consumption liters/kWh 0.25 0.26 Fuel cost per unit 4.38 4.55 Total Financial Cost 4.83 5.31 Economic Fuel Cost per Rs/liter 8.48 8.48 Economic Fuel Cost per Unit 2.12 2.20 Economic Cost at Border Prices Fixed Cost 0.36 0.61 Fuel Cost 2.12 2.20 Total Cost 2.48 2.81 kW = kilowatt, kWh = kilowatt-hour. Notes: For smaller 5 kW units, the operating hours is calculated for 260 working days at 8 hours per day. For larger 350 kW units, the operating hours is based on a 365-day working year at 30% plant load factor.

Table A11.5: Comparison of Electric and Diesel Irrigation Pumps

Item Electric DieselMotor/Engine Size (HP) (1 HP = 0.746 kW) 5 6Life in Years 15 10Investment Cost, Motor 18,000 19,600 Investment, Entire Pump Set 33,500 36,300

Annual Costs Capital Recovery at 12% 0.147 0.177 Capital Recovery Cost 4,918.61 6,424.53 O&M Rate 5% 10%O&M Cost, Motor 900.00 1,960.00 Fixed Annual Cost (Financial) 5,818.61 8,384.53 Fixed Annual Cost (Economic) 4,654.89 6,707.62 Fuel Costs Financial Price Rs/liter 17.50 Specific Fuel Consumption(liters per hour) at 0.26 liter/HP 1.56 Cost Per Hour 27.30 Economic price of fuel Rs/liter 8.48 Energy Costs Operation Hours per Year 800 800Fuel Cost 21,840 No. of kWh per annum (3.73 * 800) 2,984 Economic fuel costs 10,583.04

Total Annual Financial Cost 30,224.53 Total Annual Economic Cost 17,290.66 Cost of Electricity at which Diesel and Electricity are Equivalent 8.18

Economic Cost at which Diesel and Electricity are Equivalent 4.23 HP = horse power, kW = kilowatt, kWh =kilowatt-hour.

32 Appendix 11

3. Weighted Average Values 14. For each consumer category, current tariff levels represent the minimum willingness to pay, and the costs of alternative energy supply represent the maximum willingness to pay for additional electricity use. The average of these two values is considered the average willingness to pay for additional electricity consumption. The weighted average of willingness to pay, weighted according to the relative size of each consumer category, is Rs4.09 per kWh at local financial prices. Some proportion of electricity supply from the Project will displace alternative energy sources that would otherwise be used with the Project. This is estimated at 31%, based on discussions with NTPC and Central Electricity Authority as shown in Table A11.6. The weighted average economic cost of these alternative energy sources is estimated at Rs3.91 per kWh. The significant difference between local financial prices and economic border prices arises due to the incidence of a substantial tax element included in local financial prices. The overall weighted economic value of electricity supplied by the Project is estimated to be Rs3.27 at border prices. Details are in Table A11.6.

Table A11.6: Economic Value of Electricity Consumption

(Rs/kWh at 2001 prices)

Economic Value of Electricity Consumption

Item Domestic Agriculture Industry Commercial Weighted Average

Share in Total Consumption 27.70% 26.70% 25.30% 20.40% Current Tariffs 1.74 0.45 3.34 2.91 2.04 Willingness to Pay Maximum, based on financial 6.72 8.18 4.83 4.26 6.14 Cost of alternatives Average, at local prices 4.23 4.32 4.09 3.59 4.09 Average, at border prices 3.38 3.46 3.27 2.87 3.27 Estimated Use of Alternatives 1.00% 12.50% 15.00% 2.50% Economic Cost of Alternatives at border prices 5.71 4.23 2.48 2.81 3.91 Weights in Total Evaluation Additional Consumption 69%Alternative Energy Displacement

31.00%

Weighted Average Value 3.27kWh = kilowatt-hour.

E. Economic Evaluation

15. The annual cash flows of estimated economic costs and benefits for this Project are shown in Table A11.7. The economic internal rate of return (EIRR) is estimated at 19.4%, significantly higher than the 13.6% estimated at appraisal. The higher EIRR is due to a substantially lower project cost, which is estimated at Rs16.1 billion in 2001 prices, as against the appraisal estimate of Rs27.6 billion (in 2001 prices), a saving of 41.7%. In addition, the significant tax element on fuel, which is excluded in economic border prices, has also contributed to the higher EIRR. The EIRR indicates that the Project is expected to provide an adequate return to the economy.

Appendix 11 33 F. Financial Evaluation

16. The financial evaluation of the Project is from the perspective of NTPC, and is in Table A11.8. Tariffs charged for the new facilities have been worked out on an estimated basis using the tariff model usually applied at a PLF of 68.50%, as the Central Electricity Regulatory Commission is yet to finalize the tariff award for the new facilities. The costs and benefits are stated in 2001 prices. The project financial internal rate of return (FIRR) while operating at a PLF of 85.00% is 10.97%, as against the weighted average capital cost (WACC) of about 9.00% for this Project. This compares well with the appraisal estimate of 11.26% FIRR, when the WACC was 15.20%. As NTPC receives a cost-plus tariff, any increase or decrease in cost of capital would be automatically reflected in higher or lower tariff. The break-even FIRR occurs at 76.50% PLF. A sensitivity analysis indicates that, if NTPC were to operate the plant at 80.00%, the FIRR would drop to 10.00%, and would increase to 11.50% if the PLF were 90.00%. In general, NTPC has been operating at above 85.00% PLF in this Project.

Table A11.7: Economic Evaluation of Unchahar Thermal Power Extension Project (All Figures in 2001 Prices and in Rs million, unless otherwise stated)

Year Generation Transmission Distribution O&M Fuel Total Net Net Revenue Net

Generation Sale Cash GWh GWh Flow

1995

6.9

6.9

(6.9 )1996 1,562.0 1,562.0 (1,562.0) 1997 1,847.4 1,847.4 (1,847.4) 1998 3,325.7 3,325.7 (3,325.7) 1999 2,583.2 1,152.1 1,152.1 4,887.4 (4,887.4) 2000 1,742.9 1,152.1 1,152.1 322.8 4,369.9 (4,369.9) 2001 453.1 334.1 1,355.9 2,143.1 1,778.3 1,312.4 4,396.5 2,253.5 2002 334.1 2,259.8 2,593.9 2,963.9 2,187.4 7,327.7 4,733.9 2003 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2004 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2005 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2006 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2007 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2008 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2009 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2010 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2011 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2012 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2013 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2014 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2015 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2016 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2017 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2018 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2019 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2020 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2021 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2022 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2023 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2024 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2 2025 334.1 2,157.8 2,491.9 2,830.2 2,088.7 6,997.1 4,505.2

Economic Internal Rate of Return 19.4%

GWh = gigawatt-hour, O&M = operations and maintenance.

34 Appendix 11

Table A11.8: Financial Evaluation of Unchahar Thermal Power Extension Project (All Amounts in Constant 2001 Prices and Rs million Unless Otherwise Stated)

Year Cost Operating Costs Incremental Revenue Sales Net Cash O&M Fuel W. Cap. Total Gen. Sales Rs/kWh Flow Interest GWh GWh 1995 8.6 (8.6)1996 1,952.5 (1,952.5)1997 2,309.2 (2,309.2)1998 4,157.1 (4,157.1)1999 3,229.0 (3,229.0)2000 2,178.6 (2,178.6)2001 566.4 311.1 1,984.7 164.5 2,460.3 1,965.0 1,778.3 2.320 4,125.7 1,099.0 2002 216.2 311.1 3,307.8 164.5 3,783.4 3,275.0 2,963.9 2.240 6,639.1 2,639.5 2003 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.230 6,311.3 2,677.1 2004 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.220 6,283.0 2,648.8 2005 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.210 6,254.7 2,620.5 2006 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.150 6,084.9 2,450.7 2007 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.110 5,971.7 2,337.5 2008 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.090 5,915.1 2,280.9 2009 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.080 5,886.8 2,252.6 2010 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.060 5,830.2 2,196.0 2011 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.050 5,801.9 2,167.7 2012 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.040 5,773.6 2,139.4 2013 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 2.040 5,773.6 2,139.4 2014 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.730 4,896.2 1,262.0 2015 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2016 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2017 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2018 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2019 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2020 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2021 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2022 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2023 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2024 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9 2025 311.1 3,158.6 164.5 3,634.2 3,127.3 2,830.2 1.660 4,698.1 1,063.9

Financial Internal Rate of Return 10.97%O&M = operations and maintenance, Gen. = generation, GWh = gigawatt-hour, kWh = kilowatt-hour, W. Cap. = working capital.

Appendix 12 35

ENVIORNMENTAL MONITORING DATA AND COMPLIANCE FOR ENVIRONMENTAL CLEARANCE

Table A12.1: Environmental Monitoring Data

A. Ambient Air Quality (microgram per cubic meter [µµµµg/m3])

Pollutant Standard Monitoring Data Sulphur dioxide 120 6.6–8.2 Oxides of nitrogen 120 14–32 Suspended particulate matter 500 111–218

B. Stack Emission (milligram per normal cubic metre [mg/Nm3])

Pollutant Standard Monitoring Data Suspended particulate matter 150 70–140

C. Liquid Effluent

Parameter Standard Limits Monitoring Data PH 5.5–9.0 8–8.4 Total suspended solids 100 mg/liter 39–87 Oil and grease 10 mg/liter 3.5–4.2 Iron 1.0 ppm < 0.1 Zinc 1.0 ppm < 0.04 Mercury 0.01 ppm < 0.001 Arsenic 0.2 ppm < 0.005 Fluoride 2.0 ppm 0.381–0.559

pH = A logarithm of the reciprocal of hydrogen ion concentration in moles per liter of a solution giving a measure of its acidity or alkalinity, mg = milligram, ppm = parts per million. Source: National Thermal Power Corporation.

36 Appendix 12

Table A12.2: Compliance with Conditions Stipulated by the

Ministry of Environment and Forests

S. No.

Condition Action Taken

1.

The electrostatic precipitators should have an efficiency of more than 99.5%. The efficiency of electrostatic precipitators should be monitored and recorded.

High-efficiency (over 99.5%) electrostatic precipitators keep emission of suspended particulate matter below 150 mg per normal m3, the limit prescribed under the Environment (Protection) Act, 1986.

2. A common stack for all the three units of not less than 220 m should be installed.

A 220 m stack has been provided for 2 x 210 units under stage 2.

3. A flue gas desulfurization plant having efficiency of 90% should be installed.

The Ministry of Environment and Forests (MOEF) vide letter dated 4 January 1995 has waived this stipulation.

4. A closed cooling system should be provided for condensers instead of a once-through cooling system.

A closed cycle cooling system has been provided for condenser and auxiliary cooling for stage 2.

5. Liquid effluents from different plants of the power station should be collected and treated according to Uttar Pradesh Pollution Control Board (UPPCB) standards.

Treatment of all liquid effluents, and the final effluent conform to UPPCB standards.

6. No fly ash should be thrown into the ravines of the River Ganges. The ash dumping area should be far from the Ganges, and proper bunds should be built for the adequate settling of the fly ash.

For ash disposal from stage 1, environment clearance was accorded 264 ha on the banks of the River Ganges. National Thermal Power Corporation (NTPC) sought environment clearance for an additional 164.8 ha for ash disposal from stage 2, about 10 km from the Ganges. However, MOEF has accorded clearance for 80 ha only (away from the Ganges) and considered 264 ha and 80 ha collectively for stages 1 and 2 (Vide MOEF letter, 15 October 1996). Accordingly, ash from both stages is being disposed off in the ash dyke on the bank the Ganges. The construction of ash dyke on the additional 80 ha is ongoing.

The ash dyke is well designed, constructed, and maintained.

7. The supernatent water coming out of the ash bund should meet UPPCB standards.

The ash pond overflow conforms to UPPCB standards.

8. At least 60% of the fly ash generated should be utilized for constructive purposes such as manufacturing bricks, blocks, cement, etc.

This stipulation was further modified by MOEF Vide Office Memorandum, 8 October 1992. NTPC should ensure 100% fly ash utilization within 9 years of commissioning of plant.

However, NTPC has communicated to MOEF from time to time that it is not possible to achieve 100% fly ash utilization. A fly ash utilization plan with a maximum utilization of 10% in first 5 years, 15% in the next 5 years, and 25% afterward has been submitted to MOEF.

m = meter, m3 = cubic meter, mg = milligram.

Appendix 12 37

S.

No. Stipulation Status of Implementation

9.

Adequate infrastructure to monitor emissions of pollutants from the stacks of the power plant should be provided. Ambient levels of sulphur dioxide and particulate matter should also be collected from different locations in a radius of 5 km from the power plant, especially residential areas. Emissions should conform to UPPCB standards.

Infrastructure to monitor emissions and ambient air quality has been established at site and the data is regularly submitted to UPPCB.

10. A greenbelt should be planted all around the power plant to trap dust particles.

Stage 2 is in the premises of stage 1, and no additional land has been acquired for the plant and township of stage 2. Large-scale afforestation and tree plantation have been undertaken in all available spaces of the plant and township. More than 700,000 trees have been planted at site.

11. The workers in the coal-handling areas, particularly in the wagons tippling operations, conveyor transfer points, crushing mills, coal storage areas, fly ash dumping areas, etc. should be medically examined periodically. Adequate facilities should be provided for medical surveillance of workers engaged in other plants of the power station, the occupational health status of the workers recorded, and proper treatment given, if needed.

Workers undergo periodic medical examinations.

12. Disaster planning for fire and explosions should be done.

An onsite disaster management plan is being implemented at site.

38 Appendix 13

RESETTLEMENT AND REHABILITATION MEASURESa

A. Infrastructure Development

S. No. Activity No. of Villages/

Locations Length/Unit Amount

(Rs million) 1. Kharanja Road 7 13.5 km 3.40 2. Brick drain 4 9.5 km 2.40 3. Culverts 3 10 0.25 4. Hand pumps 6 18 0.30 5. Primary School 1 1 0.25 6. Renovation and

modification of wells 6 33 0.33

7. Community halls/Panchayat Bhawan

2 2 1.00

8. WBM road 2 7.5 km 4.50 9. Miscellaneous Works 1.50 10. Sanitary latrines 8 480 0.24 Total 14.17 B. Rehabilitation Schemes S. No. Scheme PAPs to be

benefited Total cost

(Rs million) Income Generating Schemes 1. Dairy 15 5.14 2. Shops/Kiosks 8 0.12 3. Poultry 15 0.82 4. Piggery 30 1.03 5. Goat keeping 30 1.03 Self-employment Schemes 1. Carpentry 15 0.55 2. Electrical welding 15 0.51 3. Plumbing 15 0.51 4. Motor mechanic 10 0.34 5. TV repairing 10 0.34 6. Electrical 15 0.51 7. Computer hardware 5 0.17 8. Other SESs 157 4.71 Total 480 15.77 PAP = project-affected persons, SES = self-employment schemes Source: National Thermal Power Corporation

a Infrastructure development and rehabilitation schemes undertaken by National Thermal Power Corporation

(NTPC) as per its rehabilitation action plan (RAP). The RAP was prepared as per NTPC’s rehabilitation and reconstruction policy, which was endorsed by World Bank as conforming to its guidelines.

Appendix 14 39

UNCHAHAR STAGE-2 PLANT PERFORMANCE (TWO UNITS)

Fiscal Year

Genera-tion (MU)

Availability Factor (%)

Plant Load Factor (%)

Auxiliary Consump-

tion (%)

Specific Coal Consump-

tion (kg/kWh)

Specific Oil Consump-

tion (ml/kWh)

Heat Rate (Cal/kWh)

2000 472.27 97.53 97.53 7.19 0.703 1.02 - 2001 2,091.89 85.98 84.42 8.31 0.688 1.21 2,473 2002 3,355.84 95.03 91.21 8.56 0.675 0.48 2,464 MU = million units, Cal = kilocalorie, kg = kilogram, kWh = kilowatt-hour, ml = milliliter. Note: The first unit was declared to be under commercial operation from 1 January 2001, the second unit, from 1

March 2000. Source: National Thermal Power Corporation.