ASIAN DEVELOPMENT BANK

Transcription

1 ASIAN DEVELOPMENT BANK PCR:IND PROJECT COMPLETION REPORT ON THE UNCHAHAR THERMAL POWER PROJECT (Loan 907-IND) IN INDIA September 2002

2 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

3 NOTES (i) (ii) 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 In this report $ refers to US dollars.

4 CONTENTS BASIC DATA MAP Page iii 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 Chronology of Main Events in Project Implementation Cost Breakdown by Project Components Project Costs and Summary of Contracts Annual Average Exchange Rate for the Rupee and Dollar Project Financing Plan Projected and Actual Disbursements of Loan Proceeds Implementation Schedule Organization Chart and Project Implementation Structure Status of Compliance with Major Loan Covenants Economic and Financial Evaluation Environmental Monitoring Data and Compliance for Environmental Clearance Resettlement and Rehabilitation Measures Unchahar Stage 2 Plant Performance (Two Units) 39

5 ii CONTENTS Page SUPPLEMENTARY APPENDIXES (available upon request) A. NTPC Outstanding Dues as on 31 March 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

6 iii 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) $ 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 Project Completion Report Number PCR:IND 711 B. Loan Data 1. Appraisal - Date Started 8 June Date Completed 23 June Loan Negotiations - Date Started 29 August Date Completed 2 September Date of Board Approval 29 September Date of Loan Agreement 1 December Date of Loan Effectiveness - In Loan Agreement 1 March Actual 30 April Number of Extensions 2 6. Closing Date - In Loan Agreement 30 September Actual 4 April 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.

7 iv 9. Disbursements a. Dates Initial Disbursement Final Disbursement Time Interval 5 Dec Apr years, 4 months Effective Date Original Closing Date Time Interval 30 Apr Sep years, 5 months b. Amount ($ million) Category Original Allocation Last Revised Allocation Net Amount Disbursed Undisbursed Balance 1. Steam Boilers and Auxiliaries 2. Turbine Generators and Auxiliaries 3. Local Handling Plant Ash Handling Plant Control and Instrumentation 6. Unallocated Total Local Costs (Financed) 0 C. Project Data 1. Project Cost ($ million) Cost Appraisal 2 Estimate Actual Foreign Exchange Cost Local Currency Cost Total 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.

8 v 2. Financing Plan ($ million) Cost Appraisal Estimate 3 Actual A. Implementation Costs 1. Borrower-Financed ADB-Financed Other External Financing Subtotal (A) B. IDC Costs 1. Borrower-Financed ADB-Financed Other External Financing Subtotal (B) Total ADB = Asian Development Bank, IDC = interest during construction. 3. Cost Breakdown by Project Component ($ million) Appraisal Estimate 4 Actual Component Foreign Local Total Foreign Local Total A. Base Cost 1. Structural Steel Civil Works Steam Generator with Associated Auxiliaries 4. Turbine Generator with Associated Auxiliaries 5. Control and Instrumentation 6. Coal Handling System Ash Handling System Miscellaneous Mechanical Equipment 9. Transformers Switchgears Power Cables Miscellaneous Electrical Equipment 13. Tools & Plants, Commissioning, Engineering and Administration 14. Taxes and Duties Included above Included above Subtotal (A) Amounts mentioned are revised cost estimates (November 1993), at the time of approval of change of executing agency from UPRVUN to NTPC. Excluding the unallocated $10 million out of the total loan of $160 million.

9 vi Appraisal Estimate 5 Actual Component Foreign Local Total Foreign Local Total B. Contingencies 1. Physical Contingencies Price Escalation Subtotal (B) C. Interest During Construction Subtotal (C) Total Source: Asian Development Bank estimates. 4. Project Schedule Appraisal Estimate NTPC Estimate 6 Actual Item Start End Start End Start End Land Acquisition Jan 1989 Jan 1989 Jan 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 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 Amount mentioned are revised cost estimates (November 1993), at the time of approval of change of executing agency from UPRVUN to NTPC. Start and end dates are revised dates (November 1993) at the time of approval of change of executing agency from UPRVUN to NTPC. Land was already acquired during the first stage of the Unchahar Thermal Power Plant.

10 vii D. Data on Asian Development Bank Missions Number of Persons Number of Person- Days Specialization of Members a Name of Mission Date Fact Finding 2 18 Feb a,b,c,d Appraisal 8 23 Jun a,b,c,g,h Inception Oct a Special Loan 7 15 Mar a,b Administration /Review 1 Review ,19 Nov a Review Feb a,b Fact Finding 24 Sep 3 Oct a Consultation 4 19 Feb a,b Review 4 7 Sep a Review Jul a,b Review 6 25 Nov 5 Dec a,d,i,j Review 7 4 7,17,25 Mar a Review ,25 Jan a Review Oct a Review Jul a Project Completion a Review 11 b Apr a,i 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.

11 Map 1 ix

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13 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 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 forecasts 1 up to 2000 indicated that load shedding would persist in spite of planned 2 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 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 components 3 (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 Thirteenth Electric Power Survey of India, December 1987 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. Components for consultancy service and training were taken out of the scope of the Project subsequent to change in EA in November 1993.

14 2 turbine generators and auxiliaries; (iv) instrumentation and control systems; (v) coal- and ashhandling 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 coalfired 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 FY 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)

15 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 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 $ million equivalent (as per the prevailing prices in 1993) comprising $ million (40%) in foreign currency and $ (60%) in local currency. The ADB loan at appraisal was $ million, of which only $ million (79.2%) was utilized. Cost savings of $ million equivalent (46.8%) comprised $98.84 million in foreign currency and $ 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 $ million (73.5%), with the balance of $ million to be financed by ADB (26.6%), with an unallocated $10.00 million in ADB s total loan amount of $ 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 Equipment A. Steam Boilers and Auxiliaries 90 B. Turbine Generators and Auxiliaries 60 II Unallocated 10 Total 160

16 4 Table 2: Revised Allocation of Loan Proceeds ($ million) Category Item Description Amount Allocated I Equipment A. Steam Boilers and Auxiliaries 1. Coal Handling Plant 2. Ash Handling Plant II B. Turbine Generators and Auxiliaries 1. Control & Instrumentation Unallocated (transferred to A) 0.0 Total Actual project cost estimates show NTPC s contribution to be $ million (57.9%), and borrowings from ADB, $ 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 $ million to $ 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 $ million out of the original loan amount of $ 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 as project implementation could start only in April 1995, with the award of contract for the main plant in May 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 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

17 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 The 16 stator bars of the first unit were damaged due to an earth fault that occurred on 27 July The generator was repaired at the supplier s works and recommissioned in January 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 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.

18 6 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 However, implementation was delayed by slow government investment approval, which was obtained in April The first unit was to be completed in January 2000, the second, in July 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.

19 7 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. State Table 3: Allocation of Power to Northern States Uttar Pradesh Haryana Jammu and Kashmir Himachal Pradesh Punjab Rajasthan Delhi Unallocated MW=megawatt Allocation (MW) Total 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

20 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.

21 9 D. Preliminary Assessment of Sustainability 33. The technical sustainability of the Project is high for the following reasons: (i) (ii) (iii) 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 Demand for the project-generated power will be adequate. Operation performance figures such as PLF, plant availability factor, and specific fuel consumption of plant (Appendix 14) indicate that the unit cost of the projectgenerated power will be competitive and may be reasonably cheaper than that of power generated by newer plants. 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

22 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 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 incomegenerating 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 The units were commissioned in January and October 1999, respectively.

23 11 (ii) (iii) 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. NTPC achieved high power plant operational efficiencies (Appendix 14) and project sustainability (paras ). 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 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

24 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 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 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 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.

25 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) (ii) civil works for site preparation, foundation, power station building, cooling water systems, and other facilities; 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) (vii) water treatment and chlorination plants; miscellaneous mechanical equipment and systems; (viii) (ix) (x) (xi) precipitators, cooling towers, and air pollution sampling equipment; transformers, switchyard, and other miscellaneous electrical equipment; consulting services; and 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.