ASIAN DEVELOPMENT BANK PPA: IND 18181
PROJECT PERFORMANCE AUDIT REPORT
ON THE
NORTH MADRAS THERMAL POWER PROJECT (Loan 798-IND)
IN
INDIA
June 2002 CURRENCY EQUIVALENTS Currency Unit – Indian Rupee/s (Re/Rs)
At Appraisal At Project Completion At Operations Evaluation (October 1986) (March 2001) (April 2002) Re1.00 = $0.083 $0.023 $0.021 $1.00 = Rs12.12 Rs43.00 Rs47.75
ABBREVIATIONS
ADB – Asian Development Bank EIRR – economic internal rate of return FIRR – financial internal rate of return GTN – Government of Tamil Nadu ICHS – internal coal handling system MAUP – Madras City Augmentation and Upgradation Project OEM – Operations Evaluation Mission PCR – project completion report PFC – Power Finance Corporation PPAR – project performance audit report SEB – state electricity board SERC – state electricity regulatory commission TNEB – Tamil Nadu Electricity Board TNPCB – Tamil Nadu Pollution Control Board
WEIGHTS AND MEASURES
Cal (kilocalorie) - 1,000 calories kV (kilovolt) - 1,000 volts MW (megawatt) - 1,000,000 watts kWh (kilowatt-hour) - 1,000 watt-hours GWh (gigawatt-hour) - 1,000,000 kilowatt-hours
NOTES
(i) The fiscal year (FY) of the Government and the Tamil Nadu Electricity Board ends on 31 March. FY before the calendar year denotes the year in which the fiscal year ends. For example, FY2001 begins on 1 April 2000 and ends on 31 March 2001. (ii) In this report, “$” refers to US dollars.
Operations Evaluation Department, PE-595
CONTENTS
Page
BASIC DATA iii EXECUTIVE SUMMARY iv MAPS vi
I. BACKGROUND 1 A. Rationale 1 B. Formulation 1 C. Purpose and Outputs 2 D. Cost, Financing, and Executing Arrangements 2 E. Completion and Self-Evaluation 2 F. Operations Evaluation 3
II. PLANNING AND IMPLEMENTATION PERFORMANCE 4 A. Formulation and Design 4 B. Achievements and Outputs 4 C. Cost and Scheduling 5 D. Procurement and Construction 6 E. Organization and Management 6
III. ACHIEVEMENT OF PROJECT PURPOSE 7 A. Plant Performance 7 B. Performance of the Operating Entity 7 C. Economic and Financial Reevaluation 7 D. Sustainability 8
IV. ACHIEVEMENT OF OTHER DEVELOPMENT IMPACTS 8 A. Socioeconomic Impact 8 B. Environmental Impact 9 C. Impact on Institutions and Policy 9
V. OVERALL ASSESSMENT 10 A. Relevance 10 B. Efficacy 10 C. Efficiency 10 D. Sustainability 10 E. Institutional Development and Other Impacts 10 F. Overall Project Rating 10 G. Assessment of ADB and Borrower Performance 11 H. Power Sector Policies 11
VI. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS 12 A. Key Issues for the Future 12 B. Lessons Identified 12 C. Follow-Up Actions 13 ii
APPENDIXES 1. Cost Breakdown by Project Components 14 2. Implementation Schedule 15 3. Financial Statements of the Tamil Nadu Electricity Board 17 4. Economic and Financial Reevaluation 19 5. Resettlement and Rehabilitation Measures 23 6. Actions Taken on Stipulated Environmental Conditions 26
SUPPLEMENTARY APPENDIXES (available upon request) A. Socioeconomic Impact Assessment B. Environmental Impact Assessment
BASIC DATA
North Madras Thermal Power Project (Loan 798-IND)
Key Project Data ($ million)
As per ADB Loan Documents Actual
Total Project Cost 627.5 469.4 Foreign Exchange Costs 253.8 176.4 Local Costs 373.7 293.0 ADB Loan Amount/Utilization 150.0 110.4
Key Dates Expected Actual
Fact-Finding 29 Jan–7 Feb 1986 12–27 May 1986 Appraisal 1–11 Sep 1986 Loan Negotiations 13–17 Oct 1986 Board Approval 18 Nov 1986 Loan Agreement 21 Jan 1987 Loan Effectiveness 21 Apr 1987 10 Apr 1987 First Disbursement 5 Apr 1988 Project Completion Dec 1992 Jun 1999 Loan Closing 30 Jun 1992 7 Jan 1999 Months (effectiveness to completion) 62 146
Economic and Financial Appraisal PCR PPAR Internal Rates of Return (%) Economic Internal Rate of Return 15.7 15.6 14.2 Financial Internal Rate of Return 7.4 4.0 8.4
Borrower Government of India Executing Agency Tamil Nadu Electricity Board (TNEB)
Mission Data No. of Missions No. of Person-Days
Fact-Finding 2 96 Preappraisal 1 16 Appraisal 1 30 Project Administration Inception 1 8 Review1 16 134 Project Completion 1 4 Operations Evaluation2 1 26
1 Most missions were fielded to review the progress of projects under several loans. Person-days shown are actual days spent on the Project. 2 The Operations Evaluation Mission comprised Mr. K. E. Seetharam (Evaluation Specialist/Mission Leader), Mr. K. Venkataraman (Staff Consultant), and Mr. J. P. Shrivastava (Domestic Consultant). The Mission visited India from 17 to 31 March 2002. Ms. Kus Hardjanti (Evaluation Specialist) joined the meetings and field visit from 17 to 22 March. iv
EXECUTIVE SUMMARY
The Government of India developed a long-term power development program under the Seventh Five-Year Plan (FY1985-1989). The program aimed to alleviate severe power shortages that were serious constraints to economic growth. The program included several thermal power stations utilizing the country's large coal reserves. The North Madras Thermal Power Project (the Project)1 was an integral part of the national power development program.
The main purpose of the Project was to expand the generating capacity of the Tamil Nadu Electricity Board (TNEB), the Executing Agency, by installing north of Madras (now Chennai) two units of 210 megawatts (MW) each to meet the prevailing and anticipated power shortages in Tamil Nadu. The Project comprised (i) civil works for site preparation, foundations, the power station building, and water circulation and other systems; (ii) two 690 ton/hour capacity coal-fired steam boilers and auxiliaries; (iii) two reheat steam turbine generators each with a rated capacity of 210 MW and auxiliaries; (iv) instrumentation and control systems; (v) coal and ash handling systems; (vi) water treatment and other miscellaneous mechanical equipment; (vii) transformers, switchyard equipment, and other miscellaneous electrical equipment; and (viii) consulting services.
The Operations Evaluation Mission visited India in March 2002, and held discussions with the officials and experts connected with the Project and the staff of the Asian Development Bank (ADB) India Resident Mission.
The Central Electricity Authority formulated the Project. The Project was prepared without an ADB project preparatory technical assistance. Plant design and engineering were technically sound and appropriate in the context of the urgent need for additional generating capacity.
At appraisal, the total project cost was estimated at $628 million equivalent, comprising $254 million in foreign exchange costs (40% of the total cost) and $374 million equivalent (60% of the total cost) in local currency costs. The actual project cost at completion was $469 million equivalent, comprising $176 million (38%) in foreign exchange costs and $293 million equivalent (62%) in local currency costs. The significant savings resulted mainly from (i) a major depreciation of the rupee during implementation, (ii) strong competition among international and domestic bidders for ADB-financed contract packages, and (iii) overestimated price contingencies.
The commissioning of units 1 and 2 was originally scheduled in March and December 1991, respectively. Several factors led to major delays: land acquisition problems; procurement delays in the award of contracts (due to excessive time taken by TNEB for bid evaluation, lengthy internal approvals of contract awards within TNEB, and additional lengthy process for approval of awards by the Central Electricity Authority and the Government of Tamil Nadu [GTN] before submission to ADB for approval); and considerable delays in the implementation of some contracts, particularly that for the internal coal handling system (ICHS).
Units 1 and 2 were eventually commissioned in October 1994 and March 1995, more than 3 years behind schedule. However, their optimum utilization was not possible due to the delay in the commissioning of the ICHS, which became fully operational only in June 1999. Thus the total delay in project implementation was 6.5 years.
1 Loan 798-IND: North Madras Thermal Power Project, for $150 million, approved on 18 November 1986.
As envisaged at appraisal, the Project provided the additional generating capacity of 420 MW and enabled TNEB to optimize the operation of its hydropower generation facilities. However, until the commissioning of the ICHS, plant performance suffered. Since the ICHS was commissioned in June 1999, performance has been very good with plant load factors exceeding 80%.
Operation and maintenance personnel have been adequately trained by TNEB. With the commissioning of the external coal handling system in January 2002, the availability of coal has further improved. The coal delivered by sea will be also cheaper than that delivered by rail. Future funding for the required operation and maintenance is not expected to be a problem. Thus, the long-term sustainability of the Project is likely.
Apart from the major delay, the Project has satisfactorily achieved its objectives. The additional energy generated is consumed mainly by domestic, industrial, and commercial consumers in urban areas, and by a limited number of agricultural consumers. The Project’s economic internal rate of return of 14.2% and its financial internal rate of return of 8.4% both confirm its high efficiency. The actual cost, being lower than the appraisal estimates, and excellent plant performance have more than compensated for the delay. Further, the substantive issues relating to the environment and resettlement have been addressed satisfactorily. There still remains the procedural issue of obtaining environmental compliance from the Tamil Nadu Pollution Control Board. Overall, the Project is rated successful.
The key indicator of the financial performance of TNEB is the 3% surplus required under Section 59 of the Electricity Act. The Loan Agreement stipulated that TNEB would maintain tariffs at a level to achieve the 3% surplus. However, given GTN’s decision to give power freely to agricultural consumers, this was not possible and hence subventions were needed from GTN to achieve the stipulated surplus. These subventions have become a significant burden on GTN’s budgetary resources.
As regards future power projects, the key issue, which is of national relevance, is the financial viability of the state electricity boards. Two major factors contributing to the poor state of the state electricity boards’ finances are the politically driven tariffs and inefficient meter reading and bill collection. The Government and the state governments have agreed to depoliticize the power sector reforms and implement them expeditiously, with particular emphasis on power distribution. This provides a unique opportunity for ADB to take a lead role in distribution sector reform in India and provide the requisite technical and financial assistance, with privatization of distribution systems a precondition for receiving loan assistance.
TNEB is advised to take the following actions by December 2002:
(i) resolve the issue of how and where to discharge cooling water in the sea and obtain approval from the Tamil Nadu Pollution Control Board for plant operation; and
(ii) improve plant safety and ensure that workers use the safety equipment procured by TNEB, including safety helmets.
I. BACKGROUND
A. Rationale
1. With a view to alleviating the severe power shortages experienced in India, which in turn were serious constraints to economic growth, the Government developed a long-term power development program under the Seventh Five-Year Plan (FY1985-1989). The program included several thermal power generating stations, utilizing the country's large coal reserves.
2. The Tamil Nadu Electricity Board (TNEB) in the State of Tamil Nadu was the second largest power generation system in the Southern Region, with a total installed capacity of 3,553 megawatts (MW) in 1986. TNEB’s power development program in the early 1980s added two 210 MW units at each of two thermal power stations in Tuticorin and Mettur. However, even with the progressive increases in TNEB’s thermal capacity, the huge annual deficit of over 4,000 gigawatt-hours (GWh) of electrical energy was a persistent problem affecting economic growth in the 1980s in Tamil Nadu. The power outages caused significant disruptions in the operations of industrial consumers who accounted for over 55% of total consumption.
3. The North Madras Thermal Power Project (the Project)1 was an integral part of the national power development program. It aimed at not only reducing the generating capacity deficit, but also providing the much-needed base-load backup for the then largely seasonal hydropower-based system in Tamil Nadu.
4. The country operational strategy of the Asian Development Bank (ADB) for India at the time of appraisal sought to assist the Government's industrialization efforts directly by providing financial assistance for industrial projects and indirectly for removing the bottlenecks in infrastructure, particularly in the crucial power sector. The Project was prepared before the introduction of the policy to promote private sector participation in the form of independent power producers.
B. Formulation
5. The Project was identified as an integral component of the national power development program formulated by the Central Electricity Authority, based on detailed capacity optimization system studies. The project location was decided on the basis of least-cost studies for coal transportation and water availability for cooling as well as for steam production. The coastal location of the Project provided for coal transportation by coastal shipping, thereby relieving the already strained rail sector from the additional burden of transporting coal for the Project from eastern coalfields. It also provided flexibility for importing coal if necessary. The technical design and detailed engineering for the Project were carried out in August 1985 by an experienced domestic consulting firm engaged by TNEB, the Executing Agency. ADB appraised the Project in September 1986 and considered the project report prepared by TNEB satisfactory. ADB also assessed that TNEB had the required technical competence, as demonstrated by the successful completion of two thermal power stations in the 1980s.
1 Loan 798-IND: North Madras Thermal Power Project, for $150 million, approved on 18 November 1986.
2
C. Purpose and Outputs
6. The main purpose of the Project was to expand the generating capacity of TNEB in order to meet the prevailing and anticipated power shortages in Tamil Nadu. The Project assisted in building a new coal-fired thermal power station located approximately 25 kilometers north of Madras (now Chennai), the capital of Tamil Nadu. The Project constituted Phase I of the first stage development of the power station to provide a generating capacity of 420 MW.2 The Project comprised the following components:
(i) civil works for site preparation, foundations, the power station building, and cooling water and other systems; (ii) two 690 ton/hour capacity coal-fired steam boilers and auxiliaries; (iii) two reheat steam turbine generators each with a rated capacity of 210 MW and auxiliaries; (iv) instrumentation and control systems; (v) coal and ash handling systems; (vi) water treatment and other miscellaneous mechanical equipment; (vii) transformers, switchyard equipment, and other miscellaneous electrical equipment; and (viii) consulting services.
D. Cost, Financing, and Executing Arrangements
7. At appraisal, the total project cost was estimated at $628 million equivalent comprising $254 million (40% of the total cost) in foreign exchange costs and $374 million equivalent (60% of the total cost) in local currency costs (Appendix 1).
8. The Member (Generation) of TNEB was designated to be in charge of the Project. The Chief Engineer (Thermal) was responsible for coordination with the consultants, procurement, and monitoring. The Chief Engineer (Civil Designs) was responsible for procurement of civil works. Actual project implementation was supervised by the Chief Engineer (Projects) and was supported by about 200 experienced professional staff. As stated in the Loan Agreement, the Chief Engineer (Planning) was the overall coordinator with ADB. TNEB was assisted in the implementation of the Project by an experienced domestic consulting firm for project engineering, preparation of technical specifications, preparation of bid documents, bid evaluation, review of vendors' drawings, preparation of operation and maintenance manuals, and construction supervision.
E. Completion and Self-Evaluation
9. The project completion report (PCR) circulated in April 2001 covered comprehensively all relevant aspects of project implementation. The PCR was well documented, balanced, and objective. The evaluation of the key aspects of the Project—costs, schedule, procurement of goods and services, environmental and social impacts, disbursements, conditions and covenants, performances of the Borrower, TNEB, and ADB, and the initial benefits—was
2 The power station was planned to be developed in three stages, comprising three units of 210 MW in the first stage, two units of 525 MW in the second stage, and one unit of 525 MW in the final stage, to bring the ultimate capacity to 2,205 MW. The third 210 MW unit was financed under Loan 1029-IND: Second North Madras Thermal Power Project, for $200 million, approved on 30 August 1990. 3 supported by adequate documentation and analysis.3 The PCR reported that considerable savings in foreign exchange had resulted from the major depreciation of the rupee during implementation, with lower bid prices (in dollar terms) offered by domestic contractors who won many international competitive bidding contracts. The net amount of the ADB loan disbursed was $110.4 million. The unused amount of $39.6 million was cancelled in phases.4 The PCR recorded the startup problems such as the lack of a proper project inception report, delayed land acquisition due to litigation, and other procurement and implementation problems, all of which contributed to the long delay in project completion. The overall conclusion of the PCR was that the Project was implemented substantially as conceived during appraisal, albeit with considerable delays.
10. The PCR also concluded that the issues relating to environment and safety were not adequately addressed. TNEB implemented measures to mitigate the adverse effects of the Project on the environment. However, at the time of the project completion review mission, although the power plant was operating, the Tamil Nadu Pollution Control Board (TNPCB) had not given its formal consent to do so, as there was still a disagreement on the location of the discharge point for the cooling water. Moreover, TNEB had not implemented the safety measures for power station workers (such as requiring them to use safety belts, boots, and helmets) and environmental protection measures concerning the residents in the areas near the ash pond.
11. The PCR was also correct to note that the high turnover of key personnel detracted from a sense of ownership of the Project. Based on the low financial internal rate of return (FIRR), of 4.0% the PCR concluded that the Project was partly successful.5
F. Operations Evaluation
12. The main focus of the project performance audit report (PPAR) is to assess the relevance, efficacy, efficiency, sustainability, and institutional and developmental impacts of the Project and identify lessons and follow-up actions, as well as suggestions for sector policies and strategies for future ADB operations.
13. The PPAR presents the findings of the Operations Evaluation Mission (OEM) that visited India in March 2002. The PPAR is based on findings of the OEM and the analysis of data collected during field visits. It also incorporates information from discussions with the officials and experts connected with the Project, and comments received at the workshops at ADB's India Resident Mission and headquarters. Copies of the draft PPAR were provided to the Government, TNEB, and concerned ADB staff for review; comments were considered in finalizing the PPAR.
3 TNEB revised the actual costs subsequently. Those are used in the Operations Evaluation Mission’s analysis (Table 2 and para. 18). 4 In June 1992, ADB and the Government initially agreed to use the loan savings under the loan to partly finance the external coal handling system that was included in the follow-on project (footnote 2). Subsequently, in 1996, to rationalize ADB’s loan portfolio in India, ADB decided to cancel the loan savings. 5 Under the then prevailing three-category system: generally successful, partly successful, and unsuccessful. 4
II. PLANNING AND IMPLEMENTATION PERFORMANCE
A. Formulation and Design
14. The Government’s Seventh Five-Year Plan (FY1985-1989) placed strong emphasis on modernization and improvement of the industrial sector and accelerated growth of industry and infrastructure. The endemic power shortages all over the country constituted a serious bottleneck constraining industrial development.6 Accordingly, power generation projects aimed at closing the gap between the demand and supply of power were accorded a very high priority. Given the country's large coal resources and the shorter gestation period of thermal power projects, it was logical to concentrate on coal-based generation. By locating the Project in Tamil Nadu, the requisite hydrothermal power balance was provided in the state system, with a view to optimizing the utilization of the available generating capacity. The Project was consistent with ADB's strategic development objectives of assisting the Government's industrialization efforts and helping remove the bottlenecks in the infrastructure, particularly in the crucial power and transportation sectors.
15. The Project was formulated without an ADB project preparatory technical assistance, despite being an early loan to India. The OEM concurs with the PCR’s assessment that the plant design and engineering prepared by the domestic consultants were technically sound and appropriate in the context of the urgent need for the additional generating capacity envisaged under the Project to meet the power shortages and the anticipated demand growth in Tamil Nadu.
B. Achievements and Outputs
16. At appraisal, the Project was expected to add, upon commissioning in 1991, two units each of 210 MW of generating capacity and generate 2,575 GWh annually, meeting 10% of the annual energy demand in Tamil Nadu. The Project has successfully achieved both targets, though with major delays (para. 19). The energy output reached the appraisal target in FY1999 and significantly exceeded it in FY2000 and FY2001, as a result of high plant availability and load factor. The auxiliary consumption and thermal efficiency have been satisfactory for the given plant design and coal characteristics (Table 1).
Table 1: Technical Parameters of Plant Performance
Generation Plant Load Availability Auxiliary Thermal Fiscal (GWh) Factor (%) Factor (%) Consumption Efficiency Year Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 (%) (%)
1995 568 209 41.0 19.8 74.4 54.0 9.6 28.1 1996 1,138 1,190 61.7 64.5 82.5 87.0 8.8 30.5 1997 1,172 1,238 63.8 67.3 87.0 87.1 9.9 32.1 1998 1,284 1,217 69.8 66.2 84.2 82.6 9.5 33.6 1999 1,386 1,184 75.4 64.4 91.9 91.5 9.3 33.7 2000 1,566 1,305 84.9 70.8 91.3 83.2 9.3 33.7 2001 1,645 1,513 89.4 82.3 93.5 92.6 9.0 33.8
GWh = gigawatt-hour. Source: Tamil Nadu Electricity Board.
6 At the time of appraisal, power shortages were about 21% of the total requirement (Appraisal Report, para. 24).
5
C. Cost and Scheduling
17. The total actual project cost at completion was $469 million equivalent, comprising $176 million (37.5% of the total cost) in foreign exchange costs and $293 million equivalent (62.5% of the total cost) in local currency costs. There was a significant underrun in the total project cost of 25% (Table 2; for details see Appendix 1).
Table 2: Summary of Project Costs ($ million)
Appraisal Change Item Estimate Actual (%)
A. Base Cost 403.60 392.69 (2.7) Turbine Generators and Auxiliaries 59.27 43.05 (27.4) Steam Generators and Auxiliaries 66.71 49.00 (26.6) Equipment 55.33 63.83 15.4 Coal and Ash Handling 35.12 35.78 1.9 Civil Works 93.58 131.49 40.5 TNEB Miscellaneous, Freight, and Insurance 35.54 42.01 18.2 Consulting Services 6.91 2.11 (69.5) Taxes and Duties 51.14 25.42 (50.3)
B. Contingencies 116.14 0.00
C. Interest During Construction 107.79 76.68 (28.9)
Total (A+B+C) 627.53 469.37 (25.2)
Source: Tamil Nadu Electricity Board.
18. The OEM confirms the PCR statements that significant savings resulted mainly from a major depreciation of the rupee during project implementation, and intense competition for ADB- financed contracts, with domestic bidders generally quoting lower prices than foreign bidders. In addition, the interest during construction was significantly lower, as the unused ADB loan amount of $39.6 million was cancelled in phases. Finally, the price contingencies, which were a high $96.3 million, also contributed substantially to the cost underrun.7
19. At appraisal, the commissioning of units 1 and 2 was scheduled for March and December 1991, respectively. Several factors led to significant delays: land acquisition problems; procurement delays in the award of contracts (due to excessive time taken by TNEB for bid evaluation, lengthy internal approvals of contract awards within TNEB, and additional lengthy process for approval of awards by the Central Electricity Authority and the Government
7 These contingencies were calculated on the assumption of a constant nominal exchange rate. In recent ADB projects, price contingencies are calculated on the assumption of a constant real exchange rate, and come out much lower. 6 of Tamil Nadu [GTN] before submission to ADB for approval); and delays in the implementation of some contracts, particularly that for the internal coal handling system (ICHS).
20. Units 1 and 2 were eventually commissioned in October 1994 and March 1995, respectively, more than 3 years behind schedule. However, their optimum utilization was not possible due to the delay in the commissioning of the ICHS, which became fully operational only in June 1999.8 Thus, the total delay in project implementation was about 6.5 years. The actual implementation of the various project components, compared with appraisal schedule, is in Appendix 2.
D. Procurement and Construction
21. Following its internal procedures, TNEB engaged an experienced domestic consulting firm for engineering, preparation of technical specifications and bid documents, bid evaluation, and review of construction drawings and operation and maintenance manuals. The consultants performed the assigned tasks professionally and in accordance with their terms of reference. Equipment financed by ADB was procured in accordance with ADB's Guidelines for Procurement. Civil works and other contracts not financed by ADB were procured in accordance with TNEB's procedures. TNEB reported that the performance of all contractors, except that for the ICHS, had been generally satisfactory and that all the goods and equipment procured met the required specifications.
E. Organization and Management
22. At the time of appraisal, ADB considered TNEB a mature utility possessing the requisite managerial, technical, and financial capability to plan and implement its investment and operation programs effectively. The only two matters for concern were (i) the tariff subsidies, particularly in the agricultural sector, and their adverse impact on the financial viability of TNEB; and (ii) the high power transmission and distribution losses, which stood at 22% at the time of appraisal.
23. The PCR presented a thorough analysis of the compliance with the 26 loan and project covenants (PCR, Appendix 9). The OEM concurs with the PCR’s observations. While TNEB complied with most of the key covenants, it did not maintain tariffs at a level to achieve a surplus of at least 3%, as required under Section 59 of the Electricity Act. It could achieve the 3% surplus only through major subventions provided by GTN.
24. As required by the Project Agreement, TNEB also conducted two technical studies, one for upgrading the distribution system of Greater Metropolitan Madras and the other for defining the system and identifying the equipment required for upgrading the load dispatch center for efficient system operation and load management. Based on these studies, TNEB prepared the feasibility report for the Madras City Augmentation and Upgradation Project (MAUP) for which ADB provided $50.6 million under the follow-on project (footnote 2).
8 The ICHS contract comprised coal handling plant, and dust extraction and ventilation systems. The domestic contractor awarded this contract performed unsatisfactorily with serious delays in implementation. TNEB terminated the contract in February 1997 and completed the works in June 1999 with its own resources and with the support from ADB’s subsequent project (footnote 2). In the meantime, until the ICHS’s commissioning, suspended particulate matter in the air and suspended solids in the run-off water around the coal handling area exceeded the limits specified by TNPCB. The external coal handling system for transporting the coal from Ennore port to the Project’s coal yard was completed under the subsequent project in January 2002. 7
III. ACHIEVEMENT OF PROJECT PURPOSE
A. Plant Performance
25. The Project enabled TNEB to optimize the operation of its hydropower generation facilities. Until the commissioning of the ICHS in June 1999, the plant performance suffered. For example, the heat rate (in kilocalories per kilowatt-hour [Cal/kWh]) was 3,057 in 1995, 2,683 in 1997, and 2,563 in 1998. Once the ICHS was commissioned, the heat rate improved further to 2,550 Cal/kWh. Since then, the two units have been performing very well with plant load factors exceeding 80%. The TNEB staff for plant operation and maintenance have been adequately trained. With the commissioning of the external coal handling system in January 2002, the availability of coal is expected to further improve. The coal delivered by sea will be also cheaper than that delivered by rail.
26. The additional capacity provided and the energy generated by the plant have resulted in an increase in consumption by domestic and industrial consumers, mainly in the urban areas in Chennai. TNEB reported that, in FY2002, 2,566 GWh were distributed as a result of the Project. Domestic, industrial, and commercial consumers accounted for a total of 89.9% of the energy distributed,9 agricultural consumers who received free electricity for 4.1%, and the balance of 6.0% was used for public buildings and street lights.
B. Performance of the Operating Entity
27. The key indicator of the financial performance of TNEB is the 3% surplus required under Section 59 of the Electricity Act. The Loan Agreement stipulated that TNEB would maintain tariffs at a level to achieve the 3% surplus. However, given GTN's decision to give power free of charge to agricultural consumers, this was not possible, and hence subventions were needed from GTN to achieve the stipulated surplus. The OEM concurs with the PCR that such subventions have become a significant burden on GTN’s budgetary resources. Although the subventions decreased in relative terms from 34% of TNEB’s energy sales revenues in FY1991 to 23% in FY2001, they increased in absolute terms from $2.7 billion to $3.9 billion during the same period (and much more in local currency [Appendix 3]). The financial viability of the state electricity boards (SEBs) in India is a key issue (para. 46).
C. Economic and Financial Reevaluation
28. The economic and financial reevaluation has been carried out by the OEM with the world price numeraire in FY2001 constant prices. Data for energy generated, auxiliary consumption, and fuel consumption for the period up to FY2001 are as recorded at the power plant. Total sales have been derived by deducting from the energy generated auxiliary consumption, and transmission and distribution losses. Category-wise, sales have been computed based on the percentage share of incremental sales in each year. Financial revenues for the period until
9 The breakdown was domestic, 55.4%; industrial, 19.0%; and commercial, 15.5%. 8
FY2001 are based on actual average realization of revenue for each category.10 For the period thereafter, FY2001 figures have been assumed. In the economic analysis, the benefits to consumers have been estimated using the methodology from a recent operations evaluation report.11 The details of the analysis are in Appendix 4. On this basis, the economic internal rate of return (EIRR) is 14.2%, and the FIRR is 8.4%. The PCR estimate of the FIRR was 4.0%. It was significantly lower than the appraisal estimate of 7.4%, because of the long delays in project implementation and lower revenues. In the PCR, the revenues were estimated using the actual average tariffs in FY1999, which were higher in local currency terms than the average tariffs assumed in the Appraisal Report, but significantly lower when expressed in dollar terms because of the Indian Rupee depreciation.12 The OEM's FIRR estimate is higher than both the appraisal and PCR estimates. The two main reasons for the higher FIRR are the capital cost underrun of 25% and the higher-than-expected levels of generation.13 These factors have more than compensated for the delays in implementation. In addition, agricultural consumers who are given electricity free of charge by GTN consumed only a small portion of the incremental energy generated by the plant.14 If the agricultural consumers were charged at the cost of supply, which is the amount reimbursed through the subventions by GTN, the FIRR would be even better at 9.9%.15
D. Sustainability
29. Technically, the design of the Project and the technology adopted are robust and appropriate to the available human resources and institutional capabilities. Future funding for the required operation and maintenance is not expected to be a problem. Thus, the OEM has confirmed the likely long-term sustainability of the Project, on the condition that GTN would provide subventions until agricultural consumers are charged for electricity.
IV. ACHIEVEMENT OF OTHER DEVELOPMENT IMPACTS
A. Socioeconomic Impact
30. The OEM confirmed the PCR statements that resettlement and rehabilitation efforts were in keeping with India’s prevailing standards. The OEM also investigated the PCR’s points on how these resettlement and rehabilitation measures fared with respect to ADB standards, noting that the Project was implemented before ADB adopted the Policy on Involuntary Resettlement.16 The OEM found the measures generally satisfactory (Appendix 5 and Supplementary Appendix A). Acquisition of land for the Project affected 1,010 families in three villages and a few rural
10 GTN provides subventions to TNEB to cover the cost of supply for the electricity consumed by agricultural consumers. This has not been included in the revenues. The Appraisal Report and the PCR recorded that the subventions have not covered all the financial losses incurred by TNEB because of the distribution of free power to agricultural users. Moreover, there is no contract in written form between GTN and TNEB assuring the level of subventions. 11 PE 524: Rayalaseema Thermal Power Project (Loan 988-IND) circulated in June 1999. 12 For example, for the domestic consumers, the PCR used Rs0.75/kWh ($0.017/kWh), while the Appraisal Report assumed Rs0.55/kWh ($0.044/kWh). 13 The actual plant load factor in 2001 was 89.4% for unit 1 and 82.3% for unit 2 while at appraisal and in the PCR, the generation level was assumed at 70.0% of the plant load factor for both units. 14 Agricultural consumers accounted for about 30% of the overall sales in Tamil Nadu in 1986 (Appraisal Report, para. 114), and about 35% in FY2001. The OEM observed that the energy generated by the plant essentially met the increasing demands of domestic and industrial consumers. 15 The OEM also reaffirmed the conclusion in the previous operations evaluation report (footnote 11) that charging the agricultural consumers would reduce the burden on GTN to provide subventions and ensure the long-term financial sustainability of TNEB. 16 IN.105-99. Policy on Involuntary Resettlement: Report to the Board of Directors, 30 March. 9 settlements. TNEB provided employment to one person in each displaced family; these families highly appreciated such compensation. The resettled areas and amenities provided by TNEB were also of a good standard, especially when compared with the original sites that the displaced families used to occupy prior to the Project. This condition was particularly seen in one village near the power plant, Athipathu, where initially 475 displaced families were accommodated. It has attracted others and currently the population has expanded to more than twice its original size.
31. However, as the new sites have grown, the people living there have started to make demands for more job opportunities and other social services. Such services have grown beyond the originally envisaged responsibility of the power plant under the resettlement plan. TNEB has recruited a sociologist and an environmental engineer as permanent staff to deal with these issues. The sociologist has planned routine programs on related social matters, such as education, public health, and income generating programs. The OEM suggested working closely with the community, social workers, and concerned nongovernment organizations in designing and implementing these programs to ensure ownership, continuous support, and sustainability. The OEM also suggested that the power plant open its facilities such as clinic and school to the displaced families to create a good relationship and mutual respect, and erase unnecessary suspicions between the people and the power plant. This approach has proven successful in a neighboring power plant, and the OEM recommended that the lessons learned from this success could be adopted. GTN and TNEB welcomed these suggestions and intend to incorporate them in their social programs.
B. Environmental Impact
32. The OEM conducted detailed studies to review the environmental impact of the power plant. The OEM observed that the plant is meeting environmental standards for emissions and ash disposal (Appendix 6 and Supplementary Appendix B). The temperature rise in the cooling water is also within the prescribed limits. Nonetheless, TNPCB has not yet given its approval for plant operation because TNEB is discharging the cooling water into Buckingham canal instead of Ennore creek as was originally licensed. TNEB had in fact already constructed the requisite facilities for the discharge of the cooling water into Ennore creek. However, it is discharging the water into Buckingham canal in view of the opposition of the local fisherfolk who are concerned about the impact of the hot water being discharged into the Ennore creek on the fish there. In the OEM’s view, the current practice does not constitute an environmental hazard as relatively cleaner, filtered seawater is discharged into a canal, which receives effluents and solid waste from urban areas in Chennai. TNEB is resolving this matter in consultation with TNPCB. The OEM was informed that TNEB is now preparing an $8 million project for intake and discharge of cooling water near Ennore port.
C. Impact on Institutions and Policy
33. The Project did not have any significant impact on TNEB as an institution nor on GTN's power sector policies, as none was specifically envisaged during appraisal. The institutional impact of the Project was also limited, due to rapid turnover of project personnel.
34. MAUP was successfully completed with ADB assistance under the follow-on project (para. 24). MAUP has led to significant benefits such as more effective load management, improved and balanced loading of the distribution system, reduced fault location time, reduced restoration of supply time, reduced time of changeover of supply in the 33 kV network, and 10 lower distribution system losses.17 The reliability of supply has also resulted in an increased number of industrial users, and has contributed to overall industrial development in Tamil Nadu.
V. OVERALL ASSESSMENT
A. Relevance
35. At appraisal, the Project was consistent with the Government's priorities for industrial and infrastructure development, and was in line with the strategic objectives of ADB's country operational strategy. The Project continues to be consistent with the country's priority both for economic development, for which adequate power supply is a key input, and for infrastructure. Accordingly, the Project is rated highly relevant.
B. Efficacy
36. The Project successfully installed an additional 420 MW of power generating capacity utilizing domestic coal, although the coal handling systems became fully operational only under the follow-on project (footnote 2). The Project is, therefore, rated efficacious.
C. Efficiency
37. Apart from providing additional generating capacity, the Project enabled TNEB to operate its largely hydro-based system optimally by providing the requisite thermal backup. The EIRR is 14.2% and the FIRR is 8.4%. The Project is rated efficient, considering the long delay in implementation.
D. Sustainability
38. The technology adopted for the Project is well proven and TNEB has adequate skills and organization to operate the power plant and the associated infrastructure efficiently over its economic life. Future funding for required operation and maintenance is not expected to be a problem. Accordingly, the sustainability of the Project is rated likely. However, the rating is contingent on GTN providing the subventions until the reforms in the electricity sector in Tamil Nadu allow TNEB to charge agricultural consumers for electricity.
E. Institutional Development and Other Impacts
39. At the time of appraisal, no specific targets for institutional development or other impacts were envisaged. MAUP, as formulated under the Project, achieved significant impacts in terms of capacity building, although it was implemented under the follow-on project. Overall, the Project's institutional development and other impacts are rated moderate.
F. Overall Project Rating
40. The Project has satisfactorily achieved its objectives, though the delay in its implementation was significant. The FIRR is higher than envisaged during appraisal and
17 TNEB’s transmission and distribution losses have been reduced from 22% at the time of appraisal to 16% in FY2002, well below the national average of 26% (Source: Annual Report 2001-2002, Ministry of Power, Government of India). 11 calculated in the PCR. The issues relating to the environment have been addressed adequately. Overall, the Project is rated successful.18
G. Assessment of ADB and Borrower Performance
41. ADB's performance was highly satisfactory. During implementation, ADB closely monitored progress, regularly fielded review missions, and provided valuable assistance in resolving conflicts with some of the contractors. ADB also followed up on outstanding issues during the implementation of the ICHS.
42. Both the Borrower and TNEB performed satisfactorily. TNEB in general proved to be a technically competent organization. However, its internal procedures for bid evaluation and contract awards led to considerable front-end delays, which could have been avoided through rationalization of the relevant systems and procedures. Also, for historical reasons, the turnover of project personnel was high and resulted in poor ownership. TNEB also needs to improve plant safety to meet international standards.
H. Power Sector Policies
43. The Project did not have any policy component. Several encouraging steps have been taken recently by the Government and the state governments to reform and restructure the power sector. In particular, the distribution subsector has now been targeted for improvement. During a conference of the Chief Ministers held on 3 March 2001, many state governments, including GTN, agreed that:
(i) there is an urgent need to depoliticize power sector and tariff reforms and speed up their implementation;
(ii) distribution reforms need to be carried out by making energy audits effective, developing effective management information systems, and eliminating energy theft;
(iii) commercial viability in distribution is to be achieved in 2–3 years by creating profit centers, privatizing, and/or handing over local distribution to Panchayats (local bodies)/franchisees or user associations; and
(iv) the state electricity regulatory commissions (SERCs) are to be made functional and tariff orders are to be issued; subsidies are to be given only to the extent of the Government's capacity to pay them explicitly through budget provisions.
44. As regards regulation, the Central Electricity Regulatory Commission, formed under the provisions of Electricity Regulatory Commissions Act 1988, was made fully functional in 1999. As of FY2001, 18 states, including Tamil Nadu, have either constituted or initiated action for constitution of SERCs. Under its accelerated power development program announced in 2001, the Government is also giving financial assistance, channeled through the Power Finance Corporation (PFC), to the states for system improvement if they are implementing reforms in their distribution systems. While the above steps are in the right direction, more needs to be done, and done quickly. One option is to divide the distribution systems in the SEBs into small manageable segments and to privatize them. The process could start with privatizing billing and
18 Under the current four-category rating system (highly successful, successful, partly successful, and unsuccessful). 12 collection so that there is an immediate increase in the revenues of the cash-poor SEBs. Overall, these developments provide a unique opportunity for ADB to take a lead role and assist India's power sector with technical assistance and loans in restructuring and privatizing the distribution subsector.
45. As regards the coal sector, no significant reforms have been implemented nor contemplated. As highlighted in previous ADB evaluation reports in the power sector in India, there are great concerns regarding the poor quality of the coal being mined. The Government has recognized these concerns by accepting that in future, imports of coal for coastal thermal power stations and of oil or natural gas for inland stations will be unavoidable.
VI. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS
A. Key Issues for the Future
46. Financial Viability of SEBs. The financial viability of SEBs is of national relevance. Two major factors contributing to the poor state of SEBs' finances are the politically driven tariffs and inefficient meter reading and bill collection. As regards the tariffs, competent and impartial SERCs are essential to provide the required barrier against political intervention in tariff setting. Further, SERCs will also make the tariff setting process transparent and provide a forum for the SEBs and other suppliers, and their consumers to examine and discuss the appropriateness of the proposed tariff revisions. Such a process will therefore make the tariffs more acceptable to consumers. The problem of inefficient meter reading and bill collection can be resolved by privatizing this area of the utility operations with suitable incentives for private contractors. Such privatization will likely face limited opposition since the personnel affected are relatively small in number and since most of the redundant staff are likely to find alternate employment with the private contractors. Further, such privatization should be an integral part of the program of breaking up the distribution system into manageable segments and privatizing them. The creation of such profit-oriented distribution companies would have a critical impact on tariff rationalization, as these companies would provide a strong countervailing lobby against the farmers' lobby, which is strongly opposed to rationalization of the agricultural tariff.
B. Lessons Identified
47. Land Acquisition. The Project suffered severe delays caused by difficulties in land acquisition. This problem could have been overcome by contracting out land acquisition and making it a precondition for ADB approval of the loan or for loan effectiveness. Experience in Indonesia and the Philippines demonstrates that the private sector is also effective in acquiring land expeditiously.
48. Turnkey Contract. A single turnkey contract would have avoided the considerable delays experienced in the implementation of the Project resulting from inordinate delays in the award of several contracts and coordination between them. In future projects, it is essential to discuss and agree with the Borrower and the executing agencies, prior to ADB Board approval, the systems, procedures, and timeframes for bidding and contracting processes for such turnkey contracts. Such an approach would have an additional advantage of allowing for intense scrutiny by all the concerned parties and ensuring strict compliance with ADB's Guidelines for Procurement, particularly in view of the large value of the contract.
13
C. Follow-Up Actions
49. The OEM recommends these follow-up actions:
Action Responsibility Deadline
1. Expeditiously resolve the location of TNEB and TNPCB December 2002 cooling water discharge in the sea.
2. Monitor environmental compliance of plant ADB’s India July-December 2002 operation until the requisite certificates are Resident Mission issued by TNPCB.
3. Improve plant safety by ensuring that the TNEB December 2002 tools and equipment, including safety helmets already procured, are fully utilized.
4. Associate with community bodies and TNEB December 2003 nongovernment organizations to enhance and augment efforts in the resettlement and rehabilitation of families affected.
5. Give high priority for environmental ADB’s South Asia 2004 Country Strategy concerns, due to the use of low-quality Department, Programming Mission (high ash-content, and low calorific value) Infrastructure domestic coal in the thermal power plants Division in India.
6. Take a lead role in the restructuring of ADB’s South Asia 2004 Country Strategy India’s power distribution subsector and Department, Programming Mission provide technical and financial assistance Infrastructure by adopting a sector lending approach.19 Division
7. Make a detailed review of the PCR for ADB’s Operations December 2002 Loan 1029-IND: Second North Madras Evaluation Thermal Power Project. Department
50. For actions 1, 3, and 4, ADB’s India Resident Mission is requested to monitor implementation.
19 Such assistance can be channeled through PFC with the privatization of the distribution systems as a precondition for financial and technical assistance. To qualify for ADB assistance, states would need to privatize distribution only in such areas where it is advantageous and practical. 14 Appendix 1
COST BREAKDOWN BY PROJECT COMPONENTS ($ million)
Appraisal Estimate Actuala Item Foreign Local Total Foreign Local Total
A. Base Cost Turbine Generators and Auxiliaries 59.27 0.00 59.27 43.05 0.00 43.05 Steam Generators and Auxiliaries 66.71 0.00 66.71 49.00 0.00 49.00 Instrumentation and Control 9.06 0.00 9.06 2.68 0.00 2.68 Switch-House Equipment 4.73 0.00 4.73 1.39 0.00 1.39 Water Treatment Plant 2.99 0.00 2.99 0.00 6.73 6.73 Protection, Control, and Testing Equipment 2.46 0.00 2.46 0.00 19.95 19.95 Transformers 3.38 0.00 3.38 0.00 12.00 12.00 Switchgears 5.62 0.00 5.62 0.00 6.20 6.20 Coal and Ash Handling 35.12 0.00 35.12 14.27 21.51 35.78 Miscellaneous Mechanical Equipment 0.00 11.14 11.14 0.00 8.87 8.87 Miscellaneous Electrical Equipment 0.62 8.54 9.16 0.00 3.02 3.02 Preliminary Equipment 0.00 6.79 6.79 0.00 2.99 2.99 Civil Works - Residential Colony 0.00 7.18 7.18 0.00 8.65 8.65 Civil Works - Power Station 0.00 61.42 61.42 0.00 93.41 93.41 Erection, Testing, and Commissioning 0.00 24.98 24.98 0.00 29.43 29.43 TNEB Miscellaneous, Freight, and Insurance 0.00 35.54 35.54 0.00 42.01 42.01 Consulting Services 0.00 6.91 6.91 0.00 2.11 2.11 Taxes and Duties 0.00 51.14 51.14 0.00 25.42 25.42
Subtotal (A) 189.96 213.64 403.60 110.39 282.30 392.69
B. Contingencies Physical Contingencies 9.50 10.34 19.84 0.00 0.00 0.00 Price Escalation 14.27 82.03 96.30 0.00 0.00 0.00
Subtotal (B) 23.77 92.37 116.14 0.00 0.00 0.00
C. Interest During Construction ADB Loan 28.06 5.37 33.43 66.00 0.00 66.00 Other Loans 11.99 62.37 74.36 0.00 10.68 10.68
Subtotal (C) 40.05 67.74 107.79 66.00 10.68 76.68
Total (A+B+C) 253.78 373.75 627.53 176.39 292.98 469.37 a Actual expenditures after application of contingencies, if necessary. ADB = Asian Development Bank, PCR = project completion report, TNEB = Tamil Nadu Electricity Board. Notes: 1. The "Actual" data for "Transformers" and "Civil Works - Power Station" differ from the PCR as they have been revised by TNEB during OEM. 2. "Interest During Construction" data for "Actual" has been modified from the PCR and the interest paid on ADB loan shown as Foreign Cost. 3. The following exchange rates have been used to convert local currency to dollar equivalent:
FY 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Rs/$ 12.23 12.78 12.96 14.48 16.65 17.94 24.47 30.65 31.36 31.40 33.45 35.50 37.16 42.07 43.33 45.68 47.75
Source: Operations Evaluation Mission, 2002. Appendix 2 15
IMPLEMENTATION SCHEDULE
Delay Appraisal Actual (Months) Item Start End Start End Start End
Land Acquisition Jan-86 Dec-86 Apr-86 Oct-93 3 82 Civil Works Jul-87 Jun-91 Sep-89 Jan-96 14 55 Steam Generators Nov-86 Mar-93 Nov-87 Mar-96 12 36 Turbine Generators Jan-86 Dec-92 Feb-88 Mar-96 25 39 Control and Instrumentation Mar-88 Dec-92 Apr-90 Dec-99 25 84 Coal Handling System Feb-88 Mar-92 Jun-91 Dec-99 52 93 Mechanical Services Jan-88 Sep-91 May-94 Dec-99 76 99 Transformers Jan-88 Mar-92 Dec-93 Aug-96 71 53 Switchgear Feb-88 Mar-92 Dec-91 Aug-96 46 57 Switchyard Equipment Apr-88 Dec-91 Nov-93 Jan-95 67 37 Electrical Services Mar-88 Dec-92 Nov-92 Apr-99 68 76 Transmission System Apr-86 Mar-92 Jan-92 Apr-96 69 49
Source: Operations Evaluation Mission, 2002. IMPLEMENTATION SCHEDULE 16 Appendix2
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 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 IV I II III IV I II III IV
Land Acquisition
Civil Works
Steam Generators
Turbine Generators
Control and Instrumentation
Coal Handling System
Mechanical Services
Transformers
Switchgear
Switchyard Equipment
Electrical Services
Transmission System
Appraisal Schedule Actual Implementation Source: Operations Evaluation Mission, 2002. FINANCIAL STATEMENTS OF THE TAMIL NADU ELECTRICITY BOARD Table A3.1: Balance Sheet (Rs million) Item 1990/91 1991/92 1992/93 1993/94 1994/95 1995/96 1996/97 1997/98 1998/99 1999/2000 2000/01 Current Assets 63,498.0 81,495.0 134,307.0 136,040.0 159,721.0 189,266.0 250,799.0 311,895.0 346,675.0 332,304.0 365,752.0 Less: Current Liabilities Security Deposits from Customers 25,240.0 32,369.0 36,198.0 46,887.0 53,293.0 77,608.0 86,696.0 101,341.0 110,902.0 127,902.0 141,170.0 Other Current Liabilities 79,183.0 86,750.0 86,762.0 112,916.0 105,979.0 114,583.0 177,963.0 240,523.0 255,266.0 292,770.0 432,251.0 Working Capital (40,925.0) (37,624.0) 11,347.0 (23,763.0) 449.0 (2,925.0) (13,860.0) (29,969.0) (19,493.0) (88,368.0) (207,669.0)
Plus: Non Current Assets Gross Block 364,338.0 390,050.0 425,318.0 504,126.0 560,576.0 632,016.0 796,303.0 865,830.0 947,388.0 1,051,480.0 1,160,818.0
Less: Accumulated Depreciation 78,705.0 89,559.0 101,458.0 115,243.0 132,667.0 156,559.0 188,517.0 226,824.0 271,160.0 326,791.0 383,744.0 285,633.0 300,491.0 323,860.0 388,883.0 427,909.0 475,457.0 607,786.0 639,006.0 676,228.0 724,689.0 777,074.0 Plus: Non Current liabilities Capital Expenditure in Progress 121,372.0 159,511.0 162,062.0 189,196.0 227,414.0 283,202.0 232,730.0 256,867.0 284,471.0 304,747.0 362,430.0 Assets Not in Use 910.0 932.0 898.0 958.0 879.0 223.0 540.0 433.0 441.0 96.0 111.0 Deferred Cost 41.0 66.0 91.0 7,145.0 11,474.0 11,512.0 215.0 240.0 285.0 318.0 357.0 Intangible Assets 5,543.0 8,844.0 11,347.0 (23,763.0) 449.0 (2,925.0) (13,860.0) (29,969.0) 63,609.0 32,321.0 57,341.0 Investments 5,810.0 7,496.0 7,045.0 7,026.0 7,042.0 3,694.0 3,747.0 3,680.0 4,389.0 4,348.0 4,337.0
Net Assets 378,384.0 439,716.0 516,650.0 545,682.0 675,616.0 768,238.0 817,298.0 840,288.0 1,009,930.0 978,151.0 993,981.0
Liabilities Borrowings and payments due 84,630.0 87,024.0 96,432.0 100,195.0 112,519.0 143,013.0 149,030.0 139,760.0 164,821.0 166,214.0 185,971.0 Capital Liabiliites 156,576.0 180,853.0 211,030.0 250,557.0 296,913.0 320,438.0 337,193.0 352,804.0 409,987.0 497,617.0 552,458.0 Funds State Govt. 121,004.0 125,259.0 90,496.0 84,828.0 88,301.0 91,471.0 86,008.0 78,811.0 104,548.0 0.0 10,000.0 Reserves and Surpluses 16,174.0 46,580.0 118,692.0 110,102.0 177,883.0 213,316.0 245,067.0 268,913.0 330,574.0 314,320.0 245,552.0 378,384.0 439,716.0 516,650.0 545,682.0 675,616.0 768,238.0 817,298.0 840,288.0 1,009,930.0 978,151.0 993,981.0
Statement of Capital Base and Surplus Original Cost of Fixed Assets 313,912.0 364,338.0 390,050.0 425,318.0 504,126.0 560,576.0 632,016.0 788,985.0 858,346.0 952,663.0 —
Less: Accumulated Depreciation 69,606.0 78,705.0 89,559.0 101,458.0 115,243.0 132,667.0 156,559.0 188,517.0 226,824.0 271,950.0 —
Net Block 244,306.0 285,633.0 300,491.0 323,860.0 388,883.0 427,909.0 475,457.0 600,468.0 631,522.0 680,513.0 — Appendix3 Consumer Contribution 3,739.0 4,349.0 7,727.0 12,994.0 17,807.0 24,975.0 34,087.0 41,271.0 49,577.0 58,439.0 —
Capital Base (i.e., value of fixed assets in service at the beginning of the Year under Sec. 59) 240,567.0 281,284.0 292,764.0 310,866.0 371,076.0 402,934.0 441,370.0 559,197.0 581,945.0 622,073.0 — Surplus under Sec. 59 7,217.0 25,289.0 22,510.0 22,554.0 344,775.0 33,919.0 32,963.0 27,364.0 33,496.0 35,625.0 38,787.0 Surplus as Percentage to Capital
Base under Sec. 59 3.0 9.0 7.7 7.3 9.4 8.4 7.5 4.9 5.7 5.7 — 17
— = not available. Source: Tamil Nadu Electricity Board. 18 Appendix 3
Table A3.2: Revenue Account (Rs million)
1990/91 1991/92 1992/93 1993/94 1994/95 1995/96 1996/97 1997/98 1998/99 1999/2000 2000/01
Revenue Receipts Sale of Power 140,660.0 164,995.0 204,917.0 260,354.0 346,877.0 408,204.0 443,602.0 524,400.0 558,817.0 634,927.0 742,507.0 Tariff Compensation 48,265.0 35,003.0 45,706.0 52,710.0 35,006.0 41,593.0 58,651.0 57,006.0 107,622.0 177,639.0 169,321.0 (from State Government) Miscellaneous Income 4,126.0 2,706.0 6,907.0 3,081.0 3,952.0 4,623.0 5,447.0 6,705.0 9,436.0 12,421.0 15,303.0 Total A 193,051.0 202,704.0 257,530.0 316,145.0 385,835.0 454,420.0 507,700.0 588,111.0 675,875.0 824,987.0 927,131.0
Revenue Expenses Power Purchase 44,847.0 51,255.0 52,490.0 66,052.0 82,296.0 86,961.0 97,920.0 127,653.0 179,867.0 254,308.0 313,416.0 Fuel Cost 64,816.0 68,711.0 101,269.0 123,664.0 137,733.0 187,943.0 219,012.0 226,507.0 216,030.0 258,327.0 265,566.0 Repairs and Maintenance 4,001.0 4,449.0 6,409.0 8,463.0 10,677.0 13,194.0 14,135.0 13,677.0 15,872.0 12,555.0 12,598.0 Employee Cost 35,748.0 36,416.0 42,030.0 52,158.0 63,607.0 71,153.0 82,996.0 106,888.0 126,833.0 151,547.0 156,951.0 Administration and General Expenses 5,850.0 7,353.0 7,734.0 9,474.0 11,313.0 10,908.0 13,154.0 13,861.0 14,353.0 14,428.0 14,082.0 Depreciation 9,405.0 11,009.0 12,000.0 13,696.0 17,580.0 22,330.0 32,146.0 38,314.0 44,765.0 54,881.0 57,614.0 Interest and Finance Charges 28,769.0 23,545.0 38,291.0 41,683.0 44,520.0 51,867.0 58,681.0 60,603.0 66,565.0 80,973.0 89,350.0 Total B 193,436.0 202,738.0 260,223.0 315,190.0 367,726.0 444,356.0 518,044.0 587,503.0 664,285.0 827,019.0 909,577.0
Interest and Finance Capitalized 6,083.0 6,696.0 11,242.0 11,653.0 10,470.0 13,886.0 16,454.0 14,084.0 17,751.0 22,606.0 24,990.0 Other Expenses Capitalized 6,512.0 7,948.0 11,037.0 10,440.0 11,846.0 16,929.0 17,079.0 19,087.0 19,143.0 23,907.0 23,904.0 Total C 12,595.0 14,644.0 22,279.0 22,093.0 22,316.0 30,815.0 33,533.0 33,171.0 36,894.0 46,513.0 48,894.0
Other Debits 80.0 782.0 389.0 1,511.0 1,708.0 4,188.0 2,213.0 1,515.0 1,688.0 982.0 635.0 Extraordinary Items 0.0 485.0 86.0 391.0 19.0 26.0 10.0 1.0 268.0 0.0 37.0 Prior Period Charges 4,913.0 (11,946.0) (3,399.0) (1,408.0) 3,923.0 2,746.0 (11,997.0) 4,899.0 13,034.0 7,874.0 26,989.0 Total D 4,993.0 (10,679.0) (2,924.0) 494.0 5,650.0 6,960.0 (9,774.0) 6,415.0 14,990.0 8,856.0 27,661.0
E = B-C-D 185,834.0 177,415.0 235,020.0 293,591.0 351,060.0 420,501.0 474,737.0 560,747.0 642,381.0 789,362.0 888,344.0 Surplus (A-E) 7,217.0 25,289.0 22,510.0 22,554.0 34,775.0 33,919.0 32,963.0 27,364.0 33,494.0 35,625.0 38,787.0
Source: Tamil Nadu Electricity Board. Appendix 4 19
ECONOMIC AND FINANCIAL REEVALUATION
A. General Methodology
1. The assessment of the economic and financial viability of the Project was performed using the world prices numeraire in domestic currency (Indian rupees) in constant FY2001 prices. To convert nontradable goods and services to economic prices, a standard conversion factor of 0.8 was used. All incremental costs, revenues, and benefits were derived in 2001 prices using gross domestic product (GDP) deflators for India from the Statistical Database (SDBS) of the Asian Development Bank (ADB). Interest during construction was excluded from the cost stream. In addition, taxes and duties were excluded in estimating the economic costs.
B. Generation Data
2. Data for units generated, consumption in auxiliaries, and fuel consumption for the Project for the period up to 2001 are as recorded at the plant. For the period beyond 2001, generation has been computed assuming a plant load factor of 85% until 2012 and 70% thereafter, which is in keeping with the design specifications of the power plant. Auxiliary consumption has been computed at 9% of gross generation for the period beyond 2001. Specific fuel consumption has been assumed to remain at the 2001 level for the period beyond 2001.
C. Capital Costs
3. For generation, the capital costs are based on the actual project costs on completion. Before completion of the Project, the Tamil Nadu Electricity Board (TNEB) also invested in expanding transmission and distribution in urban areas. Based on the figures provided by TNEB, the capital expenditures of transmission and distribution attributable to the Project were estimated at 50% of generation costs. Transmission costs have been assumed to occur in 3 years, with the last year coinciding with plant commissioning. The distribution costs have been prorated on the basis of sales to ultimate consumers and have been assumed to incur in the first year of sales.
D. Operation and Maintenance Costs
4. Using figures provided by TNEB, the annual operation and maintenance costs, including the costs of ash disposal and compliance with environmental obligations stipulated by the Tamil Nadu Pollution Control Board, have been estimated at 1% of the capital cost for generation, 0.5% of capital cost for transmission, and 2% of capital cost for distribution. Fuel costs of coal and oil were estimated using the respective consumption levels reported in Appendix 2. The World Bank’s Commodity Price Forecasts were used as the benchmark world price for coal, and the economic price of the coal used in the Project was estimated using the methodology in a recent operations evaluation report.1
E. Sales and Revenues
5. Total sales have been derived from the units generated net of consumption in station auxiliaries, and transmission and distribution losses. Category wise sales have been computed based on the percent share of incremental sales in each year. Financial revenues are based on actual average realization of revenue for each category in the past until 2001.
1 PE 524: Rayalaseema Thermal Power Project (Loan 988-IND) circulated in June 1999. The economic price of coal was adjusted on the basis of quality (ash content and calorific value). 20 Appendix 4
For the period thereafter, 2001 figures have been assumed. From the discussions with TNEB and the Tamil Nadu State Electricity Regulatory Commission, the Operations Evaluation Mission (OEM) learned that future tariffs would be regularly revised, considering the rate of inflation and overall performance of TNEB’s power plants. TNEB reported that, in FY2002, 2,566 million units were distributed as a result of the Project. The domestic, industrial, and commercial consumers who paid tariffs accounted for a total of 89.9% of the energy distributed. The individual consumptions were domestic: 55.4%; industrial: 19.0%; and commercial: 15.5%. Agricultural consumers accounted for 4.1% of the incremental energy distributed from the plant. The Government of Tamil Nadu (GTN) provides subventions to TNEB to cover the cost of supply for the electricity consumed by agricultural consumers. This has not been included in the revenues in the base case.
F. Benefits
6. In the economic analysis, the benefits to consumers have been estimated using the methodology adopted in a recent operations evaluation report (footnote 1). For the agricultural and some low-income domestic consumers who are not charged, the benefits have been estimated using the resource cost savings approach. First, for each of these consumer categories, the fuel substitution shares of incremental electricity were estimated. Second, electricity consumption that is replacing the alternative energy was valued in terms of the cost saved by using electricity instead of alternative energy sources. For the industrial consumers, benefits were valued at the economic price of electricity produced by captive power plants. The economic price of the captive power was estimated based on the actual data received from TNEB and other published data. The commercial and domestic consumers have increased their electricity consumption in response to the better reliability and availability of electricity after the commissioning of the Project. For these users, the benefits have been estimated using the willingness-to-pay approach. The benefits for each of the consumers were valued using the respective incremental electricity consumption and the average of the corresponding tariffs for these consumers in the with-Project and without-Project situations.
G. Internal Rates of Return
7. The economic internal rate of return was 14.2%; the financial internal rate of return (FIRR) was 8.4%. Two main reasons for the higher FIRR as compared with appraisal estimates are: (i) actual project costs on completion are lower than the appraisal estimate by 25%, and (ii) higher levels of generation compared with appraisal estimates. The actual plant load factor in 2001 was 89.4% for Unit I and 82.6% for Unit II, while at appraisal the generation level was assumed at 70.0% plant load factor for both units. These factors have more than compensated for the delays in implementation. In addition, as noted above, agricultural consumers who are given power free of charge by GTN consumed only 4.1% of the incremental energy generated by the plant.
8. The OEM observed that the high FIRR for the Project was also due to the fact that incremental energy generated by the plant essentially met the increasing demands of domestic and industrial consumers. If the agricultural consumers were charged the cost of supply, which is the amount reimbursed through the subventions by GTN, the FIRR would be even better at 9.9%. Agricultural consumers accounted for about 30% of the overall sales in Tamil Nadu in 1986 (Appraisal Report, para. 114), and about 35% in FY2001. The OEM also reaffirmed the conclusions in the earlier operations evaluation report (footnote 1) that an overall tariff increase, achieved by charging the agricultural consumers, would reduce the burden on GTN of providing subventions and help ensure the long-term financial sustainability of TNEB. Table A4.1: Economic Internal Rate of Return (Rs million, 2001 = 100)
Costs Capital Costs Benefits Year Generation Transmission Distribution O&M Fuel Total Total Net
1987/88 314.45 0.00 0.00 0.00 0.00 314.45 0.00 (314.45) 1988/89 640.65 0.00 0.00 0.00 0.00 640.65 0.00 (640.65) 1989/90 361.12 0.00 0.00 0.00 0.00 361.12 0.00 (361.12) 1990/91 1,200.26 0.00 0.00 0.00 0.00 1,200.26 0.00 (1,200.26) 1991/92 2,202.46 0.00 0.00 0.00 0.00 2,202.46 0.00 (2,202.46) 1992/93 2,782.56 0.00 0.00 0.00 0.00 2,782.56 0.00 (2,782.56) 1993/94 2,624.18 0.00 0.00 0.00 0.00 2,624.18 0.00 (2,624.18) 1994/95 2,649.15 1,756.36 1,439.45 175.06 0.00 6,020.02 8.54 (6,011.48) 1995/96 404.37 2,158.44 2,649.63 190.48 303.76 5,706.69 3,048.30 (2,658.39) 1996/97 922.82 1,501.74 145.91 201.49 775.87 3,547.81 5,325.87 1,778.06 1997/98 371.20 0.00 101.69 191.25 914.72 1,578.86 4,719.74 3,140.88 1998/99 339.11 0.00 411.07 185.84 1,085.62 2,021.64 4,590.12 2,568.48 1999/00 38.31 0.00 363.16 179.20 1,319.39 1,900.06 5,925.17 4,025.10 2000/01 36.50 0.00 97.68 166.56 1,080.61 1,381.35 5,518.68 4,137.33 2002 166.56 1,185.83 1,352.39 5,944.73 4,592.34 2003 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2004 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2005 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2006 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2007 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2008 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2009 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2010 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2011 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2012 166.56 1,207.84 1,374.40 6,539.82 5,165.42 2013 166.56 994.62 1,161.18 5,014.94 3,853.76 2014 166.56 994.62 1,161.18 5,014.94 3,853.76 2015 166.56 994.62 1,161.18 5,014.94 3,853.76
2016 166.56 996.80 1,163.36 5,014.94 3,851.57 Appendix 4 2017 166.56 996.80 1,163.36 5,014.94 3,851.57 2018 166.56 996.80 1,163.36 5,014.94 3,851.57 2019 166.56 996.80 1,163.36 5,014.94 3,851.57 2020 166.56 996.80 1,163.36 5,014.94 3,851.57
EIRR 14.17% 21
EIRR = economic internal rate of return, O&M = operation and maintenance. Table A4.2: Financial Internal Rate of Return (Rs million, 2001 = 100) 22
Costs Capital Costs Benefits Appendix 4 Year Generation Transmission Distribution O&M Fuel Total Total Net
1987/88 314.45 0.00 0.00 0.00 0.00 314.45 0.00 (314.45) 1988/89 760.61 0.00 0.00 0.00 0.00 760.61 0.00 (760.61) 1989/90 361.12 0.00 0.00 0.00 0.00 361.12 0.00 (361.12) 1990/91 1,200.26 0.00 0.00 0.00 0.00 1,200.26 0.00 (1,200.26) 1991/92 2,708.19 0.00 0.00 0.00 0.00 2,708.19 0.00 (2,708.19) 1992/93 3,561.44 0.00 0.00 0.00 0.00 3,561.44 0.00 (3,561.44) 1993/94 3,355.91 0.00 0.00 0.00 0.00 3,355.91 0.00 (3,355.91) 1994/95 3,400.53 2,391.56 1,960.04 238.37 0.00 7,990.50 6.91 (7,983.58) 1995/96 485.01 2,939.06 3,607.89 259.37 379.70 7,671.03 2,557.33 (5,113.70) 1996/97 1,222.27 2,044.85 198.67 274.36 969.83 4,709.98 4,517.73 (192.25) 1997/98 480.05 0.00 138.47 260.42 1,143.40 2,022.33 4,054.00 2,031.67 1998/99 461.75 0.00 559.73 253.05 1,357.03 2,631.56 3,981.05 1,349.50 1999/00 52.16 0.00 494.50 244.01 1,649.24 2,439.91 5,239.87 2,799.95 2000/01 49.70 0.00 133.00 226.80 1,350.77 1,760.26 4,937.58 3,177.31 2002 226.80 1,482.29 1,709.09 5,318.77 3,609.68 2003 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2004 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2005 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2006 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2007 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2008 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2009 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2010 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2011 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2012 226.80 1,509.79 1,736.59 5,851.20 4,114.61 2013 226.80 1,243.27 1,470.07 4,486.88 3,016.81 2014 226.80 1,243.27 1,470.07 4,486.88 3,016.81 2015 226.80 1,243.27 1,470.07 4,486.88 3,016.81 2016 226.80 1,246.00 1,472.80 4,486.88 3,014.08 2017 226.80 1,246.00 1,472.80 4,486.88 3,014.08 2018 226.80 1,246.00 1,472.80 4,486.88 3,014.08 2019 226.80 1,246.00 1,472.80 4,486.88 3,014.08 2020 226.80 1,246.00 1,472.80 4,486.88 3,014.08
FIRR 8.43%
If the agricultural consumers were charged the cost of supply, the FIRR would be 9.9%. FIRR = financial internal rate of return, O&M = operation and maintenance. Appendix 5 23
RESETTLEMENT AND REHABILITATION MEASURES
No. of Expenditure Resettled Amenities Provided in the Incurred Village Families Resettlement Colonies (PCR) OEM Observation
Kathivakkam 261 (i) 25 hand pumps for Rs2,561,600 Hand pumps drinking water (Rs45,000)
(ii) all-weather roads — Bitumen road (Rs1,050,000)
(iii) storm water drain — Storm water drains (Rs481,000)
(iv) school building with — Schools and noon-meal asbestos centers (Rs2,500,000) corrugated sheet roofing
(v) public toilets — Toilets (Rs55,000)
(vi) street lighting — Street lights (Rs95,000)
(vii) area development — — for temple
(viii) sand filling of low — — lying areas
(ix) permanent school — — building to be constructed Location: SF7 and part of Kathivakkam extending to 13.93 acres. 257 families accommodated in 267 plots. Employment for 1 person per family, interest free advance (Rs7,100), free grant (Rs400) for house construction and transport of personal effects.
Athipathu 475 (i) sand filling of low Rs4,212,000 — lying areas
(ii) all-weather roads — Bitumen roads of 3.5 km (Rs2,500,000)
(iii) storm water drains — Brick masonry drains of 3.5 km (Rs850,000)
24 Appendix 5
No. of Expenditure Resettled Amenities Provided in the Incurred Village Families Resettlement Colonies (PCR) OEM Observation
(iv) due to high salinity — Water supply provided of subsoil water, from NCTPS site. drinking water is being supplied from the power plant
(v) public toilets — Toilets (Rs250,000)
(vi) school buildings — Two school buildings with asbestos sheet (Rs310,000). One roofing palvadi center and toilet
(vii) street lighting — 77 street lights (Rs300,000)
Location: SF235-7 etc. of Athipattu village, Ponneri Taluk extending to 18.05 acres. 475 families accommodated close to the railway station. Employment for 1 person per family, interest free advance (Rs7,100), free grant (Rs400) for house construction and transport of household articles.
Chepakkam 75 120 m2 (i) filling of low-lying Rs1,863,000 — per areas family (ii) all-weather roads — Road of 3940 m2
(iii) as the groundwater — — is highly saline, tankers are deployed to supply drinking water
(iv) street lighting — —
(v) cyclone shelters — Cyclone shelter provided
(vi) drainage — —
(vii) protection wall–to — Wall and barbed wire be taken up fencing
Appendix 5 25
No. of Expenditure Resettled Amenities Provided in the Incurred Village Families Resettlement Colonies (PCR) OEM Observation
(viii) permanent water — Hand pump provided by supply arrangement NMTPP and additional roads/drain Puzhuthivakkam 75 — Employment for 115 village close to persons (1 per family). NCTPS ash dyke extending to 3.59 acres
— = data not available, m2 = square meter, SF7/SF235-7 = names of blocks of houses. NCTPS = North Chennai Thermal Power Station, NMTPP = North Madras Thermal Power Project, OEM = Operations Evaluation Mission, PCR = project completion report. Source: Tamil Nadu Electricity Board. 26 Appendix 6
ACTIONS TAKEN ON STIPULATED ENVIRONMENTAL CONDITIONS
Action Taken/Operations Evaluation Conditiona Mission Observation
Install adequate control equipment to limit the SO2 emission is now controlled by a 275 meter sulfur dioxide (SO2) and particulate matter in high multiflue chimney. the ambient air within the standards prescribed. The SO2 emission at present ranges from 100 parts per million (ppm) to 150 ppm. Electrostatic precipitators of efficiency 99.8% have been installed to control particulate emission.
The particulate emission by actual measurements is found to be around 115 ppm.
Set up a suitable monitoring system to monitor The following online monitoring equipment to SO2 and suspended particulate matter monitor the stack emission is provided in regularly. addition to the mobile stack monitoring unit: (i) SO2 analyzer and oxygen analyzer (ii) analyzer to measure oxides of nitrogen (NOx) (iii) opacity meter (for smoke density) (iv) suspended particulate matter.
The following meteorological data are being recorded at the site: (i) hourly wind speed and direction (ii) hourly temperature (iii) humidity (iv) rainfall (v) solar radiation (vi) atmospheric pressure.
The ambient air quality is being studied to monitor suspended particulate matter, SO2, and NOx once in a month with the help of high volume samplers at the following five locations situated in and around the power plant area:
(i) Athipattu (ii) Ennore (iii) Vallur (iv) K.R. Palayam (v) Kattupalli. a Stipulated by the Tamil Nadu Pollution Control Board and the Ministry of Environment and Forests. Appendix 6 27
Action Taken/Operations Evaluation Conditiona Mission Observation
One automatic continuous air monitoring station procured under the Asian Development Bank’s technical assistance program to monitor the following parameters is installed at Vallur:
(i) suspended particulate matter (ii) SO2 (iii) NOx.
Take measures to protect the health of Partly complied with, by provision of dust workers in the coal handling area. collection systems; but masks, gloves, and safety equipment are not provided.
Treat liquid effluents from the power plant as This is being carried out and the parameters per the limits prescribed by the Indian are maintained within the prescribed limits. Standards Institution, before final discharge.
Use fly ash beneficially. Fly ash is being used by private entrepreneurs as follows:
(i) Premier Roofings Products Ltd.1,000 tons of asbestos sheets per month (ii) Dual Structurals, Chennai–1,000 tons of bricks per month (iii) Citadel Builders & Developers (P) Ltd., Chennai–250 tons of cement per month (iv) Visaka Industries, Secundrabad–1,000 tons of cement per month.
Install electrostatic precipitators (ESPs) of ESPs of 99.8% efficiency have been installed. efficiency 99.5%. The stack emission of particulate matter is well within the prescribed limit.
Provide adequate space for flue gas This has been done. desulfurization plant.
There should be no heavy structure within 500 This has been ensured. meters zone of high tide level.
Stack height should not be less than 275 The stack height has been maintained at 275 meters. meters.
Provide an online monitor to measure NOx, Online equipment to monitor SO2, NOx, and SO2, and suspended particulate matter. suspended particulate matter has been provided.
28 Appendix 6
Action Taken/Operations Evaluation Conditiona Mission Observation
Provide three or four air quality monitoring Air quality monitoring stations have been stations. provided at five locations in and around the power plant area.
Treat liquid effluents from the power plant as Liquid effluents are treated as per the per Tamil Nadu Pollution Control Board standards of TNPCB, although total (TNPCB) standards. suspended solids and turbidity are high as seawater is being used for plant operation.
Maintain a temperature difference of not more The temperature difference of 5°C is being than 5°C between the seawater and the water maintained. discharge from the power plant.
Conserve water by recycling. Ash decanted water is recycled.
No fly ash of bottom ash should be disposed Ash is disposed of only in the ash dikes. of in the estuary.
Proper ash dikes/ponds should be built. The following ponds have been built for the collection of fly ash: (i) primary pond 1-180 hectares (ha) (ii) primary pond 2-115 ha (iii) secondary pond 20 ha.
The effluents meet the standards prescribed by TNPCB.
Establish a green belt around the power plant. A green belt of 430 acres (172 ha) is planned. Of this, an area of 360 acres (144 ha) has been developed. Tenders have been invited for the remaining area.
Discharge cooling into the Ennore creek, as Tamil Nadu Electricity Board (TNEB) had was originally licensed. constructed the requisite facilities for the discharge of the cooling water into Ennore creek. However, it is discharging the water into Buckingham canal in view of the opposition of the local fishermen who are concerned about the impact of the hot water being discharged into the Ennore creek on the fish in the creek.
In the Operations Evaluation Mission’s (OEM’s) view, the current practice does not constitute an environmental hazard, as relatively cleaner, filtered seawater is discharged into a canal, which receives effluents and solid waste from urban areas in Chennai.
Appendix 6 29
Action Taken/Operations Evaluation Conditiona Mission Observation
The OEM was informed that TNEB is now preparing a $8.0 million project for intake and discharge of cooling water near Ennore port.
Obtain TNPCB’s approval for plant operation. TNPCB has not so far given its approval for plant operation. The OEM has recommended that TNEB and TNPCB resolve the matter expeditiously.
Source: Tamil Nadu Electricity Board and Operations Evaluation Mission, 2002.