The Working Group on Power for Eleventh Plan ( )

Transcription

1 lr;eso t;rs Report of The Working Group on Power for Eleventh Plan ( ) Volume - II Main Report Government of India Ministry of Power New Delhi February 2007

2 Working Group on Power for Eleventh Plan ( ) Volume II Main Report

3 Contents CONTENTS CHAPTER DESCRIPTION PAGE NO. PREFACE INTRODUCTION EXECUTIVE SUMMARY 1-69 DEMAND FOR POWER AND GENERATION 1-93 Chapter 1 PLANNING th Plan Review 1.2 Target Capacity Addition during Tenth Plan 1.3 Actual Capacity Addition and Power Supply Position during 10th Plan (Till date) 1.4 Actual/ Likely Capacity Addition during Tenth Plan 1.5 Likely Installed Capacity at the end of 10th Plan i.e. as on Demand for Power 1.7 Approach to Selection of Projects for 11th Plan 1.8 Generation Planning Norms 1.9 Generation Expansion Planning 1.10 Twelfth Plan Perspective ( ) 1.11 Medium Term Plan: 11th Plan ( ) 1.12 Long Term Plan: 12th Plan ( ) 1.13 New Initiatives 1.14 Captive Power Plants 1.15 Maximising Generation from Existing Plants and AGS&P 1.16 Energy Efficiency Improvement through Energy Audit 1.17 Accelerated Generation & Supply Programme (AGS&P) Scheme 1.18 Non Conventional Energy Sources 1.19 Issues to be Addressed and Strategy to be adopted for 11 th Plan 1.20 Recommendation of the Group Appendix-1.1: Summary of Capacity Addition Target of 41,110 MW during 10th Plan (Region Wise, Sector Wise and Status Wise) Appendix-1.2 List of Projects Commissioned during 10 th Plan upto Appendix-1.3 List of Units dropped from 10 th Plan (41110 MW) Appendix-1.4 List of the Thermal Projects slipping from 10 th Plan (41,110 MW) and included in 11 th Plan (As per 30,641 MW) Page 1 of Contents

4 Contents CHAPTER DESCRIPTION PAGE NO. Appendix-1.5 List of the Hydro Projects slipping from 10 th Plan (41,110 MW) and included in 11 th Plan (As per 30,641 MW) Appendix-1.6 Details of Best Effort Projects Appendix-1.7 List of Projects Likely to slip to 11 th Plan Appendix-1.8 Capacity Addition programme for 11 th Plan Appendix-1.9 Year wise coal requirement for 11 th Plan Appendix-1.10 Shelf of 12 th Plan projects Appendix 1.11 Comparative Performance of Partnership in Excellence (PIE) Stations with NTPC as PIE Partner Appendix 1.12 State Wise List of Hydro RM&U Projects Completed in the 10 th Plan Appendix 1.13 State Wise List of ongoing Hydro RM&U Projects Programmed For Completion In the 10 th Plan Appendix 1.14 State Wise List of ongoing Hydro RM&U Projects Programmed for Completion in the 11 th Plan Appendix 1.15 State Wise List of Hydro RM&U Projects Programmed for Completion in the 11 th Plan but works of which are yet to be taken up for Implementation Chapter 2 TRANSMISSION PLANNING AND NATIONAL GRID 2.1 Review of Transmission System during 10 th Plan 2.2 National Grid 2.3 Eleventh Plan Programme 2.4 Technology Development 2.5 Transmission Requirements for Open Access and Trading 2.6 Power Exchange with Neighbouring Countries 2.7 Reliability Issues and Grid Operation 2.8 Fund Requirement during 11 th Plan for Transmission System Development and Related Schemes Appendix-2.1: HVDC Transmission Bipole, Backto-back and Monopole lines and terminal station Existing at the end of 9th Plan and programme for 10th Plan Appendix-2.2: Transmission lines and sub-station at 765kV Existing at the end of 9th Plan and programme for 10th Plan Page 2 of Contents

5 Contents CHAPTER DESCRIPTION PAGE NO. Appendix 2.3 List of major transmission schemes completed and programmed under the development plan of the Regional Grids and National Grid during the 10 th Plan-Northern Region Appendix 2.4 List of major transmission schemes completed and programmed under the development plan of the Regional Grids and National Grid during the 10 th Plan-Western Region Appendix 2.5 List of major transmission schemes completed and programmed under the development plan of the Regional Grids and National Grid during the 10 th Plan-Southern Region Appendix 2.6 List of major transmission schemes completed and programmed under the development plan of the Regional Grids and National Grid during the 10 th Plan-Eastern Region Appendix 2.7 List of major transmission schemes completed and programmed under the development plan of the Regional Grids and National Grid during the 10 th Plan-Inter-Regional Appendix-2.8: Inter-State Transmission Schemes For The 11 th Plan Appendix- 2.9: States Transmission Schemes for the 11 th Plan Evacuation System for Generation Projects Appendix-2.10 State-Wise Details of Normative Assessment Chapter 3 DISTRIBUTION INCLUDING VILLAGE AND HOUSHOLD ELECTRIFICATION 3.0 Overview 3.1 Key Issues in Electricity Distribution Sector 3.2 Distribution Reforms 3.3 New Legal and Policy Framework 3.4 Policy Initiatives 3.5 Distribution of Power in Urban Areas 3.6 Achievements Under APDRP 3.7 Distribution of Power in Rural Areas - Initiatives in 10 th Plan 3.8 Development of Revenue Sustainability - Franchisees 3.9 Role of Panchayati Raj in Franchisee Development 3.10 Power Distribution in Rural Areas Through DDG 3.11 Short Term Strategies for DDG Schemes 3.12 Medium Term and Long Term Strategies 3.13 Cost to Serve/ Delivered Cost 1-57 Page 3 of Contents

6 Contents CHAPTER DESCRIPTION PAGE NO Role of Stakeholders 3.15 Role of REC 3.16 Institutional and Financial Models 3.17 Special Focus Areas for 11 th Plan 3.18 New Programmes/Schemes for 11 th Plan 3.19 Agriculture Sector - Subsidies and Cross Subsidies 3.20 Water Energy Nexus 3.21 Open Access in Distribution 3.22 Multi-Year Tariff 3.23 Public Private Partnership 3.24 Impact of Power Sector Reforms Success Stories 3.25 Best Practices 3.26 Requirement of Funds 3.27 Recommendations Chapter 4 DEMAND SIDE MANAGEMENT AND ENERGY 1-14 EFFICIENCY 4.0 Introduction 4.1 The Energy Conservation Act 4.2 Energy Saving Target and Achievement of 10 th Plan 4.3 Energy Conservation Strategy in the 11 th Five- Year Plan 4.4 Policy Research for Accelerating Adoption of Energy Efficiency and DSM Programs 4.5 Budget Outlay for the 11 th Plan 4.6 Recommendations Chapter 5 RESEARCH & DEVELOPMENT Introduction 5.1 Overview of R&D 5.2 Technology Development in Power Sector 5.3 Identified Projects for 11 th Plan by Central Utilities 5.4 R&D Project Provisions and Test Facilities for CPRI 5.5 Major Project Proposals for 11 th Five Year Plan 5.6 Short Listed Short Term & Long Term Projects 5.7 R&D Funding 5.8 Intellectual Property Rights 5.9 Human Resource Development and Technical Competence Building Chapter 6 DEVELOPMENT OF POWER SECTOR IN 1-11 NORTH-EASTERN REGION 6.0 Introduction Page 4 of Contents

7 Contents CHAPTER DESCRIPTION PAGE NO. 6.1 Status at the beginning of 10 th Plan 6.2 Review of Generation Capacity Addition Programme during 10 th Plan 6.3 Reasons for Slow Pace of Project Execution 6.4 Power Demand & Supply Analysis of the Region 6.5 Generating Capacity Addition Programme in North Eastern Region/ Sikkim during 11th Plan 6.6 Development of Transmission System in North Eastern Region 6.7 Evacuation of Power from Major Generation Projects in the North-Eastern Region along with Power from Projects coming up in Sikkim and Bhutan during the 11th Plan and early 12th Plan Period 6.8 Special Attention for Distribution in NE Region 6.9 Fund Requirement 6.10 Policy Initiatives and Recommendations Chapter 7 HUMAN RESOURCE DEVELOPMENT Back Ground 7.1 Elements of HRD Planning 7.2 Assessment of Manpower 7.3 Training 7.4 Funding & Capital Outlay Appendix 7.1: Training Load during 11 th Plan for Technical Manpower (Includes Infrastructure) in Thousand-Man-Months (TMM) Appendix 7.2: Training Load during 11 th Plan for Non-Technical Manpower (Includes Infrastructure) in Thousand-Man-Months Appendix 7.3: Training Load (Induction) during 12 th Plan for Technical Manpower (Includes Infrastructure) in Thousand-Man-Months Appendix 7.4: Training Load (Induction) during 12 th Plan for Non-Technical Manpower (Includes Infrastructure) in Thousand-man-months Chapter 8 LEGISLATIVE AND POLICY ISSUES Back Ground 8.1 Implementation of Provisions of Act and Policies 8.2 Status of Implementation and Deviations of Integrated Energy Policy 8.3 National Electricity Policy - Deviations and Status of Implementation 8.4 Major Issues and Recommendations Page 5 of Contents

8 Contents CHAPTER DESCRIPTION PAGE NO. 8.5 Summary of Recommendations Appendix 8.1: Fund Requirement for Training of Electricity Regulators and Staff Appendix 8.2: Comments of Prayas Energy Group Appendix 8.3: Comments of IIT Kanpur Chapter 9 KEY INPUTS Introduction 9.2 Coal & Lignite 9.3 Transportation of Coal: Available Infrastructure 9.4 Natural Gas 9.5 Key Input Materials 9.6 Generation Expansion Plan 9.7 Material Requirements for Generating Stations 9.8 Material Requirement for Power Transmission System Network 9.9 Material Requirement for Distribution System Network 9.10 Material Requirement for Power and Distribution Transformers 9.11 Other Materials for 11 th & 12 th Plan Projects 9.12 Total Requirement of Various Materials for Capacity Addition Planned during 11 th & 12 th Plans 9.13 Availability / Supply of Key Materials 9.14 Constraints / Policy Support Required 9.15 Availability / Capability of Manufacturers 9.16 Construction Capability 9.17 Availability/Capability of Construction Agencies 9.18 Availability of Construction Equipment 9.19 Special Measures for Thermal Projects 9.20 Recommendations Appendix 9.1: Port wise Projected Traffic and Capacity Estimation ( ) Appendix 9.2: List of Construction Equipments to be Augmented for Hydro Projects Appendix 9.3: Construction Equipment Availability vis a vis Augmentation required for adding MW / per yr. Chapter 10 FINANCIAL ISSUES AND POWER SECTOR 1-46 FINANCING 10.1 Financial Performance of Power Sector during 10 th Plan 10.2 Fund Requirement for 11 th Plan 10.3 Renovation and Modernization of Power Plants 10.4 Transmission Network Page 6 of Contents

9 Contents CHAPTER DESCRIPTION PAGE NO Distribution and Rural Electrification 10.6 Human Resource Development 10.7 Research and Technology Development 10.8 Demand Side Management th Plan Estimated Fund Requirement Year Wise Fund Requirement Sources of Funds Estimated Funds Mobilization Lenders Issues Developers Concerns Recommendations & Implementation Strategy Implementation Mechanisms Appendix 10.1: Detailed Outlay and Achievement for Funding 10 th Plan - State Sector Appendix 10.2: Approved Tenth Plan Outlay Internal and Extra Budgetary Resources Gross Budgetary Support Appendix 10.3: Assumptions for Estimation of Cost of Generation Projects Appendix 10.4: Projects Under Construction Appendix 10.5: Committed Projects Appendix 10.6: Projects to be taken up in 11 th Plan for Likely Benefit in 12 th Plan ACRONYMS Page 7 of Contents

10 INTRODUCTION The Working Group on Power was constituted by the Planning Commission vide its Office Order No.I-15/1/2005-P&E dated 20 th April 2006 (copy enclosed at Appendix- A) to formulate the power programme for 11th Plan. Secretary (Power) was the Chairman of the Working Group and Member (Planning), CEA was the Member Secretary of the Working Group. The Composition and Terms of Reference of the Working Group for Eleventh Plan are given in Appendix-A. The first meeting of the Working Group was held on 19 th May 2006 under the Chairmanship of Secretary (Power). It was decided to constitute 8 specialized Sub- Groups to go into the specific areas to cover comprehensively all the Terms of Reference of the Working Group. Subsequently, review meetings of the Working Group were held in MoP on a regular basis to assess the progress of the Sub-Groups from time to time. During the discussions, it emerged that it was essential to have a separate Sub- Group on Human Resource Development and accordingly Sub Group 9 was constituted. Details of the various Sub Groups are enclosed in Appendix- B The Sub-Groups discussed various issues regarding Demand, Generation, Transmission & Distribution Expansion Planning, Households & Rural Electrification, Demand Side Management & Energy Efficiency Issues, Research & Development, Manpower Planning & Training and Fund Requirement. A separate chapter has also been included on development of North Eastern Region as well as Policy Issues. A review of and measures for implementation of National Electricity Policy and Integrated Energy Policy have also been included in the Report. The report is based on 10 th Plan likely capacity addition of 30,641 MW corresponding to which the 11 th Plan capacity addition is 68,869 MW and 12 th Plan capacity addition is 82,000 MW. Subsequent to the finalization of the Report, CEA had reviewed the likely capacity addition during the 10 th Plan. This is now expected to be around 23,250 MW. The balance 10 th Plan capacity would slip to 11 th Plan in addition to 68,869 MW planned for 11 th Plan. These changes have, however not been effected in the body of the Report. Various Sub-Groups submitted their Reports to the main Working Group. Based on the recommendations of these Sub-Groups the Report of the Working Group for 11 th Plan has been formulated. It is in 2 Volumes- Volume I containing the Executive Summary of the Report and Volume II containing the main Chapters of the Report. The Executive Summary has also been made part of Volume II for the sake of completeness & ease of reference. New Delhi 15th Feb (V. S. VERMA) Member (Planning) CEA and Member Secretary of the Working Group on Power

11 No.I-15/1/2005-P&E GOVERNMENT OF INDIA PLANNING COMMISSION (POWER & ENERGY DIVISION) ****** Appendix-A Yojana Bhawan Sansad Marg New Delhi Dated: 20th April, 2006 ORDER Subject: Constitution of a Working Group on Power for formulation of Eleventh Five Year Plan ( It has been decided to constitute a Working Group on Power in the context of preparation of Eleventh Five Year Plan ( ). The Composition and Terms of Reference of the Group will be as follows: A. Composition Secretary, Ministry of Power - Chairman Members PSUs 1. Adviser (Energy), Planning Commission 2. Chairperson, Central Electricity Authority 3. Representative of Ministry of Non-Conventional Energy Sources 4. Representative of Department of Atomic Energy 5. Representative of Ministry of Coal 6. Representative of Ministry of Petroleum & Natural Gas 7. Representative of Ministry of Environment & Forests 8. Representative of Department of Science & Technology 9. Member (Planning), Central Electricity Authority Member Secretary 1. CMDs, NTPC/NHPC/PGCIL/PFC/REC 2. Chairmen, GRIDCO/APTRANSCO/MSEB/MPEB/TNEB/PSEB Private Sector Representatives 1. Representative of Reliance Energy Company 2. Representative of Tata Electric Company 3. Representative of Torrent Electric Company

12 OTHERS 1. Shri Girish Sant, PRAYAS 2. Shri Navroj Dubash, NIPFP 3. Prof. Anoop Singh, lit Kanpur B. Terms of Reference i) To review the Integrated Energy Policy Report and suggest measures to operationalise its recommendations during the Eleventh Plan Period. ii) To review the status of various policies notified under the provisions of Electricity Act, 2003 and identify steps needed to realize the objectives of the Electricity Act, iii) To recommend an industry structure that would enhance the number of players, promote competition, provide a consistent & transparent pricing regime and raise conversion, transmission, distribution & end use efficiency. iv) To review the likely achievement during the Tenth Plan period in meeting targets set for Generation, Transmission, Distribution and Renovation & Modernisation R&M). An analysis of the reasons for shortfalls, if any, may be highlighted. v) To review the current status of captive generation in the country, highlight issues facing this sub sector and make recommendations for enhancing/reducing captive generation during the Eleventh Plan period. vi) To review the effectiveness of Eleventh Plan Schemes such as Accelerated Generation & Supply Programme (AG&SP), Accelerated Power Development & Reforms Programme (APDRP) and Rajiv Gandhi Grameen Vidyutikaran Yojana (RGGVY). To suggest modifications and/or give recommendations for scrapping these schemes or replacing them with alternative schemes to better address the desired objectives. vii) To assess the State-wise/region-wise demand for power in terms of both peak and energy requirements. viii) To recommend the optimal mix of additional generating capacity to be created during the Eleventh Plan period in terms of hydro, thermal (coal, gas, lignite and liquid fuel) and nuclear generation on the basis of relative economics of different fuels at different locations. The executing agency of the project i.e. State Sector, Central Sector or Private Sector should also be identified. A possible listing of the projects and their phasing for benefits during Eleventh Plan must be prepared. Advance action to be taken in the Eleventh Plan period for the Twelfth Plan projects may also be identified. ix) To assess the potential for improving availability of power from existing power stations through Renovation & Modernisation/life extension. x) To maximise benefit from the existing plants by improving their operational efficiency and capacity utilization, improvement and augmentation of Transmission and Distribution network and dealing effectively with the problem of Aggregate Technical & Commercial (AT&C) losses and theft of power. xi) To review the on-going reform process undertaken by States in the power sector. xii) To assess if privatisation is an answer to address the ills of the Power Sector. xiii) To suggest energy conservation measures through Demand Side Management (DSM) such as staggering of load, time of the day metering and pricing, reduction in the energy intensity of the large consumers etc. xiv) To recommend the operational norms for thermal including Gas, Liquid fuel and nuclear generations.

13 xv) To develop a work plan to tackle problems in ash disposal, pollution and other environmental issues. xvi) To make recommendations regarding S&T programme to be implemented in the Eleventh Plan period and the institutional arrangements necessary therefore. xvii) To explore avenues for purchase of power from neighbouring countries through joint venture schemes. xviii) To assess the investment requirement for the Eleventh Plan in the Power Sector. xix) To assess the infra-structural support such as transportation, port facilities, construction and manufacturing capabilities, roads etc. that would be required for implementation of the Eleventh and Twelfth five year Plans. 2. In order to assist the Working Group in its task, separate Sub-Groups on specific aspects may be formed by the Working Group. These Sub-Groups will furnish their reports to the Working Group 3. The Chairman of the Working Group may co-opt experts as may be considered necessary. 4. The Working Group will submit its report to the Planning Commission latest by 30th September, Non-official members shall be entitled to payment of TA/DA by the Planning Commission as per SR 190(a). Official members will be entitled to payment of TAJDA by their respective Departments/Organizations, as per the rules of entitlement applicable to them. 6. The name(s) of the Representative(s) of various organizations, as per the above composition may be communicated to the Member-Secretary of the Working Group under intimation to Shri Surya P. Sethi, Adviser (Energy), Planning Commission. 7. Shri R.K. Kaul, Joint Adviser, Planning Commission, Room No.503, Yojana Bhavan, New Delhi-i (Telephone No ), shall be the Nodal Officer for this Working Group and for any further query/correspondence may be made with him. (K.K. Chhabra) Under Secretary to the Government of India Chairman and Members (including Member-Secretary) of the Working Group. Copy for information to: 1. PSs to Deputy Chainman/ MOS(Planning)/ Members/ Member-Secretary, Planning Commission. 2. All Principal Advisers/ Advisers/JS(SP&Admn.) 3. Prime Minister s Office, South Block, New Delhi. 4. Information Officer, Yojana Bhavan. 5. For general information in Yojana Bhavan through . (K.K. Chhabra) Under Secretary to the Government of India

14 Appendix-B WORKING GROUP ON POWER FOR 11 TH FIVE YEAR PLAN ( ) Details of Sub-Groups SUB-GROUP 1- DEMAND PROJECTION AND GENERATION PLANNING. Shri Rakesh Nath-Chairperson, CEA- Chairman of Sub-Group Shri A.S. Bakshi-Chief Engineer (IRP) CEA - Member Secretary of Sub-Group SUB-GROUP 2- TRANSMISSION PLANNING INCLUDING NATIONAL GRID Shri V. Ramakrishna - Member (PS) CEA - Chairman of Sub-Group Shri A.K. Asthana, Chief Engineer (SP&PA), CEA - Member Secretary of Sub-Group Shri Jiwesh Nandan,Director (PTC & Trans), Ministry of Power - Member Secretary of Sub- Group SUB-GROUP 3- DISTRIBUTION INCLUDING VILLAGE & HOUSEHOLD ELECTRIFICATION Shri Anil Kr. Lakhina - Chairman, REC - Chairman of Sub-Group Ms Dharitri Panda, Director (RE), Min. of Power, Member Secretary of Sub-Group SUB-GROUP 4 - LEGISLATIVE AND POLICY ISSUES FORMULATION, IMPLEMENTATION & FEEDBACK Shri Ajay Shankar Additional Secretary, Ministry of Power - Chairman of Sub-Group Shri Alok Kumar, Director (R&R), Ministry of Power - Member Secretary of Sub-Group SUB-GROUP 5 - DEMAND SIDE MANAGEMENT, ENERGY EFFICIENCY & ENERGY CONSERVATION Dr. Ajay Mathur- Director General, BEE - Chairman of Sub-Group Shri K.K.Chakarvarti Energy Economist BEE - Member Secretary of Sub-Group SUB-GROUP 6 - TECHNOLOGICAL ADVANCEMENT AND RESEARCH & DEVELOPMENT Shri A.K.Tripathi - Director General CPRI - Chairman of Sub-Group Dr. R.R. Sonde, Executive Director (R&D) NTPC- Member Secretary of Sub-Group SUB-GROUP 7 - ISSUES CONCERNING KEY INPUTS Shri T. Sankarlingam - CMD NTPC - Chairman of Sub-Group Shri S.Sheshadri-Chief Engineer (TPIA)CEA - Member Secretary of Sub-Group

15 SUB-GROUP 8 - FINANCIAL ISSUES Dr. V.K.Garg - CMD, PFC - Chairman of Sub-Group Sh. Mukul Modi,Asstt Vice President,SBI Capital Markets Limited- Member Secretary of Sub- Group SUB-GROUP 9 - HUMAN RESOURCE DEVELOPMENT AND CAPACITY BUILDING Shri U.N. Panjiar, Additional Secretary, Ministry of Power - Chairman of Sub-Group, Shri C.S.Malik, Principal Director, NPTI - Member Secretary of Sub-Group Chief Coordinator from MoP Shri Sudhakar Shukla, Director, MoP

16 Executive Summary Working Group on Power-11 th Plan ( ) EXECUTIVE SUMMARY 1.0 DEMAND PROJECTION AND GENERATION PLANNING 1.1 TENTH PLAN REVIEW The capacity addition target of 41,110 MW comprising 14,393 MW hydro, 25,417 MW thermal and 1,300 MW nuclear was fixed for the 10 th Plan. The sector wise, type wise summary of this capacity addition target is given in Table below. 10 TH PLAN CAPACITY ADDITION TARGET-SECTOR WISE (Figures in MW) SECTOR Hydro Thermal Nuclear Total (%) CENTRAL 8,742 12,790 1,300 22,832 (55.5%) STATE 4,481 6, ,157 (27.2%) PRIVATE 1,170 5, ,121 (17.3%) TOTAL 14,393 25,417 1,300 41,110 (100%) A moderate target was set for state and private sectors keeping in view the preparedness of various state power utilities and IPPs Actual Capacity Addition (till ) A capacity addition of 17,995 MW has been achieved during 10th Plan till 31/12/06. The total installed capacity as on 31/12/2006 was 1,27,753 MW comprising 33,642 MW hydro, 84,020 MW thermal including gas & diesel, 3,900 MW nuclear power plants and 6,191 MW from renewable energy sources including wind. (The sector wise details of installed capacity are given in Table 1.4 in Chapter-1.) Power supply position in 10 th plan The year-wise actual power supply position during , , , and (till Dec-06) of 10 th plan is given in Table below 1

17 Executive Summary Working Group on Power-11 th Plan ( ) ACTUAL POWER SUPPLY POSITION (ALL INDIA BASIS) Year Peak Energy Requir ement (MW) Availab ility (MW) Shortage MW (%) Require ment (MU) Availability (MU) Shortage MU (%) (12.2%) (8.8%) (11.2%) (7.1%) (11.7%) (7.3%) (12.3%) (8.4%) (upto Dec,06) (14.0%) (8.8%) The likely achievement of capacity addition during the 10 th Plan is expected to be 30,641 MW which includes 2,578 MW capacity of projects which have been included on best effort basis. Any slippage of these best efforts projects from 10 th plan would be reckoned as additional capacity in 11 th plan over and above being proposed in this document. In 8 th & 9 th plan, capacity addition of 16,423 MW and 19,119 MW respectively was achieved. Even though the capacity addition target of 10 th plan could not be achieved, the actual capacity addition is expected to be much higher than the earlier five year plans. The reasons for the slippages during the 10 th plan have been analysed to learn lessons for capacity addition planning for future plans. During the first year of 10 th plan itself it became clear that a number of projects totalling to 3,009 MW in public and private sectors could not be taken up due to various reasons which included non availability of escrow cover by State Government to IPP projects and fund constraints. There was also delay in super critical technology tie-up by BHEL for six units of 660 MW to be taken up by NTPC which resulted in delay in tendering. Additional projects totalling to 5,008 MW capacity were identified for execution during 10 th plan to make up for the projects which could not take off. However, a total capacity of 12,516 MW (excluding 3,009 MW projects which could not be taken up) is expected to slip to 11 th Plan due to reasons mentioned against each, in the following table: 2

18 Executive Summary Working Group on Power-11 th Plan ( ) Sl. No Major Reasons of slippage Capacity slipped (MW) Thermal Hydro 1. Delay in super critical technology tie up by BHEL 2. Geological Surprises Natural Calamities Delay in award of works Delay in MoE&F clearance Investment decision/ Funds tie up constraints/ delay in financial closure 7. Delay in Preparation of DPR & signing of MOU with state govt. 8. ESCROW cover (Private Sector) R&R issues Court Cases Law & Order problem 500 Total (The details are given in Para 1.5 of Main Working Group Report) It is pertinent to point out that a number of projects of 10 th plan ordered on BHEL were delayed due to delayed and non-sequential supply of equipment and materials and inadequate manpower in commissioning teams. Some of the projects expected to be commissioned during the last quarter of are also running behind schedule due to the above reasons. 1.2 GROWTH IN ENERGY GENERATION Growth in Generation During 10 th Plan The growth in generation has been 3.2%, 5.1%, 5.2% and 5.2% during , 03-04, and respectively. In the year (upto Dec-2006) a growth rate of 7.5 % has been recorded. The Compounded Annual Growth Rate(CAGR)of generation during the 10 th Plan period is expected to be about 5.1%. However, higher growth could have been achieved if adequate gas would have been available for the existing and new gas based plants commissioned during 10 th plan Growth in Generation during 11 th Plan As per the Integrated Energy Policy (IEP), issued by the Planning Commission, GDP growth rates of 8%-9% have been projected during the 11 th Plan. Assuming a higher growth rate of 9% and assuming the higher elasticity projected by the IEP of around 1.0, electrical energy generation would be required to grow at 9% p.a. during the 11 th plan period. Also generation has to be collectively met by utilities, captive plants and Non-conventional energy sources. No reliable plans 3

19 Executive Summary Working Group on Power-11 th Plan ( ) about captive power capacity expansion are available but based on indications available from the manufacturers for addition in captive capacity and present utilization of available capacity, the generation from captive plants is expected to increase from 78 BU to 131 BU per annum. Since the load factor of nonconventional energy sources is very low (about 20% on an average), even though the capacity projected by MNRE from these sources is about 23,500 MW by the end of 11 th Plan, the expected generation would be only around 41 BU. The generation from these renewables however has not been taken into account for planning purposes. Based on these assumptions following scenario emerges: (i) Likely energy Generation by utilities in BU (ii) Likely Energy Generation by captive plants in BU (iii) Total Likely Generation in BU (iv) Compounded Annual Growth Rate 9% (v) Required Energy Generation by 9% growth rate over 741 BU 1140 BU (vi) Less Estimated Energy Generation by captive plants in BU (vii) Total Estimated Generation Requirement from Utilities by BU However to meet the objectives of NEP to increase the per capita consumption to 1000 units by the year , the requirement of generation works out to 1210 BU, assuming a population of 121 crores in as per projections of Census After excluding the generation from captive plants (131 BU) and that from renewables (41 BU), the requirement of generation from utilities works out to 1038 BU. This would require a generation growth rate of 9.5% p.a (CAGR)for utilities Growth in generation During 12 th Plan During the 12 th Plan period, assuming a GDP growth rate of 9% per annum and elasticity 0.8 as compared to 1.0 during 11 th plan mainly due to adoption of energy efficient technologies & other Energy Conservation and Demand Side Management measures being taken up during 11 th Plan, electricity demand is likely to 7.2% p.a. Keeping this in view, the energy generation should increase to a level of 1470 BU by from a level of 1038 BU in However sensitivity analysis have been carried out assuming 8,9 & 10 % GDP growth rates & GDP-electricity elasticity of 0.9 & 0.8 respectively and the same is given in table below: 4

20 Executive Summary Working Group on Power-11 th Plan ( ) Generation Requirement for ( As Per 8,9,10 % GDP Growth) GDP Growth 8 % 9 % 10 % GDP/ Electricity Elasticity Electricity Generation Required (BU) APPROACH TO SELECTION OF PROJECTS FOR 11 TH PLAN Keeping in view the lessons learnt from 10 th plan while planning for capacity addition during 11th Plan, cautious approach have been adopted while choosing projects for commissioning in the 11 th plan. It has been the endeavour to include only such projects as have high degree of certainty of implementation during 11 th Plan. The approach adopted for selection of Hydro, Thermal and Nuclear projects have been as follows: Hydro India is duly concerned about climate change and efforts are on to promote benign sources of energy. Hydro Power is one such source and is to be accorded priority also from the consideration of energy security. Irrespective of size and nature of hydro projects, whether ROR or Storage projects, these are all renewable technologies. However, execution of hydro projects requires thorough Survey and Investigation, preparation of DPR, development of infrastructure, EIA and other preparatory works, which are time consuming and require two to three years for their preparation. It would take about 5 years to execute a hydro project after the work is awarded for construction. Thus in order to achieve completion of a hydro project during 11 th plan, the project should either be already under construction or execution should start at the beginning of the plan. The broad criteria adopted for selection of hydro projects for 11 th plan are as under: Those hydro projects whose concurrence has been issued by CEA and order for main civil works is likely to be placed by March

21 Executive Summary Working Group on Power-11 th Plan ( ) Apart from the above, a few hydro projects of smaller capacity which are ROR type having surface power houses and where gestation period is expected to be less than 5 years have also been included. These projects would need to be rigorously followed up for completion during the 11 th Plan. Keeping in view the preparedness of various hydro projects, a capacity addition of 15, 585 MW is envisaged for 11 th Plan. (The details of projects are given in Appendix 1.8- in Chapter-1 of main Working Group Report.) Nuclear Nuclear is environmentally benign source of energy and over a period of time, its proportion in total capacity should increase. Keeping in view the availability of fuel, a moderate capacity addition of 3,160 MW nuclear plants has been programmed during the 11 th Plan by the Nuclear Power Corporation. All projects are presently under construction. However, in view of the recent developments in the Nuclear Sector, capacity addition in nuclear plants during 12 th Plan is expected to be much higher. (The details of projects are given in Appendix 1.8- in Chapter-1 of main Working Group Report.) Thermal Gas Although gas is relatively a clean fuel, at present there is uncertainty about the availability, period of availability and price of gas. Only 2,114 MW gas based capacity has been planned for 11 th Plan where gas supply has already been tied up. This does not include NTPC s gas based projects at Kawas and Gandhar, totalling to 2,600 MW, for which NTPC says that it has the gas supply contract but the matter is sub-judice. However more gas based projects could be taken up for construction as and when there is more clarity about availability and price of gas. (The details of projects are given in Appendix 1.8- in Chapter-1 of main Working Group Report.) Coal & Lignite based Thermal plants Coal is expected to be main stay of power generation in the years to come. The following criteria have been adopted for identifying the coal and lignite based projects for inclusion in the 11 th plan. Such projects as have already been taken up for execution in the 10th Plan period itself and are due for commissioning in the 11 th Plan period. Those thermal projects whose LOA has already been placed by the State and Central Public Sector Corporations, other inputs also being in place. 6

22 Executive Summary Working Group on Power-11 th Plan ( ) Those thermal projects whose LOA has already been placed and the financial closure achieved by private developers. Those thermal projects whose LOA is expected to be placed by 30 th Sept, 2008 and commissioning is expected during the 11 th Plan keeping in view the normal gestation period, the size of the plant & the type(green field/expansion). After discussion with the various State Government and Central Generating Companies, thermal projects with total capacity of 46,635 MW of coal based and 1375 MW lignite based capacity have been identified for capacity addition during 11 th plan. (The details of projects are given in Appendix 1.8- in Chapter-1 of main Working Group Report.) 1.4 CAPACITY ADDITION DURING 11 TH PLAN ( ) Based on the preparedness of the projects, it was envisaged that a capacity of about 68,869 MW is feasible for addition during 11 th plan period. The sector wise break-up of feasible capacity addition during 11 th plan is given in Table below: SECTOR HYDRO TOTAL THERMAL THERMAL BREAKUP COAL LIGNITE GAS/LNG NUCLEAR TOTAL (%) CENTRAL (53.2%) STATE (33.4%) PRIVATE (13.4%) ALL-INDIA (100%) In addition to above, thermal projects totalling to 11,545 MW have been identified as best effort projects. These projects would normally be commissioned in the beginning of 12 th Plan but in case of any constraints in taking up of any of the projects included in 11 th plan, some of these projects would be tried for commissioning during 11 th Plan. Further, a capacity of 13,500 MW has been planned under renewable as per information given by MNRE. As can be seen from the above profile of capacity addition plan, central sector will play a lead role with capacity addition of more than half of the capacity addition target. There has been a good response from states on the need for 7

23 Executive Summary Working Group on Power-11 th Plan ( ) capacity addition to meet their growing demand and the states with IPPs, have been given target for achieving the balance capacity. The State owned capacity projected for the 11 th Plan is 33.4 % of the total plan as compared to 27% likely during 10 th Plan. Out of feasible capacity addition of 68,869 MW, projects totalling to 31,345 MW are already under construction and the balance projects totalling to 37,524 MW have been committed for implementation by the concerned generating companies during the 11 th Plan. Details are furnished in the Table below: SECTOR Projects Under Construction Committed Projects HYDRO TOTAL THERMAL THERMAL BREAKUP COAL LIGNITE GAS/LNG NUCLEAR TOTAL * Total (The details of projects are given in Appendix 1.8- in Chapter-1 of main Working Group Report.) * Note: Out of the projects totalling to 37,524 MW under committed category as given above, orders for Dadri Unit-6 (490 MW) & Mezia Ph-II (1000 MW) has been recently placed. The thermal capacity addition comprises of1 unit of 800 MW, 11 units of 660 MW, 53 units of 500/600 MW class, 49 units of 210/250/300 MW class, 7 units of 110/125 MW class. With the above capacity addition it would be possible to meet the projected energy requirement of 1038 BU (considering peak demand of 1,51,500 MW) for meeting per capita consumption of 1000 units at the end of 11 th plan. With this capacity addition it would be feasible to achieve a generation growth rate of 9.5% p.a. (CAGR) 1.5 FUEL REQUIREMENT The requirement of various fuels for the thermal plants during the terminal year of the 11 th Plan ( ) at normative generation parameters (PLFs and specific fuel consumption is summarised in the table below. This is based on a thermal capacity addition of 20,387MW and 50,124MW during the 10 th and 11 th Plan respectively. 8

24 Executive Summary Working Group on Power-11 th Plan ( ) Fuel Requirement (Tentative) during Fuel Requirement ( ) Coal* 545 MT Lignite 33 MT Gas/LNG** 89 MMSCMD (The details of projects are given in Appendix 1.9- in Chapter-1 of main Working Group Report.) * From domestic sources, total coal availability is expected to be 482 MT per annum by Accordingly, imported coal of the order of 40MT, equivalent to 63 MT of Indian coal, may have to be organised. This quantity may reduce provided production of domestic coal is increased. ** 89 MMSCMD of gas requirement at 90% PLF has been projected in At present, the availability of gas is of the order of 40 MMSCMD and therefore not sufficient to meet the requirement of even existing plants. 1.6 INITIATIVES DURING 11 TH PLAN High Hydro Development 50,000 MW Hydro Initiative was launched in 2003 and Preliminary Feasibility Report (PFRS) of 162 projects totalling to 48,000 MW were prepared. Out of this 77 projects with total capacity of about MW for which first year tariff is expected to be less than Rs.2.50/unit were selected for execution. Hydro projects have longer gestation period and therefore there is a need to formulate a 10 year plan for hydro projects. In 11 th plan a capacity addition of over 15,500 MW has been targeted keeping in view the present preparedness of these projects. Projects totalling to a capacity of 30,000 MW have been identified for 12 th Plan on which necessary preparations have to be made from now onwards to ensure their commissioning during 12 th Plan. Thus the effect of 50,000 MW initiative would be visible in 12 th Plan period. Preparation of DPR and various clearances and approval etc for these projects are to be obtained during the first two years of 11 th Plan. It is recommended that CEA should closely monitor the progress of preparedness of DPR of these projects and their further execution Initiatives in Thermal Power Development: Efforts were made to bring in highly efficient super critical technology in the country for thermal power plants and execution of six super critical units of 660 MW capacity each was taken up during the 10 th Plan period. The first unit of 660 MW based on super critical technology is likely to be commissioned during the 9

25 Executive Summary Working Group on Power-11 th Plan ( ) first year of 11 th Plan i.e The 11 th Plan feasible capacity addition of coal based plants includes 12 units based on super critical technology with a capacity of 8060 MW which is about 18% of total coal capacity planned for 11 th Plan. More and more power projects based on super critical technology are under planning stage and they would yield benefit during the 12 th Plan period. It is envisaged that more than 50-60% of capacity addition of thermal plants during 12 th plan period would be based on super critical units. This would also help in reducing the Carbon dioxide emission from new coal fired capacity Ultra Mega Power Projects (UMPP): Ministry of Power in the year 2006 has launched an initiative of development of coal based ultra mega projects with a capacity of 4,000 MW each on tariff based competitive bidding. Ultra Mega Power projects are either pit head based projects having captive mine block or coastal projects based on imported coal. Sasan UMPP, a pithead plant in Chattisgarh based on domestic fuel and Mundra UMPP in Gujrat based on imported coal have already been awarded for execution to the respective developers. According to the bids submitted by these developers only one unit of 660 MW is expected to be commissioned during the 11 th Plan and the remaining unit during 12 th Plan. Other projects where considerable progress has been made are coastal projects in Andhra Pradesh and Tamil Nadu and a pit head based project in Jharkhand. Further the projects under consideration include pit head projects in Orissa and Chatisgarh and coastal projects in Maharashtra and Karnataka Nuclear Power Development: 11 th Plan power programme includes 3160 MW of nuclear power plants all of which are under construction. Recently, agreement has been signed with USA in respect of nuclear co-operation which is expected to improve the supply of nuclear fuel for nuclear power plants. It is also expected that execution of nuclear projects will also be opened up to enable participation by other PSUs and private sector. The effect of this is likely to be visible in 12 th Plan period. Nuclear Power Corporation of India has indicated a capacity addition of about 11,000 MW during 12 th plan. In addition, NTPC have also expressed their intention to enter into the nuclear power arena and have proposed an addition of 2,000 MW during 12 th plan period Merchant Power Plants: A merchant power plant does not have long term PPA for sale of its power and is generally developed on the balance sheet of developers. Government of India has reserved coal block with reserves of 3.2 Billion Tons of coal for allotment by Screening Committee of Ministry of coal for merchant and captive plants. About 10,000 MW capacity is expected to be developed through this initiative. This capacity has not been taken into account while working out the capacity required 10

26 Executive Summary Working Group on Power-11 th Plan ( ) in the 9.5% growth in generation scenario. Capacity addition through this route would further contribute to better economic growth, better reliability of power, more spinning reserve and above all would promote creation of competition in the electricity market Decentralised Distributed Generation (DDG): In some of the remote areas, it is not techno-economically feasible to extend the grid supply. For meeting the demand of such remote areas, it is proposed to set up some power plants based on local energy sources available. These are small hydro and non-conventional sources such as Bio-Mass, Wind, DG sets etc wherein other sources are not available. During the XI plan period a capacity addition of about 5,000 MW of capacity under DDG is envisaged. (Refer Para 3.1 of the Report) 1.7 CAPTIVE POWER PLANTS The generation from captive power plants at the end of X plan ( ) is likely to be about 78 billion units. It is envisaged that during the XI plan period about 12,000 MW capacity power plants would be added to the system which will take care of the demand of the industry and also supply surplus power to the grid under Open Access arrangements which has been allowed as per the Electricity Supply Act, It is envisaged that the generation from non utility captive power plants by the year may be of the order of 131 billion units which results into a CAGR of 10.5% p.a in captive generation TH PLAN SCENARIO The requirement of installed capacity and capacity addition to meet the generation requirement during the 12th Plan period as discussed in Para of this Report are given in Table below: Capacity addition required during 12th plan ( ) GDP Growth 8 % 9 % 10 % GDP /Electricity Elasticity Electricity Generation Required (BU) Peak Demand (MW) Installed Capacity (MW) Capacity Addition Required During 12 th PLAN (MW)

27 Executive Summary Working Group on Power-11 th Plan ( ) It would be seen from the above table that under various growth scenarios, the capacity addition required during 12 th plan would be in the range of 71,000-1,07,500 MW, based on normative parameters. The Working Group recommends a capacity addition of 82,200 MW for the 12 th Plan based on Scenario of 9% GDP growth rate and an elasticity of 0.8%. During 12 th plan about 30,000 MW capacity addition is likely to be based on hydro and about 11,000-13,000 MW will be nuclear based. The balance capacity addition of about 50,000 MW will be from thermal projects. A shelf of projects totalling over 1,50,000 MW has been identified & listed in main report. 1.9 RENOVATION & MODERNIZATION, LIFE EXTENSION AND PIE PROGRAMME A Renovation and Modernisation (R&M) Programme for Thermal Power Stations was launched by the Government of India all over the country way back in September 1984 for completion during the Seventh Plan Period. This programme was successfully completed and intended benefits were achieved. In the subsequent 8 th and 9 th Plans, Renovation and Modernisation and Life Extension (LE) works were carried out on a number of older generating units which resulted in improvement in their performance and extension of their useful life. In the 10 th plan life extension of 106 Nos of thermal units totalling to 10,413 MW was envisaged. However progress was not satisfactory due to high execution time & cost involved in LE works. The cost of LE was also not economically feasible considering the age of plants and there was reluctance from power plants to shut down their units for longer periods due to prevailing power shortages. In view of above a new initiatives called Partnership of Excellence was taken up. Under this programme generating companies who were performing well provide assistance in improving performance of non-performing units by following measures; Phase-I: Toning up of O&M Practices Phase-II: Comprehensive Overhaul Phase-III: LE for those units were found techno-economically feasible. Towards this initiative, CEA identified 22 power stations of 11 utilities, with a capacity of MW across the country. Out of these, 17 stations with an operating capacity of 5050 MW were entrusted to NTPC and one stations (280 MW) to TATA power. On remaining 4 stations the respective utilities are taking their own course of action. The plants entrusted to NTPC recorded an additional generation of power-3690 MUs- corresponding to an equivalent capacity addition 12

28 Executive Summary Working Group on Power-11 th Plan ( ) of 720 MW, considering national average PLF. Capacity addition of this order requires an investment of around Rs.3,000 crore at a Greenfield project. The phase-ii of the programme, therefore, needs to be continued. Some additional units have also been identified for R&M and life extension. The decision for investment for R&M/LE will be based on cost benefit analysis. If not economically viable installation of new plants at existing sites, may be considered. (The details of R&M, LE & PIE programme and their status are given in Chapter-1,Para 1.15 of main Working Group Report) 1.10 NEW AND RENEWABLE ENERGY SOURCES The Ministry of New and Renewable Energy Sources (MNRE) have chalked out plan of adding 13,500 MW of renewable power in the country during 11 th Plan period. This would make total installed capacity of these plants at 23,500 MW by the year which is detailed as below: Wind MW Bio Mass MW Small Hydro MW Although installed capacity of the plants is high but on an average plant load factor of wind turbine plants is only of the order of 15-20% and as such this capacity can generate about 41 billion units at the maximum RECOMMENDATIONS 1. The Working Group recommends generation planning based on growth of energy generation requirement of 9.5%. Keeping in view the above objectives and preparedness of various projects the Working Group recommends capacity addition of 68,869 MW during 11 th Plan as per details given below: SECTOR HYDRO TOTAL THERMAL THERMAL BREAKUP COAL LIGNITE GAS/LNG NUCLEAR TOTAL (%) CENTRAL (53.2%) STATE (33.4%) PRIVATE (13.4%) ALL-INDIA (100%) (Detail list is in Appendix-1.8 of main Working Group Report) 13

29 Executive Summary Working Group on Power-11 th Plan ( ) 2. States are required to take an active role in the capacity addition programme by their own agencies & by private sector participation through tariff based competitive bidding route on the lines of developments of Ultra Mega Power Project. In the 11 th plan addition of less than 50% of total capacity is targeted in states and private sector. It is recommended that in 12 th Plan more than 50% capacity should come through initiative of the states. 3. Some of the states do not have resources for capacity addition in their states. Such states should tie up long term PPAs with surplus states/generation companies. 4. Manufacturing capacity of BHEL needs to be enhanced to meet the capacity addition programme envisaged in 11 th & 12 th Plans. 5. A 10 year plan for hydro development is to be pursued in view of higher gestation period. A hydro capacity of 30,000 MW has been identified for commissioning during 12 th Plan. The survey and investigation, preparation of DPR, statutory clearances should be vigorously followed up right from now to enable their commission during 12 th Plan. The CEA should closely monitor progress on these projects.. 6. The Working Group recommends continuation of PIE programme during 11 th Plan also. 7. In addition to capacity addition programme, concerted efforts to continue in regard to: - Development of captive power plants. - Maximising Generation from existing plants. - Energy Efficiency improvement through Energy Audit. - Better O & M practices. - RM&U/Partnership in Excellence (PIE) Programme. - Development of Non-Conventional Energy Sources. 8. Major recommendations for facilitating open access in distribution and harnessing surplus captive generation in the country are as under: Reasonable cross subsidy surcharge and other charges to provide some economic incentive to the generators to avail open access. The SERCs should allow recovery of some portion of fixed cost in addition to the variable cost of captive generation. The captive generators may offer their surplus power on the basis of a firm schedule. Infirm power from CPP should also be considered for purchase. There should be no penalty for reduction of contract demand by any industry having captive plant. 14

30 Executive Summary Working Group on Power-11 th Plan ( ) 2.0 TRANSMISSION PLANNING INCLUDING NATIONAL GRID The transmission system facilities had earlier been planned on regional basis with provision of inter-regional link to transfer regional surplus power arising out of diversity in demand. The generation resources in the country are unevenly located, the hydro in the northern and north-eastern states and coal being mainly in the eastern part of the country. Development of strong National Grid has become necessity to ensure reliable supply of power to all. The planning & operation of the transmission system has thus shifted from regional to national level. Formation of a strong National Power Grid has been recognized as a flagship endeavour to steer the development of Power System on planned path leading to cost effective fulfilment of the objective of Electricity to All at affordable prices. A strong All India Grid would enable exploitation of unevenly distributed generation resources in the country to their optimum potential by providing enhanced margins in inter-regional transmission system. These margins, together with open access in transmission, would facilitate increased trading in electricity leading to market determined generation dispatches thereby resulting in supply at reduced prices to the distribution utilities and ultimately to consumers benefit. 2.1 PROGRAMME OF DEVELOPMENT OF NATIONAL GRID As on today, the inter-regional transmission capacity of 11,450 MW is existing and inter-regional energy exchanges of more than 12 billion kwh in a year are taking place contributing to optimum utilization of generation capacity. The program is to achieve inter-regional capacity of MW by the end of 10th Plan and about 37,150 MW by the end of 11th Plan. Transmission systems within the regions to support the above inter-regional transmission capacity has been also planned. The plan for National Power Grid and the schemes have been identified. (Ref 2.2 of Main Working group Report) 2.2 North Eastern region, Sikkim and Bhutan have vast untapped hydro potential which is planned for development during 11 th plan and beyond. A major component of this power will be utilised by deficit states in the northern and western region and for which reliable evacuation system is planned to be developed. The requirement of transmission system for evacuation of NER hydro power has been estimated corresponding to the capacity of hydro projects which may be feasible to develop say in the next about 20 years. This generation is estimated to be about MW in NER, about 8000 MW in Sikkim and about MW in Bhutan. Taking local development at accelerated pace resulting in demand within the NER, Sikkim and Bhutan to be in the range of MW (presently it is about 1500 MW), the transmission requirement through the chicken neck works out to be of the order of MW. The total requirement including additional circuits for meeting the contingencies and reliability needs, 15

31 Executive Summary Working Group on Power-11 th Plan ( ) would work out to 7 or 8 numbers of 800 KV HVDC bi-pole lines and 4 or 5 numbers of 400kV double circuit lines a total of 12 numbers of high capacity transmission corridors passing through the chicken neck. For this, RoW requirement would be about 1.5 Km in width considering minimum distance between adjacent towers to be such that fall of any tower does not affect the adjoining line. The first 800kV HVDC bi-pole line has been planned from a pooling substation at Biswanath Chariyali in North-eastern Region to Agra in Northern region. This is being programmed for commissioning matching with Subansiri Lower HEP in ASSESSMENT OF TRANSMISSION CAPACITY REQUIREMENT The focus of transmission system development programme for the XI Plan is to provide adequate inter-regional and intra-regional transmission capacity so as to consolidate and strengthen the National Grid network towards a strong All India Grid. The inter-regional power exchange requirement has been assessed from possible scenarios of regional surpluses and deficit for the peak and off-peak conditions of winter, summer and monsoon months. Projections of deficit/surplus based on which transmission requirement has been assessed are given in Chapter-8 of this report. The projection based on programme of generation and anticipated demand aims at estimating the transmission requirement at the interregional level. Grid expansion plan evolved based on this projection would be able to cater to the needs of various feasible operating scenarios and also provide required margins to support market oriented power exchanges. (Ref Para 2.3 of main Working Group Report) 2.4 TRANSMISSION CAPACITY FOR TRADING The above method adopted for evolving the transmission system expansion plan provides sufficient transmission capacities which would have inherent margins for trading transactions. Transmission system implemented on the basis of the expansion plan evolved in this manner would enable trading across the regional boundaries towards optimal utilization of generation resources in the country for ultimate benefit of the consumer. As the system is evolved based on extreme dispatches, it would facilitate trading most of the time without congestion. Currently, trading is taking place through short-term bilateral contracts. With introduction of Power Exchange at National level, which is being envisaged to be in place in near future, trading would also take place through Power Exchange which would be day ahead contracts. All the short term as well as Power exchange transaction would need transmission capacity which would come out of the spare capacity inbuilt in the transmission system. The reliability and operational margins in the planned and implemented transmission system corresponding to the committed long-term transmission needs would provide the transmission capacity for trading of power. (Ref Para 2.5 of main Working Group Report) 16

32 Executive Summary Working Group on Power-11 th Plan ( ) 2.5 TRANSMISSION CAPACITY MARGINS Transmission capacity through creation of additional transmission system could be provided based on long-term commitment for the transmission charges. It has been estimated that reliability and operation margins would be generally of the order of 25-30% of the transmission capacities required for meeting the firm transmission needs of the long-term open access. This level of redundancy would generally provided sufficient margins for trading needs. However, it should be noted that short-term open access (STOA) transactions operating on these margins, even if curtailable, cause reduction in the security level. Therefore, unless margins are increased by design, the system operator would have tendency to keep cushions by underestimating the operational margins. As such, and as the system security is of paramount importance, creation of increased margins by design becomes essential for accommodating STOA. (Ref para 2.5 of main Working Group Report) 2.6 TRANSMISSION PLANNING CRITERIA The network expansion has been planned to provide a reliable power system with sufficient redundancies for secure operation maintaining adequate margins at all times to maintain system parameters with in such limits that contingencies do not lead to loss of system integrity. The contingency criteria is based on N-1 in general and N-2 for large generating complexes and multi-line corridors. 2.7 TRANSMISSION SYSTEM FOR MERCHANT PLANTS Merchant plants would sell their power to customers who are not predetermined through Power exchange contracts. However, they are long term-user of the transmission system. The transmission system for the connectivity of the merchant plant as well as for meeting their transmission needs is required to be planned and built matching with the implementation of the merchant generation plant. Also, some of the generation plants have only a part of their generation capacity tied-up in long-term bi-lateral PPAs. When such plants seek long-term open access only for a part of their full generation capacity, they inherently also seek connectivity for the remaining capacity which would be available with them as a merchant plant capacity. As the transmission system in both the cases would be required to be planned and implemented corresponding to the full requirement, they are long-term beneficiary of the transmission system. For proper planning and implementation of transmission system, the merchant generators need to inform about region(s) in which they would generally sell their power, so that transmission system requirement for evacuation of their power and transmitting it to identified load centres could be assessed and any additional capacity required could be planned. As building the identified transmission schemes including obtaining necessary approvals by the identified transmission 17

33 Executive Summary Working Group on Power-11 th Plan ( ) company /companies would generally require almost same time as that for implementation generation projects, firming up of sellers and assessment of transmission requirement should be started at the earliest. (Ref para 2.5 of main Working Group Report) 2.8 TRANSMISSION SYSTEM UNDER STATE SECTOR A well planned and reliable transmission system at the National and Regional level would need to be complemented with development of matching transmission system at 220kV and 132kV and also the sub-transmission and distribution system so as to cater to the load growth and ensure proper utilisation of development in generation and transmission facilities for the ultimate goal of delivery of the services up to the end consumers in the country. Inadequate development of sub-transmission and distribution system facilities in the States of NER has been adversely affecting the reliability of power supply to the consumers and also hampering the load growth in the region. The transmission, sub-transmission and distribution systems of states require major strengthening/up-gradation. Transmission lines that are under outage require speedy restoration for bringing them into operation so that the states could avail their central sector shares as well as utilize their own generation without any constraint. Inadequacies in the transmission and distribution system had been on account of slow implementation of schemes due to various factors such as time consumed in E&F clearances, land acquisition, RoW constraints, fund limitation, organizational difficulties of state utilities, lack of vendor response due to locational factors, law and order, terrain specific difficulties, etc. Due to limited funding capabilities of state utilities, most of the required transmission projects are generally funded by NEC or by NLCPR under DONER and investment/funding approval of scheme so funded also takes additional time. All these issues need to be addressed to achieve the accelerated demand growth in NER. 2.9 ELEVENTH PLAN PROGRAMME Evolving the Perspective Transmission System for XI Plan In transmission system development in the country, the focus of XI Plan programme is formation of the National Power Grid. A strong All India Grid would enable exploitation of unevenly distributed generation resources in the country to their optimum potential. The transmission capacity together with the margins provided for required redundancies as per planning criteria would provide a reliable transmission system. This would meet the firm transmission needs and with open access in transmission, would facilitate increased real time trading in electricity leading to market determined generation dispatches thereby resulting 18

34 Executive Summary Working Group on Power-11 th Plan ( ) in supply at reduced prices to the distribution utilities and ultimately to the consumers. Development of National Grid has been necessitated by the large thermal generation potential in eastern part of the country and equally large hydro generation potential in north-eastern part. It has also been spurred by the opportunity provided by open access, variation in hydrology / hydro potential and diversity of load across the country. It is envisaged to add during the XI plan period new inter-regional capacities of MW at 220kV and above. This would increase the total inter-regional transmission capacity of National Power Grid at 220kV and above from MW of XI Plan beginning to MW by (Ref Para 2.3 of main Working Group Report) Fund Requirement for Transmission System Development and Related Schemes Total Fund requirement for transmission system development and related schemes has been estimated as following: Rs Crores Inter State system Intra State system TOTAL (For details please refer to Para 2.8 of main Working Group Report) 2.10 TECHNOLOGY DEVELOPMENT Adopting New Technologies In Transmission System New technologies would need to be adopted and implemented in a proactive manner to achieve the objective of optimum utilization of the available transmission assets as well as conservation of Right-of-Way, reducing transmission costs, reduction of losses etc. Some of the new technologies adopted/being adopted in its transmission system include: High capacity 6000MW +800kV HVDC system 765kV AC Transmission System Ultra High Voltage AC Transmission System(1000kV) Application of Series Compensation Flexible AC Transmission System (FACTS) Upgradation/Uprating of transmission line High temperature endurance conductor Tall/Multi-circuit & Compact tower High Surge Impedance Loading Line (HSIL) 19

35 Executive Summary Working Group on Power-11 th Plan ( ) Remote operation of substation, substation automation and Gas Insulated substation (GIS) All Aluminum Alloy Conductors (AAAC) and Polymer/Composite Insulators. Development of disc insulators of 320kN & 420kN indigenously for both AC & HVDC applications, as import substitution. Indigenous development of semi-conducting glazed insulators (Offering better pollution performance) Introduced source/process inspection of equipment to ensure zero defect Airborne Laser Terrain Mapping (ALTM) for detailed route survey Thermo-vision scanning of the lines and sub-stations Conditional monitoring of equipment Preventive maintenance of Transformers using State-of-art Oil testing laboratories set up by the company Emergency Restoration System (ERS) For modernization of transmission system through latest technology integration, two pronged strategies have been envisaged as under: Enhance capacity and reliability of existing systems. Suitable technology for new systems keeping in view the long term perspective 3.0 DISTRIBUTION INCLUDING VILLAGE & HOUSEHOLD ELECTRIFICATION 3.1 OVERVIEW OF DISTRIBUTION SECTOR The electricity distribution section is the most daunting sector due to its interface with the public at large with different needs and expectations and varying degrees of capacity to pay. The distribution sector is the cutting edge and as the need to improve this sector was realized, in the 10 th plan the emphasis was on steps to reduce the huge aggregate technical and commercial losses, control the theft & pilferage and rationalise the tariff structures. Investment was also made in the distribution sector and across the states reforms were taken up. Major schemes like Accelerated Power Development & Reform Program for urban areas and the Rajiv Gandhi Grameen Vidyutikaran Yojana was also initiated in the 10 th plan which aimed at bringing in investment in urban areas and creating an electricity infrastructure in rural areas. There is however a pressing need to continue these efforts in the 11 th plan so as to reduce the AT&C losses and to continue with the reforms in the distribution sector to provide an affordable, good quality and reliable power supply to the citizen of India, be it in urban or rural areas. 20

36 Executive Summary Working Group on Power-11 th Plan ( ) The distribution of power can be studied in two distinct components viz., (i) Distribution of power in urban areas, and (ii) Distribution of power in rural areas. (Refer Para 3.0 of main Working Group Report) 3.2 QUALITATIVE APPROACH Distribution of power in urban areas The Accelerated Power Development & Reform Program (ARDRP) was aimed at bringing about improvement in the urban distribution sector by funding investment in the distribution network, and by incentivising the states who performed well in reducing losses. The Ministry of Power constituted a task force in 2006 under Shri P. Abraham which has recommended that APDRP may be continued with investment and incentive component beyond the 10 th plan. However the conditions may be made more stringent and reform oriented. While broadly agreeing with recommendations of the Abraham Committee report, it is felt that APDRP needs to be continued in 11 th plan with revised terms and conditions. The focus of the programme should be on establishment of base line data, which shall enable reduction of AT&C losses in major towns of the country through strengthening, upgradation of sub-transmission and distribution network and adoption of Information Technology in the areas of energy accounting & auditing and improvement in consumer services through establishment of Bijlee Sewa Kendras. The programme may focus on the town and cities covering all district headquarters and town with population of more than 50,000 and town with lesser population in special category sates. The investment and incentive components may be merged and funding may be in form of loan assistance with the provision of conversion of loan to incentives to the distribution companies on achieving specified milestones with regard of reforms and reduction of AT&C losses. There also needs to be a provision of incentive to the employees of the utilities. The loan assistance may be converted to grant (50 % for general category states and 90 % for special category states) and the loan should be from Central Sector with a moratorium of three years on interest and on repayment. The rate of interest may be as determined by Ministry of Finance from time to time. ADDRP assistance should be also available to private distribution companies as the ultimate beneficiary was the consumer. The loan / grant needs to be funded under Central sector through REC / PFC Distribution of power to rural areas RGGVY (Rajiv Gandhi Grameen Vidyutikaran Yojna) aims to achieve power for all by 2009 and in the long run accelerate rural development, adequate employment and eliminate poverty through irrigation, development of small scale industries, provision of health care and promotion of education and information 21

37 Executive Summary Working Group on Power-11 th Plan ( ) technology. RGGVY also aims at bridging the urban rural gap and provide reliable quality power supplies to rural areas. However, in order to bring about access to electricity to all rural households, there would be need to widen the electricity coverage to hamlets / habitations of the country. In case the funding of RGGVY becomes a constraint it is proposed that in the first phase all un-electrified villages and hamlets with more than 300 population are covered. Those hamlets with less then 300 populations may be excluded except those in hilly, forest, desert and tribal areas. The total cost of phase 1 is estimated at Rs. 24,000 crore. Phase 1 would be completed by 2009 and would reach electricity to all the un-electrified villages and about 3 lakh hamlets. The second phase would start from 2009 onwards and would reach electricity to the balance un-electrified hamlets and complete the task of providing access to all rural households by Second phase is estimated around Rs. 16,000 crores. The two phases is estimated around at Rs. 40,000 crores. (Refer Para 3.7 of main Working Group Report) Prioritization of RGGVY Maximum number of un-electrified villages exist in the under developed States. RGGVY programme should give top priority in the allocation of funds for these States. Second priority should be given for intensive electrification of such States where the household electrification is below the national average. Third priority should be on the intensive electrification for the remaining States. (Refer Para of main Working Group Report) Public Private Partnership through rural franchisees Management of rural infrastructure has to be based upon all inclusive growth model that involves rural set ups and provides the local Panchayat Raj institutions a supervisory function to ensure the durability and sustainability of electricity infrastructure. Franchisee system for management of rural distribution has been made mandatory under RGGVY to make the revenue model sustainable. RGGVY allows enterprising individuals, NGOs, private entrepreneurs, co-operatives, Panchayat Raj institutions to become franchisees. The franchisees system needs major push in 11 th plan with initiatives for capacity building and financial support. (Refer Para 3.23 of main Working Group Report) 22

38 Executive Summary Working Group on Power-11 th Plan ( ) Financial support to Franchisees Not many people are coming forward for franchiseeship especially from remote rural areas where loads are small and sustainability difficult. As franchisees will be mainly rural entrepreneurs, they will have difficulties in raising small funds for their micro level projects to guarantee their performance or meet working capital requirements. No funds have been allocated under RGGVY for development of franchisees. It is necessary to develop institutions that extend micro credit to meet the franchise level financing needs Distribution of power in Rural Areas through Decentralized Distributed Generation (DDG) Electricity Act, 2003 provides the requisite framework for accelerating electrification in rural areas with necessary empowerment. It permits operation of stand alone systems independent of the regulatory regime. Integrated Energy Policy 2006 has estimated the requirement of power at 8,00,000 MW by It implies that India must add MW or more every year for a quarter century. It is a colossal task and would require exploitation of all renewable and fossil resources. Secondly, the creation of huge rural village and block level electricity infrastructure will require immediate supply of power. Village level energy resources like biomass, hydro and solar energy will help to reduce the dependence on grid based thermal, gas nuclear and hydro power. India has a potential to generate MW of power from the available biomass. DDG based on this resource will meet the critical needs of parched villages asking for timely power. Cost of electricity should be based on cost to serve basis and DDG to be taken up on a mission mode. Viability gap funding may be adopted in case of grid interconnected schemes. Bio mass cultivation may be encouraged to support DDG and bio-fuel cultivation to be funded by Financial Institutions (FIs) / Banks. However, multifuel technologies may be encouraged. (Refer Para 3.10 of main Working Group Report) Pilot Programmes on DDG The problem of providing power to rural areas would be critical when the infrastructure under RGGVY becomes ready but remains without the supply of power. To attract the entrepreneurs, REC may be encouraged to put up pilot projects in the selective rural areas to have a demonstrative effect. Such projects could be linked to the neighboring substations and incorporated as the long-term lease infrastructure under RGGVY on cheaper finance. DDG will go a long way to ameliorate the shortages of power in rural areas. Nationwide survey of available resources in each villages to be undertaken in fixed time frame through a nodal agency like REC. (Refer Para 3.10 of main Working Group Report) 23

39 Executive Summary Working Group on Power-11 th Plan ( ) One Megawatt Power Plants in Rural Areas To meet the power supply requirements of rural areas stand alone / grid connected power plants of optimum one megawatt capacity power plants should be encouraged. REC should act as nodal agency for providing technical and financial support under the scheme. (Refer Para 3.18 of main Working Group Report) Akshay Prakash Yojana Maharashtra has launched a new programme called Akshay Prakash Yojana aimed at demand side management. This programme has shown good results in ensuring quality and reliable supply of power to the villages. Both consumers and utilities are benefiting under this programme. It is recommended that this programme should be popularized among other utilities Centres for Excellence for Distribution of Power The Electricity Act has opened new avenues for variety of players to take up distribution of power. In the changed environment and to seize the new opportunities REC should set up centres of excellence for distribution of power in all the states to take up rural distribution by setting up a subsidiary company. (Refer Para 3.18 of main Working Group Report) Non Discriminatory Supply Option RGGVY scheme provides for making adequate arrangements for supply of electricity and there should be no discrimination in the hours of supply between rural and urban areas. To achieve this, there should be a clear allocation of Power Supply for the rural areas Agricultural Sector Agricultural consumption comprises of approx 20% to 40% of the total consumption of the utility in the states. There is a fear with regard to depletion of water table due to unrestricted exploitation of the ground water. The adoption of flat rate pricing for agricultural power is cause for this perverse state of affairs. Under this system, a farmer pays a fixed price per horsepower per month for electricity. Therefore, the marginal cost of pumping water is zero. This leads to energy wastage, over-pumping and inefficient selection of crops. Flat rate pumping also masks the true cost of power to farmers. Agriculture consumption is mostly un-metered and this allows manipulation of the loss by the utilities in the name of Agriculture Consumption therefore, during the 11 th plan all agriculture connections need to be compulsorily metered 24

40 Executive Summary Working Group on Power-11 th Plan ( ) Energization of Pumpsets in Eastern Region Eastern sectors irrigation potential should be fully exploited during 11 th Plan by launching a special scheme for energization of pumpsets. It is estimated that Eastern region has only 10% agricultural consumers. A targeted programme will not only provide livelihood to the poor farmers but also provide food security to the nation. Out of 35 lakh pumpsets energisation targeted for 11 th Plan, 20 lakh should be taken up in the Eastern region and other states where huge potential exists North-East and Backward Regions In all the backward and north-eastern States the programme of electricity distribution projects need to be supported with low cost funds along with substantial portion of subsidy or grants. Rural Infrastructure Development Funds (RIDF) available with NABARD should be utilized for the development of electricity distribution in the North-eastern and other backward regions of the country. For the System Improvement Schemes in these regions RIDF funds may be allowed to be utilized for making available cheaper credit for an accelerated development of these regions Tariffs Performance based regulation through Multi Year Tariff (MYT) framework, is an important incentive to minimize risks for utilities and consumers, promote efficiency and rapid reduction of system losses. It would also bring greater predictability to consumer tariffs by restricting tariff adjustments to known indicators. Benchmarking should be properly adopted after adequate studies to establish the desired performance standards. Regular review of the performance levels also need to be suitably undertaken. As regards Agricultural tariff it should be in consonance with the sustainable water management requirements. A higher level of subsidies could be considered to support poorer farmers of the region where adverse ground water table condition requires larger quantity of electricity for irrigation purposes but restricted suitably for maintaining ground water levels for a sustainable usage. Even a combined tariff in such cases for electricity and water may be an option to consider. Differential tariffs for usage during different time of the day i.e. distribution based on peaking or off peak hours etc. needs to be introduced expeditiously by introducing Time of the day Metering to flatten the demand curve to more manageable levels 25

41 Executive Summary Working Group on Power-11 th Plan ( ) Open Access Access to transmission and distribution network is one of the most important elements of Electricity Act 2003 and National Electricity Policy At the retail level the consumers with a minimum requirement of 1 MW are to be granted the right to avail open access by 2009 in a phased manner. A consumer allowed open access under the regulations is therefore free to choose any electricity supplier other than the distribution licensee of its area. The major issue in making open access operational is the level of cross-subsidy and other charges applicable to open access consumers. Most states have released open access regulations with the open access phasing plan time frame. The incumbent licensee may not like migration of creamy customers and put barriers to prevent it. The open access customers may also fear discrimination on availing supply from alternative source to the current retail supplies. In this context the regulators have an important role to play in encouraging open access. The 11 th plan should focus on creating awareness, providing communication, customer protection and promoting open access to the consumers as envisaged in the Electricity Act Open access in distribution should be in place including phasing out of cross subsidy surcharge by end of 11 th plan Other issues Newly created distribution companies (consequent to reorganization of SEBs) need to be given full autonomy. This should be a condition for release of central assistance to the states. Huge investment is required for distribution network up gradation. The central govt. should provide resources to the State Utilities with the condition that large part would be treated as grant if targeted reduction in T&D losses is achieved. There is a need to popularize TOD tariff. Separate distribution companies could be carved out for rural areas so that subsidy could be targeted to only needy and poor consumers. Forum of Regulators should come out with a model agreement for distribution of electricity by distribution licensees through a franchisee in urban area. The licensee should have discretion to give rebate to a category of consumers in the tariff determined by ERCs, if he considers it necessary, for effectively facing the competition caused by open access in distribution. Where applicable, carbon credits should be obtained. A business model including simplified tariff determination for generation- cumdistribution projects in rural areas should be developed to facilitate these projects. 26

42 Executive Summary Working Group on Power-11 th Plan ( ) 3.3 QUANTITATIVE ASSESSMENT OF 11 TH PLAN PROGRAMME The expected outcomes from the 11 th plan programme is given at Para 3.25 of the report. 3.4 ISSUES OF INSTITUTIONAL NATURE LIKE CENTRAL, STATE & PRIVATE SECTOR Enlarging Role of central Government Central Government should consider enlarging its role in the area of rural distribution and generating station to give power to consumers in the vicinity. Financial Institutions should support bio-diesel plantations, consultancy, R&D, DPR preparation etc. The priority sector status available to REC for the energisation of Agricultural pumpsets etc was recently withdrawn which should be restored in order to enhance the pumpset energisation programme during the 11 th plan to at least 35 lakh pumpsets. REC/PFC may finance the power equipment manufacturers in their modernization and expansion plans. REC/PFC may float Venture Capital Funds to encourage manufacture of critical quality components used for power infrastructure and promote ready market for such products at competitive rates State All concessions extended by States for Industrial development may be given for DDG projects. A separate Rural Electricity Agency (REA) may be considered for each state to look into needs of rural areas. The State Govts., State Utilities/ Discoms and Local administration should create proper enabling atmosphere to encourage DDG projects District Committees/ Local Management The District Committees should be suitably strengthened, made fully functional and active during the 11 th Plan. This should cover all the districts in the country. Specific funds should be allotted to the District Committees. Local institutions like 27

43 Executive Summary Working Group on Power-11 th Plan ( ) Panchayat, cooperatives, NGOs, SHGs should be encouraged to take up local management Private The APDRP assistance, both investment and incentive component, may be extended to the Private Distribution Utilities also. The incentive for loss reduction by the private utilities may be given to the State instead of the utility. 3.5 TECHNOLOGY ASSESSMENT AND NEEDS Pre-paid Meters Pre-paid meters, should be promoted in the 11 th Plan. This will enable efficient use of power for agricultural use and will also eliminate adverse impact on water table due to excessive exploitation of ground water. Though it involves huge capital cost the gains from the system would offset such costs in the long run. It is also expected that large scale use would bring down the cost of the technologies HVDS System The advantages of HVDS system are well known particularly in containing theft of electricity. Besides, it improves the quality of power significantly and thereby customer satisfaction. HVDS system needs to be given a special focus in the 11 th Plan to get immediate results in loss reduction. Efforts should be made to bring down HT/LT ratio during the 11 th Plan. (Refer Para 3.17 of main Working Group Report) Priority to IT applications It is well established that IT application can play a major role in AT&C loss reduction and provide management of distribution utilities. The IT task force clearly laid out a plan for introduction of IT on a large scale in the power distribution sector. The task force recommendation should be implemented. It is also suggested that the incentive fund under APDRP should be re-deployed for promoting cost effective IT in the entire distribution sector Customer Indexing & GIS based Database Customer indexing is absent in most of the utilities. This is a major impediment for any reform in the sector. Consumer indexing has been done by some utilities but incomplete. Consumer indexing based on GIS application needs to be given priority in the 11 th Plan Load Management 28

44 Executive Summary Working Group on Power-11 th Plan ( ) In the scenario of energy and peak shortages, load management plays a very important role for efficient use of energy. Feeder separation programme needs to be given a major push in those states where agricultural consumption is more than 20%. In addition SCADA/DA should be introduced in all the million plus towns by the end of 11 th Plan Demand Side Management & Energy Efficiency Using of energy efficient devices should be incentivised. The focus should be on use of efficient pumpsets in the agricultural sector. Use of CFL lighting etc. should be encouraged. An awareness campaign should be launched to educate stakeholders at all levels and quantifiable targets should be fixed to improve energy efficiency gains Reliability Monitoring of Power Distribution System Present reliability of power is carried out by CEA in terms of outages of 11 kv feeders on monthly basis in respect of State capitals and major urban conglomeration. There are number of reliability indices which are in practice internationally. The international practices should be adopted for proper monitoring of reliability. The reliability monitoring is to be gradually brought in line with the world practice i.e. to measure the outage in terms of consumer hours and number of consumer interruptions. The reliability monitoring will become more fruitful once Consumer Indexing i.e. linking of every consumer to the feeder is completed by all the Discoms /SEBs and will provide a direct index for customer satisfaction Distribution Network Planning Inadequate network planning is one of the reasons for hap-hazard and unscientific development of the distribution system. The utility should move to proper distribution network planning both for demand forecasting on medium and long term basis and for determining need for system expansion and improvement to meet the load growth. Utility should prepare perspective network plan for 10 year period and this should become part of the conditionalities for sanction of grants under various programmes Energy Accounting & Auditing Energy Accounting & Auditing is done in many utilities but not comprehensive. In absence of complete energy accounting and auditing, the system losses can not be measured accurately and also identification of areas of losses becomes difficult. 11 th Plan should make efforts to standardize energy accounting and auditing practices and incentivize utilities undertakings complete accounting and auditing exercise. 29

45 Executive Summary Working Group on Power-11 th Plan ( ) 3.6 ASSESSMENT OF FINANCIAL REQUIREMENTS The detailed table of quantities and financial requirements for 11 th plan are given at Para 3.25 of report. However, the final summary of the estimated cost is given below: 1. Sub Transmission & Distribution for Urban & Rural areas: Rs. 1, 97,000 crore RGGVY Rs. 40,000 crore Rs. 2, 37,000 crore 2. APDRP & Other Schemes (pumpsets etc.) Rs. 40,000 crore 3. Decentralised Distributed Generation Rs. 20, 000 crore 4. Others Rs. 10,000 crore TOTAL Rs. 3,07,000 crore 3.7 RECOMMENDATIONS 1. ARPDP to be continued in 11 th plan with focus on auditing and accounting and reducing AT&C losses in major town and cities It interventions,technological upgradation, control of theft and pilferage, GIS and consumer indexing and establishment of Bijlee Sewa Kendra. 2. RGGVY needs to be continued with more focus and with regular flow of funds so that the envisaged benefits reach the rural masses. 3. Franchisees need to be developed in both urban and rural areas. A scheme of public private partnership for franchisees development may be encouraged.and adequate financial support through liberal micro credit schemes needs to be given for encouraging franchisee development. 4. Decentralised distributed generation needs to be taken up in a mission mode. Pilot projects needs to be set up initially to gain experience. DDG proposals may be offered capital subsidies under the public private partnership scheme for viability gap funding nation wide survey may be undertaken to analyse resources for DDG. 5. One megawatt power plants in rural areas to be encouraged. 6. Centre for excellence in distribution to be set up. 7. Capacity building programmes of franchisees to be vigorously followed. 8. Special programme of energisation of pump sets in eastern region to be implemented. 30

46 Executive Summary Working Group on Power-11 th Plan ( ) 9. Open access in distribution section to be encouraged. 10. Multi year tariffs and rationalization of tariff to be implemented. 11. IT applications to be given priority. 12. Prepaid meters, HVDC systems, consumer indexing, GIS based database, reliability indexing, energy efficiency, demand side management and energy accounting and auditing to be implemented. 4.0 DEMAND SIDE MANAGEMENT, ENERGY EFFICIENCY & ENERGY CONSERVATION 4.1 THE ENERGY CONSERVATION ACT AND INTEGRATED ENERGY POLICY The 10 th plan period ( ) marked the enactment of the Energy Conservation Act, 2001 and setting up of the Bureau of Energy Efficiency (BEE) at the national level. The Act has given the mandate to BEE to implement the provisions of the Act, and spearhead the improvement in energy efficiency of the economy through various regulatory and promotional measures. The Planning Commission in its recent report on an Integrated Energy Policy (IEP) laid out a vision of providing energy security to all citizens. IEP emphasizes energy efficiency & demand side management as essential components of the natural energy strategy. The Sub-Group report focuses on operationalizing and implementing the recommendations of the integrated energy policy. (Refer Para 4.2 of main Working Group Report) 4.2 ENERGY CONSERVATION STRATEGY IN THE 11 TH FIVE-YEAR PLAN The basic aim of the energy conservation strategy in the 11 th Five Year Plan is to create and strengthen institutions at the centre and in the states to carry out the provisions of the EC Act 2001, in line with the recommendations of the Integrated Energy Policy. The strategy will strengthen the existing institutional linkages, pursue the task of consolidating energy conservation information, trends and achievements, and create a market for energy conservation and for energy efficient goods and services. (Refer Para 4.3 of main Working Group Report) 31

47 Executive Summary Working Group on Power-11 th Plan ( ) Strengthening of BEE and SDAs In the 11 th Five Year Plan, BEE will be strengthened as a nodal organization at the national level, and will be empowered to provide direction to the energy conservation programmes in the States. An Energy Conservation Information Centre (ECIC) will be set up within BEE to collate energy use data, and analyze energy consumption trends and monitor energy conservation achievements in the country. Supporting organizational set-up will also be strengthened in the state designated agencies (SDAs) in various States and Union Territories (UTs). For this, a matching grant support from Central Government restricted to the contribution made by the respective States/UTs Governments will be extended to establish State Energy Conservation Fund as mandated under EC Act. (Refer Para of main Working Group Report) Energy Conservation Programmes in the Targeted Sectors In the 11 th Five Year Plan, BEE will focus energy conservation programmes in the following targeted sectors: Targeted sectors (i) Industrial Sector (Energy Intensive Industries). BEE will develop 15 industry specific energy efficiency manuals/guides for the following sectors: Aluminium, Fertilizers, Iron &Steel, Cement, Pulp & Paper, Chlor Alkali, sugar, textile, chemicals, Railways, Port trust, Transport Sector (industries and services), Petrochemical &Petroleum Refineries, Thermal Power Stations & Hydel power stations, electricity transmission companies & distribution companies. The manuals will cover Specific energy consumption norms as required to be established under the EC Act, energy efficient processes and technologies, best practices, case studies etc. Follow up activities will be undertaken in the States by SDAs and manuals will be disseminated to all the concerned units in the industries. (Refer Para of main Working Group Report) (ii) Small and Medium Enterprises (SMEs) SDAs in consultation with BEE will initiate diagnostic studies in 25 number of SMEs clusters in the country, including 4-5 priority clusters in North East Region, and develop cluster specific energy efficiency manuals/booklets, and other documents to enhance energy conservation in SMEs. (Refer Para of main Working Group Report) 32

48 Executive Summary Working Group on Power-11 th Plan ( ) (iii) Commercial Buildings and Establishments BEE will prepare building specific energy efficiency manuals covering Specific energy consumption norms, energy efficient technologies, best practices etc. As a follow up, SDAs would initiate energy audits and their implementation in 10 Government buildings in each state and 1-2 buildings at UT level. BEE will also assist SDAs in the establishment and promulgation of energy conservation building codes (ECBC) in the States, and facilitate SDAs to adapt ECBC. (Refer Para of main Working Group Report) (iv) Residential/Domestic sector BEE will enhance its on-going energy labeling programme to include 10 other - appliances - Air conditioners, Ceiling Fans, Agricultural pump-sets, Electric motors ( general purpose), CFLs, FTL 61cm, Television sets, Microwave ovens, Set top boxes, DVD players and Desk top monitors. To facilitate this consumer awareness will also be enhanced nation wide. (Refer Para of main report) (v) Street Lighting & Municipal Water Pumping To promote energy efficiency in municipal areas in various states, SDAs in association with State utilities will initiate pilot energy conservation projects in selected municipal water pumping systems and street lighting to provide basis for designing state level programmes. (Refer Para of main Working Group Report) (vi) Agriculture Sector In the 11th Plan, SDAs will collect document and disseminate information on successful projects implemented in some states, launch awareness campaigns in all regional languages in print and electronic media, and initiate development of state level programmes along with utilities. (Refer Para of main Working Group Report) (vii) Transport Sector SDAs with assistance of concerned institutions/agencies will conduct diagnostic studies to establish the status of energy consumption and conservation in the sector. BEE will also set up labeling and/or norms for specific fuel consumption for a few automobile and Transport categories (Services/ Public transport). (Refer Para of main Working Group Report) 33

49 Executive Summary Working Group on Power-11 th Plan ( ) Demand Side Management Programmes BEE in association with SDAs will facilitate State Utilities to pursue DSM options by focusing on orientation workshops for awareness building, setting up of DSM cells in utilities to conceive and implement DSM programs, support load research and studies to rationalize the tariff structures, and initiation of DSM programmes, especially in the residential, agricultural pumping and municipal water works & street lighting sectors (Refer Para of main Working Group Report) Human Resource Development Programmes There is a vast potential for energy savings through human intervention. BEE and SDAs have a major responsibility for stimulating a major change in the energy efficiency ethos and practices (energy modesty) by directing the national energy conservation campaign as a mass movement and seeking wide support. In the 11 th Plan, BEE will continue with their campaigns. The initiatives like capacity building of energy professionals, establishment of Demonstration centers in 2 industrial estates, and Nationwide campaigns through media and other modes will be undertaken. (Refer Para of main Working Group Report) 4.3. POLICY RESEARCH FOR ACCELERATING ADOPTION OF ENERGY EFFICIENCY AND DSM PROGRAMS Policy research on legislative amendments, policy interventions including fiscal and non- fiscal measures are planned to be undertaken in 11 th Plan. (Refer Para 4.4 of main Working Group Report) 4.4 RECOMMENDATIONS The target of additional electricity savings which may accrue to the national economy at the end of 11 th Five year plan as a consequence of intensive energy conservation and DSM drive is expected to be about 5% of the anticipated energy consumption level in the beginning of 11 th Plan. BEE will device a suitable mechanism for assessing these savings. The outlay for various strategies and programs as proposed is Rs. 652 Crores. Out of this proposed allocation, Rs crs is the estimated requirement for BEE at the centre and the balance Rs crs as the assistance for strengthening the institutional structure at the State level for effective implementation of EC Act. These initiatives will also seek funding support from state governments, other complementary programs, user industry, financial institutions, and other donor agencies besides innovative financing options. 34

50 Executive Summary Working Group on Power-11 th Plan ( ) 5.0 TECHNOLOGY ADVANCEMENT AND R&D There is a need to introduce advanced technology in generation, transmission and distribution and encourage Research & Development to meet the ambitious plan of power sector growth during the 11 th Plan. A review of utilization of R&D fund during the 10 th Plan period by major players in the power sector shows that it was less than RS.150 crores against a provision of Rs.500 crores. This is considered unsatisfactory and needs to be substantially improved in the 11 th plan. Considering International technology trend and India s power sector requirement following broad areas were identified for selecting R&D projects during the 11 th Plan. a) Introduction of larger size energy efficient thermal generation for Indian coal with a good mix of fossil and renewable source of energy. b) Efficient operation of a large grid with 800 kv AC &DC transmission with high reliability, flexibility and open access in transmission c) Technology development and demonstration of distributed generation covering bio mass, bio diesel, solar, wind and focus on microgrids. d) Reduction of distribution system losses, energy conservation methods and introduction of large scale automation in distribution sector. e) Clean technology development 5.1 OVERVIEW OF R&D IN THE PAST In the generation sector commendable work has been done by NTPC and BHEL in the areas of stabilization of 210 and 500 MW units, development of pulverized coal fired boiler for coal with high ash content, efficiency improvement of Thermal Power Plants, control, instrumentation and loss minimization. Similarly in the hydro generation, BHEL, NHPC and other hydro utilities have contributed in uprating of old units, improving turbine design etc. In transmission, Powergrid and BHEL have introduced many new technologies like Series Compensation, Thyristor Controlled Series Capacitor, Controlled Shunt Reactor, etc. Powergrid have contributed to the development of high temperature conductors, development of insulators, introduction of 800kV AC and planning for ± 800 kv DC first time in the country. Many of the development by Powergrid and NTPC have come through project route in the county and although their R&D units have not shown substantial expenditure on R&D, the organizations have encouraged new technology. 35

51 Executive Summary Working Group on Power-11 th Plan ( ) It is felt that where as some of the available technology abroad are being introduced in the country, commensurate R&D efforts to get it improved and sustained through available inhouse resources, has not been pursued. Further, an institutional mechanism to conduct and monitor National Level R&D Projects has not been in place to make the indigenous R&D encouraged and its impact assessed. As a result, there is no technology breakthrough that has actually taken place in power sector through indigenous route. 5.2 TECHNOLOGY DEVELOPMENT IN POWER SECTOR Major utilities like NTPC, NHPC and PGCIL have their inhouse R&D setup which addresses introduction and absorption of new technology primarily through project routes. Major manufacturers like BHEL, Crompton Greaves have their own R&D set up, focusing on product development. Central Power Research Institute (CPRI) is provided with capital funds from the Ministry of Power for inhouse research as well as disbursement of research funds to utilities, industries and academic institution. Central Electricity Authority has a role in identification of appropriate new technology for the country. Recently a few projects under National Perspective Plan on R&D have been taken up by CPRI which are collaborative research projects involving more than one organisation. The R&D policy of the Government recommends R&D projects that help the nation to become self reliant in technology. 5.3 IDENTIFIED PROJECTS FOR 11 TH PLAN BY CENTRAL UTILITIES NTPC has identified a few good projects for inhouse research where they would involve other research institutes like BARC, CPRI, CSIR and other consulting houses. The list of projects identified by NTPC is as follows: 1. Flue gas heat recovery system for a 200 MW Unit. 2. IGCC technology demonstration project. 3. Automated boiler tube inspection system (robotics application). 4. On line condition monitoring of power transformers. 5. Modeling & design of natural draft cooling tower assisted flue gas dispersion. 6. Technology demonstration for suitable capacity solar (Thermal) KW sterling engine based TDP suitable for distributed generation. Powergrid has similarly identified a number of inhouse projects a list of which is as follows: 1. Technology Development for +/- 800 kv HVDC system for transfer of 6000 MW power from NER to NR 2. Aerial route survey using Air borne laser terrain (ALTM) along with National Remote Sensing Agency (NRSAR) 36

52 Executive Summary Working Group on Power-11 th Plan ( ) 3. Development of High surge impedance loading line (HSIL) 400 kv Purnea Biharshariff D/C 4. Fault current limiter at 400 kv level 5. Indigenization of polymer insulator 6. Specification of suitable oil for transformer 7. Indigenized development of MOV R&D in infrastructure development 8. Intelligent grid 9. Converter transformer design 10. Converter transformer less HVDC system / 1200 kv EHVAC development 12. Residual life assessment of transmission system 13. Indigenous development of GIS 14. Real time digital simulator and studies 15. Indigenous development of high strength insulators like 320 / 420 kn AC & HVDC kv compact line 17. Lightning mapping BHEL has identified a few broad based projects in generation, transmission and distribution which are given as under: 1. Clean coal technologies. 2. Super critical boilers. 3. Ultra High Voltage Equipment. 4. IGBT based drives and controls. The laboratories of CSIR who also carry out basic and applied research have following inhouse research programmes identified for the 11 th plan: 1. R&D on Photovoltaics and other solar energy applications (NPL, New Delhi) 2. Energy for cleaner and greener environment (CECRI, Karaikudi). 3. Bio energy technology: Strategy designing of Jatropha curcas for bio diesel (NBRI). 4. Development of gas to liquid (GTL) processes for DNE & Fischer Tropsch fuels (NCL). 5. Hydrogen economy initiative (NCL, Pune). 6. Development of coal to liquid (CTL) technology for synthesis of liquid from hydrocarbons (CFRI, Dhanabad). 7. Development of a composite approach suitable for clean coal initiatives (CMRI, Dhanabad). 8. Development of Underground coal gasification and IGCC Technology in India (CMRI, Dhanabad). 37

53 Executive Summary Working Group on Power-11 th Plan ( ) CPRI has identified few areas of research and investment in infrastructure building which are given below: a) Development of new ceramic and polymer composites for power sector application particularly for power capacitors. b) Research on new material development for turbine blades for hydro stations and new coating material along with other CSIR Laboratories and NHPC. c) Study of thermal mapping of power stations and heat rate improvements. d) Diagnostic techniques and mulit criteria approach for RLA of EHV substations. e) Simulator studies for large AC/DC grids. Other than the projects listed, a few projects of National interest which are necessary to be taken up were identified for the following reasons: a) They are collaborative research projects where more than one agency have to be involved. b) Some of them are demonstration projects involving best practices that would help further research c) Some of them are new application areas of available technology A list of projects have been proposed for Generation, Transmission, Distribution & Environment areas. Details of the same are furnished in Para 5.6 of Working Group Report. Estimated cost of R&D projects recommended for 11 th plan by the Working group have been discussed with the PSUs of MOP, BHEL and also shared with CSIR. Details of the funds are as follows: Total for Generation Total for Transmission Total for Distribution New Projects : Rs crores : Rs crores : Rs crores : Rs crores (Project wise details of funds are furnished in Para 5.6 of the main Report) 38

54 Executive Summary Working Group on Power-11 th Plan ( ) 5.4 CPRI S ROLE AND A NEED FOR RESTRUCTURING CPRI was established to work as a nodal agency for power sector research but had a larger role assigned to work as a neutral testing laboratory. Although the organisation has contributed to encourage R&D in utilities, academic institutions and in its own laboratories, it has not been able to build up resources to work as a driver of R&D in the power sector. It is recommended that a restructuring of CPRI is necessary if it has to play a proactive role in collaborative research in the country. For this the following are suggested: a) Testing and Research have to be separate functions within CPRI. b) Testing has to sustain on its own and as far as possible government grant should not be utilized for meeting test facility requirements. The beneficiaries of test facility, i.e., the manufacturing units and utilities should largely bear this burden. c) CPRI should be corporatised to reduce its dependence on Government funding and have better operational flexibility. This would help CPRI to be competitive and self reliant. The major utilities like NTPC, PGCIL, NHPC and PFC should come forward to make it happen. d) CPRI is to develop its ability to enhance industrial & system related consultancy work and get more sponsored projects for improving its financial health Assessment of CPRI s requirements of fund CPRI gets planned funds for expenditure of capital nature on replacement of old test facility, addition of new test facility and for research under three heads, viz. (a) for its own internal research projects, (b) for research projects on Power (RSOP) to encourage research at utility centers and (c) National Perspective Plan projects. The 10 th Plan utilization of fund by CPRI is Rs.67.0 crores. For the 11 th plan period, CPRI has asked for a major investment under the following heads For Test facility - Rs crores For research projects & facilities - Rs crores (Details are furnished in Para 5.4 of the main Working Group Report.) 39

55 Executive Summary Working Group on Power-11 th Plan ( ) 5.5 FUNDING OF R&D R&D expenditure of a few world class utilities and industries are given below: Company R & D Exp Net sales % of % of R&D % of R&D R&D R & D Exp Net sales R & D Exp Net sales Exp Exp Exp GE (billion Dollar) Siemens (Billion Euro) Company Alstom (million Euro) Hitachi ( billion Yen) Mitsubishi Electric (million Yen) BHEL (million Rupee) R & D Exp Net sales % of R&D Exp R & D Exp Net sales % of R&D Exp R & D Exp Net sales % of R&D Exp It may be observed that most of the organizations spend between 1.8 to 6% on R&D depending on the nature of their business. Technology advancements and research & development have so far not been properly addressed. Major organizations like NTPC, NHPC, POWERGRID, on the generation side and BHEL, ABB, SIEMENS on the manufacturing side must enhance substantially their budget allocations for research and development. The utilities should aim at least about 1% of their profit to be utilized for research and development activities and the manufacturing organizations should consider 3-4% to be provided for technology development. Networking of R&D resources and expertise would be an important strategy aimed at getting effective results. CPRI, apart from testing, must reorient its strategy and activities towards research. 5.6 RECOMMENDATIONS AND POLICY ISSUES. 1. Technology advancements and research & development have so far not been properly addressed. Major organizations like NTPC, NHPC, POWERGRID, on the generation side and BHEL, ABB, SIEMENS on the manufacturing side must enhance substantially their budget allocations for 40

56 Executive Summary Working Group on Power-11 th Plan ( ) research and development. The utilities should aim at least about 1% of their profit to be utilized for research and development activities and the manufacturing organizations should consider 3-4% to be provided for technology development. 2. Networking of R&D resources and expertise would be an important strategy aimed at getting effective results. CPRI, apart from testing, must reorient its strategy and activities towards research. 3. Ultra Super Critical boiler technology, IGCC technology and oxy-fuel technology are well researched abroad but have to be developed for Indian coal. NTPC, the major Indian Central Sector utility should have its R&D centre strengthened to expedite the work started during 10 th plan on IGCC. It is recommended that this project may be given top priority and completed with the help of BHEL or with a private party if necessary. 4. There is a need to work with specialized S&T laboratories under CSIR & other space and nuclear establishments to develop material technology for advanced boilers, fuel cells, solar power, battery & super conducting material application in power sector. 5. For the projects of National interest to be taken upon collaborative research route the estimated R&D expenditure of 452 crores is recommended. It is also recommended that in future capital fund support for R&D should be reduced and utilities and industries should collaborate to fund R&D projects. 6. An institutional change in handling R&D is required. A suggestion is to have generation, transmission & distribution R&D units to be established as separate entities in the central sector undertakings or to set up a corporate technology centre for R&D activities in various areas of power sector 7. R&D import should be exempted from custom duty to encourage indigenous R&D 8. Power sector should seriously consider attracting young talents by offering them challenging opportunities. This will be possible by encouraging R&D and offering a good package, like many MNCs are offering at present. 9. A High Power Committee in R&D should monitor R&D projects and regulate funds. This will avoid duplication & ensure competitive R&D. 10. Organisations like CPRI and NPTI should be spared from manpower optimization rules where vacant positions are surrendered. This is in view of the depleting cadre of scientists and specialists in these organizations. 41

57 Executive Summary Working Group on Power-11 th Plan ( ) 6.0 NORTH-EASTERN DEVELOPMENT The details of Development of Power Sector in North-Eastern Region have been covered in the respective areas. 7.0 HUMAN RESOURCE DEVELOPMENT AND CAPACITY BUIDING 7.1 MANPOWER The manpower at the end of the 10 th Plan will be of the order of 9.50 lakhs, out of which the technical manpower is 7.16 lakhs and non-technical 2.34 lakhs. The total manpower by the end of 11 th Plan shall be of the order of lakhs, out of which 8.89 lakhs will be technical and 2.86 lakhs, non-technical. The total manpower by the end of 12th Plan shall be lakhs, out of which lakhs will be technical and 3.18 lakhs will be non-technical. (Ref Tables 1 to 22- of Chapter 7 of the main Working Group Report) 7.2 TRAINING LOAD Overall training load expected during the 11 th Plan is 4.65 lakh man-months per year against the available training infrastructure of only 0.77 lakh man-months per year. For the 12 th Plan, the expected training load is 4.78 lakh man-months per year. (Ref Para of the main Working Group Report) 7.3 MAN-MW RATIO The Man-MW ratio is expected to gradually decline from 9.42 per MW in the 9 th Plan to about 7 in the 10 th Plan and subsequently to 5.82 and 4.93 in the 11 th and 12 th plans respectively. (Ref Table 23 of Chapter 7 of the main Working Group Report) 7.4 MAJOR OBSERVATIONS / RECOMMENDATIONS Training for All Every employee should be provided refresher training of minimum one-week per year as mandated in the National Training Policy. Provisions for Refresher training for O & M personnel has been made in the Indian Electricity Rules. 42

58 Executive Summary Working Group on Power-11 th Plan ( ) However provisions for Refresher training for all power sector personnel as per their requirements may be included Induction Level Training Induction level training should be made compulsory for personnel getting inducted in all areas viz., Thermal, Hydro, Transmission and Distribution etc. Statutory provisions for Induction level Distribution Training in the Indian Electricity Rules is under active consideration and would be notified shortly. Simulator training should also be necessarily included as one of the modules for the O & M personnel. The Induction level training for Thermal, Hydro and Transmission is presently a Statutory obligation as per the I.E. Rules. This may be made mandatory and in particular enforced for the personnel working in the State Utilities and Boards. Formal Induction level training should also be imparted to all non-technical personnel in power sector. The duration could be three (3) months for executives and one (1) month for non-executives Reporting Training activities to CEA As many as 51 Training Institutes are recognized by CEA and it is recommended that all training activities including expenditure incurred on training and personnel trained should be reported to CEA. Every Utility/Organisation should display the manpower and the training infrastructure available category-wise on their website Strengthening of Existing Training Institutes Capacity of existing Institutes to be strengthened. Provisions should be made in the plan budgets for augmenting Training Centres from time to time. Upgradation of the Training Institute s Lab facilities may also be reviewed on a regular basis and funds should be accordingly allocated New Training Institutes All Power Utilities should set up Training facilities encompassing training infrastructure for Induction level, Linemen and for Distribution Franchisees where the Govt. of India could provide part funding. A National Level Training Institute for Transmission with necessary infrastructure with Central support at HLTC, Bangalore and Power Grid may be created. A National level training centre for Distribution should be created with Central Support at PSTI, Bangalore and CIRE, Hyderabad. 43

59 Executive Summary Working Group on Power-11 th Plan ( ) Emphasis should be given to Linemen Training. It should be ensured that the Linemen recruited should be at least 8 th class pass with an ITI qualification. New Linemen Training Centres should be established within the proposed institutes in the Utilities in line with the recommended requirements of Distribution training. Need for training on Hotline LT Distribution lines may also be actively considered for interruption free maintenance to the consumers Capacity Building in Training for Franchisees (RGGVY) A national program for training and capacity building to be initiated targeting at enhancing the skill of franchisees and trainers so as to enable them to play the desired role in improving rural electricity access. Every major state should have one (1) Training institute for Franchisee training. Commercial and Legal issues should also be necessarily included in these training programs. Training Centres should also be set up in the districts, which are covered under Rajiv Gandhi Grameen Vidyutikaran Yojna along with Linemen Training Centres Capacity Building in Training for Franchisees may also be taken up by the Institutes conducting DRUM training Networking The Sub Group also stressed on Networking and tie-ups with the Training/Academic institutions like NPTI, IIMs, ASCI, PMI etc., and other reputed institutions for providing training to power sector personnel and other stakeholders Training for Contract Labour Adequate training should be made a pre-requisite for the contractor s labour to qualify for supply of Labour in power plants. Contract documents should accordingly be modified Training on Attitudinal Changes/ Behavioral Sciences Apart from the stress put on acquisition of knowledge and upgradation of skill emphasis should be given on attitudinal changes/behavioural sciences, in order to develop a sense of belongingness amongst the employees. 44

60 Executive Summary Working Group on Power-11 th Plan ( ) Areas of Concern Inspite of lack of availability of required infrastructure, the available infrastructure of various Training Institutes remain under utilized Statutory Induction Level Training is not being taken seriously by the Power Utilities Inadequacy of Trainers and insufficient Career Development Opportunities ITIs and other vocational training institutions have to be substantially expanded in terms of the number of persons they train and in the number of different skills and trades they teach. The quality and range of their training will have to keep pace with the changing needs of the economy and opportunities Recurring Investment on Training As recommended in the National Training Policy, Organizations should allocate some portion of their salary budget towards training and development. All the Organizations, which are provided with Grants either from Central or State Sector, should separately allocate Funds in particular for Training, which should not be spent for other purposes. 7.5 FUNDING The Total Plan period outlay is about Rs. 462 Crores. This does not include the plan fund outlay proposed by other Sub-Groups, which includes setting up of new training institutes, infrastructure upgradation, provision of incentives for sponsoring organizations, Technology upgradation, procurement of Simulators and GIS based training packages etc. (Ref. Para 7.4 of the main Working Group Report) 8.0 LEGISLATIVE AND POLICY ISSUES FORMULATION, IMPLEMENTATION & FEEDBACK 1. Situation is not ripe for procurement through Case-I route since both coal and gas are not yet freely available in the market. All efforts should be made to develop new capacity under Case-II procurement. 2. SPV is necessary to develop new generation capacities quickly. 3. There is need to streamline and standardize the procedure to shorten time cycle for obtaining environmental/forest clearance with greater emphasis on compliance with laid down standards and conditions. 45

61 Executive Summary Working Group on Power-11 th Plan ( ) 4. Exploration capacity of CMPDIL may be augmented and also it may be given more autonomy so that it can discharge its responsibility in fair and neutral manner. Number of agencies having authorization to undertake exploration of coal blocks should be increased. 5. Coal blocks to be used for captive coal mining by power projects should be explored fully at the earliest and GRs should be readily made available to power project developers on actual cost basis. 6. Appropriate cut-off of gross station heat rate, say 3000 kilo calorie per unit, can be considered for identifying inefficient old power plants of more than 25 years age and the sites could be released for setting-up plants of more efficient and large sized units depending on the scope of expansion available and with due cost benefit analysis. Coal linkages of the old power plants should be transferred to new generating units. 7. Till the long-term coal supply contracts emerge in international coal markets, the option of competitive bids for net heat rate may be explored for imported coal based stations. 8. In the interests of larger competition aimed at consumer benefits, procurement from non-conventional energy sources should not be restricted to within the State but suppliers from outside State should also be allowed to compete. 9. Procurement from non conventional sources should, unless there are compelling reasons, be done through competitive bidding process as this would add to transparency and lower procurement costs. 10. After assessing the stage of development of various non conventional energy technologies, definite timeframe should be laid down for doing away with preferential tariff for power generated from such sources. 11. Tariff Policy advises States to rationalize taxes and duties on captive power consumption. This may be reviewed periodically with States and made a condition for Central assistance to State power sector. 12. In competitive procurement of power, bidding by CPSUs should be ensured in initial few projects to encourage competition. 13. CERC could set up benchmarks for capital expenditure to facilitate accelerated R&M of old power plants. 14. To make available adequate power for open access consumers, there is need for enabling policy framework for merchant power plants. Size of MPPs could be up to 1000 MW which may be appropriate considering greater possibility of financial closure without long-term PPAs for comparatively smaller sized projects and also of making available 46

62 Executive Summary Working Group on Power-11 th Plan ( ) transmission corridors for such MPPs. We could target MPP capacity of about 10,000 to 12,000 MW by end of 11 th Plan. Such merchant capacity would be without the basis of long term PPAs. 15. Coal linkages should be freely available for power project developers who come forward to set up such MPPs. In case captive coal blocks are given to MPPs, there should be a mandatory condition that such the project developer would not compete in competitive bidding for long-term PPA based power procurement in order to avoid unequal competition since only few developers would have such coal blocks. For allocation of linkage or coal blocks for MPPs, an additional condition should be that captive mining must begin within a period of 3 to 4 years failing which the allocation should be cancelled. 16. For providing transmission corridors for such MPPs, adequate redundancy should be built at the stage of transmission planning. Presently, also there is a redundancy of about 20-25% in the transmission planning. There is need to identify the major load centres who would draw power from such MPP. These load centres would be most likely situated in northern and western region where many States are deficit in power supply. Therefore, the required redundancies could be planned from the likely location of the MPP (which would be in eastern region) to such load centres. The cost of providing such redundancy should be absorbed in the transmission tariff by the concerned beneficiaries. This would be in the long-term interests of consumers who will gain from efficiency arising out of competition among the generators. 17. Tariff Policy envisages a National Transmission Tariff Framework sensitive to distance and direction and related to quantum of power offered. CERC is in the process of developing such a Framework which needs to be done expedited. This would be a necessary pre-requisite for promoting open access and power trading. 18. There is urgent need for regulations for providing grid connectivity to MPPs. The National Electricity Policy already provides that prior agreements would not be a pre-condition for network expansion and the transmission utilities should undertake network expansion after identifying the requirements in consonance with the National Electricity Plan and in consultation with the stakeholder, and taking up the execution after due regulatory approvals. 19. The reduction in cost of production of coal on account of higher efficiency in captive coal mining should be passed on to the consumers through reduced cost of bulk power. The coal blocks should be offered on the basis of competitive bidding as part of the integrated coal mine-cumpower project to achieve this objective. Any other method of allocating 47

63 Executive Summary Working Group on Power-11 th Plan ( ) coal blocks for power projects is not likely to pass on the efficiencies of captive coal mining to the consumers. 20. As long as there is shortage of natural gas and the two major users of gas fertilizer and power work in a regulated cost plus environment, price of domestic gas and its allocation should be independently regulated on cost plus basis including reasonable returns. 21. Like crude oil and coal, natural gas and LNG may also be included in the category of declared goods so that central sales tax of 4% is levied on them and exemption from any state sales tax is extended. 22. Import duty on coal has been lowered to 5%. This position needs to be continued as we would be depending on imported coal for generation. 23. Exemption of import duties available to generation projects under Mega Policy should be available to all important transmission projects where imported components form large part of the project cost. 24. Nuclear power stations are likely to be segregated from other strategic nuclear installations in future. In that case, tariff determination from nuclear power stations should be done through regulatory mechanism in a transparent manner adopting two part tariff structure and efficient operating norms. 25. There is a need to levy cess on the basis of consumptive use of water. This would encourage closed cooling system which is the need of the hour considering decreasing availability of water at project sites. 26. Service conditions of staff of the Regulatory Commissions and BEE should be made attractive. Such staff should be eligible for housing accommodation, medical facilities etc. on the lines of Government employees. 27. State Governments should be asked to establish the Regulatory Commission Funds at the earliest. This could be one of the follow up points while releasing central assistance to the States. 28. There is a need to put in place a mechanism for periodical training/ reorientation for staff of the Commissions and for newly appointed regulators. A corpus could be made available to the Forum of Regulators (FOR) for this purpose income from which could be used for the training programmes. The training programme and the training institutions should be settled by FOR after taking into account guidelines issued by the Central Government in this regard. 29. FOR has been entrusted with number of responsibilities in the Tariff Policy with a view to ensure consistency in the regulatory approach. For 48

64 Executive Summary Working Group on Power-11 th Plan ( ) discharging this role, the FOR would require consultancy for availing relevant expertise including international experience on various matters. Central Government should provide funds for this purpose. 30. FOR should also compile periodically various progressive orders of the SERCs for sharing the best practices. The compilation may also include important judgments of the Appellate Tribunal for Electricity. 31. To bring in appropriate accountability of the regulatory process, proposed regulations of the Regulatory Commissions should be examined indepth at draft stage itself. Further, there is a need for scrutinizing the regulations for ensuring consistency with the letter and spirit of the law before they are laid in the Parliament/ State Assembly. This is important since regulations, once published in the gazette, become sub-ordinate legislation. 32. FOR should also undertake periodical review of implementation of the National Electricity Policy and Tariff Policy since the law requires the Commissions to be guided by these policies. 33. High loss making feeders may be franchised by distribution companies. Towns having ATC losses higher than 35% may be franchised on input energy basis immediately. Towns having losses between 25-30% should be observed for improvement for 6 months and if there is no improvement, these towns should also be franchised. 34. Through appropriate metering and energy audit, feeders incurring high level of losses (may be more than 20% for urban feeders and more than 35% for rural feeders, this would depend on the stage in which distribution reforms are in a particular state) should be identified. Performance of the staff should be then assessed on the basis of Key Performance Indicators(KPI) which would be primarily loss reduction. ATC loss reduction of 3% every year in next five years should be targeted. The Tariff Policy emphasizes on the need of putting in place local area based incentive/disincentive scheme for the staff linked to distribution losses. This should be immediately implemented by the SERCs. 35. The robust legal framework contained in the Act for control of theft is being further strengthened. Annual conferences of power utilities should be organized at national level for highlighting success stories and achievement made in different States in controlling theft. 36. To enlist public support for rapid reduction of commercial losses, the list of high losses feeders should be publicized periodically. 37. To realize the objective of Tariff Policy of supplying uninterruptible electricity to those consumers who are ready to pay efficient cost, the distribution tariff should move to distribution margin model which is also provided in the Tariff Policy. Such distribution margin could be based on 49

65 Executive Summary Working Group on Power-11 th Plan ( ) loss reduction trajectory in a MYT framework and the actual power purchase costs should be paid by the consumers over and above the distribution margin. Consumers of a particular area should be given option to collectively choose either uninterruptible supply or otherwise and the tariff could be determined accordingly. 38. Setting up of peaking power stations should be encouraged to overcome peaking shortages as the additional power costs of supply from such a station could be then passed on to the consumers who opt for uninterruptible supply. 39. Use of electronic meters and spot billing should be expanded rapidly and State should be emphasized upon to do so. 40. FOR should develop a model agreement for distribution of electricity by distribution licensee through a franchisee in urban areas outlining the responsibilities and duties of various parties clearly. 41. There have been some experimental efforts, with good success, for outsourcing distribution of electricity for an identified feeder by the licensee to a private entrepreneur selected competitively. This model needs to be supported fully and replicated in high loss areas. 42. Necessary financial assistance may be provided to consumer groups having proven track record for facilitating effective representation before the Regulatory Commission. In addition, Central Government should also arrange orientation programmes to educate these groups about various provisions of the law and rules. Such scheme(s) should be administered by the Department of Consumer Affairs. 43. The Rural Policy provides that standalone systems of upto one MW would have automatic approval for a. Land use change for area as per norms b. Pollution clearance if technology is proven within laid down norms and c. Safety clearance on the basis of self certification. These policy measures need to be implemented by the concerned authorities at the earliest. 44. Schemes for separation of agricultural feeders in rural areas need to be promoted. Agricultural consumers could be supplied electricity as per seasonal demand for agricultural purpose and the tariff could be fixed taking into view off-peak pricing and uninterruptible supply. 50

66 Executive Summary Working Group on Power-11 th Plan ( ) 45. Schemes for transferring subsidies directly to consumers may be encouraged. 46. State Government should set up a dedicated planning cell for developing electricity plan at the State level including specific projects which could be posed for investment to the power sector. Such a plan could be on the lines of National Electricity Plan. 47. With the objective of promoting more efficient use of electricity and also to provide another payment option to the consumers, use of pre-paid meters needs to be promoted. 48. In order to assess the progress made in achieving higher energy efficiency, suitable mechanism should be put in place indicating the clear cut methodology for computing various parameters in this regard. 49. Statutory rules may provide for periodical refresher training for all the O&M personnel in different segments i.e. generation, transmission and distribution. In addition, refresher training may also be provided to all other personnel in power sector as per the requirement of their work areas. 50. A national programme needs to be launched for training and capacity building for upgrading and enhancing the skills of franchisee who are proposed to be deployed on a large scale for rural as well as urban areas. 9.0 ISSUES CONCERNING KEY INPUTS 9.1 FUEL Coal Requirement / Availability for 11 th Plan Coal Demand Supply Projection for Power Sector (11th Plan Period) (As Projected By CEA) DESCRIPTION Installed Capacity Additions Retirements Total Installed Capacity (MW) Normative Coal Reqmnt (Linkage) (Details are given in Table 9.7 of main Working Group Report) 51

67 Executive Summary Working Group on Power-11 th Plan For calculation of linked coal requirement for the above installed capacity, average 5 MTPA per 1000 MW of capacity, has been considered. This coal requirement projection does not include coal requirement for captive power plants (CPPs). However, all the units envisaged for capacity addition, as shown above yearwise, may not be in full commercial operation for the whole periods of those particular years, in which these units shall be commissioned. So, considering that aspect, the following generation level year-wise has been targeted by CEA and corresponding coal requirement are worked out as under. DESCRIPTION Total Generation (BU) (^) Total Coal Requirement (MT) including Transit Coal Availability - From CIL (MT) # From SCCL (MT) $ From Captive Mines Total Availability (MT) Gap between Supply & Demand (MT) (^) Generation is projected (as projected by CEA), assuming PLF of 76% in & and 77% in subsequent years existing units and 85% for new capacity additions, with due consideration of initial commissioning period for new units. # CIL s projection of Coal Production including their emergency production plan, considered here, is provided by Working Gr. member from CIL. Distribution of around 72% of CIL coal to Power Sector (except CPPs) considered here based on historical supply figures and as considered by CEA for their computation & analysis purpose. $ SCCL s projection of Coal Production, considered here, is provided by SCCL. Distribution of around 71% of SCCL coal to Power Sector (except CPPs) considered here based on historical supply figures and as considered by CEA for their computation & analysis purpose. (X) Coal Production from Captive Mines in the terminal year of 11 th. Plan, as projected by CEA. However, as per projections made in the Draft Report by the Working Group on Coal & Lignite, under the Chairmanship of Secretary (Coal), out of 127 captive blocks allotted so far, about 60 have already submitted mine plan to Coal Controller s organization, indicating production projection of about 104 MT by Remaining block-holders are also expected to submit mine plan shortly. Out of 104 MT of coal production, as projected, around MT will be available for Power Sector (Utilities) in However, achievement of this production level or even enhanced level from Captive Mining are possible subject to expeditious approval of Mining Plan, various notifications for Land Acquisitions, Environment Clearances & other clearances / approvals, as elaborated in this report, later on. 52

68 Executive Summary Working Group on Power-11 th Plan ( ) Capacity Addition in 11 th Plan vis-à-vis Coal Tie-Up (As projected by CEA) Description Capacity (MW) Normative Requirement (MT) Coal Linkage Available Block Allocated Imported Coal tied up 0 0 TOTAL AVAILABLE Linkage required to be accorded Block required to be Allocated $ Imported Coal to be tied up TOTAL TO BE TIED UP TOTAL COAL BASED CAPACITY ADDITION (MW) IN 11 th PLAN $ Projects totaling to 1750 MW have applied / applying for coal blocks, however, during 11 th. Plan it would require tapering coal linkages Gas scenario At present 2114 MW Gas Based Power Project have been included in the 11 th Plan against the target of MW by thermal capacity. The additional power could be planned / generated based on the following factors which would however largely influence the ultimate gas demand in the power sector. Assured supply of gas and its time frame Price of gas and stability for 15 years Expanding the scope of regulator for regulating the price of gas. 9.2 TRANSPORT Railways: Present Scenario Important modes of transport of coal in India are Railways, Road, Merry-go- Round Systems, Conveyor Belts and the Rail-cum-Sea Route. Railways constitute the major system of coal transportation in India and coal is the largest single commodity transported by the Railways. The dispatch of coal by rail is governed by the Preferential Traffic Schedule of the Indian Railways, under which the program of movement is to be sponsored by the various sponsoring authorities and accepted by the coal companies. In case of deregulated coal, Railways have allowed coal companies to sponsor the movement of coal. Coal requirement of some consumers in Southern India, which include power stations and cement plants, are met by moving coal by Rail-cum-Sea Route. This 53

69 Executive Summary Working Group on Power-11 th Plan ( ) is done in view of the difficulties experienced in moving coal via all Rail Routes from Bengal-Bihar and Main Line-Talcher Coalfields. The requirement of power stations of Tamil Nadu Electricity Board (TNEB) is met by Rail-cum-Sea Route. Haldia, Paradip and Vizag Ports handle the shipments. Some load center projects have been identified for expeditious implementation to meet the increased power requirements for the forthcoming Commonwealth Games-2010 to be held in Delhi. Such projects of NTPC are Badarpur Expansion (1000 MW), Dadri (Coal) Expansion (980 MW) and Jhajjar JV Project (1500 MW). At present 26 rake per day are being moved through over crowded Railways section between Mughalsarai & Delhi which caters to existing plants at Badarpur and Dadri (Coal). The number of rakes will increase to 34 rake / day when both of the expansion projects at Dadri and Badarpur are commissioned. Railways need to gear up to tackle this increased movement of coal in this section. In the case of proposed Jhajjar project to be implemented by NTPC in Joint Venture with Delhi and Haryana, Problem exists in transportation of coal beyond Mathura up to the plant i.e. the section from Mathura to Jharli (station nearest to Jhajjar: Total distance is 240 Kms.) is singlelined. Power project at Hissar in Haryana is also being implemented during the same time frame which will also be using the same Railways line. Considering the above and also considering the proposed requirements of the power stations in the adjoining region this section needs to be made double-lined. 9.3 PORT FACILITIES Ports: Present Scenario Ports form a critical part of transportation infrastructure of our country. India has about 6000 km. of natural peninsular coastline. There are 12 major and 185 minor ports in India. Major ports handle about 75% of the country s port traffic. Present capacity for coal in Indian Ports account for about 65 Million Tonnes (as on ) and it will be enhanced to about Million Tonnes by , as projected by National Maritime Policy on Port & Shipping Sector. 54

70 Executive Summary Working Group on Power-11 th Plan ( ) Present & Proposed Capacity Additions by Indian Ports (Commodity-wise) Commodity Existing Capacity as on Capacity requirement by (In Million Tonnes) Additional Capacity Estimated by POL Iron Ore Coal (including coking coal) Container Tonnage Container TEUs General Cargo TOTAL: CONSTRUCTION AND MANUFACTURING CAPABILITIES Manpower requirement for Hydro Projects (Supervisory Staff) Category Estimated requirement Available Augmentation required Senior level Executives Middle level Executives Junior level Executives Non executives Total Manpower requirement for Hydro Projects (Workers) Sl No Type of Worker Estimated requirement Available Augmentation required 01 Skilled Un skilled Total

71 Executive Summary Working Group on Power-11 th Plan ( ) Manpower requirement for Thermal Projects (Supervisory Staff) Category Estimated requirement Available Augmentation Required Senior Level Executive Middle Level Executive Junior Level Executive Supervisors/ Nonexecutive Total Manpower requirement for Thermal Projects (Workers) Category Estimated requirement Available Augmentation Required Mechanics Electricians Crane operators Drivers LP welders HP welders Aluminium welders Fitters Riggers Insulation applicators Cable jointers Carpenters Masons Bar benders Total Requirement of construction equipment Hydro Projects (Main Equipments) Main Equipment required to be procured during 11 th plan could be summarized as below: 56

72 Executive Summary Working Group on Power-11 th Plan ( ) Sl. No Particulars of equipment Estimated Requirement Available Augmentation Required 1 Hydraulic Drill Jumbos ( to 3 boom) 2 Hydraulic Excavators ( to 5.2 cum) 3 Loaders Dozers Dumpers (12T to 35 T) Road Rollers Raise Borer/Climber Concrete Batching plant (30 to 360 cum/hr) 9 Aggregate Processing Plant (50 to 600 TPH) 10 Tower Crane (6.5 to T) 11 Shutter with travellers Dry Shotcrete machines Wet Shotcrete machines Cranes (5 T to 60T) EOT/ Gantry Cranes (10T to 20T) Thermal Projects (Main Equipments) The major equipment required to be deployed for simultaneous construction of 24 projects of less than 500 MW and 21 projects of more than 500MW is summarized below. S.No. Particular of equipment Estimated Requirement Available Augmentation required 1) 325 T Fm Crane Or Equivalent ) Sumitomo crane or equivalent 150 t ) Crawler mounted crane 100 t ) Crawler mounted crane 75 t ) Mobile crane - 20 mt / 8 mt ) Mobile crane 40 mt ) Heavy duty trailer mt ) Dumpers ) Dozers ( heavy duty d-6 & d-8) (hydraulic) 10) Vibro compactors ) Concrete pump ) Truck mounted concrete pumps

73 Executive Summary Working Group on Power-11 th Plan ( ) S.No. Particular of equipment Estimated Requirement Available Augmentation required with placing boom 13) Transit mixer (min. 5 cum Capacity) 14) Batching plant (more than 30 cum. / hr. Capacity) 15) Rotaritory hydraulic piling rig ) Compressors ) DG sets ) Boring equipment for trench less construction 19) Welding machines ) Slip form equipment ) Strand and jack arrangement for boiler 22) ETDA cleaning arrangement for boiler 23) Passenger cum goods lifts for boiler ) Induction heating machines ) Gantry Crane ) Pock lain ) Tipper REQUIREMENT OF KEY INPUT MATERIALS Total requirement of various materials for Capacity Addition planned during 11 th & 12 th Plans Lakh Tonnes Material 11 th Plan 12 th Plan 68,869 MW 82,200MW Cement Structural Steel Reinforcement Steel CRGO Steel Castings Forgings for TG sets Special Steel for Sub-Stations Steel for Conductors in Transmission system Lines Steel for Conductors in distribution system Lines Aluminium

74 Executive Summary Working Group on Power-11 th Plan ( ) Material 11 th Plan 12 th Plan 68,869 MW 82,200MW Copper Zinc Thermal Insulation Static Meters with downloading facility (Nos.) 12.44Crores 4.96Crores 9.6 RECOMMENDATIONS Coal and Lignite Domestic coal would continue to be the main stay for thermal power generation in India. In order to make available the coal and lignite for power generation following are recommended: Coal Mining 1. Coal Sector may be given Infrastructure Status with Tax Holiday & Duty exemptions as at present the total duty incidence on mining equipment/spares is about % after including the countervailing and other additional duties. 2. Alternatively, the concept of Mega Project may be introduced in the coal sector also by according Mega Status to Coal Mines of production level of 5 MTPA or above and providing benefits of tax / duty concessions. 3. Deployment of state-of-the-art technology in the Indian mines for enhancing the productivity and exploitable quantity of coal needs to be encouraged by liberalization of import policy. 4. All coal blocks with firm Geological Report (GR) may be earmarked with no reservation / blocking. 5. Mobilization of the investment in coal mining requires inducting and encouraging more players from both public and private sectors. 6. Reputed International Coal Companies may be encouraged to come to India which will facilitate introduction of latest mining technologies and mine safety measures. 7. There is an urgent need to encourage more exploratory agencies and for relaxation of mandatory supervision by CMPDIL alone. 8. The pace of regional surveys and drilling needs to be accelerated to complete the comprehensive coal resource assessment exercise at the earliest. 9. The list of agencies authorized to supervise may be expanded and the Govt. agencies which are otherwise permitted to under take exploration without seeking project specific exploration license could also be authorized to supervise the exploration by other players. Further, new Public Sector agencies including their joint venture such as JV of NTPC & 59

75 Executive Summary Working Group on Power-11 th Plan ( ) SCCL may also be entrusted with the task of new exploration and accorded exemption from obtaining exploration license. 10. Expeditious environmental clearance needs to be accorded by MOEF on priority for 11 th Plan coal mining projects. 11. Formulation of unified R&R policy and simplification of issuance of notification and clearances shall help in expeditious development of coal mining projects. 12. In case of more than one nearby coal mine projects, centralized/ combined forestation at a suitable location needs to be accepted Lignite 1. At present only a small percentage of the total reserves of lignite have been exploited. This needs to be enhanced to make use of this proven source of energy. Allocation of Lignite blocks to interested developers could facilitate faster growth of Lignite Production. If generation target is enhanced to around 80% PLF, there will likely be shortfall in tune of 2 MTPA Railways 1. Railways need to expedite sectoral studies, development of suitable plans and ensure adequate rail network for coal movement. Dedicated trunkroutes for coal transport to the power project need to be developed. Interim measures to be taken if dedicated freight corridor does not come up in 11 th Plan period. 2. Development of new rail links is required to be expedited along with the Railways connectivity with Ports. 3. Timely establishment of rail links with allotted coal mining blocks. 4. Rail freight rates for coal transport may be rationalized. 5. The Railways, Coal and Power Ministry may work together to draw up a well conceived model of Fuel Supply & Transport Agreement (FSTA) Ports 1. Port capacity needs to be augmented to meet the increased infrastructure requirement. 2. To expeditiously complete the existing projects like captive coal jetty at New Mangalore Port, Coal Berth at Ennore port, Deepening Channel at Paradeep port. 3. The major ports of the country may be developed as mega ports with satellite ports dedicated to cargo like coal. 4. Port connectivity through seamless hinterland road and rail development needs to be enhanced to meet the requirement of imported coal. 60

76 Executive Summary Working Group on Power-11 th Plan ( ) Natural Gas Natural gas is the fastest growing primary energy source amongst fossil fuel. Gas supply to the existing gas based power stations has been inadequate and the plants have been operating at around 58-60% PLF. The gas based stations comparatively have shorter gestation period and are easier to operate. Following are recommended in this regard: 1. The Government Quota of Gas from fields allotted / to be allotted under NELP as per the respective Production Sharing Agreement should first be utilized to meet the shortfall in supply from the linkage of existing customers before allocation to others 2. There is need to ensure that assets like Gas Based Power Plants which have been set up with substantial investment are not stranded / idle or inadequately utilized on account of constraints of Gas / Infrastructure availability and should get priority over new units. Therefore, while granting Open Access for transportation of gas to sectoral players, preference should be given to existing customers of gas. 3. Planning Commission, Govt. of India should facilitate the allocation of gas to new gas based projects as well as in setting the reasonable pricing of gas for power generation Key Input Materials With a view to help industries to plan/ allocate build up their capacities over a longer time frame, assessment of material requirement for 11 th and for 12 th Plan period on a broad basis have been made and on prima facie considerations, availability of various materials required for capacity addition planned for 11 th & 12 th Plan may not be a constraint unless requirements get bunched up in any particular year. Following are recommended in this regard: 1. CRGO being the critical input for transformers and imported item, needs to be exempt from Customs Duty to bring down the cost of transformers. This is particularly important in view of the massive distribution system augmentation planned in the 11 th plan. 2. Simultaneously. Domestic producers may be encouraged for production of CRGO as in the past non-availability of CRGO has led to delay in project implementation. 3. Detailed analysis of the key materials availability for power sector needs to be done by Planning Commission considering requirement of other sectors of the economy. 4. The number of static meters required for 11 th Plan is of the order of crores. The manufacturers of static meters need to be geared up to meet such huge requirements. 61

77 Executive Summary Working Group on Power-11 th Plan ( ) Capability for manufacture of main plant equipment by indigenous manufacturers, m/s BHEL for coal based power plants Sl No. 1. M/s BHEL is the only major manufacturer of main power plant equipment for thermal and hydro power projects in India. In the 10 th Plan, the main plant equipments for 65% of the thermal capacity addition, are being supplied by BHEL. In the year BHEL received major orders totalling to 5125 MW to be commissioned by Some of the units out of this capacity are found to be slipping from 10 th Plan target. This matter was taken up with BHEL and a study was carried out by CEA for the reasons leading to the delay. It has been found that it was mainly due to inadequate manufacturing capacities of its various manufacturing units, delay in finalization of orders for Balance of Plant (BoP) for EPC contracts and shortage of construction /commissioning machinery, and manpower. With the present capacity existing in BHEL manufacturing plants, BHEL can deliver equipment only up to 3000 MW per year for coal based projects. This was taken up with BHEL and they are proposing to increase this capacity to 4675 MW by Dec and further to 6475 MW by the year for coal based power projects. Similarly the manufacturing capacity for Hydro projects would also need augmentation to cater to the increased requirements for 11 th & 12 th plan. 2. Based on the capacity additions planned for coal fired thermal power projects, the following position emerges: Year of Commissioning/ Details i) BHEL s Capabilities (MW) ii) (a) Orders received by BHEL/ likely orders (MW) Grand Total (likely)* 6475 (likely) (b) Orders by other manufacturer (MW) Total (MW) * assuming that the full capacity of BHEL would be utilised 1. From the above it is evident that BHEL would be finding it difficult to meet the commissioning targets for the year Further, for the years and , equipment for huge capacity has to be supplied by other manufacturers to meet the capacity addition targets. 2. Accordingly, it is informed that the country needs to develop additional manufacturers of main plant equipment to meet the projected capacity addition targets and also to induce competition 62

78 Executive Summary Working Group on Power-11 th Plan ( ) in the market for achieving a lower price/tariff. This has also been emphasised by the Honble Minister of Power in the past, while finalising the capacity addition programs. BHEL needs a substantial expansion in the manufacturing capacity for thermal and Hydro plants Construction Capability Capability of construction agencies, availability of construction equipment, appropriate construction technology and manpower are vital for implementation of the capacity addition programme. Construction industry in India has grown significantly and has acquired adequate experience in the field of construction and infrastructure projects. Following are recommended in this regard: 1. Construction agencies are available in India (Domestic as well as International) for taking up hydro as well as thermal power projects in 11 th Five Year Plan. Augmentation of manpower and construction equipment would be required by the construction agencies to meet the targets. 2. Serious efforts need to be made by the major power companies to develop vendors for supply and erection of equipment and for taking up civil construction. 3. Power Projects should be granted infrastructure status for qualifying for exemption of taxes and duties. 4. Government should consider taking up construction of approach road to feasible project sites through a common fund to be recovered from the developers subsequently. 5. Single window clearance should be encouraged with time frame for all the statutory clearances required by the developers. 6. Immediate action need to be taken to create at least 10 Accredited Training Institutions at different geographical locations for skill building in specific areas like HP Welder, Aluminum Welders, Crane Operators, Cable Jointer etc. vocational training wing of Ministry of Education, NICMAR and CIDC could play the part of nodal agencies for such institutions. 7. Cooperation of State Govt. must be ensured to facilitate smooth land acquisition and implementation of R&R Plan. 8. New technologies like RCC Dam, jet grouting and use of Geotextile/ geosynthetics in place of filter materials should be adopted in Hydro Projects. 9. Use of latest construction equipment like Tunnel Boring Machine (TBM), Road Headers, Raise Borers, Forepoling machines, Jet grouting Equipment, Hydro fraise equipment etc should be encouraged to achieve fast progress. 10. Low bed wagons for transportation of transformers/generators/stator/boiler drum need to be augmented at least by 14 Nos. 63

79 Executive Summary Working Group on Power-11 th Plan ( ) Integrated Energy Policy Integrated Energy Policy Report of the Expert Group under the Chairmanship of Shri Kirit S. Parikh, Member, Planning Commission, Govt. of India has addressed wide ranging issues and has suggested policy initiatives to provide energy availability and security for sustainable economic development. A few of the important issues delineated in the policy and impacting the power sector needs to be implemented. Following are recommended in this regard: 1. Standardization of Main Plant equipment in bands of different unit sizes is desirable particularly from the point of view of faster capacity addition; however there is a need for an Empowered Committee for centralized procurement and to bench mark the price for different unit sizes. 2. The rate of return on the investment in power sector has to be adequate to attract investment and to compete with the opportunities of investment in other sectors. 3. To ensure capacity addition through tariff based completive bidding there is a need to create an enabling framework by both State and Central governments in the areas of allocation of site, water & fuel linkage, environmental clearance, R&R etc. 4. Coal price for supply of coal under long term agreement should not be linked with e-auction coal price as it will only push up the coal price. Further, linking of coal price with the imported coal price would also not be appropriate. There is an urgent need of Regulator in Coal Sector. 5. The captive coal mining blocks should be fully explored with ready Geological Report (GR), so as start the production from captive coal blocks in a timely manner. 6. Opening up of coal sector to promote competition. 7. Allocation of coal mining blocks for generation sector based on least cost generation. 8. Open access to the Gas network should be ensured to promote competition in gas sourcing. Role of Regulator in Oil & Gas sector needs to be expanded to include gas pricing. 64

80 Executive Summary Working Group on Power-11 th Plan ( ) 10.0 FINANCIAL ISSUES AND POWER SECTOR FINANCING 10.1 During 11 th Plan period, the overall generation capacity addition of 68,869 MW is envisaged. (Refer Para of main Working Group Report) (MW) SECTOR HYDRO THERMAL NUCLEAR TOTAL Projects Under Construction 11,931 16,254 3,160 31,345 Committed Projects 3,654 33, ,524 Total capacity 15,585 50,124 3,160 68, The overall requirement of funds in 11 th Plan has been estimated as Rs. 1,031,600 crore with details as follows: (Refer Para 10.9 main Working Group Report) ( Rs. Crore) Particulars State Central Private Total Generation including Nuclear 1,23,792 2,02,067 85,037 4,10,896 DDG 20,000 20,000 R & M 15,875 15,875 Transmission 65,000 75,000 1,40,000 Distribution including Rural electrification 2,87,000 2,87,000 HRD R&D Outlay 1,214 1,214 DSM Total Power Sector 4,91,667 2,99,396 85,037 8,76,100 NCES and Captive 22,500 93,000 1,15,500 Merchant Plants 40,000 40,000 Total Funds Requirement 5,14,167 2,99,396 2,18,037 10,31,600 Year wise Funding Requirement for 11 th Plan (Rs. Crore) Total 1,32,264 1,74,003 2,24,754 2,52,707 2,47,872 10,31, The details of major sources and estimated mobilization, funding gap and possible sources of bridging the gap is given below in following Tables (Refer Para of main Working Group Report) 65

81 Executive Summary Working Group on Power-11 th Plan ( ) (Rs. Crore) Description State Central Private Total Funds required 5,14,167 2,99,396 2,18,037 10,31,600 A) Equity Required (D/E - 70:30) 1,54,250 89,819 65,411 3,09,480 B) Equity Available 1 -Promoters including FDI for IPPs ,511 25,511 -Promoters including FDI for NCES & Captive ,900 27,900 -Merchant Power Plant 12,000 12,000 2 Internal Resources 0 62, ,922 3 Govt. Support 3.1 State Govt Central Govt C) Total Equity Available 0 62,922 65,411 1,28,333 D) Additional Equity to be arranged (A-C) 1,54,250 26, ,81,147 E) Debt Required (D/E - 70:30) 3,59,917 2,09,577 1,52,626 7,22,120 F) Debt Available 1.1 Direct Market Borrowing 10,000 15, , Banks and AIFIs 37,173 58,415 10, , PFC 64,960 8,120 8,120 81, REC 47,320 5,915 5,915 59, IIFCL 0 6,000 9,000 15, Multilateral/Bilateral Credits 5,520 19,320 2,760 27, ECA/ECB/Syndicated Loan etc. 0 46,000 11,500 57,500 G) Total Debt Available 1,64,973 1,58,770 47,916 3,71,660 H) Additional Debt to be arranged (E-G) 1,94,943 50,807 1,04,710 3,50,460 I) Additional Equity & Debt required (D+H) 3,49,193 77,704 1,04,710 5,31,607 J) Total Availablity of Debt and Equity 1,64,973 2,21,692 1,13,327 4,99,993 K) Funding by Special Schemes 1 APDRP 40, ,000 2 RGGVY 40, ,000 L) Total shortfall to be arranged (I-K) 2,69,193 77,704 1,04,710 4,51,607 66

82 Executive Summary Working Group on Power-11 th Plan ( ) Description Summary of Funds Requirement and Mobilization for Different Debt: Equity Scenario D/E 70:30 ( Rs. Crore) D/E 80:20 Funds required 10,31,600 10,31,600 Equity Required 3,09,480 2,06,320 Total Equity Available 1,28,333 1,28,333 Additional Equity to be arranged 1,81,147 77,987 Debt Required 7,22,120 8,25,280 Total Debt Available 3,71,660 3,71,660 Additional Debt to be arranged 3,50,460 4,53,620 Additional Equity & Debt required 5,31,607 5,31,607 Less: Funding by Special Schemes 80,000 80,000 Total shortfall to be arranged 4,51,607 4,51,607 Equity required after funding from special schemes 1,21,147 17,987 Debt required after funding from special Schemes 3,30,460 4,33, PROPOSED MEASURES FOR REDUCING FUNDING GAP 1. Modification of ECBs guidelines permitting infrastructure borrowers including intermediaries PFC, REC, IDFC etc to borrow funds from overseas market under automatic approval route and Debt Servicing to be eligible for exemption under Section 10 (15) (iv) of Income Tax Act. (Refer Para of main Working Group Report) 2. Introduce Power Bonds or Vidyut Vikas Patra, as transferable bearer instrument for wider retail participation (Refer Para of main Working Group Report) 3. Additional investment limit of Rs. 50,000 per year for infrastructure bonds under Section 80C of the Income Tax Act, 1961 over and above existing limit of Rs. 1,00,000 with a lock in period of at least 5 years. Expected mobilization over 5 years is estimated at Rs. 1,50,000 crore. (Refer Para of main Working Group Report) 4. Long term Capital Gains Bonds: Allow Section 54EC benefit under Income Tax Act for bond issuances by PFC & IIFCL in line with REC & NHAI. (Refer Para of main Working Group Report) 5. Possible Sources of Bridging the Gap 67

83 Executive Summary Working Group on Power-11 th Plan ( ) (Rs. Crore) S. No. Particulars Estimated Amount Debt 1 Power Bonds 50,000 2 Tax incentive under Section 80 C 1,50,000 3 Bonds under Section 54EC 50,000 4 Insurance 20,000 Sub Total 2,70,000 Equity 5 IPO/FPO 15,000 Grand Total 2,85,000 Net Gap 1,66, Reinstatement of 10(23) G benefit (tax exemption on interest income from infrastructure projects) to be reintroduced. (Refer Para of main Working Group Report) 7. 5% of PF, Gratuity, Pension and Insurance funds must be regulated for investments in Power Bonds. (Refer Para of main Working Group Report) 10.5 FISCAL AND OTHER MEASURES TO ENABLE CHEAPER POWER: (REFER PARA ) 1. Excise Duty/ CVD on power Generation, Transmission & Distribution equipment (which is currently at 16%) should be abolished for Projects with 1,000 MW dispatch on the lines of concession provided to the Mega Power project. 2. Existing Income Tax exemption for Power Sector projects under section 80IA expiring in March 2010 to be extended till March Additional depreciation of 20% (WDV) under IT Act available for investments in plant and machinery in industries other than power to be made available to power industry also MAJOR RECOMMENDATIONS & POLICY MEASURES 1. IPO by Power companies: Profit making Central/ State Utilities in generation, transmission & distribution to be encouraged for supply of PSUs stock in the market by way of IPOs/ FPOs (Follow-on Public Offer)/ Offer for sale. (Refer Para of main Working Group Report) 2. Public Private Participation models: PPP on the lines of UMPP where Govt. undertakes to get the various clearances before the bidding 68

84 Executive Summary Working Group on Power-11 th Plan ( ) facilitates quicker financial closure. (Refer Para of main Working Group Report) 3. Relaxation in Companies (Issue of Share Capital with Differential Voting Rights) Rules, 2001, for issuing Equity Shares with Differential Voting Rights: Waive requirement of having distributable profit for three financial years. (Refer Para of main Working Group Report) 4. Equity support by State Governments through Budget Allocation: State Government should allocate funds through its budget for providing equity support to State Utilities in Power Sector (Refer Para of main Working Group Report) 5. Specialized debt funds for infrastructure financing (Refer Para of main Working Group Report) 6. Development of a Venture Capital / PE fund to invest in equity of power projects. (Refer Para of main Working Group Report) 7. Development of Primary Markets for Bonds and Corporate Debt by enhancing issuer base and investor base (Refer Para of main Working Group Report) 8. Development of Hydro Power Viability Fund which finances the deferred component of the power tariff of the first five years and recovers its money during 11th to 15th year of the operation. (Refer Para of main Working Group Report) 9. Viability Gap Fund (for Remote areas) which finances the deferred component of the power tariff of the first five years and recovers its money during 11th to 15th year of the operation. (Refer Para of main Working Group Report) ********** 69

85 Demand for Power and Generation Planning Chapter 1 DEMAND FOR POWER AND GENERATION PLANNING 1.0 TENTH PLAN REVIEW The total installed capacity at the beginning of the 10th Plan i.e was 1,05,046 MW comprising 26,269 MW hydro, 74,429 MW thermal (including gas and diesel), 2,720 MW nuclear and 1,628 MW wind-based power plants. The region-wise details of installed capacity as on are given in Table 1.1 Table 1.1 Summary of Installed Capacity at the Beginning of 10th Plan ( ) (Figures in MW) Thermal Renewable Sector Hydro Nuclear Energy Total Coal Gas Diesel Total Sources State 22,639 36,722 2, , ,642 Private 581 3,991 4, , ,567 10,799 Central 3,049 21,418 4, ,837 2, ,605 ALL INDIA 26,269 62,131 11,163 1,135 74,429 2,720 1,628 1,05,046 At the beginning of 10th Plan the country was facing peak shortages of 12.6% and energy shortage of 7.5%, with lowest of 3.7% in Eastern Region and highest at 16.9% in Western Region in terms of peak and 1% to 10.4% in terms of Energy. 1.1 TARGET CAPACITY ADDITION DURING TENTH PLAN Taking into account the preparedness of the projects and resources available, a feasible capacity addition target of 41,110 MW comprising 14,393 MW hydro, 25,417 MW thermal and 1,300 MW nuclear was fixed for the 10th Plan as detailed below. Table th Plan Capacity Addition Target-Sector Wise (Figures in MW) SECTOR Hydro Thermal Nuclear Total CENTRAL 8,742 12,790 1,300 22,832 STATE 4,481 6, ,157 PRIVATE 1,170 5, ,121 TOTAL 14,393 25,417 1,300 41,110 Page 1 of Chapter 1

86 Demand for Power and Generation Planning 10th PLAN CAPACITY ADDITION TARGET (41,110 MW) - BY SECTORS PRIVATE SCTOR 17% 7,121 MW STATE SECTOR 27% 11,157 MW 22,832 MW CENTRAL SECTOR 56% Region wise/ Status wise Summary of this capacity addition target is furnished in Appendix STRATEGY FOR ACHIEVING 10TH PLAN TARGET The capacity addition achieved during the 9th Five Year Plan was below 20,000 MW and the best performance during any plan in the past was 21,400 MW added during the 7th plan period. The goal of capacity addition of 41,110 MW during 10th Plan was a great challenge to the central, state and private sector generating companies. MOP and CEA formulated a strategy for achieving the planned target of capacity addition during the 10th Plan by carrying out rigorous monitoring of the progress of construction of the projects. The efforts of CEA and MOP have yielded good results. Critical projects not making satisfactory progress have been identified and focused efforts have been made to remove constraints in their implementation. However, in spite of best efforts by project authorities, CEA and MOP, a few projects in hydro and thermal are still likely to slip from the 10th Plan. At the same time, action has also been taken to add new additional capacity which was initially not included in the target for the 10th plan. This was done to supplement the effort as some of the plants included in the target were likely to slip. 1.3 ACTUAL CAPACITY ADDITION AND POWER SUPPLY POSITION DURING 10TH PLAN (TILL DATE) Actual Capacity Addition A capacity addition of 17,995 MW has been achieved during 10th Plan till Yearwise details of the target and actual capacity addition during 10th Plan up to is given in Table 1.3 Page 2 of Chapter1

87 Demand for Power and Generation Planning Table 1.3 Year wise Capacity Addition During 10th Plan up to ( All India) (Figures in MW) Year (MW) Type Target Actual Achievements Hydro *** Thermal ,223 Coal Lignite Gas Oil Nuclear 0 0 Total 4,109 2,872 Hydro 3,765 2,590 Thermal 1,437 1,362 Coal Lignite Gas Oil 23 0 Nuclear 0 50* Total 5, Hydro 2,585 1,015 Thermal 2,661 2,934 Coal Lignite Gas Oil Nuclear 0 0 Total 5,246 3,949 Hydro Thermal Coal Lignite Gas Diesel 0 0 Nuclear ** Total Hydro Thermal (Coal, Lig, Up to 31st Gas & Diesel) December, 2006 Nuclear Total Grand Total (Up to 31st December 2006) * and **Additional capacity 50 MW each due to uprating of MAPS-1 &2 (Nuclear) ***- Includes projects of 12 MW capacity not included in the target viz. Potteru (6 MW) & Likimiro (8 MW). Page 3 of Chapter 1

88 Demand for Power and Generation Planning The Year-wise details of projects already commissioned during 10th Plan are given in Appendix Installed Capacity as on The total Installed Capacity as on was 1,27,753 MW comprising 33,642 MW hydro, 84,020 MW thermal including gas & diesel, 3,900 MW nuclear based power plants and 6,190 MW from renewable energy sources including wind. The sector wise details of installed capacity is given in Table 1.4 Table 1.4 Summary of Installed Capacity as on (Figures in MW) Sector Hydro Thermal Coal Lig Gas$ Oil Total Nucl. Total CENTRAL 6,672 24,020 2,490 5, ,409 3, ,981 STATE 25,664 37, ,500 1,239 42, ,568 70,821 PRIVATE 1,306 2, ,183 1,507 9, ,523 13,951 TOTAL 33,642* 64,237** 3,455 13,582 2,746 84,020 3,900 6,191 1,27,753 Source: DMLF Division, R.E.S. = Renewable Energy Sources includes Small Hydro Project(SHP), Biomass Gas (BG), Biomass Power (BP) Urban and Industrial waste power (U&I) & Wind Energy * Includes ROR- 15,143 MW, PSS- 664 MW, Storage- 17,835 MW ** 21,759 MW Pithead & 42,478 MW Load Center/ Non Pit Head $ Includes Liquid Fuel based Kayamkulam Project-350 MW 1544 MW Dual firing stations included in oil Power supply position in 10th plan The year-wise actual power supply position during , , , and (till Dec-06) of 10th plan is given in Table 1.5 Table 1.5 Actual Power Supply Position ( All India Basis ) Year Peak Energy Requirement Availability Surplus (+)/Shortage Shortage/ Surplus Requirem ent (MU) Availability (MU) (MW) (MW) (-) % Surplus (+)/Shortage (-) (MU) (MW) ,492 71,547-9, ,45,983 4,97,690-48, ,574 75,066-9, ,59,264 5,19,398-39, ,906 77,652-10, ,91,373 5,48,115-43, ,255 81,792-11, ,31,757 5,78,819-52, April Dec ,00,466 86,425-14, ,10,223 4,65,149-45, Shortage /Surplus % Page 4 of Chapter1

89 Demand for Power and Generation Planning 1.4 ACTUAL/ LIKELY CAPACITY ADDITION DURING TENTH PLAN A capacity of 17,995 MW has been commissioned till date( ) during the 10th Plan and a capacity of 12,646 MW is expected to be commissioned during the balance period (Jan.07-March07) of 10th Plan. Year wise capacity addition is given in Table 1.6. Table 1.6 Year wise Capacity Addition During 10th Plan (All India Basis) (Figures in MW) Type * * * * @ Total Hydro 635 2,590 1,015 1,340 3,274 8,854 Thermal 2,223 1,362 2,934 1,588 12,280 20,387 Nuclear ,400 Total 2,858 4,002 3,949 3,518 16,314 30,641 likely, (Excluding wind & Res.) The target set for capacity addition during the 10th Plan was 41,110 MW. Even though stringent monitoring of projects has been done, the likely capacity addition during 10th Plan has been assessed to be about 30,641 MW out of which about 17,995MW has already been commissioned as on The details of projects included in original 10 th plan target and their present status are given in Appendix 1.3 As per latest indication, out of 30,641 MW a capacity of 5,727 MW may further slip to 11 th Plan because of various reasons including delay in supply and execution by BHEL. Any slippage of the projects from 10 th plan would be reckoned as additional capacity in 11 th plan over and above being proposed in this document. The details of 5,727 MW capacity expected to slip to 11 th Plan is given in Appendix 1.4. During the first year of 10 th plan itself it became clear that a number of projects totalling to 3,009 MW in public and private sectors could not be taken up due to various reasons which included non availability of escrow cover by State Government to IPP projects and fund constraints. Certain projects totalling to a capacity of 12,516 MW comprising 7,458 MW thermal and 5,058 MW hydro as included in the 10th Plan target of 41,110 MW are slipping to 11th Plan. Further 5,056 MW capacity additional projects comprising of 4,956 MW thermal and 100 MW nuclear (uprating) originally not included in the 10th Plan target have been additionally identified for benefits during 10th Plan by expediting the process of project implementation and compression of the construction schedule to make up for the projects which could not take off. This has been possible through extraordinary efforts made by CEA & Ministry of Power in pursuing the developers and other Stake holders A summary of the slippages and additional projects identified is given in Table 1.7. Page 5 of Chapter 1

90 Demand for Power and Generation Planning Table 1.7 Summary of Likely Capacity Addition during 10th Plan (Figures in MW) Thermal Hydro Nuclear Total Original programme 25,417 14,393 1,300 41,110 Dropped 2, (-)3,009 Capacity slipping to 11th plan 7,458 5,058 0 (-)1,25,16 Back up capacity likely to be 4, ,056 added Total 20,387 8,854 1,400 30,641** **This includes a capacity of 2578 MW which were the best efforts projects. This also includes a further capacity of 2445 MW which would need extra ordinary efforts for completion during 10 th plan mainly due to constraints on the side of BHEL. 1.5 LIKELY INSTALLED CAPACITY AT THE END OF 10TH PLAN I.E. AS ON The likely Installed Capacity at the end of 10th Plan i.e. as on is 1,40,571 MW comprising 35,600 MW hydro, 94,660 MW thermal including gas & diesel, 4,121 MW nuclear based power plants and 6,191 MW from renewable energy sources including wind. The sector wise details of this is given in Table 1.8. Table 1.8 Summary of Likely Installed Capacity as on (Figures in MW) Sector Hydro Thermal Nucl. Wind/RES Total Coal Lignite Gas Oil Total CENTRAL 75,62 27,728 2,490 4, ,637 4, ,319 STATE 26,745 41, ,760 1,239 47, ,568 76,607 PRIVATE 1,293 3, ,641 1,507 12, ,623 17,645 TOTAL 35,600 72,440 3,655 15,820 2,746 94,660 4,120 6,191 1,40, Analysis of reasons for 10th plan slippages The causes for slippages and delays in implementation of 10th plan power projects is discussed below: It has emerged that out of 41,110 MW capacity addition target during 10th plan over 12,500 MW was not feasible within 10th Plan because of inadequate preparedness. Some of the major groups in this category are as follows: (a) About 3960 MW (660 MW unit size ) projects of NTPC based on super critical technology were not found feasible to be commissioned during 10th plan as originally, NTPC was of the view that indigenous manufacturer BHEL would tie up collaboration agreement and participate in tender for development of these projects, which BHEL had not done even till middle of Page 6 of Chapter1

91 Demand for Power and Generation Planning (b) 10th plan target included over 3,300 MW hydro projects in case of which preparedness in terms of crucial inputs like Techno-economic clearance, PIB, Environmental clearances, etc were not in place. (c) In case of private sector projects, the reasons of slippages are due to escrow cover not being given by State Government and financial closure not achieved by the developers. Such projects add up to 900 MW. (d) In case of thermal projects under execution during 10th Plan, the main reason of slippage is delay in placement of main plant order by the utilities. The other reason of delay is non-sequential supply of material by the manufacturers. (e) Some of the Hydro projects slipped from original 10th Plan mainly due to delay in award of works, delay in investment decisions, forest clearance. Some of the Hydro projects in state sector are delayed due to funds constraints as well. (f) Two gas based project of NTPC namely Kawas and Gandhar were also included as additional projects but are not likely to take off on account of bleak gas availability scenario. Table 1.9 indicates the major reasons of slippage and the capacity slipped due to each of these reasons: Table-1.9 Sl. Major Reasons of slippage Capacity slipped (MW) No Thermal Hydro 1. Delay in super critical technology tie up 3,960 - by BHEL 2. Geological Surprises Natural Calamity Delay in award of works Delay in MoE&F clearance Delay in clearance/ Investment decision / 1,500 1,400 Funds tie up constraints/delay in financial closure 7. Delay in Preparation of DPR & sign up of MOU between HP&SJVNL 8. ESCROW cover (Private Sector) R&R issues Court Cases Law & Order problem 500 Total 7,458* 5,058* * This does not include 3009 MW projects dropped from 10 th Plan It is pertinent to point out that a number of projects of 10 th plan ordered on BHEL were delayed due to delayed and non-sequential supply of equipment and materials and inadequate manpower in commissioning teams. Some of the projects expected to be commissioned during the last quarter of are also running behind schedule due to the above reasons. Page 7 of Chapter 1

92 Demand for Power and Generation Planning An analysis was carried out of the projects slipping from 10th Plan. Detail of the thermal and hydro projects which are expected to slip from the original target are given in the following Appendices: Appendix-1.5 List of projects dropped from original 10 th Plan target (41,110 MW). Appendix -1.6 List of the thermal projects slipping from 10 th plan target (41,110 mw) Appendix -1.7 List of the hydro projects slipping from 10 th plan target (41110 mw) 1.6 DEMAND FOR POWER Growth in Generation During 10 th Plan The growth in generation has been 3.2%, 5.1%, 5.2% and 5.2% during , 03-04, and respectively. In the year (upto Dec-2006) a growth rate of 7.5 % has been recorded. The Compounded Annual Growth Rate(CAGR)of generation during the 10 th Plan period is expected to be about 5.1%. However, higher growth could have been achieved if adequate gas would have been available for the existing and new gas based plants commissioned during 10 th plan Growth in Generation During 11 th Plan Assessment of generation requirement during the 11 th Plan is important to work out the generation capacity requirement to be planned for the 11 th Plan. Demand projections of various utilities are done by the Electric Power Survey (EPS) Committee. The last power demand projections were made by 16 th EPS in 2000 and the 17 th EPS Report is under finalization by the Committee. Besides the EPS, Integrated Energy Policy stipulates generation to grow at 9% p.a. during 11 th Plan. Also, as per National Electricity Policy (NEP), the per capita electricity consumption is to increase to 1000 units by the year The Working Group has assessed the generation requirement according to the above Committee Report/ Policies. Since the requirement worked out to meet the objectives of National Electricity Policy is higher, the same has been adopted for planning purposes. Details of the above three assessments are given below:- (i) 16 th EPS Report The energy requirement by Utilities in is 975 BU at the busbar. Considering about 6.5% - 7% auxiliary consumption, the gross energy requirement is about 1040 BU. (ii) Integrated Energy Policy (IEP) As per the Integrated Energy Policy (IEP), issued by the Planning Commission, GDP growth rates of 8%-9% have been projected during the 11 th Plan. Assuming a higher growth rate of 9% and assuming the higher elasticity projected by the IEP of around 1.0, electrical energy generation would be required to grow at 9% p.a. during the 11 th plan period. Also generation has to be collectively met by utilities, captive plants and Nonconventional energy sources. No reliable plans about captive power capacity expansion are available but based on indications available from the manufacturers for addition in Page 8 of Chapter1

93 Demand for Power and Generation Planning captive capacity and present utilization of available capacity, the generation from captive plants is expected to increase from 78 BU to 131 BU per annum. Since the load factor of non-conventional energy sources is very low (about 20% on an average), even though the capacity projected by MNRE from these sources is about 23,500 MW by the end of 11 th Plan, the expected generation would be only around 41 BU. The generation from these renewables however has not been taken into account for planning purposes. Based on these assumptions following scenario emerges: (i) Likely energy Generation by utilities in BU (ii) Likely Energy Generation by captive plants in BU (iii) Total Likely Generation in BU (iv) Compounded Annual Growth Rate 9% (v) Required Energy Generation by 9% growth rate 1140 BU over 741 BU (vi) Less Estimated Energy Generation by captive plants in BU (vii) Total Estimated Generation Requirement from Utilities by BU (iii) National Electricity Policy (NEP) (i) Likely Population by (Census 2001) 121 Crores (ii) Generation Required if Per Capita Consumption is to be 1000 kwh/yr 1210 BU (iii) Likely Generation from Captive Plants in BU (iv) Likely Generation from Renewable Plants in BU (v) Requirement of Generation from Utilities (ii-iii-iv) 1038 BU Requirement of Generation from Utilities by from various methods has been summarized as below:- 16 th EPS Report About 1040 BU Integrated Energy Policy Report 1008 BU National Electricity Policy 1038 BU The requirement of generation as per 16 th EPS & National Electricity Policy(NEP) are more or less same and greater than the requirement as per Integrated Energy Policy. Since the NEP is the guiding document for the power sector, requirement of generation (from utilities) for planning purpose adopted is 1038 BU. This would require a generation growth rate of 9.5 % p.a. (CAGR) for utilities. The 16 th EPS report stipulates peak demand of 1,57,000 MW by and 1,51,000 MW considering interregional diversity. This has been considered while assessing the 11 th Plan capacity addition Growth in generation During 12 th Plan During the 12 th Plan period, assuming a GDP growth rate of 9% per annum and elasticity 0.8 as compared to 1.0 during 11 th Plan mainly due to adoption of energy efficient technologies & other Energy Conservation and Demand Side Management measures being taken up during 11 th Plan, electricity demand is likely to 7.2% p.a. Keeping Page 9 of Chapter 1

94 Demand for Power and Generation Planning this in view, the energy generation should increase to a level of 1470 BU by from a level of 1038 BU in However sensitivity analysis have been carried out assuming 8,9 & 10 % GDP growth rates & GDP-electricity elasticity of 0.9 & 0.8 respectively and the same is given in table below: Table 1.10 Generation Requirement for ( As Per 8,9,10 % GDP Growth) GDP Growth 8 % 9 % 10 % GDP/ Electricity Elasticity Electricity Generation Required (BU) APPROACH TO SELECTION OF PROJECTS FOR 11TH PLAN: An analysis of the reasons for slippages of projects from the 10th Plan target has been carried out above. In order to avoid such slippages while planning for capacity addition during 11th Plan, efforts have been made to set 11th Plan targets realistically. The approach adopted for selection of Hydro, Thermal and Nuclear projects have been as follows: Hydro India is duly concerned about climate change and efforts are on to promote benign sources of energy. Hydro Power is one such source and is to be accorded priority also from the consideration of energy security. Irrespective of size and nature of hydro projects, whether ROR or Storage projects, these are all renewable technologies. However, execution of hydro projects requires thorough Survey and Investigation, preparation of DPR, development of infrastructure, EIA and other preparatory works, which are time consuming and require two to three years for their preparation. It would take about 5 years to execute a hydro project after the work is awarded for construction. Thus in order to achieve completion of a hydro project during 11 th plan, the project should either be already under construction or execution should start at the beginning of the plan. The broad criteria adopted for selection of hydro projects for 11 th plan are as under: Those hydro projects whose concurrence has been issued by CEA and order for main civil works is likely to be placed by March Apart from the above, a few hydro projects of smaller capacity which are ROR type having surface power houses and where gestation period is expected to be less Page 10 of Chapter1

95 Demand for Power and Generation Planning than 5 years have also been included. These projects would need to be rigorously followed up for completion during the 11 th Plan. Keeping in view the preparedness of various hydro projects, a capacity addition of 15, 585 MW is envisaged for 11 th Plan Nuclear Nuclear is environmentally benign source of energy and over a period of time, its proportion in total capacity should increase. Keeping in view the availability of fuel, a moderate capacity addition of 3,160 MW nuclear plants has been programmed during the 11 th Plan by the Nuclear Power Corporation. All projects are presently under construction. However, in view of the recent developments in the Nuclear Sector, capacity addition in nuclear plants during 12 th Plan is expected to be much higher Thermal Gas Although gas is relatively a clean fuel, at present there is uncertainty about the availability, period of availability and price of gas. Only 2,114 MW gas based capacity has been planned for 11 th Plan where gas supply has already been tied up. This does not include NTPC s gas based projects at Kawas and Gandhar, totalling to 2,600 MW, for which NTPC says that it has the gas supply contract but the matter is sub-judice. However more gas based projects could be taken up for construction as and when there is more clarity about availability and price of gas. Coal & Lignite based Thermal plants Coal is expected to be main stay of power generation in the years to come. The following criteria have been adopted for identifying the coal and lignite based projects for inclusion in the 11 th plan. Such projects as have already been taken up for execution in the 10th Plan period itself and are due for commissioning in the 11 th Plan period. Those thermal projects whose LOA has already been placed by the State and Central Public Sector Corporations, other inputs also being in place. Those thermal projects whose LOA has already been placed and the financial closure achieved by private developers. Those thermal projects whose LOA is expected to be placed by 30 th Sept, 2008 and commissioning is expected during the 11 th Plan keeping in view the normal gestation period, the size of the plant & the type(green field/expansion). After discussion with the various State Government and Central Generating Companies, thermal projects with total capacity of 46,635 MW of coal based and 1375 MW lignite based capacity have been identified for capacity addition during 11 th plan. Page 11 of Chapter 1

96 Demand for Power and Generation Planning 1.8 GENERATION PLANNING NORMS The Indian Power Sector comprises of units of different type of power plants i.e. hydro, coal, lignite, gas based, DG Sets and nuclear power plants. The unit size of coal based plants has also been steadily increasing over the years from 30 to 50 to 67.5 MW during the 70 s to 500 MW at present. During the 11th & 12th Plan periods supercritical units of 660 MW and 800 MW have also been planned. In respect of nuclear plants, MW unit size plants are in operation and 540 MWe reactors have recently been put in operation during the 10th Plan MW units are also under construction by the Nuclear Power Corporation. In this Chapter Planning Norms have been evolved for different type of plants with varying unit sizes Objective of evolving Norms In the Planning exercise, generation norms are used as representative performance parameters of various types of generation sources to estimate the availability of peaking power and energy from each generating unit. These norms are then used to assess the availability of energy from each source of generation and thus assess generation capacity addition required to meet the stipulated demand. The planning studies require accurate performance parameters of various type of generating units to assess their availability and energy generation capabilities. Availability and generation capacity are important parameters for meeting the projected demand in the country and also in various regions. Availability and PLF are key performance factors required for the planning studies. Other features used for planning studies are the Auxiliary Power Consumption and Heat Rate of the generating units, etc. Different types of generating units have varied operational performance and accordingly different norms have been used for thermal (coal), gas, hydro and Nuclear projects to make a fare assessment of the generation capacity requirement. The impact of size, age and design of plant has been considered while arriving at the norms. The actual operating data for past 5 years has been collected for all individual units operating in the country and their average performance worked out. The norms have been arrived at only after very detailed exercise and analysis of a large data on performance of various units Parameters covered by Norms Norms for thermal, hydro and nuclear stations have been evolved as all India average figures. The parameters covered under Norms are as follows: (a) (b) (c) (d) Availability Auxiliary Power Consumption Unit Heat Rate Plant Load Factor (a) Availability The Availability (gross) of the various types of generating units is given in Table 1.11 Page 12 of Chapter1

97 Demand for Power and Generation Planning Thermal (Coal/ lignite) Unit Size 800/660 MW Table 1.11 Availability Availability (%) Existing Units Future Units /250/210/200 MW Below 200 MW Below 200 MW operating below 20 % PLF at 50 - present Gas Based OCGT all sizes CCGT all sizes DG Sets All sizes Nuclear All sizes Hydro All sizes (b) Auxiliary Power Consumption (APC) After deliberations, it was concluded that the auxiliary power consumption for 800 MW and 660 MW supercritical units is expected to be in the same range as for other coal based units of 200 MW class and above. These would be different for units adopting turbine driven feed pump, motor driven feed pump and for units with or without cooling towers. The values indicated in the Table 1.12 for coal based units are for units with Turbine driven Boiler Feed Pumps (BFPs) and using cooling tower for Cooling Water system. Values will be lower by 0.5% for units without cooling tower. However, values will be higher by 1.5% for units with Motor driven BFPsThe auxiliary consumption of the various types of generating units considered is given in Table 1.12 Table 1.12 Auxilliary Power Consumption Type Unit size A.P.C (%) Coal-based power 800/660 MW supercritical 7.5% stations: 500/ 200/210/250 MW 7.5% Less than 200 MW 12% Gas-based power Combined Cycle GT 3% stations Stations Open Cycle GT Stations 1% Hydro Stations 0.5% c) Unit Heat Rate The Unit heat rates (Gross) used for planning studies for thermal units of various capacities as arrived at by the past average data are given in Table 1.13 Page 13 of Chapter 1

98 Demand for Power and Generation Planning Table 1.13 Unit Heat Rates Unit Size (MW) Heat Rate kcal/kwh Coal based plants 800(247 kg/cm2, 565C 2325 /592 C) 800(247 kg/cm2,535 C/ C) /210/250 (KWU) /210 (LMZ) MW class MW class MW class 3300 Lignite 200 MW class 2750 Gas Turbine Units Combined Cycle 2000 Open Cycle 2900 (d) Plant Load Factor The Plant Load Factor (PLF) to be adopted for thermal units of various capacities are furnished in Table 1.14 Table 1.14 Plant Load Factor Type Coal Based Lignite Based Gas Based Nuclear Units Units PLF (%) Remarks 800/660 MW 80 Future Units 500/250/210/200 MW 80 Existing and Future Units Below 100/110 MW 60 80% for future units Units in ER and NER 40 operating Below 20% PLF. 125/ 200/250 MW 75 CCGT 80 OCGT 33 All units 68.5 Normative capacity factor For hydro units it was agreed that the energy generation shall be taken as the designed energy generation in a 90 % dependable year. Page 14 of Chapter1

99 Demand for Power and Generation Planning 1.9 GENERATION EXPANSION PLANNING Eleventh Plan Programme ( ) To meet the energy requirement of 1038 BU and a peak load of 1, 51,648 MW with diversity & 5% spinning reserve, a capacity addition of about 72,000 MW is required. However, based on the preparedness of the projects, it was envisaged that a capacity of about 68,869 MW is feasible for addition during 11 th plan period. These projects have been categorized as Projects under construction and Committed Projects and summarized in Table Details are given at Appendix -1.8 SECTOR Projects Under Construction Committed Projects HYDRO TOTAL THERMAL Table 1.15 COAL THERMAL BREAKUP LIGNITE GAS/ LNG NUCLEAR TOTAL 11,931 16,254 14,115 1,125 1,014 3,160 31,345 3,654 33,870 32, ,100-37,524 Total 15,585 50,124 46,635 1,375 2,114 3,160 68,869 (The above does not include Merchant Power Plants which may additionally come during 11 th plan period.) * Note: Out of the projects totalling to 37,524 MW under committed category as given above, orders for Dadri Unit-6 (490 MW) & Mezia Ph-II (1000 MW) has been recently placed. The sector wise break-up of feasible capacity addition during 11 th plan is given in Table SECTOR HYDRO TOTAL THERMAL Table 1.16 THERMAL BREAKUP COAL LIGNITE GAS/LNG NUCLEAR TOTAL (%) CENTRAL 9,685 23,810 22,060 1, ,160 36,655 (53.2%) STATE 2,637 20,352 19, ,989 (33.4%) PRIVATE 3,263 5,962 5, ,225 (13.4%) ALL-INDIA 15,585 50,124 46,635 1,375 2,114 3,160 68,869 (100%) In addition to above, thermal projects totalling to 11,545 MW have been identified as best effort projects. These projects would normally be commissioned in the beginning of 12 th Plan but in case of any constraints in taking up of any of the projects included in 11 th plan, some of these projects would be tried for commissioning during 11 th Plan itself. Page 15 of Chapter 1

100 Demand for Power and Generation Planning A capacity of 13,500 MW has been planned under renewable as per information obtained from MNRE. It can be seen from the above profile of capacity addition plan that central sector will play a lead role with capacity addition of more than half of the capacity addition target. There has been a good response from states on the need for capacity addition to meet their growing demand and the states with IPPs, have been earmarked the balance capacity for execution.. The State owned capacity projected for the 11 th Plan is 33.4 % of the total plan as compared to 27% likely during 10 th Plan. The thermal capacity addition comprises 1 unit of 800 MW, 11 units of 660 MW, 53 units of 500 MW class, 49 units of 210/250/300 MW class, 7 units of 110/125 MW class Projects under Construction: Projects totalling to 31,345 MW are already under construction for likely benefits during 11th plan. The type wise, sector wise details are given in Table 1.17 Table 1.17 Projects under Construction as on SECTOR HYDRO TOTAL THERMAL BREAKUP THERMAL COAL LIGNITE GAS/LNG NUCLEAR TOTAL CENTRAL 7,633 7,200 6, ,160 17,993 STATE 2,107 5,852 5, ,959 PRIVATE 2,191 3,202 2, ,393 ALL-INDIA 11,931 16,254 14,115 1,125 1,014 3,160 31,345 The details are given in Appendix Committed Projects: In addition to projects under construction, a number of projects are under various stages of development for which necessary inputs are being arranged by the implementing agencies. Various clearances required for setting up these projects are being obtained which include environment and forest clearance, cooling water availability, land acquisition, DPR preparation, concurrence of CEA/ State Government (wherever required), financial tie ups/ CCEA clearance from government, fuel linkages etc. Important milestones towards obtaining these clearances are being closely monitored and therefore there is reasonable certainty of these projects materializing during 11 th plan. There is commitment from the Power Companies/ states to implement the projects during 11 th Plan. Based on present status, it emerges that a total capacity of 37,524 MW could be considered as committed capacity for benefits during 11th plan comprising of 3,654 MW hydro and 33,870 MW thermal. The details are given in Table 1.18 Page 16 of Chapter1

101 Demand for Power and Generation Planning Table 1.18 Committed Capacity (Orders yet to be placed) SECTOR HYDRO TOTAL THERMAL BREAKUP THERMAL COAL LIGNITE GAS/LNG NUCLEAR TOTAL CENTRAL 2,052 16,610 15, ,662 STATE ,500 14, ,030 PRIVATE 1,072 2,760 2, ,832 ALL-INDIA 3,654 33,870 32, , ,524 ** Order for 1490 MW namely Mezia Ph-II (1000 MW) & Dadri U-6 (490 MW) have recently been placed. The details are given in Appendix-1.8 All the hydro projects included under Committed category have been accorded concurrence by CEA/State Government except four number projects totalling to 485 MW viz. Vyasi, 120 MW in Uttaranchal (HRT fully excavated, Power House and Dam area partially excavated), UBDC III, 75 MW in Punjab (DPR prepared earlier being revised, alloted to Malana Power Company on BOO basis, Tendring in Process), Lower Jurala, 240 MW in Andhra Pradesh (Tendering in process, commissioning period around 4 years, DPR ready) and Tangu Romai HEP, 50 MW in Himachal Pradesh. Taking into account the uncertainty in the availability of Gas and prevailing high price of petroleum products, the thermal capacity addition is predominantly coal based. If gas becomes available at reasonable price more gas based projects may materialize during later half of 11 th plan Projects with Additional Efforts: In addition to 68,869 MW capacity addition feasible during 11 th plan, a capacity of 11,545 MW Thermal can come up during 11 th plan with additional efforts. The details are given in Table These projects also form part of shelf of 12 th plan projects. Table1.19 Thermal Projects with Additional Efforts SECTOR TOTAL THERMAL BREAKUP THERMAL NUCLEAR TOTAL COAL LIGNITE GAS/LNG CENTRAL 4,190 4, ,190 STATE 3,300 2,300 1, ,300 PRIVATE 4,055 4, ,055 ALL-INDIA 11,545 10,545 1, ,545 Page 17 of Chapter 1

102 Demand for Power and Generation Planning Decentralised Distributed Generation (DDG) In some of the areas, it is not possible to extend the grid connected supply of electricity for meeting the demand of such remote areas, it is proposed to set up some power plants based on local energy sources available which may be small hydro, non-conventional sources such as Bio-Mass, Wind, etc and DG sets wherein other sources are not available. During the XI plan period, it is proposed to add about 5,000 MW of capacity under DDG Fuel Requirement Fuel Requirement during terminal year of 11th Plan ( ), considering 68,869 MW capacity addition during 11 th plan and normative PLFs is summarized in Table This is based on a thermal capacity addition of 20,387MW and 50,124MW during the 10 th and 11 th Plan respectively. Details regarding coal requirement calculation are given in Appendix-1.9 The actual gas supplied to power sector at present is of the order of 40 MMSCMD as against requirement of 61 MMSCMD during current year ( ). The requirement of Gas at 90% PLF would worke out to about 89 MMSCMD. Table 1.20 Fuel Requirement Estimated during Fuel Requirement ( ) Domestic Coal* Lignite Gas/LNG ** 545 MT 33 MT 89 MMSCMD * The total coal availability from domestic sources is expected to be 482 MT per annum by Accordingly, imported coal of the order of 40MT, equivalent to 63 MT of Indian coal, may have to be organised. This quantity may reduce provided production of domestic coal is increased. ** 89 MMSCMD of gas requirement at 90% PLF has been projected in At present, the availability of gas is of the order of 40 MMSCMD and therefore not sufficient to meet the requirement of even existing plants Thermal Projects The capacity of thermal power projects totalling to 50,124 MW (projects under construction and committed) in terms of their location i.e. pithead, load centre and coastal and also in terms of unit sizes regionwise is given in Table 1.21 and Page 18 of Chapter1

103 Demand for Power and Generation Planning Table 1.21 Details of Thermal Power Projects-By Type PIT HEAD * COAL LOAD CENTRE COAL COASTAL COAL Page 19 of Chapter 1 TOTAL COAL LIGNITE GAS /LNG TOTAL NORTHERN 2,500 9,105 11, ,340 WESTERN 6,430 6, , ,102 14,902 SOUTHERN 500 3,850 3,800 8, ,742 EASTERN 10,870 1,710 12,580 12,580 NORTH EASTERN ,560 ALL-INDIA 20,300 22,035 4,300 46,635 1,375 2,114 50,124 * Pit Head stations are those plants having their own dedicated coal transportation system (MGR/Rope way) and are not dependent upon Railways for coal movement. Table 1.22 Details of Thermal Power Projects-By Unit Size 800/660 MW UNITS 500 MW UNITS 210/ MW UNITS 110/125 MW UNITS TOTAL GAS/LNG MODULE TOTAL NORTHERN WESTERN SOUTHERN EASTERN NORTH EASTERN ALL-INDIA (NOS.) ALL-INDIA (MW) Status of Fuel Linkage Coal Out of the total likely coal based capacity addition of 46,635 MW, 32,455 MW have been allocated linkage; 5,830 MW have been allocated captive coal blocks ; 4,500 MW linkages are yet to be allocated and 2,500 MW Coal Blocks to be allocated 1350 MW are likely to be on imported coal for which formal fuel supply arrangements are yet to be made. 20,300 MW capacity is pithead based ;

104 Demand for Power and Generation Planning 22,035 MW is load centre based and 4,300 MW coastal power plants. In the present day scenario, the transmission of electricity from pithead power plants to load centre works out to be a cheaper option compared to load centre power plant for a distance of 300 kms onwards at current price level of coal and railway transportation tariffs. However, following considerations warrant setting up of load centre thermal power plants as well. System stability/security Security of state grid and emergency supplies to various critical systems in the state e.g. Railway, Hospital, Airports etc. To take care of emergencies in case of transmission systems failure Dispersion of environmental degradation Problems of right-of-way in case of construction of new transmission lines Consequently, in the 11th Plan about 42 % coal based capacity is likely to be set up at load centres Gas Scenario: Due to uncertainty in availability of gas and its high price only about 2,114 MW gas based projects have been included for benefits during 11th Plan. These projects have already tied up the gas supply. At present domestic production of natural gas is around BCM. On rough indications in , the target of natural gas production by public sector companies of ONGC and OIL limited will be BCM which might increase to BCM in The likely natural gas production in private sector and through joint ventures is estimated at around 8.60 BCM in which might increase to 23 BCM in , if the newly discovered fields get into commercial production on schedule. Therefore, in the terminal year of the 11th Plan in the Base-Case Scenario in the indigenous production of gas would be of the order of 49 BCM per annum. The India Hydro Carbon forum 2025 estimated that by demand for gas would be 313 MMSCMD (equivalent to 114 BCM p.a). Therefore, it is reasonable to expect that sizeable quantity of Natural Gas would need to be imported to meet the demand in future, either as LNG or through Trans-national pipelines. Going by the progress of present negotiations with the natural gas suppliers (Qatar, Iran, Australia), it is expected that about 54 MMSCMD of natural gas (about 19 BCM p.a.) could become available by However, the investment plans for improvement of LNG infrastructure in future include: Dahej : 7.5 MMTPA Dabhol : 5.0 MMPTA Cochin : 2.5 MMPTA Hajira : 2.5 MMPTA and additional 2.5 MMPTA capacity each for Dahej, Cochin and Hazira. Page 20 of Chapter1

105 Demand for Power and Generation Planning Pricing of Gas 1) Gas Pricing in the APM: Due to dominance of National Oil Companies, namely, ONGC and OIL, the pricing in India has been administered on cost plus basis. The gas price payable to ONGC and OIL for its nomination fields is much below the market price. There will be no further gas available under APM mechanism. 2) Pre NELP Contract: The prices were negotiated between sellers and buyers and generally linked to fuel oil prices. 3) Gas Pricing in NELP: Contractors including ONGC and Oil have the freedom to sell the gas at market rated prices. Government approval is required in the gas prices formally to be used for evaluation of gas for calculating the various non tax dues to the Government. 4) Pricing of LNG: Pricing of LNG is done at market rates. In future also, the same principle will be made applicable. 5) Status of development of gas discoveries: The normal process after a discovery decision on commerciability and submission and approval of development plan of the commercial discovery. The commercialization of discovery is monitored by DGH (Director General, Hydrocarbons) and Ministry of Petroleum and Natural Gas with respect to time frame stipulated in respective PSCs (Production Sharing Contracts). (i) Reliance (RIL) Fields: The initial development plan of Dhirubhai 1 and 3 discoveries has been approved by the management committee. The DGH approved original gas in place (OGIP) at 5.5 TCF. The envisaged rate of production is 40 MMSCMD for a 10 year period. The date of availability of indigenous gas has been indicated as June, 2008 and no delay has been reported by DGH based on current work progress. (ii) Gujarat State Petroleum Corporation (GSPC) field: The block is located in Krishna Godavari shallow water offshore. The contractor is yet to submit the appraisal programme for the discovery. No reserve or production can be realistically estimated until the completion of appraisal of discovery. (iii) ONGC:ONGC is currently developing G1 and G15 discoveries in Central Gujarat basin. The production of gas is expected in March, 2007 and the estimated gas production from the above two fields is about 2.1 MMSCMD for the period of 7 years Hydro Projects: Out of the total hydro capacity of 15,585 MW included in the 11 th Plan, 11,931 MW are under construction. 3,169 MW have been accorded concurrence by CEA/State Government and are awaiting investment decision/work award. 485 MW the DPR is ready and concurrence of CEA/State Government is awaited. Page 21 of Chapter 1

106 Demand for Power and Generation Planning The details of hydro projects in terms of storage/run-of-river (ROR)/pumped storage (PSS) is given in Table Table 1.23 Details of Hydro Power Projects ROR STORAGE PSS TOTAL NORTHERN 6,145 1,320 1,000 8,465 WESTERN SOUTHERN ,178 EASTERN 1, ,298 NORTH EASTERN 40 2, ,724 ALL-INDIA 8,981 4,929 1,675 15, TWELFTH PLAN PERSPECTIVE ( ) The requirement of installed capacity and capacity addition to meet the generation requirement during the 12th Plan period as discussed in Para of this Report are given in Table below: Table 1.24 Capacity addition required during 12th plan ( ) GDP Growth 8 % 9 % 10 % GDP /Electricity Elasticity Electricity Generation Required (BU) Peak Demand (MW) Installed Capacity (MW) Capacity Addition Required During 12 th PLAN (MW) 0.8 1,415 2,15,700 2,80,300 70, ,470 2,24,600 2,917,00 82, ,470 2,24,600 2,917,00 82, ,532 2,33,300 3,03,800 94, ,525 2,32,300 3,02,300 92, ,597 2,44,000 3,17,000 1,07,500 It would be seen from the above table that under various growth scenarios, the capacity addition required during 12 th plan would be in the range of 70,000-1,07,500 MW, based on normative parameters. The Working Group recommends a capacity addition of 82,200 MW for the 12 th Plan based on Scenario of 9% GDP growth rate and an elasticity of 0.8%. This is very close to the projection of draft 17 th EPS report based on requirement of about 86,000 MW during 12 th Plan. During 12 th plan about 30,000 MW capacity addition is likely to be based on hydro and about 11,000-13,000 MW will be nuclear based. The balance capacity addition of about Page 22 of Chapter1

107 Demand for Power and Generation Planning 50,000 MW will be from thermal projects. Shelf of projects identified for likely benefits during 12th plan is given at Appendix The projects indicated in Appendix 1.8 as projects with best efforts will also form part of 12th plan shelf of projects. Shelf of projects for likely benefits during 12th plan is summarized in Table Table 1.25 Shelf of Projects for 12th Plan TYPE MW Capacity likely in 11th plan with best efforts (MW) Hydro 40,658 0 Thermal 1,14,018 11,545 Coal 94,185 10,545 Lignite 4,250 1,000 Gas/LNG 15,583 - Nuclear 12,800 - Total 1,67,476 11,545 The Working Group recommends the following for 11th and 12th plan capacity additions MEDIUM TERM PLAN: 11TH PLAN ( ) It has been estimated that depending upon the preparedness of various projects about 68,869 MW capacity addition is feasible during 11th plan (15,585 MW hydro, 50,124 MW thermal and 3,160 MW nuclear). This comprises 46,635 MW coal based plants, 2,114 MW gas/lng based plants and 1,375 MW lignite based plants. In addition renewable energy sources (MNRE has projected a grid connected renewable capacity addition of 13,500 MW during 11th plan) would also contribute towards augmenting the power generation. Demand side management and energy efficiency measures would also help in this direction. Efforts shall also be made to realize benefits from 12th plan projects which can be brought with additional efforts during 11th plan (Projects indicated as Best Efforts in Appendix 1.8). Efforts are also underway to tap surplus power from new captive power plants of about MW into the grid. A 5% spinning reserve would give a comfortable margin since normally during an emergency situation, capacity equivalent to the highest size unit and the next highest size unit in the system would suffice as reserve. Total coal requirement during would be about 545 million tones per annum LONG TERM PLAN: 12TH PLAN ( ) Under various growth scenarios, the capacity addition required during 12 th plan would be in the range of 71,000-1,07,500 MW, based on normative parameters. The Working Group recommends a capacity addition of 82,200 MW for the 12 th Plan based on Scenario of 9% GDP growth rate and an elasticity of 0.8%. During 12 th plan about 30,000 MW capacity addition is likely to be based on hydro and about 11,000-13,000 MW will be nuclear based. The balance capacity addition of about Page 23 of Chapter 1

108 Demand for Power and Generation Planning 50,000 MW will be from thermal projects. A shelf of projects totalling over 1,50,000 MW has been identified and given in Appendix 1.10 All necessary inputs for projects need to be tied up well in advance, which may pose very big challenge for power sector as a whole NEW INITIATIVES Initiatives in Thermal Power Development Efforts were made to bring in highly efficient super critical technology in the country for thermal power plants and execution of six super critical units of 660 MW capacity each was taken up during the 10 th Plan period. The first unit of 660 MW based on super critical technology is likely to be commissioned during the first year of 11 th Plan i.e The 11 th Plan feasible capacity addition of coal based plants includes 12 units based on super critical technology with a capacity of 8060 MW which is about 18% of total coal capacity planned for 11 th Plan. More and more power projects based on super critical technology are under planning stage and they would yield benefit during the 12 th Plan period. It is envisaged that more than 50-60% of capacity addition of thermal plants during 12 th plan period would be based on super critical units. This would also help in reducing the Carbon dioxide emission from new coal fired capacity Ultra Mega Power Projects Ministry of Power in the year 2006 has launched an initiative of development of coal based ultra mega projects with a capacity of 4,000 MW each on tariff based competitive bidding. Ultra Mega Power projects are either pit head based projects having captive mine block or coastal projects based on imported coal. Sasan UMPP, a pithead plant in Chattisgarh based on domestic fuel and Mundra UMPP in Gujrat based on imported coal have already been awarded for execution to the respective developers. According to the bids submitted by these developers only one unit of 660 MW is expected to be commissioned during the XIth plan and the remaining unit during 12 th Plan. Other projects where considerable progress has been made are coastal projects in Andhra Pradesh and Tamil Nadu and a pit head based project in Jharkhand. Further the projects under consideration include pit head projects in Orissa and Chatisgarh and coastal projects in Maharashtra and Karnataka. To facilitate tie-ups of inputs and clearances project specific Shell companies are set up/to be set up as wholly owned subsidiaries of the Power Finance Corporation Ltd. These companies will undertake preliminary studies and obtain necessary clearances including water, land, fuel, power selling tie-up etc. prior to award of the Project to the successful bidder. Initially five sites were identified by CEA in different states for the proposed Ultra Mega Power Projects. These include two pithead sites one each in Madhya Pradesh and Chhattisgarh and three coastal sites in Gujarat, Karnataka & Maharashtra. On the request of the State Govts of Orissa & Andhra Pradesh, two more locations have been identified for Ultra Mega Projects consisting of a pithead location in Ib-Valley coalfield in Orissa and a coastal site at Krishnapatnam in Andhra Pradesh. It is proposed to set up pithead projects Page 24 of Chapter1

109 Demand for Power and Generation Planning as integrated proposals with corresponding captive coal mines. imported coal shall be used. For the coastal projects The projects are to be developed with a view to result in minimum cost of power to the consumers. Because of bigger capacity, the cost of the project would be lower due to economy of scale, these projects would be environmental friendly as supercritical technology is proposed to be adopted to reduce emissions. Further, a time bound action plan for preparation of project report, tie-up of various inputs/clearances, appointment of consultants, preparation of RFQ/RFP is being followed. Once the developer is selected, the ownership of the Shell companies shall be transferred to the successful bidder. Following six shell companies as 100% subsidiaries of Power Finance Corporation have already been formed: a) Sasan Power Limited (Madhya Pradesh)- Pithead b) Coastal Gujarat Power Limited (Gujarat) c) Coastal Maharashtra Mega Power Limited (Maharashtra) d) Coastal Karnataka Power Limited (Karnataka) e) Akaltatra Power Limited (Chhattisgarh)-Pithead specific. f) Coastal Andhra Power Ltd. The name of seven ultra mega power projects proposed in various states is as follows: i) Sasan Ultra Mega Project (Madhya Pradesh) ii) Mundra Ultra Mega Project (Gujarat) iii) Akaltara Ultra Mega Project (Chhattisgarh)- iv) Tadri Ultra mega project (Karnataka) v) Girye Ultra Mega project (Maharashtra) vi) Krishnapatnam Ultra Mega Power Project (Andhra Pradesh) vii) Orissa Ultra Mega Power Project (Orissa) The inputs of above projects are tied up by Shell companies. As soon as developers/ bidders are selected, the ownership shall be transferred to them. The likely commissioning period Ultra Mega projects is 69 months from the signing of agreement, which is expected in February, High Hydro Development 50,000 MW Hydro Initiative was launched in 2003 and Preliminary Feasibility Report (PFRS) of 162 projects totalling to 48,000 MW were prepared. Out of this 77 projects with total capacity of about MW for which first year tariff is expected to be less than Rs.2.50/unit were selected for execution. Hydro projects have longer gestation period and therefore there is a need to formulate a 10 year plan for hydro projects. In 11 th plan a capacity addition of over 15,500 MW has been earmarked keeping in view the present preparedness of these projects. Projects totalling to a capacity of 30,000 MW have been identified for 12 th Plan on which necessary preparations have to be made from now onwards to ensure their commissioning during 12 th Plan. Thus the effect of 50,000 MW initiative would be visible in 12 th Plan period. Preparation of DPR and various clearances and approval etc for these projects are to be obtained during the first two years of 11 th Page 25 of Chapter 1

110 Demand for Power and Generation Planning Plan. It is recommended that CEA should closely monitor the progress of preparedness of DPR of these projects and their further execution Decentralised Distributed Generation (DDG) In some of the remote areas, it is not techno-economically feasible to extend the grid supply. For meeting the demand of such remote areas, it is proposed to set up some power plants based on local energy sources available. These are small hydro and nonconventional sources such as Bio-Mass, Wind, DG sets etc wherein other sources are not available. During the XI plan period a capacity addition of about 5,000 MW of capacity under DDG is envisaged Merchant Power Plants A merchant power plant does not have long term PPA for sale of its power and is generally developed on the balance sheet of developers. Government of India has reserved coal block with reserves of 3.2 Billion Tons of coal for allotment by Screening Committee of Ministry of coal for merchant and captive plants. About 10, MW capacity is expected to be developed through this initiative. This capacity has not been taken into account while working out the capacity required in the 9.5% growth in generation scenario. Capacity addition through this route would further contribute to better economic growth, better reliability of power, more spinning reserve and above all would promote creation of competition in the electricity market Coal Bed Methane The Directorate General of Hydrocarbons has estimated the country s resource base or Coal Bed Methane (CBM) to be between 1400 BCM (1260 Mtoe) and 2500 BCM (2340 Million Tonnes Oil Equivalent). To give impetus to exploration and production, the government has formulated the CBM policy. Based on two rounds of bidding under this policy, contracts have been signed with PSUs/private companies for the exploration and production of CBM in 13 blocks. An additional three blocks have been taken up for development on the basis of nomination. The estimated investment in these blocks is about Rs.560 crore and the likely CBM resources generated is estimated as 850 BCM (765 Mt). ONGC maintains that commercial production of CBM from some of these blocks will start in Thus at the very low current rate of production, the proven gas and CBM reserves, together, can last for some 50 years Coal Gasification In-situ coal gasification can significantly increase the extractable energy from India s vast in-place coal reserves. This is so because in-situ coal gasification can tap energy from coal reserves that cannot be extracted economically based on available open cast/underground extraction technologies. However, in-situ gasification has not yet been deployed commercially anywhere in the world. ONGC is engaged in trials to establish the feasibility and economics of this technology for Indian coal and lignite in collaboration with Russia. Neyveli Lignite Corporation has tied up with an Australian group to pursue in-situ gasification of lignite. In-situ gasification has many environmental advantages. The problems of overburden removal and ash disposal faced by conventional coal mining and use are eliminated. Gasification is the first step towards a clean coal technology since Page 26 of Chapter1

111 Demand for Power and Generation Planning carbon can be captured from the syn-gas produced and sequestered in the mine or pumped back in oil or gas fields to enhance oil or gas recovery. In-situ coal gasification, with or without carbon sequestration could be eligible for carbon credits. Finally, using this process at abandoned coalmines might provide an economically attractive option for full extraction of energy from in-place reserves. Clearly, the potential for domestic energy supply based on in-situ coal gasification can be large but it has not yet been assessed CAPTIVE POWER PLANTS Large number of captive plants including co-generation power plants of varied type and sizes exist in the country which are either utilized in process industry or used for in-house power consumption. A number of industries have set up their own captive plants so as to get reliable and quality power. Some Captive plants are also installed as stand-by units for operation only during emergencies when the grid supply is not available. The installed capacity of CPPs has increased from 588 MW in 1950 to 19,103 MW in March Captive plants including co-generation power plants could, therefore, play a supplementary role in meeting the country s power demand. After the enactment of Electricity Act 2003, there is a renewed interest in captive generation. Surplus power, if any, from captive power plants could be fed into the grid as the new act (Electricity Act 2003) provides for open access, in non-discriminatory way. It is envisaged that the generation from non utility captive power plants by the year may be of the order of 131 billion units which results into a CAGR of 10.5% p.a in captive generation Provisions of Electricity Act and National Electricity Policy Electricity Act, 2003 defines Captive Generating Plant as a power plant set up by any person to generate electricity primarily for his own use and includes a power plant set up by any co-operative society or association of persons for generating electricity primarily for use of members of such co-operative society or association. The captive power plant can be set up as stipulated under Section 9 of the Act. Provision of which are as below: (1) Notwithstanding anything contained in this Act, a person may construct, maintain or operate a captive generating plant and dedicated transmission lines: Provided that the supply of electricity from the captive generating plant through the grid shall be regulated in the same manner as the generating station of a generating company. (2) Every person, who has constructed a captive generating plant and maintains and operates such plant, shall have the right to open access for the purposes of carrying electricity from his captive generating plant to the destination of his use: Provided that such open access shall be subject to availability of adequate transmission facility and such availability of transmission facility shall be determined by the Central Transmission Utility or the State Transmission Utility, as the case may be: Page 27 of Chapter 1

112 Demand for Power and Generation Planning Provided further that any dispute regarding the availability of transmission facility shall be adjudicated upon by the Appropriate Commission. The Electricity Rules issued by MoP notification dated prescribes that No power plant shall qualify as a 'captive generating plant' under Section 9 read with clause (8) of section 2 of the Act unless: a. In case of power plant (i) not less than twenty six percent of the ownership is held by the captive user(s), and (ii) not less than fifty one percent of the aggregate electricity generated in such plant, determined on an annual basis, is consumed for the captive use: Provided that in case of power plant set up by registered cooperative society, the conditions mentioned under paragraphs at (i) and (ii) above shall be satisfied collectively by the members of the co-operative society; Provided further that in case of association of persons, the captive user(s) shall hold not less than twenty six percent of the ownership of the plant in aggregate and such captive user(s) shall consume not less than fifty one percent of the electricity generated, determined on annual basis, in proportion to their shares in ownership of the power plant within a variation not exceeding ten percent; b. In case of a generating station owned by a company formed as special purpose vehicle for such generating station, a unit or units of such generating station identified for captive use and not the entire generating station satisfy(s) the conditions contained in paragraphs (i) and (ii) of sub-clause (a) above including - Explanation:- 1. The electricity required to be consumed by captive users shall be determined with reference to such generating unit or units in aggregate identified for captive use and not with reference to generating station as a whole; and 2. The equity shares to be held by the captive user(s) in the generating station shall not be less than twenty six per cent of the proportionate of the equity of the company related to the generating unit or units identified as the captive generating plant. 3. It shall be the obligation of the captive users to ensure that the consumption by the captive users at the percentages mentioned in sub-clauses (a) and (b) of sub-rule (1) above is maintained and in case the minimum percentage of captive use is not complied with in any year, the entire electricity generated shall be treated as if it is a supply of electricity by a generating company. On the captive power generation the National Electricity Policy stipulates as under:- Para : The liberal provision in the Electricity Act, 2003 with respect to setting up of captive power plant has been made with a view to not only securing reliable, quality and cost effective power but also to facilitate creation of employment opportunities through speedy and efficient growth of industry. Page 28 of Chapter1

113 Demand for Power and Generation Planning Para : The provision relating to captive power plants to be set up by group of consumers is primarily aimed at enabling small and medium industries or other consumers that may not individually be in a position to set up plant of optimal size in a cost effective manner. It needs to be noted that efficient expansion of small and medium industries across the country would lead to creation of enormous employment opportunities. Para : A large number of captive and standby generating stations in India have surplus capacity that could be supplied to the grid continuously or during certain time periods. These plants offer a sizeable and potentially competitive capacity that could be harnessed for meeting demand for power. Under the Act, captive generators have access to licensees and would get access to consumers who are, allowed open access. Grid inter-connections for captive generators shall be facilitated as per section 30 of the Act. This should be done on priority basis to enable captive generation to become available as distributed generation along the grid. Towards this end, non-conventional energy sources including cogeneration could also play a role. Appropriate commercial arrangements would need to be instituted between licensees and the captive generators for harnessing of spare capacity energy from captive power plants. The appropriate Regulatory Commission shall exercise regulatory oversight on such commercial arrangements between captive generators and licensees and determine tariffs when a licensee is the off-taker of power from captive plant Captive Generation At present, the Installed Capacity of Captive Power Plants (1MW and above) is about 19,000 MW. The energy generation from captive power plants (1MW and above) during the year has been about 72 billion units. The growth of captive plant capacity during the period to and the growth of energy generation from captive plants during this period has been 3.67% and 5.01% respectively. During the year surplus power of 4.2 BU from captive was fed into the grid. Further, a capacity addition of about 12,000 MW from Captive plants is expected during the 11th Plan based on information/details received from captive power plant manufacturers and about 20% of 12,000 MW is expected to be surplus and available to be fed into the grid. However, to harness surplus capacity from captive power plants it is essential that various bottlenecks being faced are addressed and technical and commercial issues are resolved to make the export arrangements attractive and commercially viable. It is envisaged that the generation from non utility captive power plants by the year may be of the order of 131 billion units which results into a CAGR of 10.5% p.a Discussions with Forum of Regulator (FOR) The issue of various charges levied by SERCs was taken up by Ministry of Power with Forum of regulators (FOR). During the meeting of FOR, it was decided to constitute a Subgroup consisting of CERC, State Regulators of Gujarat, Karnataka, Chhattisgarh, Andhra Pradesh, Delhi, Orissa, Rajasthan, Haryana, MoP and CEA. A meeting of the Sub-group was held on 16th-17th November, 2005 and these issues were discussed and various measures were recommended for facilitating open access in distribution and harnessing Page 29 of Chapter 1

114 Demand for Power and Generation Planning surplus captive generation in the country. Major recommendations of the Sub-group are as under: Reasonable cross subsidy surcharge and other charges to provide some economic incentive to the consumers to avail open access. The procedure for grant of open access should be simple enough to encourage the consumer to exercise his choice. All future Captive generation capacity need not be fully locked in long term PPAs % of the future capacity could be kept out of long term PPAs so that it is available to open access consumers or in the market. The SERCs should allow recovery of some portion of fixed cost in addition to the variable cost of captive generation. The captive generators may offer their surplus power on the basis of a firm schedule. Infirm power from CPP should also be considered for purchase. Benchmark tariff for generators using different fuels may be indicated by the Appropriate Commission for purchase of power from CPP of up to 15 MW plant size. There should be no penalty for reduction of contract demand by any captive plant For computation of wheeling charges and losses, the Sub-Group recommended the following methodology: The transmission charges should be specified on the basis of voltage level of transmission. Only technical losses should be taken into account while specifying transmission losses Losses should be applied in kind, i.e., the drawal schedule of the Open Access Consumer shall be the injection schedule adjusted for losses. The Group felt that reactive energy charges from the open access consumers or captive power plant owners may be levied by the licensee of the area at par with other users Status of Various issues Identified Various Regulatory/Technical/Commercial issues raised during regional level meetings as well as meetings in CEA held with CPPs/Industry Associations etc. along with the status of action taken is given as under. Page 30 of Chapter1

115 Demand for Power and Generation Planning Sl. Issues Action/Status No. 1. Open Access, which is the key provision to attract investment in new generation/ transmission/distribution projects, should be made Most of the SERCs have already issued regulations. effective as per the provisions of Electricity Act, 2003 and National Electricity Policy, 2. Surcharge/ Cross Subsidy Surcharge in some States is very high Tariff policy notified by GoI on 6th January, Very high, discriminate electricity duty imposed on captive power Sub group recommends that generation and imposition of cess on captive power generation by some State Govts. electricity duty should not be imposed on generation of power from captive power plant. This may be considered by State Govts. 4. Reduction in contract demand by CPP not allowed by state DISCOM Recommended by Sub group resulting in higher demand charges 5. Demand charges levied on connected load irrespective of actual Recommended by Sub group drawal from DISCOM. 6. Exorbitant wheeling charges for intra-state transmission system for Recommended by Sub group transfer of surplus power from captive plant. 7. Other charges levied on CPPs by Regulatory Commissions. Recommended by Sub group Additional surcharge Parallel operation charge Contract Demand Charge/ Annual Minimum Guarantee Charge Transmission Charge Fixed Charge for electricity connection SLDC charge Reactive energy charge Banking charge Recommendations for The Working Group discussed various recommendations of the Regional level meetings held with CPPs/ Industry Associations etc. and workshop held by MoP & CEA and feels that Captive/group captive generation should be encouraged as envisaged in the National Electricity Policy and Integrated Energy Policy. To further address the problems faced by the captive generators and harnessing surplus power from the CPPs, following recommendations are made by the Sub-group. (A) General- Captive & Renewable/ Cogeneration Plants i) To initiate action through Energy Departments of all the States to identify the surplus capacity available from the captive power plants and approach State Utilities/Discoms to buy the surplus power available from the captive power plants. ii) As one of the option, CPP may be given tariff at frequency based UI rates under ABT mechanism. At present the UI rates are as under: Frequency UI Rate (Rs.) 49.0 Hz Hz Hz Hz Page 31 of Chapter 1

116 Demand for Power and Generation Planning iii) Single Window at State level to handle all issues relating to installation of Captive plants i.e. environment clearance, open access etc): (As per amended Electricity Act CPPs have been freed from licensing. However, permission needs to be obtained in respect of environmental clearance as well as third party sale of power (Open Access). The single window to handle all such issues will greatly facilitate in obtaining the required clearance within a stipulated period). iv) Electricity duty plus cess to be reduced as it is high in certain States i.e. AP 25p/unit; Chattisgarh- 10p/unit; West Bengal- 20p/unit. v) Electricity duty to be imposed on consumption and not on generation vi) Custom duty on import of all fuels (coal, gas and Furnace oil) to be fixed at reasonable rates. vii) Open access to be allowed in phases by SECRs who have issued regulations Connected demand 10 MW and above June 2005/April 2006 Connected demand 1 MW and above April 2007/ December 2008 viii) Monitoring of capacity addition and generation from captive/co-generation plants is required to be strengthened. In this exercise a methodology is required to be worked out in association with Ministry of Non-Conventional Energy Sources as there is an apprehension that the co-generation plants and renewable energy sources plants which are captive also are included in the Installed Capacity of Utility as well as in Captive Plants Capacity. (B) Renewable/Co-generation Plants i) SERCs to encourage and specify minimum percentage for purchase of power from renewable and co-generation plants. ii) Mandating the distribution utilities in the State to purchase renewable energy to reach at least a target of 5% of total energy consumption in the area of each DISCOM/licensee by the year iii) Co-generation power is to be given Must Run status. Co-generation power should be treated at par with non-conventional energy sources such as wind energy. Therefore, no backing down of the co-generation power be resorted to by the off taking distribution utilities except in events of force majeure. iv) Provision of banking facility may be considered and withdrawal of banked energy may not be linked with grid frequency and time of day in respect of renewable energy sources captive/co-generation plants. iv) There should be no cross-subsidy surcharge on surplus power to be supplied by a renewable source based captive/co-generation plant. Page 32 of Chapter1

117 Demand for Power and Generation Planning 1.15 MAXMISING GENERATIOM FROM EXISTING PLANTS AND AGS&P Optimization of generation from the existing generation capacity is of utmost importance in the resource crunch environment. The installation of new power projects involves large investment and long gestation period. Among various options considered by the Working- Group, following options are recommended: 1. Renovation & Modernization and Life Extension of Power Plants 2. Energy Audits 3. Better O & M practices Renovation & Modernization and Life Extension of Power Plants The main objective of Renovation & Modernization (R & M) of power generating units is to make the old operating units well equipped/ modified/ augmented with a view to improve their performance in terms of efficiency, output, reliability, safety and availability as compared to the original values. It involves replacement and modification of various systems/equipment and overcoming design deficiencies, if any, & obsolescence. It also involves activities relating to viable technological up gradation R&M and LE of Thermal Power Plants A Renovation and Modernisation (R&M) Programme for Thermal Power Stations was launched by the Government of India all over the country way back in September 1984 for completion during the Seventh Plan Period. This programme was successfully completed and intended benefits were achieved. In the subsequent 8 th and 9 th Plans, Renovation and Modernisation and Life Extension (LE) works were carried out on a number of older generating units which resulted in improvement in their performance and extension of their useful life by about 15 to 20 years. This is evident from the fact that the average plant load factor (PLF) of these thermal power stations increased from 53.9% in the year to 74% during the year (upto Nov. ). At the beginning of the 10 th plan, 106 old thermal units aggregated to a capacity of about MW were identified for Life Extension works at an estimated cost of Rs.9200 crores for completion during 10 th Plan. However progress was not satisfactory due to high execution time & cost involved in LE works. The cost of LE was also not economically feasible considering the age of plants and there was reluctance from power plants to shut down their units for longer periods due to prevailing power shortages. In view of above a new initiatives called Partnership of Excellence was taken up the details of which is given in following paragraphs PARTNERSHIP IN EXCELLANCE (PIE) PROGRAMME Under this programme generating companies who were performing well provide assistance in improving performance of non-performing companies. Towards this initiative, CEA identified 22 power stations of 11 utilities, with a capacity of MW across the country. Out of these, 17 stations with an operating capacity of 5050 MW were entrusted to NTPC and one stations (280 MW) to TATA power. On remaining 4 stations the respective utilities Page 33 of Chapter 1

118 Demand for Power and Generation Planning are taking their own course of action. The plants entrusted to NTPC recorded an additional generation of power-3690 MUs corresponding to an equivalent capacity addition of 720 MW, considering national average PLF. Capacity addition of this order requires an investment of around Rs.3,000 crore at a Greenfield project. Some additional units have also been identified for R&M and life extension. The decision for investment for R&M/LE will be based on cost benefit analysis. If not economically viable installation of new plants at existing sites, may be considered. Steps involved in implementation of PIE Programme PIE programme is envisaged to be implemented in 3 phases as under: Phase-I : Toning up of O&M practices and training of operating personnel Phase-II: Procuring essential spares from Original Equipment Manufacturers (OEM), carrying out comprehensive Capital Overhauling and doing essential R&M works to improve PLF above 60 %. Phase-III : Residual Life Assessment ( RLA) studies and major Renovation & Modernisation / Life Extension ( R&M / LE ) works based on techno-economic viability. Present status of progress The following steps have been taken / are being taken on identified stations: Agreements with concerned power utilities have been signed by better performing Partners viz. NTPC and Tata Power between October 2005 to December NTPC has already deputed 136 executives at 13 stations and has also set up head office at Patna for implementation and monitoring of PIE programme. On remaining 2 PIE stations of NTPC namely Bandel and Santaldih, PIE activities could not be undertaken due to lack of interest from WBPDCL as reported by NTPC. As informed by NTPC, WBPDCL has planned to phase out Bandel TPS (unit 1 to 4) due to ageing of these units. Santaldih TPS has been operating at low PLF due to inadequate capacity of Coal Hahdling Plant. Tata Power has deputed its executives at Dhuvran station (units-1 & 2) of GSECL for effective implementation and monitoring of PIE programme. Phase-I activities of improved O&M practices and minimum overhauling have been mostly completed on 13 PIE stations by NTPC and 1(one) PIE station by Tata Power. Implementation of management practices as per NTPC s O&M system Manual is in progress. Phase-II activity of Comprehensive overhauling has been initiated on 13 PIE stations by NTPC. In order to accelerate the pace of supply of spares and obviate the need for signing of MOUs with the concerned power utilities, a system of placement of Open Order on BHEL by power utilities has been introduced. Most of Page 34 of Chapter1

119 Demand for Power and Generation Planning the power utilities have placed open order for supply of spares on BHEL in Oct- Nov The details of PLF and Generation in December 2006 and during April to December 2006 on various stations covered under PIE programme as well as same during the corresponding period last year are given in Annexure It can be seen that 10 stations under PIE programme with partnership with NTPC and Tata Power have shown marked improvement in Generation and PLF during the period April to December 2006 as compared to corresponding period last year. Achievements The programme has started showing results in the form of improvement in PLF. In December 2006, 8 (eight) stations achieved PLF above 65% as shown below: Sl no. Utility Power Station 1. JSEB Patratu units 1 & 2 2. DVC Durgapur units-3 &4 3. IPGCL Rajghat units-1 &2 4. DVC Chandrapura units-1,2 &3 5. TNEB Ennore units 2,3 &5 6. TVNL Tenughat TPS units- 1&2 7. UPRVUNL Parichha Units-1,2 of 8. DVC Bokaro B units-1,2 &3 Capacity under PIE (MW) Plant Load Factor ( % ) during Dec, 05 Dec, MW MW MW MW MW MW MW MW Most of other stations also showed improvement in their PLF. This improvement in performance has been achieved through implementation of phase-i activities of PIE programme. Further, improvement in PLF is expected on completion of phase-ii activities. The phase-ii of the programme, therefore, needs to be continued and new stations which are perpetually running at PLF below 60% and have sufficient remaining lifetime (Details given in table 1.26) can be considered for inclusion under PIE programme. Page 35 of Chapter 1

120 Demand for Power and Generation Planning Table 1.26 Stations running at PLF lower that 60% to be considered for Inclusion under PIE Name of the Station Faridabad Extn. (HPGC) Chandrapur (MSEB) Neyveli Lig. St. II ( NLC ) Cap. (MW) PLF( %) up to Dec x60 = x210+3x500= x210 = R&M and Uprating of Hydro Plants: The normal life expectancy of a hydroelectric power plant is 30 to 35 years after which it needs life extension. Many of the existing hydro power stations could be modernized to generate reliable and higher yield by minor modifications. By adopting modern equipment like static excitation, micro-processor based controls, electronic-micro processor based governors, high speed static/numerical relays, data logger, optical instruments for monitoring vibrations, air gaps, silt content in water etc. availability of hydro power stations could be improved and outages minimized. In situations like run-of-the river schemes in Himalayan and Sub-Himalayan region, excessive silt contained in the inflows causes enormous damage to the under water parts of turbines, requiring rehabilitation almost every year. Upgrading of hydro plants calls for a systematic approach in view of a number of influencing parameters pertaining to the prime mover besides its repercussions on the total hydro electric development which itself may be a sub system of an integrated power development. A number of hydraulic, mechanical, electrical and above all economic factors play a vital role in deciding the course of action and the modalities of an upgrading / uprating programme. Uprating of hydro power plant cannot thus be considered in isolation. It has to be strategically planned, may be in certain steps, keeping in view all the technoeconomic considerations. (a) Review of 10 th Plan Programme of R&M and LE Hydro The Group reviewed the Hydro R&M & Uprating Programme as well as the achievements during the 10th Plan. A Summary of the projects planned, completed and on which work is ongoing in the 10th Plan is as furnished in Table 1.27 Page 36 of Chapter1

121 Demand for Power and Generation Planning Table 1.27 Summary of R&M and Life Extension Programme and Achievements for 10th Plan Hydro Description R&M LE No. of Projects Covered Capacity (MW) Estimated Cost (Rs. Crores) Expenditure incurred (Rs. Crores) till 5/ Targeted Benefits (MW ) Actual Benefits achieved Project-wise details of projects completed during 10th Plan is furnished at Appendix 1.12 and of ongoing projects programmed for completion during 10th are furnished in Appendix (b) Programme for 11 th Plan Hydro The Group deliberated on the 11th Plan programme for hydro R&M & Uprating Schemes and a Summary of 11th Plan programme as well as ongoing projects and those projects on which work is yet to commence is furnished in Table Table 1.28 Summary of R&M and Life Extension Programme and Achievements for 11th Plan - Hydro Description R&M LE No. of projects Covered Capacity (MW) Estimated Cost (Rs. Crores) Expenditure incurred (Rs. Crores) till 5/ Targeted Benefits (MW) Actual Benefits achieved Project-wise details of ongoing hydro RM&U projects for completion in 11 th Plan are furnished in Appendix Project-wise details of hydro RM&U projects for completion in 11th Plan but works on which are yet to be taken up for implementation are furnished in Appendix R&M and Plant Life Extension of Nuclear Plants During the course of the operating life of a Nuclear Power Plant, it goes through a series of routine and several safety reviews, based on which periodic improvement/safety upgrades are implemented. The coolant channel of older units (which commenced commercial operation in 1993) Pressurized Heavy Water Reactors need replacement. After about 10 years of operation at full power, these coolant channels are replaced during a long shut down. Advantage of this shut down is taken for safety upgrades and plant life extension, as required. Page 37 of Chapter 1

122 Demand for Power and Generation Planning Such R&M activities have been completed for Rajasthan Atomic Power Station Unit-2 and Madras Atomic Power Station Unit-1&2. R&M activities as above have been taken up on NAPS-1 and are expected to be completed during Similar work is planned for NAPS-2 and KAPS-1 in the 11th Plan. Details of financial outlay in respect of these projects are given in Table Table 1.28 Summary of R&M and Life Extension Programme and Achievements for 11th Plan Nuclear (Figs in Rs cr.) Name of Estd. Anticipated Total 11th project Completion exp. by Plan cost 10th Plan end NAPS &2 KAPS ENERGY EFFICIENCY IMPROVEMENT THROUGH ENERGY AUDIT As per Energy Conservation Act 2001, Energy audit means the verification, monitoring and analysis of use of energy including submission of technical report containing recommendations for improving energy efficiency with cost benefit analysis and an action plan to reduce energy consumption. Also under the provision of Energy Conservation Act 2001, all designated consumers declared by the Government would have to undertake mandatory Energy Audit studies by accredited Energy Auditors. Energy Audit studies aim at determining the present level of performance of main power plant equipment and selected sub-systems and comparing them with design figures. Reasons for deterioration are analysed. The studies may also involve review of design of various equipment to see if these are over-designed. Techno-economic viability of introducing new efficient technologies is also included in the energy audit studies. In fact the basic objective is to reduce the consumption of various inputs (coal, oil, power, water) per unit of power generation. Areas normally covered in a power plant are: Boiler efficiency Air heater performance Mills performance Furnace radiation losses Turbine heat rate Regenerative system performance HP/IP cylinder efficiency Condenser performance Auxiliary power consumption Lighting systems DM water consumption Page 38 of Chapter1

123 Demand for Power and Generation Planning Secondary fuel oil consumption Any other sub-system i.e. air compressor, air conditioning etc. In view of the foregoing, it is suggested that Energy Efficiency Cell shall be created at all thermal power stations. This cell shall be responsible for the following: Internal Energy Audit groups shall be set up in each power plant. Capacity building of the efficiency group must be done to enable them to carry out Energy Audit tests on their own. Regular audits shall also be got conducted from accredited Energy Auditors. All recommendations that emerge from these audits must be implemented if these are techno-economically feasible. Short term measures can be made part of the annual plan/annual overhaul of the unit whereas long term measures can be taken up under the R&M schemes of these stations. Energy Efficiency Awareness campaign shall be taken up among staff of the power plant. Better O&M practices Better O&M practice is also an effective tool to improve the performance of existing plants major ones being as follows: 1. Run the machines at parameters near to design parameters. 2. Keep proper fuel/air mixture to reduce high carbon loss in ash. 3. Replacement of air heater seal to avoid air ingress in Air preheaters. 4. Maintain the recommended fineness of Pulverized coal. 5. Reduce the excessive R/H spray & enforce burner tilt mechanism to control reheat temperature. 6. Instrumentation needs to be checked and calibrated regularly. Wide variation in readings may be observed and corrected. 7. Control CW flow to check under cooling of condensate. 8. Attend air ingress into condenser. 9. Keep the condenser tubes clean ACCELERATED GENERATION & SUPPLY PROGRAMME (AGS&P) SCHEME Under the AGS&P Scheme, MOP is providing interest subsidy through financial institution (PFC & REC) with an objective to reduce the rate of interest on the term loans for R&M of State Sector thermal power grants Scope of the scheme The Scope of the AGS&P Scheme is as follows: The Scheme covers all States/UTs. The financial support, to be provided for the renovation/modernization and uprating works undertaken by the Utilities in Government /Public Sector. Page 39 of Chapter 1

124 Demand for Power and Generation Planning The Scheme is applicable to thermal power stations of station capacity Note: Release of AG & SP funds under new loans sanctioned at Stage II and Stage III shall take place only after appointed consultant/ partner confirms that the O&M practices have reached satisfactory level Salient features of the scheme The salient features of the scheme extension of Accelerated Generation & Supply Programme to Tenth Five Year Plan period and Govt. directions/guidelines thereto are as under:- a) The assistance under the AG&SP scheme shall be limited to only state sector R&M generation projects including those based on non-conventional energy sources. Interest subsidy under AG&SP schemes will be admissible for D.V.C. s R&M projects also. b) Only those States, which perform satisfactorily with respect to the agreed milestones of the reform MoUs entered into with the Ministry of Power and of the Action Plans to achieve commercial viability in accordance with the Reform programme, would be eligible for funding under AG&SP. The better performing states would be given preference. The milestones of Action Plans would be stringent and will aim at progressively reducing the gap between the cost per unit and the revenue collected per unit of electricity. c) The total assistance under the Scheme will be limited to the budget provision in the Tenth Five Year Plan. d) Interest subsidy under the scheme has been reduced from 4% in Ninth Plan to 3% in Tenth Plan i.e to The subsidy for projects in North-Eastern Region would be 4%. Interest Subsidy would be restricted to difference of lending rate and benchmark rate subject to a maximum of 3% and 4% respectively.. The benchmark rate would be rate of interest on 12 years Government security for that financial year. e) Grants under the AG&SP scheme will be provided to State Electricity Boards (SEBs), State Generating Corporations (SGCs) and state Power Departments (SPDs) for carrying out studies which help to achieve policy objectives of the Government relating to Power sector. These include Power sector Reform and Restructuring Studies, System Studies, Renovation & Modernisation (R&M) Studies, Life Extension (LE) Studies, retainer consultancy for R&M and Environment/social studies. Distribution studies which are covered under the proposed APDRP Scheme will not be eligible for grant of assistance under AG&SP Scheme. some minimum expenses relating to overall power sector reforms and restructuring studies on a need based approach would be considered for funding under the AG&SP Programme. To this extent guidelines issued in OM No /23/2001- PFC dated and 7th March, 2003 and supplemented for the sanction of appropriate level of funds within the overall allocation of the 10th Plan as budgeted from year to year. Page 40 of Chapter1

125 Demand for Power and Generation Planning f) Interest subsidy in respect of generation project covered under AG&SP will be reduced in proportion to the delay in commissioning of the project in following manner: Reduction %Delay(D/X) Reduction 0% - 10% Nil >55% - 70% 2% >10%-25% 0.5% >70% - 85% 2.5% > 25% - 40% 1.0% >40% - 55% 1,5% Above 85% 3.0% D is delay (in days) = Actual Commissioning date- agreed Commissioning Date X (in days) = Agreed Commissioning Date Date of sanction of loan. The reduction in interest subsidy will be applicable from the actual date of commissioning or the date of 85% delay, whichever event occurs earlier. Wherever the interest subsidy is less than 3%, the same would be spread over seven slabs proportionately as per formula laid down above and the concerned lending institution will account for it to the Ministry of Power as interest subsidy is front ended. (g) All generation projects which are estimated to be commissioned in Tenth Plan period would be eligible for assistance under AG&SP Eligibility criteria for the scheme (a) (b) (c) (d) (e) The project authority are to ensure that there has been annual overhaul of the plant on regular basis. In case, this has not been done so, the same have to be done by the project authority In case, if it is found that improvement can be affected by making a change in the management of the plant, that should be resorted to by the project authority without any delay. Emphasis will be on the rehabilitation of core and essential equipments of the plant. However, while accepting replacement of major items, clear evidence of failure or frequent operational trouble will form the main criteria. The replacement of minor items which could otherwise be covered under the routine and preventive maintenance of power stations, shall not be covered under this scheme. The R&M Report should contain brief history of the project, technical details, unitwise annual generation data since commissioning, details of forced outages, modifications/replacement works undertaken earlier, problem now encountered and the reasons for poor performance. The report should also indicate the nature & scope of the R&M works involved, cost estimates and the cost benefits analysis etc, The proposals shall be considered subject to their merits, techno-economic viability and availability of funds Procedure for availing interest subsidy Page 41 of Chapter 1

126 Demand for Power and Generation Planning i) If the project is found suitable for renovation/modernization work, leading to optimum generation of power. The State Government/ SEBs will then be firm up the cost estimates of the identified works so as to fix the financial requirements for the R&M activities to be undertaken. A firm time schedule will be worked out to complete the work. The project authority/state 0Government must furnish a certificate that loans for R&M absolutely necessary. ii) iii) iv) The PFC and R.E.C. shall have to include a clause in their Term Loan Agreement with the Project authorities to recover the subsidy amount along with the penal interest of 3% more alongwith the recovery of Term Loan for cases of default where the interest subsidy is cancelled by MOP for violation of terms of conditions of this circular. Loan can be recalled by the FIs before project completion or where project is not completed for whatever reason. They shall create a pari-passu charge for the recoveries to be made by them for refund of subsidy amount to MOP. The un - disbursed amount of interest subsidy released by MOP to the FIs along with the penal interest as above will, be returned immediately in all such cases. MOP will examine the proposal received from the financial institution and approve interest subsidy on the basis of overall viability of the proposal, fulfilment of general terms and conditions, availability of funds and general policies of MOP. All expenses towards the cost of the project, over and above the Ministry s support agreed to, including escalations in the cost, if any, will have to be met by the Executing Agencies. It is recommended that R&M schemes shall be continued during 11th and 12th Plan also. However it must be ensured that routine maintenance activities are not included in these schemes. Only activities which aim at increasing the efficiency of the unit or improve the availability or are required to meet environmental norms or are aimed at renovating obsolete equipment- Controls and Instrumentation are included in R & M schemes. Further for Life Extension schemes, a cost benefit analysis should be carried out vis-à-vis installation of new unit at the same site. The Group recommends that the AGS&P Scheme shall continue NON CONVENTIONAL ENERGY SOURCES Our country has significant potential for generation of power from Non Conventional Energy Sources such as Wind, Small Hydro, Bio mass and Solar Energy. Limited availability of fossil fuel like coal and gas has further highlighted the importance of power from these sources. In addition, these sources provide a particularly attractive solution for meeting requirement of power at remote locations, in case of which it is not feasible to extend the grid. All efforts are therefore being made to tap these resources for generation of power to supplement power from Conventional Sources Development of Non-Conventional Energy Resources The total estimated medium-term potential (2032) for power generation from renewable energy sources such as wind, small hydro, solar, waste to energy and biomass in the country is about 1,83,000 MW. The grid interactive installed capacity from renewable is Page 42 of Chapter1

127 Demand for Power and Generation Planning likely to increase from about 3,500 MW at end of 9th Plan to 23,500 MW at the end of 11th Plan. The grid interactive Installed Capacity as on is 8996 MW. Source wise details of Potential and Installed Capacity as on are furnished in Table 1.29 Table 1.29 Potential and Installed Capacity of Renewable Power (AS ON ) (Figures in MW) Sources / Systems Estimated mid- Term (2032) Potential Cumulative Installed Capacity (As on ) Wind Power 45, Bio- Power(Agro residues & 61, Plantations) Co-generation Baggasse 5, Small Hydro (up to 25 MW) 15, Waste to Energy 7, Solar Photovoltaic 50, TOTAL 1,83, Source MNRE Sector-wise details of renewable energy sources are as follows: Tenth Plan Target and Achievement A target of 3075 MW was set for the 10th Plan in respect of grid interactive renewable power against which an achievement of 4635 MW has been made during the 1st four years of the 10th Plan and a target of 1888 MW has been set for i.e. last year of the 10th Plan. Source wise details are furnished in Table Table th Plan Targets and Achievements for Grid Interactive Renewable Power Sources / Systems Target Page 43 of Chapter 1 Achievement ( to ) As on (Figures in MW) Target Wind Power Biomass Power Baggasse Cogeneration Biomass Gasifiers Small Hydro (up to 25 MW) Waste to Energy -MSW Industrial Waste Solar Power TOTAL Source MNRE

128 Demand for Power and Generation Planning 11 th Plan Target Details of 11 th Plan target of Grid Interactive renewable power are furnished in Table Table th Plan Tentative Targets for Grid Interactive Renewable Power (Figures in MW) Sources / Systems Target for 11th plan Wind Power 10,000 Biomass Power 2,100 Baggasse Co-generation Biomass Gasifiers Small Hydro 1,400 (up to 25 MW) TOTAL 13,500 Source MNES The above target of 13,500 MW for grid interactive renewable power does not include 1000 MW from Distributed Renewable Power System (DRPS). The programme is based on the draft report of the Working group on Non- Conventional Energy Sources for 11 th Plan Summary of Installed Capacity Considering the 10 th Plan and tentative 11 th Plan capacity addition as detailed above, Summary of Installed Capacity is furnished below: Installed capacity by the end of 9 th Plan (As on ) 3,475 MW Installed capacity by the end of (As on ) 8,088 MW Programme for ,888 MW 11 th Plan programme for ,500 MW Total Installed Capacity by the end of 11 th plan 23,476 MW Say 23,500 MW Reliable figures for generation from these projects are not available but assuming average PLF of 20%, this will generate about 131 BU by ISSUES TO BE ADDRESSED AND STRATEGY TO BE ADOPTED FOR 11 th PLAN Transition of the Indian Power Sector from the era of SEBs to separate generation, transmission and distribution utilities, independent regulatory bodies and entry of private and foreign players is expected to fundamentally transform the power scenario. However, since this restructuring is still under the process of evolution, a number of crucial issues Page 44 of Chapter1

129 Demand for Power and Generation Planning need to be addressed and sorted out. A conducive environment needs to be created to fructify the benefits expected from the Acts and the Policies of the Government. With a view to achieve the above as also learning from experiences during the past Plans, it is essential to identify Issues, both direct and indirect involving infrastructural constraints. These Issues need to be addressed to facilitate the planned capacity of about 68,869 MW during the 11th Plan. Some of the Issues pertaining to Capacity addition and maximizing generation from existing plants are as follows: Analysis and Close monitoring of 11th Plan projects In order to fulfill the Government s Mission of providing power to all by the end of 11th Plan i.e.2012, a detailed analysis of the status of 11th Plan projects has been carried out with a view to tie up all requisite inputs and to remove all bottlenecks in their implementation. Details of the analysis given in Table Table 1.32 Status of 11th Plan Projects Under Construction Hydro Thermal Nuclear Figures in MW 31,345 11,931 16,254 3,160 Committed projects 37,524 Feasible for benefit during 11th Plan 68,869 In so far as projects under construction are concerned, no difficulty is foreseen in implementation of these projects Status of Committed Capacity in 11th Plan on which construction is yet to start are given in Table-1.33 Table-1.33 Figures in MW Hydro 3,654 Thermal 33,870 Coal 32,520 Lignite 250 Gas 1,100 Total 37, Preparedness of Projects on which Construction is yet to start are given in Table-1.34 & Table Page 45 of Chapter 1

130 Demand for Power and Generation Planning Table-1.34 Hydro Status MW Projects awaiting investment 3,169 decisions/work award Concurrence to be accorded by 485 CEA/State Government Total 3,654 Table-1.35 Thermal Status MW Coal blocks/linkages yet to be 7,000 allocated Total 7,000 In case of above projects, for each project a milestone time-schedule has been created which would ensure timely completion of each activity. This should be adhered to avoid bunching of projects in the last two year of 11 th plan and to ensure that plan targets are met Augmentation of Infrastructural facilities Implementation of this large capacity would call for augmentation of manufacturing capabilities in the various input sectors namely, Main Plant and equipments - BHEL has drawn up a Plan for capacity augmentation from 6,000 MW to 10,000 MW with an investment of Rs 1600 crs. This programme is in an advanced stage of implementation and is expected to be completed by BHEL plans to further enhance its capacity as deemed necessary, on receipt of sustained capacity addition programme along with the mix in the 11th & 12th Plan periods. Key inputs - This would call for augmentation in manufacturing capacities of steel, cement, aluminum and also in the manufacturing capabilities of various associated equipment like, large motors, coal handling plants, water treatment plant, ash handling and ash utilizing facilities, etc. Construction agencies This area also needs large augmentation as at present there is lack of qualified contractors for taking up construction of large hydro and thermal power plants Arrangement for fuel requirement Coal based capacity of about 46,635 MW has been identified for commissioning during 11th Plan period and the requirement of coal during has been assessed as 545 Million tons per annum. Details of total requirement of coal viz-a-viz indigenous production plans are given in Table 1.36 & Appendix 1.9 Page 46 of Chapter1

131 Demand for Power and Generation Planning Table 1.36 Fuel Requirement (Tentative) during Fuel Requirement ( ) Coal* Lignite Gas/LNG** 545 MT 33 MT 89 MMSCMD * From domestic sources, total coal availability is expected to be 482 MT per annum by Accordingly, imported coal of the order of 40MT, equivalent to 63 MT of Indian coal, may have to be organised. This quantity may reduce provided production of domestic coal is increased. ** 89 MMSCMD of gas requirement at 90% PLF has been projected in At present, the availability of gas is of the order of 40 MMSCMD and therefore not sufficient to meet the requirement of even existing plants. On an average, power sector is being supplied 70-75% of the coal produced by Coal India Ltd. The above requirement of coal also includes the coal produced by individual organizations from captive blocks allotted to them. Tie up of coal requirement as per the above schedule shall be ensured As regarding requirement of gas 2114 MW gas based projects have been planned during 11th Plan and these projects have firm tie up of gas Summary of Fund Requirement for Generation Projects The details of the overall capacity addition programme of 68,869 MW during 11 th Plan and fund requirement of Rs 4,10,897 crore including start-up projects for capacity addition in 12 th Plan are tabulated in Table Table th Plan Capacity addition & Fund Requirement (including advance action funds for 12 th plan projects) Sector Fuel Type Likely capacity addition (MW) Fund Requirement (Rs. crore) Central Hydro 9,685 27,231 Thermal 22,310 74,782 Nuclear 3,160 8,970 Total 35,155 1,10,982 State Hydro 2,637 4,349 Thermal 21,852 75,278 Total 24,489 79,627 Private Hydro 3,263 13,234 Page 47 of Chapter 1

132 Demand for Power and Generation Planning Sector Fuel Type Likely capacity addition (MW) Fund Requirement (Rs. crore) Thermal 5,962 17,858 Total 9,225 31,092 All India Hydro 15,585 44,814 Thermal 50,124 1,67,918 Nuclear 3,160 8,970 Funds for projects Total 68,869 2,21701 benefiting in 11 th Plan Funds for projects benefiting in 12 th Hydro 31,734 86,291 Thermal 47,225 81,877 Plan Nuclear 12,800 21,208 Total 91,759 1,89,195 Grand Total 1,52,963 4,10,896 The overall requirement of funds in 11 th Plan has been estimated as Rs. 10,31,600 crore including NCES, Captive and Merchant Power Plants. The details along-with sources of funds are given in Chapter 10 of the report Manpower Requirement In order to facilitate a capacity addition of 68,869 MW during the 11th Plan, trained and qualified manpower is the most essential requirement. Recruitment of proper personnel and necessary training facilities and programmes need to be made available. However quantification of the same is given in Chapter-7 on Manpower Requirement RECOMMENDATION OF THE GROUP 1. The Working Group recommends generation planning based on growth of energy generation requirement of 9.5%. Keeping in view the above objectives and preparedness of various projects the Working Group recommends capacity addition of 68,869 MW during 11 th Plan as per details given below: Table 1.38 SECTOR HYDRO TOTAL THERMAL BREAKUP NUCLEAR THERMAL COAL LIGNITE GAS/LNG TOTAL (%) CENTRAL STATE PRIVATE ALL-INDIA (53.2%) (33.4%) 9225 (13.4%) (100%) Page 48 of Chapter1

133 Demand for Power and Generation Planning 2. States are required to take an active role in the capacity addition programme by their own agencies & by private sector participation through tariff based competitive bidding route on the lines of developments of Ultra Mega Power Project. In the 11 th plan addition of less than 50% of total capacity is targeted in states and private sector. It is recommended that in 12 th Plan more than 50% capacity should come through initiative of the states. 3. Some of the states do not have resources for capacity addition in their states. Such states should tie up long term PPAs with surplus states/generation companies. 4. Manufacturing capacity of BHEL needs to be enhanced to meet the capacity addition programme envisaged in 11 th & 12 th Plans. 5. A 10 year plan for hydro development is to be pursued in view of higher gestation period. A hydro capacity of 30,000 MW has been identified for commissioning during 12 th Plan. The survey and investigation, preparation of DPR, statutory clearances should be vigorously followed up right from now to enable their commission during 12 th Plan. The CEA should closely monitor progress on these projects.. 6. The Working Group recommends continuation of PIE programme during 11 th Plan also. 7. In addition to capacity addition programme, concerted efforts to continue in regard to: - Development of captive power plants. - Maximising Generation from existing plants. - Energy Efficiency improvement through Energy Audit. - Better O & M practices. - RM&U/Partnership in Excellence (PIE) Programme. - Development of Non-Conventional Energy Sources. 8. Major recommendations for facilitating open access in distribution and harnessing surplus captive generation in the country are as under: Reasonable cross subsidy surcharge and other charges to provide some economic incentive to the generators to avail open access. The SERCs should allow recovery of some portion of fixed cost in addition to the variable cost of captive generation. The captive generators may offer their surplus power on the basis of a firm schedule. Infirm power from CPP should also be considered for purchase. There should be no penalty for reduction of contract demand by any industry having captive plant. ******** Page 49 of Chapter 1

134 Demand for Power and Generation Planning Appendix 1.1 SUMMARY OF CAPACITY ADDITION TARGET OF 41,110 MW DURING 10th PLAN (REGION WISE, SECTOR WISE AND STATUS WISE) A SECTOR WISE (Figures in MW) HYDRO THERMAL NUCLEAR TOTAL CENTRAL 8,742 12,790 1,300 22,832 STATE 4,481 6, ,157 PRIVATE 1,170 5, ,121 TOTAL 14,393 25,417 1,300 41,110 B REGION WISE NORTHERN 7,274 5, ,320 WESTERN 3,752 6,604 1,080 11,436 SOUTHERN 1,158 5, ,376 EASTERN 1,860 7, ,935 NORTH EASTERN ,018 A & N Islands TOTAL 14,393 25,417 1,300 41,110 C STATUS WISE SANCTIONED ON GOING ,634 1,300 17,022 CEA CLEARED , ,831 STATE CLEARED NEW SCHEMES , ,479 TOTAL ,417 1,300 41,110 Page 50 of Chapter1

135 Demand for Power and Generation Planning Appendix 1.2 LIST OF PROJECTS COMMISSIONED DURING 10 TH PLAN UPTO ( ) Name of the Project Sector/State Type Capacity (MW) THERMAL Pragati CCPP S.S/Delhi Gas Pragati CCPP S.S/Delhi Gas Ramgarh CCGT-2 S.S/Rajasthan Gas 75.3 Simhadri TPS C.S./A P Coal 500 Neyveli FST Ext. C.S/Tamilnadu Lignite 210 Peddapuram CCGT P.S/ A P Gas 78 Raichur U-7&8 SS/Karnataka Coal 210 NLC-II Ext U-0 PS/ Tamilnadu Lignite 250 Valuthur CCGT SS/ Tamilnadu Gas 94 Talcher-II CS/Orissa Coal 500 Rokhia II U- SS/Tripura Gas 21 Baramura GT Ext. SS/ Tripura Gas 21 Likakhong DG SS/Manipur Diesel 18 Bamboo flat DG PS/A&N Diesel 20 Sub-Total (Thermal) HYDRO Baspa-II PS/HP Hydro 200 Sardar Sarovar SS/Guaratj Hydro 100 Bansagar Tons-III SS/MP Hydro 20 Bansagar Tons-II SS/MP Hydro 15 Srisailam LBPH SS/AP Hydro 300 Sub-Total (Hydro) 635 Total (Thermal + Hydro) ( ) ( ) Thermal Kota TPS St-IV SS/Rajasthan Coal 195 Suratgarh III SS/ Rajasthan Coal 250 Dhuvaran CCGT SS/Gujarat Gas Neyveli FST Ext. CS/Tamilnadu Lignite 210 Kutralam CCPP SS/Tamilnadu Gas 100 Talcher II CS/Orissa Coal 500 Sub-total (Thermal) Hydro Nathpa Jhakri CS/HP Hydro 1500 Chamera-II CS/HP Hydro 300 Baspa-II PS/HP Hydro 100 Indira Sagar JV CS/MP Hydro 500 Srisailam LBPH SS/AP Hydro 150 Almattti Dam SS/Karnataka Hydro 15 Page 51 of Chapter 1

136 Demand for Power and Generation Planning Kopili ST-II CS/Assam Hydro 25 Sub-Total (Hydro) 2590 NUCLEAR MAPS-2 Uprating CS/Tamilnadu Nuclear 50 Sub-Total (Nuclear) 50 Total(Thermal + Hydro+Nucl.) ( ) ( ) Thermal Rihand-II CS/UP Coal 500 Panipat U-7&8 SS/Haryana Coal 500 Akrimota TPP SS/Gujarat Coal 125 Ramagundam CS/AP Coal 500 Karuppur CCPP PS/Tamilnadu Gas 70 Mezia U-4 CS/DVC Coal 210 Talcher-II CS/Orissa Coal 1000 Bairabi HFO SS/Mizoram Diesel 22.9 Rangat Bay SS/A&N Diesel 6.0 Sub-Total (Thermal) HYDRO Indira Sagar JV CS/MP Hydro 500 Sardar Sarovar SS/Gujarat Hydro 350 Almatti Dam PH SS/Karnataka Hydro 165 Sub Total (Hydro) Grand Total (T+H) ( ) Thermal Rihand-II CS/UP Coal 500 Akrimota TPP SS/Gujarat Coal 125 Karuppur CCPP PS/Tamilnadu Gas 49.8 Jojobera PS/Jharkhand Coal 120 Valentharvi PS/Tamilnadu. Gas 38 Jagrupadu CCPP PS/AP Gas 220 Paricha Extn. SS/UP Coal 210 Dhuvaran SS/Gujarat Gas 72 Vemagiri-I PS/AP Gas 233 Rokhia GT SS/Tripura Gas 21 Sub-Total (Thermal) NUCLEAR TAPP Unit 3&4 CS/Maharashtra Nuclear 540 MAPS-1 Uprating CS/TN Nuclear 50 Sub-Total (Nuclear) 590 Page 52 of Chapter1

137 Demand for Power and Generation Planning HYDRO Dhauliganga SS/Uttranchal Hydro 280 Sardar Sarovar Ss/Gujarat Hydro 800 Almatti Dam PH SS/Karnataka Hydro 110 Pykara Ultimate ST SS/Tamilnadu Hydro 150 Sub-total (Hydro) 1340 Grand Total (T+N+H) Upto Thermal Valentharvi PS/Tam Gas 14.8 Vemagiri-I CCGT PS/AP Gas 137 Ratnagiri Gas (JV) JV/Maha Gas 740 Vindhyachal NTPC Thermal 500 Unchahar III NTPC Thermal 210 Paricha Extn. SS/UP Coal 210 Sub-Total (Thermal) Nuclear Tarapur 3 & 4 CS/Maha Nuclear 540 Sub-Total (Nuclear) 540 Hydro Vishnuprayag PS/Uttranchal Hydro 400 Tehri I THDC Hydro 500 Larji SS/HP Hydro 126 Bhawani Kathalai Tam Hydro 30 Sardar Sarovar SS/Guj. Hydro 200 Bansagar-IV MP/SS Hydro 20 Marikheda MP/SS Hydro 40 Sub-Total (Hydro) 1316 Grand Total (T+N+H) ALL INDIA -10 TH PLAN CAPACITY ADDITION TILL DATE Thermal (Coal+Gas+Diesel) 9919 (Hydro) 6896 (Nuclear) 1180 GRAND TOTAL MW UP TO Page 53 of Chapter 1

138 Demand for Power and Generation Planning Appendix-1.3 LIST OF POWER PROJECTS FOR BENEFITS DURING 10TH PLAN (Central, State & Private Sector) SUMMARY Plant Name ORIGINAL TARGET PRESENT STATUS HYDRO CENTRE STATE PRIVATE THERMAL CENTRE STATE PRIVATE NUCLEAR TOTAL-ALL-INDIA CENTRE STATE PRIVATE NOTE: 1. PROJECTS AND FIGURES IN RED COLOR ARE THOSE SLIPPING FROM ORIGINAL TARGET OF 41,110 MW 2. PROJECTS AND FIGURES IN GREEN CLOUR ARE ADDITIONAL PROJECTS AND BENEFITS AS PER MID TERM REVIEW 3. FIGURES IN BLUE ARE AS PER PRESENT STATUS IN NOVEMBER 2005 SOG-Sanctioned on Going CEA- Cleared by CEA SC-State Cleared NEW- Yet to be cleared C-Central Sector S-State Sector P-Private Sector JV-Joint Venture Page 54 of Chapter1

139 Demand for Power and Generation Planning LIST OF POWER PROJECTS FOR BENEFITS DURING 10TH PLAN (Central, State & Private Sector) Plant Name Fuel Type Sector Capacity MW ORIGINAL TARGET PRESENT STATUS Likely date of commissioning NORTHERN REGION CENTRAL SECTOR NHPC CHAMERA II HYDRO C Commissioned DULHASTI HYDRO C U 2-Feb 07, U 1&3-Mar 07 DHAULI GANGA HYDRO C Commissioned SEWA II HYDRO C SUB-TOTAL (NHPC) NJPC NATHPA JHAKRI HYDRO C Commissioned RAMPUR HYDRO C SUB-TOTAL (NJPC) NTPC RIHAND II COAL C Commissioned UNCHAHAR III COAL C Commissioned DADRI II COAL C SUB-TOTAL (NTPC) NPC RAPP U-5 NUCLEAR C SUB-TOTAL (NPC) THDC TEHRI I HYDRO C U 2,3&4- Commissioned U 1 -Mar 07 KOTESHWAR HYDRO C TEHRI PSS PSTOR C SUB-TOTAL (THDC) NLC BARSINGSAR LIGNITE C TOTAL NR (CENTRAL SECTOR) STATE SECTOR DELHI PRAGATI (GT2 +ST) GAS S Commissioned SUB TOTAL (DELHI) HARYANA YAMUNANAGAR COAL S PANIPAT U 7&8 COAL S Commissioned SUB TOTAL (HARYANA) Page 55 of Chapter 1

140 Demand for Power and Generation Planning HP LARGI HYDRO S Commissioned KASHANG -I HYDRO S SUB TOTAL (HP) J&K BAGHALIHAR HYDRO S SUB TOTAL (J & K) PUNJAB GHTPP-II COAL S U 1-Mar 07 U 2- May 07* SHAHPURKANDI HYDRO S SUB TOTAL (PUNJAB) RAJASTHAN RAMGARH-2 GAS S Commissioned DHOLPUR CCGT GAS S GT 1&2-Mar 07 ST - Aug 07* GIRAL LIG U-1 LIGNITE S February-07 MATAHANIA CCPP LNG S KOTA TPS ST IV COAL S Commissioned SURATGARH III COAL S Commissioned SUB TOTAL (RAJASTHAN) UP PARICHHA EXTN COAL S Commissioned ANPARA C COAL S SUB TOTAL (UP) UTTARANCHAL MANERIBHALI II HYDRO S U 1 - Sep 07* U 2 - Oct 07* U 3 - Nov 07* U 4 - Dec 07* SUB TOTAL(UTTARANCHAL) TOTAL NR (STATE SECTOR) PRIVATE SECTOR PUNJAB GOINDWAL SAHIB COAL P SUB TOTAL (PUNJAB) HP BASPA HYDRO P Commissioned DHAMVARI SUNDA HYDRO P SUB TOTAL (HP) P UTTARANCHAL VISHNU PRAYAG HYDRO P Commissioned SUB TOTAL (UTTARANCHAL) P TOTAL NR PRIVATE SECTOR TOTAL (NORTHERN REGION) * On best efforts being included in X Plan Capacity Addition Page 56 of Chapter1

141 Demand for Power and Generation Planning WESTERN REGION CENTRAL SECTOR NPC TARAPUR U3&4 NUCLEAR C Commissioned NTPC SIPAT I COAL C SIPAT II COAL C SIPAT ST II U-4,5 COAL C U 4 - Mar 07 U 5 - May 07 VINDHYACHAL III COAL C U 9 - Comm. U 10 - Feb 07 GANDHAR CCGT GAS C 1300 March-07 KAWAS CCGT GAS C 1300 RATNAGIRI GAS (JV) LNG C MW-Comm. 704 MW-Mar 07 SUB TOTAL (NTPC) NHPC BAV-II HYDRO C SUB TOTAL (NHPC) NHDC OMKARESHWAR HYDRO JV INDIRA SAGAR HYDRO JV Commissioned SUB TOTAL (NHDC) SUB TOTAL WR (CENTRAL SECTOR) STATE SECTOR GUJARAT SAR.SAROVAR-2 HYDRO S Commissioned AKRIMOTA LIGNITE S Commissioned KLTPS EXTN(Panan) LIGNITE S U 4 - July 07* DHUVRAN GAS S GT-Comm. ST- Feb 07 DHUVRAN GAS S Commissioned SUB TOTAL (GUJARAT) MAHARASTRA GHATGHAR PSTOR S U 1-May 07 U2-July 07* PARAS TPS EXT. U-I COAL S PARLI TPP EX. ST-I COAL S March-07 SUB TOTAL (MAHARASHTRA) * On best efforts being included in X Plan Capacity Addition MP BIRSINGPUR EXT COAL S U 5 - Feb 07 AMARKANTAK U-5 COAL S BANSAGAR II HYDRO S Commissioned BANSAGAR III HYDRO S Commissioned MARIKHEDA HYDRO S Commissioned Page 57 of Chapter 1

142 Demand for Power and Generation Planning BANSAGAR IV HYDRO S Commissioned SUB TOTAL (MP) CHHATTISGARH KORBA EAST EXT. COAL S U 1 - Mar 07 U 2 - May 07 SUB TOTAL(CHHATTIS) SUB TOTAL WR (STATE SECTOR) PRIVATE SECTOR CHHATTISGARH RAIGARH TPP U-1 COAL P June 07* SUB TOTAL (CHHATISGARH) P GUJARAT JAMNAGAR REFRES P AKHAKHOL CCPP BLK-I GAS P SUB TOTAL (GUJARAT) P MP MAHESHWAR HYDRO P BINA COAL P SUB TOTAL (MP) P SUB TOTAL WR (PRIVATE SECTOR) TOTAL (WESTERN REGION) SOUTHERN REGION CENTRAL SECTOR NLC NEYVELI EXT LIGNITE C Commissioned NEYVELI II EXP LIGNITE C SUB TOTAL (NLC) NPC KUDANKULAM U-1 NUCLEAR C KAIGA U3 NUCLEAR C March-07 MAPP UPGRADING NUCLEAR C 100 Commissioned SUB TOTAL (NPC) NTPC SIMHADRI COAL C Commissioned RAMAGUNDAM III COAL C Commissioned SUB TOTAL (NTPC) SUB TOTAL SR (CENTRAL SECTOR) STATE SECTOR AP RAYALSEMA-II COAL S Commissioned U 4 - Mar 07 SRISAILAM LBPH HYDRO S Commissioned Page 58 of Chapter1

143 Demand for Power and Generation Planning JURALA PRIYA HYDRO S June 07* SUB TOTAL (AP) KARNATAKA RAICHUR U7 COAL S Commissioned ALMATI DAM HYDRO S Commissioned BELLARY COAL S March-07 SUB TOTAL (KARNATAKA) KERALA KUTTIYADI AUG. HYDRO S SUB TOTAL (KERALA) TAMILNADU PYKARA ULTIMATE HYDRO S Commissioned PERUNGULAM GAS S Commissioned (VALUTHUR) BHAWANI KATHALAI 1&2 HYDRO S KUTRALAM GAS GAS S Commissioned SUB TOTAL (TAMILNADU) * On best efforts being included in X Plan Capacity Addition PONDICHERRY KARAIKAL CCGT GAS S SUB TOTAL SR (STATE SECTOR) PRIVATE SECTOR AP PEDDAPURAM CCGT GAS P Commissioned VEMAGIRI-I GAS P Commissioned GAUTAMI GAS P GTs- Feb 07 ST - Mar 07 RAMGUNDAM BPL COAL P JEGRUPADU-EXT 1 GAS P Commissioned KONASEEMA GAS P GT 1&2- Feb 07 ST - Mar 07 SUB TOTAL (AP) P KARNATAKA HASSAN LNG P KANIMINKE CCPP NAPHTHA P SUB TOTAL (KARNATAKA) P TAMILNADU KURUPPUR GAS P Commissioned VALENTHARAVAI GAS P Commissioned NEYVELI ZERO LIGNITE P Commissioned SUB TOTAL (TAMILNADU) P SUB TOTAL SR (PRIVATE SECTOR) TOTAL (SOUTHERN REGION) Page 59 of Chapter 1

144 Demand for Power and Generation Planning EASTERN REGION CENTRAL SECTOR DVC MEZIA-U4 COAL C Commissioned MEZIA-U5 COAL C March-07 MEZIA-U6 COAL C May 07* MAITHON-RBC COAL JV CHANDRAPURA U7&8 COAL C SUB TOTAL (DVC) NHPC TEESTA V HYDRO C PURLIA PSS PSTOR JV March-07 TEESTA LOW DAM III HYDRO C TEESTA LOW DAM IV HYDRO C SUB TOTAL (NHPC) NTPC TALCHER-II COAL C Commissioned NORTH K PURA COAL C KAHALGAON U-5,6&7 COAL C U5 - Feb 07 U6 - Mar 07 U7 - Jun 07* KAHALGAON II COAL C BARH COAL C SUB TOTAL (NTPC) SUB TOTAL ER (CENTRAL SECTOR) STATE SECTOR JHARKHAND TENUGHAT EXT COAL S SUB TOTAL (JHAR) ORISSA BALIMELA II HYDRO S March-07 SUB TOTAL (ORISSA) WEST BENGAL SAGARDIGHI-I COAL S U 1 - Mar 07 U 2 - Apr 07 DPL EXTENSION COAL S U 7 - Mar 07 SANTALDIH COAL S June 07* BAKRESHWAR 4,5 COAL S U 4 - Jul 07 SUB TOTAL (WB) SUB TOTAL ER (STATE SECTOR) * On best efforts being included in X Plan Capacity Addition Page 60 of Chapter1

145 Demand for Power and Generation Planning PRIVATE SECTOR BIHAR BIHTA TPS COAL P SUB TOTAL (BIHAR) P JHARKHAND JOJOBERA COAL P Commissioned SUB TOTAL (JHAR) P SUB TOTAL ER (PRIVATE SECTOR) TOTAL (EASTERN REGION) NORTH EASTERN REGION NEEPCO TUIRIAL HYDRO C KOPILI II HYDRO C Commissioned TRIPURA GAS GAS C SUB TOTAL (NEEPCO) SUB TOTAL NER (CENTRAL SECTOR) STATE SECTOR ASSAM KARBI LANGPI HYDRO S Commissioned U2 - Feb 07 LAKWA WH GAS S SUB TOTAL (ASSAM) MEGHALAYA MYNTDU(LISKA) HYDRO S BYRNIHAT HFO S MENDIPATHAR HFO S SUB TOTAL (MEGHALAYA) MIZORAM BAIRABI (THERMAL) HFO S Commissioned BAIRABI HYDRO HYDRO S SUB TOTAL (MIZORAM) NAGALAND DIMAPUR DGPP HFO S SUB TOTAL (NAGALAND) TRIPURA BARMURA GT GAS S Commissioned ROKHIAU7 GAS S Commissioned SUB TOTAL(TRIPURA) MANIPUR MANIPUR DG DIESEL S Commissioned SUB TOTAL NER (STATE SECTOR) TOTAL (NORTH EASTERN REGION) Page 61 of Chapter 1

146 Demand for Power and Generation Planning A&N ISLAND BAMBOO FLAT DIESEL P Commissioned RANGIT BAY DIESEL S Commissioned SUB TOTAL(A&N) TOTAL (ALL INDIA) Page 62 of Chapter1

147 Demand for Power and Generation Planning LIST OF PROJECTS LIKELY TO SLIP TO 11 th (Due to constrains on BHEL side) Appendix-1.4 Project Name Total Capacity Likely during 10 th Slipping to 11 th Likely date of Commissioning Hydro Maneri Bhal-II Sept.07-Dec.07 Ghatghar PSS July-07 Jurala Priya June 07 Balimela May-07 Sub-total (Hy) 618 Thermal GHTPP-II May,07 Sipat II May-07 Kahalgaon-II June-07 Korba East Ext May-07 Raigarh May-07 Bakreshwer U 4& July-07 Mejia U-5& May2007 Rayalseema May2007 Bellary April2007 Sagardighi April2007 Santaldih June2007 Kutch Lignite TPS July 2007 Dholpur August2007 GH TPP II May 2007 Kahalgaon June 2007 Dabhol-II June 2007 Sub-total (Th) 5109 Total (Hy+Th.) 5727 Page 63 of Chapter 1

148 Demand for Power and Generation Planning Appendix 1.5 LIST OF UNITS DROPPED FROM 10 th PLAN (41,110 MW) THERMAL PROJECTS Name of the Agency Name of the Project MW Rajasthan (RRECL) Mathania ISCC GTs+ST 140 Jharkand Tenughat TPP II Unit Pondicherry Karaikal CCPP GT+ST 100 Meghalaya Byrnihat DGPP 24 Meghalaya Mendipathar DGPP 24 Bihta TPPU Bihar Gujarat Jamnagar TPP U-!&2 2x Karnataka Hassan CCPP GT+ST 189 Karnataka Kaniminike CCPP GT+ST M.P Bina TPP U-!&2 2x A.P Ramagundam TPP BPL U-!&2 520 SUB TOTAL THERMAL HYDRO PROJECTS Name of the Agency NAME OF THE PROJECT MW NHPC Bav II Maharashtra 37 NEEPCO Tuirial Mizoram 60 PIW/PSEB Shahpurkandi,Punjab 168 HPSEB Kashang I 66 Dhamwari Power Dhamwari Sunda HEP 70 P&E Dept. Mizoram Bairabi Dam, Mizoram 80 SUB TOTAL HYDRO GRAND TOTAL Page 64 of Chapter1

149 Demand for Power and Generation Planning LIST OF THE THERMAL PROJECTS SLIPPING FROM 10 th PLAN (41,110 MW) AND INCLUDED IN 11 TH PLAN (As per 30,641 MW) THERMAL PROJECTS:- Name of the Agency Name of the Project IC (MW) NTPC Barh STPP 660 Kahalgaon STPS Stage II Ph-I U North Karanpura TPP U Sipat STPP-I 2x660 U-1& Dadri TPS 1x Sipat STPS II U NLC Neyveli TPS II Exp 2*500 U-1&2 500 NLC Barsingsar lignite TPP U DVC Maithon RBC TPP 4x250 U-1 to DVC Chandrapura TPS Extn. U-7&8 500 NEEPCO Monarchak CCPP GT+ST 500 UP. Anpara ( c ) TPS U Assam ( Lakwa WH ST 38 ASEB) West Bengal Bakreshwer TPS-II U Punjab Goindwal TPP U-I&2 500 A.P. Jegurupadu CCPP EXT. GT 10 TOTAL 7458 Appendix 1.6 Page 65 of Chapter 1

150 Demand for Power and Generation Planning Appendix 1.7 LIST OF HYDRO PROJECTS SLIPPING FROM 10 th PLAN (41,110 MW) AND INCLUDED IN 11 TH PLAN (As per 30,641 MW) Name of the Agency NAME OF THE PROJECT IC(MW) NHPC Sewa II J&K 120 NJPC Rampur (J.V.) 400 THDC Tehri St-.II (PSS) 1000 NHPC WB Teesta Low Dam -IV 168 * NHPC/ WBPDCL Purlia PSS 675 NHDC Omkaresswer MP 390 Meghalaya Myntdu (Leiska) I 84 SMHPC Maheshwar 400 A.P. Jurala Priya 39 Tamil Nadu Bhawani Kathalai 60 THDC Koteshwer THDC 400 TVL Teesta Low Dam III (IPP) 132 J&K Baglihar 450 Kerala Kuutiyadi Aug. 100 Sikkim Teesta -V 510 NHDC Omkareshwar 130 TOTAL HYDRO 5058 * capacity changed to 160 MW Page 66 of Chapter1

151 Demand for Power and Generation Planning Working Group on Power for 11th Plan HYDRO A. PROJECTS UNDER CONSTRUCTION TOTAL THERMAL THERMAL BREAKUP COAL LIGNITE GAS Appendix 1.8 SUMMARY OF CAPACITY ADDITION PROPOSED DURING 11TH PLAN NUCLEAR TOTAL CENTRAL SECTOR STATE SECTOR PRIVATE SECTOR ALL-INDIA B. PROJECTS WHERE LOA IS YET TO BE PLACED (COMMITTED PROJECTS) CENTRAL SECTOR STATE SECTOR PRIVATE SECTOR ALL-INDIA CENTRAL SECTOR STATE SECTOR PRIVATE SECTOR ALL-INDIA C. PROJECTS WITH BEST EFFORTS TOTAL FEASIBLE AT PRESENT CENTRAL SECTOR STATE SECTOR PRIVATE SECTOR ALL-INDIA TOTAL SHELF OF PROJECTS CENTRAL SECTOR STATE SECTOR PRIVATE SECTOR ALL-INDIA Page 67 of Chapter 1

152 LIST OF PROJECTS PROPOSED FOR LIKELY BENEFITS DURING 11TH PLAN --HYDRO Sl.No. PLANT NAME STATE AGENCY SECT OR ULTIMAT E CAPACIT Y (MW) TYPE BENEFITS IN 11TH PLAN LOA DATE Appendix 1.8 (contd.) EQUIPMENT ORDER PROJECTS UNDER CONSTRUCTION 1 PARBATI - II HP NHPC C 800 ROR SEPT,02 DEC,02 BHEL 2 CHAMERA-III HP NHPC C 231 ROR SEP, 05 JAN,07 ALSTOM 3 PARBATI - III HP NHPC C 520 ROR SEP,05 DEC,06 BHEL 4 SEWA-II J&K NHPC C 120 ROR SEPT, 03 JUNE,06 BHEL 5 URI-II J&K NHPC C 240 ROR SEPT,05 DEC,06 ALSTOM 6 OMKARESHWAR MP NHDC C 520 ROR JUNE, 03 JUNE,03 SIEMENS 7 TEESTA V SIK NHPC C 510 ROR DONE NOV,01 MITSUI 8 TEESTA LOW DAM-III WB NHPC C 132 ROR OCT,03 JULY,04 VA TECH 9 TEESTA LOW DAM-IV WB NHPC C 160 ROR DEC 05. MAR, SUBANSIRI LOWER AR.PR. NHPC C 2000 STO DEC,03 FEB,05 ALSTOM 11 KOTESHWAR UKND THDC C 400 STO AUG,02 MAR,03 BHEL 12 KAMENG AR.PR. NEEPCO C 600 STO DEC,04 DEC,04 BHEL 13 KOL DAM HP NTPC C 800 STO JUNE, 03 JULY,04 BHEL 14 LOHARI NAGPALA UKND NTPC C 600 ROR JULY,06 SEP UHL - III HP HPJVVNL S 100 ROR SEPT.05 FEB,07 16 BAGLIHAR-I J&K JKPDC S 450 ROR DONE JULY,99 SIEMENS 17 JURALA PRIYADARSHNI AP APGENCO S 234 STO April, 04 MAR,04 CEMC, CHINA 18 NAGARJUNA SAGAR TR AP APGENCO S 50 STO MAY, 05 MAY,06 BHEL 19 VARAHI EXTN. KAR KPCL S 230 ROR NOV, 05 MAY,06 VA TECH 20 ATHIRAPALLI KERL KSEB S 163 ROR MAY,05/ DEC,06 MAY,05 BHEL 21 KUTAYADI EXT. KERL KSEB S 100 ROR AWARDED OCT,03 BHEL 22 BHAWANI BARRAGE II & III TN TNEB S 60 ROR AWARDED NOV,06 23 PURLIA PSS WB WBSEB S 900 PSS JUNE, 01 JULY,2000 MITSUI 24 MYNTDU St-I MEGH MeSEB S 84 STO MAR,04 NOV,05 VA TECH 25 BUDHIL HP LANCO IPP P 70 ROR AWARDED JULY,06 DONGFANF ELC. 26 ALLAIN DUHANGAN HP RSWML P 192 ROR NOV, 05 NOV,05 BHEL 27 MALANA II HP EVREST PC P 100 ROR JAN, 06 MAR,07 28 KARCHAM WANGTOO HP JPKHCL P 1000 ROR AWARDED MAR,07 29 SRINAGAR UKND GVK P 330 ROR MAR, MAHESHWAR MP IPP P 400 STO AWARDED CHUJACHEN SIKKIM GATI P 99 ROR AWARDED DEC,06 ALSTOM SUB-TOTAL ( UNDER CONSTRUCTION) C: Central Sector; S: State Sector; P: Private Sector; ROR : Run of River; STO: Storage; PSS: Pumped Storage AGENCY Page 68 of Chapter 1

153 LIST OF PROJECTS PROPOSED FOR LIKELY BENEFITS DURING 11TH PLAN --HYDRO Sl.No. PLANT NAME STATE AGENCY SECT OR ULTIMAT E CAPACIT Y (MW) TYPE BENEFITS IN 11TH PLAN LOA DATE Appendix 1.8 (contd.) EQUIPMENT ORDER PROJECTS WHERE LOA IS YET TO BE PLACED 1 RAMPUR HP SJVNL C 412 ROR FEB, 07 2 TEHRI PSS UKND THDC C 1000 PSS JULY, 07 AUG,07 3 TAPOVAN VISHNUGARH UKND NTPC C 520 ROR DEC, VYASI UKND NHPC C 120 STO JUNE, SAWARA KUDDU HP PVC S 110 ROR JUNE, PALLIVASAL KERL KSEB S 60 ROR MAR, MANKULAM KERL KSEB S 40 STO MAR, THOTTIAR KERL KSEB S 40 ROR MAR, LOWER JURALA AP APGENCO S 240 STO MAY, NEW UMTRU MEGH MeSEB S 40 ROR MAR, LAMBADUG HP IPP P 25 ROR MAR, SORANG HP SORAND PC P 100 ROR MAR, TIDONG-I HP PCP/IPP P 100 ROR JULY, TANGU ROMAI HP PCP/IPP P 50 ROR JULY, UBDC- III PUN MALANA POWER P 75 ROR JUNE, SADAMANDER SIK GATI P 71 ROR JUNE, BHASMEY SIK GATI P 51 ROR SEP, TEESTA III SIK TEESTA URJA P 1200 ROR MAR, 07 FEB,07 SUB-TOTAL ( COMMITTED) TOTAL FEASIBLE HYDRO PROJECTS C: Central Sector; S: State Sector; P: Private Sector; ROR : Run of River; STO: Storage; PSS: Pumped Storage Note: Orders in respect of Rampur HEP, 412 MW & Tapovan Vishnugarh HEP, 520 MW has been recently placed STATUS WISE DETAILS SUMMARY TYPE WISE DETAILS AGENCY Page 69 of Chapter 1

154 LIST OF PROJECTS PROPOSED FOR LIKELY BENEFITS DURING 11TH PLAN --THERMAL Appendix 1.8 (contd) Sl.No PLANT NAME STATE AGENCY SECTO R ULTIMATE CAPACITY (MW) TYPE BENEFITS IN 11TH PLAN COAL LINKAGE STATUS PROJECTS UNDER CONSTRUCTION 1 DADRI EXT(U-5) UP NTPC C 490 LC LINKAGE CCL JUL,06 BHEL 2 SIPAT I CHG NTPC C 1980 PH LINKAGE SECL APR,04 KOREA+ RUSSIA 3 BHILAI JV CHG NTPC C 500 PH LINKAGE SECL MAR, 05 BHEL 4 KORBA III CHG NTPC C 500 PH BLOCK MAR, 06 BHEL 5 BARH-I BIH NTPC C 1980 PH LINKAGE CCL MAR, 05 RUSSIA 6 FARAKKA STAGE-III WB NTPC C 500 PH LINKAGE ECL OCT,06 BHEL 7 CHANDRAPUR JHAR DVC C 500 PH LINKAGE BCCL JUN,06 BHEL 8 BARSINGSAR LIG RAJ NLC C 250 PH-LIG LIGNITE DEC,05 BHEL 9 NEYVELI - II LIG TN NLC C 500 PH-LIG LIGNITE AUG,05 BHEL 10 YAMUNA NAGAR HAR HPGCL S 600 LC LINKAGE CCL AUG,05 CHINA 11 GIRAL U-2 RAJ RRVUNL S 125 PH-LIG LIGNITE NOV,05 BHEL 12 CHABRA TPS RAJ RRVUNL S 500 LC LINKAGE SECL MAR,06 BHEL 13 KOTA U7 RAJ RRVUNL S 195 LC LINKAGE SECL JUN, 06 BHEL 14 SURATGARH EXT RAJ RRVUNL S 250 LC LINKAGE SECL AUG,06 BHEL 15 DHOLPUR RAJ RRVUNL S 330 GAS/LNG JUN,04 BHEL 16 PARICHHA EXT UP UPRVUNL S 500 LC LINKAGE BCCL JUN,06 BHEL 17 HARDUAGANJ UP UPRVUNL S 500 LC LINKAGE CCL JUN,06 BHEL 18 SURAT LIGNITE EXT GUJ GIPCL S 250 PH-LIG LIGNITE MAR,06 BHEL 19 AMARKANTAK MP MPGENCO S 210 LC LINKAGE SECL JUN, 04 BHEL 20 PARLI EXT U-2 MAH MAHA GEN S 250 LC LINKAGE MCL AUG, 06 BHEL 21 PARAS EXT U-2 MAH MAHA GEN S 250 LC LINKAGE MCL AUG, 06 BHEL 22 KAKTIYA AP APGENCO S 500 LC LINKAGE SECL JUL, 05 BHEL 23 VIJAYWADA TPP AP APGENCO S 500 LC LINKAGE MCL JUL, 05 BHEL 24 BELLARY TPS U-2 KAR KPCL S 500 LC LINKAGE REQUIRED AUG, 06 BHEL 25 RAICHUR U 8 KAR KPCL S 250 LC LINKAGE MCL SEP, 06 BHEL 26 VALUTHUR EXT TN TNEB S 92 GAS/LNG MAY, 06 GEA ENERGY 27 BAKRESHWAR U-5 WB WBPDCL S 210 LC LINKAGE ECL NOV.04 BHEL+JAPAN 28 LAKWA WH ASM ASGENCO S 37.2 GAS/LNG MAR, 06 BHEL 29 DIMAPUR DG NAG ELECT.DEPT. S 23 GAS/LNG JUL, 03 BHEL 30 RAIGARH PH II CHG JIN. POWER P 750 PH BLOCK JUN, 04 BHEL 31 PATHADI (LANCO) U1 CHG LANCO-IPP P 300 PH LINKAGE SECL JUL, 05 CHINA 32 PATHADI (LANCO) U2 CHG LANCO-IPP P 300 PH LINKAGE SECL JUL, 05 CHINA 33 SUGEN TORRENT GUJ TORRENT P 1128 GAS/LNG JUN, 05 SIEMENS 34 TROMBAY TPS MAH TATAPOWER P 250 LC IMPORTED COAL JUL, 06 BHEL 35 TORANGALLU KAR JINDAL P 600 LC IMPORTED COAL JUN,06 CHINA 36 BUDGE-BUDGE EXT WB CESC P 250 LC BLOCK REQUIREDSEP, 06 BHEL SUB-TOTAL ( UNDER CONSTRUCTION) C: Central Sector; S: State Sector; P: Private Sector; LC: Load Center; PH: Pit Head; PH-LIG: Lignite based COAL COMPA NY LOA DATE (E&M EQPT.) AGENCY Page 70 of Chapter 1

155 LIST OF PROJECTS PROPOSED FOR LIKELY BENEFITS DURING 11TH PLAN --THERMAL Appendix 1.8 (contd) Sl.No PLANT NAME STATE AGENCY SECTO R ULTIMATE CAPACITY (MW) TYPE BENEFITS IN 11TH PLAN COAL LINKAGE STATUS COAL COMPA NY LOA DATE (E&M EQPT.) AGENCY PROJECTS WHERE LOA IS YET TO BE PLACED 1 BADARPUR-X DELHI NTPC C 980 LC LINKAGE MCL FEB,07 2 DADRI EXT(U-6) UP NTPC C 490 LC LINKAGE CCL DEC, 06 BHEL 3 TPS for DELHI/JHAJJAR HAR NTPC C 1500 LC LINKAGE MCL FEB,07 4 MAUDA MAH NTPC C 1000 PH LINKAGE MCL NOV,07 5 SIMHADRI-EXT AP NTPC C 1000 COASTAL LINKAGE MCL JUN,07 6 ENNORE-JV TN NTPC C 1000 COASTAL LINKAGE MCL JUN,07 7 BARH II BIH NTPC C 1320 PH BLOCK MAY,07 8 NABINAGAR BIH NTPC C 1000 PH LINKAGE CCL JAN,08 9 NORTH K PURA JHAR NTPC C 1320 PH LINKAGE CCL OCT,07 10 BONGAIGAON ASM NTPC C 750 LC LINKAGE NEC/ECL AUG,07 11 MEJIA PH II (DELHI) WB DVC C 1000 PH BLOCK DEC, 06. BHEL 12 BOKARO REPLACEMENT (DELHI) JHAR DVC C 500 PH LINKAGE CCL FEB,07 13 KODERMA U1&2 (DELHI) JHAR DVC C 1000 PH LINKAGE MCL FEB,07 14 DURGAPUR STEEL WB DVC C 1000 PH LINKAGE ECL AUG,07 15 MAITHAN RBC JHAR DVC C 1000 PH LINKAGE BCCL FEB,07 16 BARSINGSAR EXT RAJ NLC C 250 PH-LIG LIGNITE JUL,08 17 TUTICORIN JV TN NLC C 1000 COASTAL LINKAGE MCL DEC,07 18 TRIPURA GAS ILFS TRI ONGC C 750 GAS/LNG JUN,07 19 HISSAR TPS I HAR HPGCL S 500 LC LINKAGE MCL MAR,07 20 HISSAR TPS II HAR HPGCL S 500 LC LINKAGE MCL JUN,08 21 TALWANDI SABO PUN PSEB S 1500 LC LINKAGE REQUIRED JAN,08 22 KALISINDH TPS RAJ RRVUNL S 1000 LC BLOCK REQUIRED JAN,08 23 ANPARA-D UP UPRVUNL S 1000 PH LINKAGE REQUIRED JAN,08 24 OBRA REP UP UPRVUNL S 1000 PH LINKAGE REQUIRED JAN,08 25 KORBA WEST EXT CHG CSEB S 600 PH LINKAGE SECL FEB,07 26 UTRAN GUJ GSECL S 350 GAS/LNG FEB,07 27 SIKKA EXT GUJ GSECL S 500 COASTAL IMPORTED COAL OCT,07 28 UKAI EXT GUJ GSECL S 500 LC LINKAGE REQUIRED JAN,08 29 KHAPER KHEDA EX MAH MAHA GEN S 500 LC LINKAGE MCL FEB,07 30 BHUSAWAL MAH MAHA GEN S 1000 LC LINKAGE MCL JUN,07 31 KORADI REP& OTHERS MAH MAHA GEN S 585 LC LINKAGE JUN,07 32 KORADI EXT MAH MAHA GEN S 1000 LC LINKAGE REQUIRED JAN,08 33 CHANDRAPUR MAH MAHA GEN S 500 PH BLOCK FEB,07 34 MALWA MP MPGENCO S 1000 LC LINKAGE SECL JUN,07 35 SATPURA EXT MP MPGENCO S 500 LC LINKAGE REQUIRED JAN,08 36 KOTHAGUDEM ST-V AP APGENCO S 500 PH LINKAGE MCL FEB,07 Page 71 of Chapter 1

156 LIST OF PROJECTS PROPOSED FOR LIKELY BENEFITS DURING 11TH PLAN --THERMAL Appendix 1.8 (contd) Sl.No PLANT NAME STATE AGENCY SECTO R ULTIMATE CAPACITY (MW) TYPE BENEFITS IN 11TH PLAN COAL LINKAGE STATUS COAL COMPA NY LOA DATE (E&M EQPT.) AGENCY 37 KRISHNAPATNAM AP APGENCO S 1600 COASTAL LINKAGE MCL DEC,07 38 KAKATIYA EXT AP APGENCO S 500 LC BLOCK JAN,08 39 NORTH CHENNAI EXT TN TNEB S 500 LC LINKAGE MCL AUG,07 40 METTUR EXT TN TNEB S 500 LC LINKAGE MCL MAR,07 41 SAGARDIGHI EXT WB WBPDCL S 1000 LC BLOCK REQUIRED DEC,07 42 SANTHALDIH EXT (U 6) WB WBPDCL S 250 LC BLOCK REQUIRED FEB,07 43 GOINDWAL SAHIB PUN GVK P 600 LC BLOCK JAN,08 44 ANPARA-C UP LANCO P 1000 PH LINKAGE NCL NOV,07 45 BARA UP IPP P 1000 LC BLOCK REQUIRED JAN,08 46 ULTRA MEGA SASAN MP LANCO P 3960 LC BLOCK JAN,08 SUB-TOTAL ( COMMITTED) TOTAL FEASIBLE THERMAL PROJECTS C: Central Sector; S: State Sector; P: Private Sector; LC: Load Center; PH: Pit Head; PH-LIG: Lignite based; COASTAL : Coastal Stations Note: Orders in respect of Dadri Ext (U 6), Mezia PH II,Bhusawal,Khaperkheda Ext,Kothagudem and Hissar has been recently placed SUMMARY OF THERMAL CAPACITY ADDITION STATUS WISE DETAILS UNIT SIZE GROUP WISE DETAILS TYPE WISE DETAILS OF COAL PLANTS UNDER CONSTRUCTION LOA TO BE PLACED TOTAL FEASIBLE 660/ / /125 Gas TOTAL FEASIBLE PH LC COASTAL TOTAL COAL STATUS OF COAL AVAILABILITY LINKAGE AVAILABLE LINKAGE REQUIRED BLOCK ALLOTED BLOCK REQUIRED IMPORTED COAL TOTAL COAL Page 72 of Chapter 1

157 LIST OF PROJECTS PROPOSED FOR LIKELY BENEFITS DURING 11TH PLAN --THERMAL Appendix 1.8 (contd) Sl.No PLANT NAME STATE AGENCY SECTO R ULTIMATE CAPACITY (MW) TYPE BENEFITS IN 11TH PLAN COAL LINKAGE STATUS COAL COMPA NY LOA DATE (E&M EQPT.) AGENCY PROJECTS UNDER BEST EFFORTS 1 RIHAND-X UP NTPC C 500 PH LINKAGE REQUIRED DEC,07 2 NORTH K PURA JHAR NTPC C 660 PH LINKAGE CCL AUG,07 3 INTEGRATED PROJECT DARIPALI ORS NTPC C 3200 PH BLOCK SEP,07 4 NABINAGAR BIH NTPC C 1000 PH LINKAGE CCL JAN,08 5 BOKARO STEEL JHAR DVC C 500 PH LINKAGE REQUIRED JUN,07 6 RAGHUNATH PUR WB DVC C 1000 PH BLOCK REQUIREDDEC,07 7 MARGHERITA ASSAM NEEPCO C 480 PH LINKAGE REQUIRED JAN, 08 8 CHHABRA II RAJ RRVUNL S 500 LC BLOCK REQUIREDJAN, 08 9 GUJARAT LIGNITE GUJARAT NLC JV S 1000 PH-LIG LIGNITE JAN, DPL TPS U7A WB WBPDCL S 300 LC BLOCK REQUIREDAUG,07 11 DPL TPS U8 WB WBPDCL S 500 LC BLOCK REQUIREDOCT,07 12 BAKRESHWAR EXT WB WBPDCL S 500 LC BLOCK REQUIREDJAN,09 13 MUZAFFARPUR EXT BIHAR SHALI POW S 500 LC LINKAGE REQUIRED JAN, ROSA UP OSA POWE P 600 PH LINKAGE REQUIRED JAN, BHAIYATHAN CHG IPP P 1600 PH BLOCK JUN,07 16 LANCO NAGARJUNA KAR NPCL-IPP P 1015 COASTAL IMPORTED COAL FEB, HALDIA PH I WB CESC P 600 LC LINKAGE REQUIRED SEP, MALAXMI ORISSA NAVABH P 1040 PH LINKAGE (2.404 MT); JAN,08 ARAT SUB-TOTAL ( BEST EFFORTS) ADDITIONAL PROJECT IDENTIFIED BY STATES 1 Yamuna Nagar EXT HAR S Linkage Required JUN,07 2 Jhajjar TPS (Case 2) HAR P Linkage Required 3 Shankargarh U P P Block Required 4 Dopaha U P P Block Required 5 Chhabra III RAJ P Block Required 6 Kawai RAJ P Block Required 7 Dopawe MAH P Imported Coal 8 Marwa TPS CHG S Block Available SEP,07 9 Korba South CHG S Linkage Required 10 Godhna CHG S Linkage Required 11 Ennore EXP TN S Linkage Required 12 Tuticorin Ext TN S Linkage Required DEC,07 13 Cuddalore TN P Imported Coal 14 Kudgi KAR S Block Requitred DEC,07 15 Barauni TPS BIH S Linkage Required SUB-TOTAL ( ADDITIONAL IDENTIFIED) C: Central Sector; S: State Sector; P: Private Sector; LC: Load Center; PH: Pit Head; PH-LIG: Lignite based; COASTAL : Coastal Stations Page 73 of Chapter 1

158 Appendix 1.8 (contd.) LIST OF PROJECTS PROPOSED FOR LIKELY BENEFITS DURING 11TH PLAN -NUCLEAR Sl.No. PLANT NAME STATE AGENCY SECTOR NO.OF UNITS UNIT SIZE ULTIMATE CAPACITY (MW) TYPE BENEFITS IN 11th PLAN ( ) PROJECTS UNDER CONSTRUCTION 1 RAPP U5&6 RAJ NPC C PHWR KUDANKULAM U 1,2 TN NPC C LWR PFBR(Kalapakkam) TN NPC C FBR KAIGA U-4 KAR NPC C PHWR TOTAL NUCLEAR(UNDER CONSTRUCTION) C: Central Sector UNDER CONSTRUCTION HYDRO LOA TO BE PLACED FEASIBLE UNDER CONSTRUCTION TYPE WISE STATUS WISE SUMMARY THERMAL LOA TO BE PLACED FEASIBLE NUCLEAR UNDER CONSTRUCTION UNDER CONSTRUCTION TOTAL LOA TO BE PLACED TOTAL FEASIBLE Page 74 of Chapter 1

159 Appendix 1.9 YEAR-WISE COAL REQUIREMENT FOR 11th PLAN (tentative)-utilities th Plan details INSTALLED CAPACITY(MW) Programme EXISTING CAPACITY PLF(%) GENERATION ADDITIONS RETIREMENTS PLF(%) GENERATION TOTAL INSTALLED CAPACITY TOTAL GENERATION(BU) COAL REQUIREMENT (Million Tons) TRANSIT 1% CUMULATIVE STOCK ADDITIONAL STOCK TOTAL COAL REQUIREMENT Note: Total installed capacity of coal fired stations at the end of = 1,18,816 MW 2. Requirement of coal in the year for the coal fired capacity indicated above = 545 MT 3.The above assumes only 40% generation from the new capacity addition during the year. 4.The requirement of coal for the total installed capacity of 1,18,816 MW at the end of 11th plan,in the year first year of 12th plan i.e would be about 600 MT 5. Any new capacity addition during the year shall need additional coal Page 75 of Chapter 1

160 Appendix 1.10 Shelf of Projects for Likely benefits during 12th plan Type Best Effort Projects of 11th plan 12th Plan Projects (MW) Total Shelf of Projects (MW) Hydro Thermal Coal Lignite Gas/LNG Nuclear Total Page 76 of Chapter 1

161 Appendix 1.10 (contd) SHELF OF HYDRO PROJECTS FOR LIKELY BENEFITS DURING 12 th PLAN Sl. No Name of scheme State Agency Sector Type IC (MW) Likely Benefit in 12th Plan (MW) 1 Bharmour H P IPP P ROR Bajoli Holi H P IPP P ROR Chirgaon (Majhgaon) H P HPSEB S ROR Dhaula Sidh H P IPP P ROR Dhamvari Sunda H P HPSEB S ROR Harsar H P IPP P ROR Jhangi Thopan H P IPP P ROR Kutehr H P IPP P ROR Kashang-II H P HPSEB S ROR Luhri H P SJVNL C ROR Pudital Lassa H P IPP P STO Renuka Dam H P HPSEB S STO Sainj H P HPSEB S ROR Tidong-II H P IPP P ROR Thopan Powari H P IPP P ROR Kashang - I & III H P HPJVVNL S ROR Shongtong Karcham H P HPSEB S ROR Nimoo Bazgo J & K NHPC C ROR Chutak J & K NHPC C ROR Baglihar-II J & K PDC S ROR Kiru J & K To be decided To be decided ROR Kishan Ganga J & K NHPC C STO Kawar J & K To be decided To be decided ROR Parnai J & K PDC S ROR Pakhal Dul J & K NHPC C STO Ratle J & K To be decided To be decided ROR Sawalkot J & K PDC S ROR Kotli Bhel I A UKND NHPC C ROR Kotli Bhel I B UKND NHPC C ROR Kotli Bhel II UKND NHPC C ROR Lata Tapovan UKND NTPC C ROR Vishnugad Pipalkoti UKND THDC C ROR Arkot Tiuni UKND UJVNL S ROR Alaknanda (Badrinath) UKND IPP P ROR Bogadiyar Sirkari Bhyal UKND IPP P ROR Mapang Bogudiyar UKND IPP P ROR Bowala Nand Prayag UKND UJVNL S ROR Devsari Dam UKND SJVNL C STO Hanol Tiuni UKND IPP P ROR Jakhol Sankari UKND SJVNL C ROR Jelam Tamak UKND THDC C ROR Lakhwar UKND NHPC C STO Maleri Jhelam UKND THDC C ROR Mori Hanol UKND IPP P ROR Nand Prayag Lingasu UKND UJVNL S ROR Naitwar Mori (Dewra Mori) UKND SJVNL C ROR Pala Maneri UKND UJVNL S ROR Rupsiyabagar Khasiyabara UKND NTPC C ROR Sirkari Bhyal Rupsiabagar UKND UJVNL S ROR Singoli Bhatwari UKND IPP P ROR Page 77 of Chapter 1

162 Appendix 1.10 (contd) SHELF OF HYDRO PROJECTS FOR LIKELY BENEFITS DURING 12 th PLAN Sl. No Name of scheme State Agency Sector Type IC (MW) Likely Benefit in 12th Plan (MW) 51 Tamak Lata UKND UJVNL S ROR Taluka Sankri UKND UJVNL S ROR Tuini Plasu UKND UJVNL S ROR Dhauli Ganga Intermediate UKND NHPC C ROR Gauri Ganga St III-A UKND NHPC C ROR Shahpur Kandi PUN PSEB S STO Hoshangabad MP NHDC C ROR Handia MP NHDC C ROR Borus MP NHDC C ROR Matnar CHG CSEB S ROR Dummugudem A P APID S STO Pollavaram MPP A P APID S STO Chinnar KERL KSEB S ROR Achenkovil KERL KSEB S STO Kundah PSS T N TNEB S PSS Gundia KAR KPCL S ROR Ramam St-III W B NTPC C ROR Ramam St-I W B WBSEB S ROR Panan SIK IPP P ROR Dikchu SIK IPP P ROR Rolep SIK IPP P ROR Rangit-II SIK IPP P ROR Rangit-IV SIK IPP P ROR Lachen SIK NHPC C ROR Rangyong SIK IPP P ROR Rukel SIK IPP P ROR Rongnichu SIK IPP P STO Teesta St.-I SIK IPP P ROR Teesta St.-II SIK IPP P ROR Teesta St.-IV SIK NHPC C ROR Teesta-VI SIK IPP P ROR Teesta-III SIK Teesta Urja P ROR Pare Ar Pr NEEPCO C STO Siang Middle (Siyom) Ar Pr IPP P STO Dibbin Ar Pr To be decided To be decided ROR Badao Ar Pr To be decided To be decided ROR Kapak Leyak Ar Pr To be decided To be decided ROR Talong Ar Pr To be decided To be decided STO Etalin Ar Pr NTPC C STO Attunli Ar Pr NTPC C ROR Siang Lower Ar Pr IPP P STO Nyamjunchhu St-I Ar Pr IPP P ROR Nyamjunchhu St-II Ar Pr IPP P ROR Nyamjunchhu St-III Ar Pr IPP P ROR Dibang (Joint venture) Ar Pr NHPC C STO Tawang-II Ar Pr NHPC C STO Tawang-I Ar Pr NHPC C STO Lohit Ar Pr To be decided To be decided STO Subansiri Upper Ar Pr NHPC C STO Subansiri Middle Ar Pr NHPC C STO Page 78 of Chapter 1

163 Appendix 1.10 (contd) SHELF OF HYDRO PROJECTS FOR LIKELY BENEFITS DURING 12 th PLAN Sl. No Name of scheme State Agency Sector Type IC (MW) Likely Benefit in 12th Plan (MW) 101 Lower Kopili ASM AGENCO S ROR Upper Borpani ASM AGENCO S ROR Tipaimukh MANI NEEPCO C STO Umiam Umtru-V MEGH MeSEB S ROR Ganol MEGH MeSEB S ROR Mawhu MEGH NEEPCO C ROR TOTAL Note: C: Central Sector; S: State Sector; P: Private Sector; ROR: Run of River; STO: Storage Page 79 of Chapter 1

164 Appendix 1.10 (contd) SHELF OF COAL AND LIGNITE BASED PROJECTS FOR LIKELY BENEFITS DURING 12th PLAN S.NO NAME STATE AGENCY ULTIMATE CAPACITY (MW) LIKELY BENEFITS IN 12th PLAN (MW) 1 YAMUNANAGAR EXT HAR HRVUNL JHAJJAR HAR IPP TALWANDI SABO PUN PSEB NABHA PUN PSEB LEHRA GHAGGAR PUN PSEB CHHABRA RAJ RRVUNL CHHABRA III RAJ IPP KALISINDH TPS RAJ RRVUNL KAWAI RAJ IPP JALIPA/ KAPURDI- LIGNITE RAJ IPP RIHAND EXT@ U P NTPC MAYURPUR (SONEBHADRA) U P UPRVUNL U P ROSA P.C BARA TPS U P UPRVUNL OBRA REPLACEMENT U P UPRVUNL SHANKARGARH U P IPP DOPAHA U P IPP ULTRA MEGA AKALTARA CHG IPP INTEGRATED PROJECT LARA CHG NTPC CHG IPP MARWA CHG CSEB KORBA SOUTH CHG CSEB GODHANA CHG CSEB ULTRA MEGA MUNDRA GUJ IPP BHAVNAGAR LIGNITE GUJ NIRMA GUJARAT GUJ NLC PIPAVAV POWER PROJECT GUJ GPCL JV ULTRA MEGA GIRYE MAH IPP DOPAWE MAH IPP ULTRA MEGA SASAN MP LANCO SHAHPUR BHITONI MP MPGEN ULTRA MEGA KRISHNAPATNAMA P IPP KRISHNAPATNAM A P APGENCO LANCO KAR IPP ULTRA MEGA TADRI KAR IPP Page 80 of Chapter 1

165 Appendix 1.10 (contd) SHELF OF COAL AND LIGNITE BASED PROJECTS FOR LIKELY BENEFITS DURING 12th PLAN S.NO NAME STATE AGENCY ULTIMATE CAPACITY (MW) LIKELY BENEFITS IN 12th PLAN (MW) 36 RAICHUR NEW KAR KPCL KOWSHIKA TPP KAR KPCL KUDGI TPP KAR KPCL NANDUR TPP KAR KPCL NEYVELI III LIGNITE T N NLC JAYANKONDAM LIGNITE T N NLC ENNORE EXT T N TNEB TUTICORIN EXT T N TNEB CUDDALORE T N IPP ULTRA MEGA CHEYYUR T N IPP NABINAGAR BIHAR NTPC MUZAFFARPUR EXT BIHAR VAISHALI POWER BARAUNI EXT BIHAR BSEB KATIHAR BIHAR BSEB NABINAGAR BIHAR BSEB PIRPIANTI BIHAR BSEB ULTRA MEGA JHARKHAND BIHAR IPP NORTH KARAN JHAR NTPC BOKARO JHAR DVC TENUGHAT EXT JHAR TVNL COAL BASED TPP PHASE I JHAR CESC COAL BASED TPP PHASE II JHAR CESC ULTRA MEGA ORISSA ORI IPP INTEGRATED PROJECT ORI NTPC NUELPOI ORI CESC RENGALI ORI NLC OPGCL JV ORI OPGCL ORI NAVBHARAT HALDIA WB CESC KATWA WB WBPDCL RAGHUNATH WB DVC DPL WB WBPDCL DPL WB WBPDCL BAKRESHWAR WB WBPDCL Page 81 of Chapter 1

166 Appendix 1.10 (contd) SHELF OF COAL AND LIGNITE BASED PROJECTS FOR LIKELY BENEFITS DURING 12th PLAN S.NO NAME STATE AGENCY ULTIMATE CAPACITY (MW) LIKELY BENEFITS IN 12th PLAN (MW) 70 BARGOLOI TPS ASM ASEB BADARPUR JV ASM ASEB CHANDRAPUR JV ASM ASEB MARGHERITA ASM NEEPCO GARO HILL MEGH NEEPCO WEST KHASI HILLS TPP MEGH NEEPCO TOTAL BEST EFFORT PROJECTS DURING 11TH PLAN NOTE: THE LIST INCLUDES MW PROJECTS INCLUDED AS PROJECTS WITH BEST EFFORTS IN 11TH PLAN Page 82 of Chapter 1

167 Appendix 1.10 (contd) IDENTIFIED GAS BASED PROJECTS FOR LIKELY BENEFITS DURING 12th PLAN Sl.No. PLANT NAME STATE AGENCY SECTO R ULTIMATE CAPACITY (MW) LIKELY BENEFITS IN 12th PLAN (MW) 1 KAYAMKULAM KERL NTPC C KAWAS II GUJ NTPC C GANDHAR II GUJ NTPC C PRAGATI II DELHI PRAGATI POWER S PRAGATI III (BAWANA) DELHI PRAGATI POWER S URAN MAH MAHAGENCO S RELIANCE-DADRI UP RELIANCE ENERGY P PYGUTHAN GUJ GPECL P ESSAR HAZIRA GUJ ESSAR POWER P KANNUR KERL KANNUR POWER PVT LTD P TOTAL Note: If Gas/LNG becomes available at reasonable price, some of the above mentioned gas based projects may yield benefits during 11th plan Page 83 of Chapter 1

168 Appendix 1.10 (contd) SHELF OF NUCLEAR PROJECTS FOR LIKELY BENEFITS DURING 12th PLAN S.NO. NAME STATE AGENCY LIKELY BENEFITS IN 12th PLAN (MW) 1 KUDANKULAM U3,4 T N NPC KUDANKULAM U5,6 T N NPC JAITAPUR 1,2 GUJ NPC RAPP EXT RAJ NPC KAPP 3&4 KAR NPC LWR 3,4 NPC 2000 Sub total (NPCIL) NEW NUCLEAR NTPC 2000 Sub total (NTPC) TOTAL Page 84 of Chapter 1

169 Demand for Power and Generation Planning Appendix 1.11 COMPARATIVE PERFORMANCE OF PARTERNERSHIP IN EXCELLENCE (PIE) STATIONS NTPC AS PIE PARTNER Sl Station Unit No. Capacit No. y under PIE MW Generat ing Cap. (MW) Dec'05 Dec'06 Apr-Dec'05 Apr-Dec'06 Change in 'Apr-Dec' period Act Gen Act PLF Act Gen Act PLF Act Gen Act PLF Act Gen Act PLF Generation change PLF change MU % Net % 1 Tenughat 1, Ennore 2,3, Bokaro 'B' 1,2, Parichha 1, Durgapur DVC 3, Harduaganj 3,7 (4)* RPH 1, Chandrapura 1,2, IP 2,3,4, Panki 3, Obra 7 to Patratu 1,2 (9,10)* Durgapur DPL 1 to Total * Units are under long shut down. Page 85 of Chapter 1

170 Demand for Power and Generation Planning Appendix-1.12 (Page 1 of 2) STATE WISE LIST OF HYDRO RM&U PROJECTS COMPLETED IN THE 10 TH PLAN (PHASE I PROJECTS* & PHASE II PROJECTS) As on S. No Project, Agency Inst. Cap. (MW) Cost (Rs. in Crs.) Estimated Actual Benefits (MW) Himachal Pradesh 1. Pong, BBMB 6x (U) Punjab 2. Shanan Ph.A, PSEB Karnataka 3. Nagjhari, U- 1&3, KPCL 4. Supa PH, KPCL 5. Mahatma Gandhi*, VVNL 6. Munirabad, VVNL 7. Mani Dam, KPCL 8. Shivasamudr am, VVNL 9. Bhadra, Ph.II, KPCL Kerala 10. Pallivasal, KSEB 11. Sengulam, KSEB 12. Panniar, KSEB Tamilnadu 13. Pykara*, TNEB 14. Papanasam*, TNEB Category Year of completion RM&U x15+ 1x R&M x RM&U (U) 2x R&M x12+4x (U) (LE) RMU&LE x9+1x RM&LE (LE) 2x R&M x3+4x RM&LE (LE) 1x (LE) RM&LE x5+3x (LE) 4x (LE) 2x (LE) 3x6.65+1x11+ 2x (LE) 4x (U) (LE) RM&LE RM&LE RM&LE RM&LE RMU&LE Page 86 of Chapter 1

171 Demand for Power and Generation Planning Appendix-1.12 (Page 2 of 2) S. No Project, Agency Orissa 15. Hirakud-I, U- 3&4*, OHPC West Bengal 16. Maithon, U- 2*, DVC Maharashtra 17. Bhira Tail Race, MSPGCL 18. Tillari, MSPGCL 19. Koyna Gen. Complex, MSPGCL Meghalaya 20. Umium St.I* MeSEB 21. Khandong, Inst. Cap. (MW) Cost (Rs. in Crs.) Estimated Actual Benefits (MW) 2x (U) (LE) 1x (LE) +3.20(U) Category Year of completion RMU&LE RMU& LE x R&M x (U) RM&U x70+4x80+ 4x R&M x (LE) RM&LE x R&M NEEPCO Total [ (U) (LE)] Abbreviations: R&M Renovation & Modernisation; RM&U Renovation, Modernisation & Uprating, RM&LE Renovation, Modernisation & Life Extension RMU&LE Renovation, Modernisation, Uprating & Life Extension; R&M+Res.-Renovation & Modernisation + Restoration; RM&LE+Res.- Renovation, Modernisation & Life Extension + Restoration; RM&U+Res. Renovation, Modernisation & Uprating + Restoration. MW Mega Watt; Res Restoration; U Uprating; LE Life Extension Phase I Projects started in 1987; Phase II Projects started in 1998 Page 87 of Chapter 1

172 Demand for Power and Generation Planning Appendix-1.13 (Page 1 of 2) STATE WISE LIST OF ONGOING HYDRO RM&U PROJECTS PROGRAMMED FOR COMPLETION IN THE 10 TH PLAN (PHASE I PROJECTS* & PHASE II PROJECTS) As on S. No Project, Agency Jammu & Kashmir 1. Sumbal Sindh*, J&KPDC Punjab 2. Ganguwal,U- 1, BBMB 3. Kotla, U-1, BBMB 4. Anandpur Sahib, PSEB Rajasthan 5. Jawahar Sagar, RRVUNL 6. Rana Pratap Sagar, RRVUNL Uttaranchal 7. Chibro, UJVNL Inst. Cap. (MW) Cost (Rs. in Crs.) Estimated cost Expend. Incurred 2x (as on ) 1x (incl. IDC 6.28) 1x (incl. IDC (as on ) 6.28) 4x (as on ) Benefits (MW) Category Completion Schedule - R&M (LE) (Res) (LE) (Res) RM&LE+R es. RM&LE+R es R&M x N.A - R&M x N.A - R&M x (as on ) - R&M Khodri, UJVNL 9. Chilla, UJVNL Andhra Pradesh 10. Lower Sileru, APGENCO Karnataka 11. Varahi, KPCL 4x (as on ) 4x (as on ) - R&M R&M x N.A - R&M x (as on ) - R&M Page 88 of Chapter 1

173 Demand for Power and Generation Planning S. No Project, Agency 12. Sharavathy, Ph.A, KPCL Kerala 13. Neriamangalam* KSEB Tamil Nadu 14. Mettur Dam*, TNEB Orissa 15. Hirakud-I (Sw.yard)*, OHPC Maharashtra 16. Koyna St.III, MSPGCL Inst. Cap. Cost (Rs. in Crs.) (MW) Estimated Expend. Incurred 10x ( ) 3x (as on ) 4x (as on ) (as on x80@ (tentativ e) 4.25 (as on ) Benefits (MW) Category Appendix-1.13 (Page 2 of 2) Completion Schedule - R&M (LE) (U) 10.00(U) (LE) Total @ [19.00(U) (LE) (Res.)] RMU&LE RMU& LE R&M R&M Installed Capacity Koyna St. III at Sl. No. 16 not included in the total, as the same has already been accounted for at Sl. No. 19 of Appendix 6.4 under Koyna Gen. Complex. Page 89 of Chapter 1

174 Demand for Power and Generation Planning S. No Appendix-1.14 (Page 1 of 2) State wise List of Ongoing Hydro RM&U Projects programmed for completion in the 11 th Plan (Phase I Projects* & Phase II Projects) Project, Agency Himachal Pradesh 1. Bhakra LB, BBMB Inst. Cap. (MW) Cost (Rs. in Crs.) Estimated Expend. Incurred Benefits (MW) 5x (LE) (U) 2. Bassi, HPSEB 4x Nil 6.0(U)+ 60 (LE) Jammu & Kashmir 3. Lower 3x Jhelum*, (as on (Res.) J&KPDC Chenani, J&KPDC 5. Salal Ph. II, NHPC Punjab 6. Shanan, Ph.B, PSEB 7. UBDC I&II, PSEB 8. Mukerian St.I, PSEB Uttar Pradesh 9. Matatila, UPJVNL Category As on Completion Schedule RMU&LE RMU&LE R&M+ Res x (LE) RM&LE x R&M x115 4x15 + 1x50 3x15 + 3x (as on ) (as on ) 3x (as on ) 3x (as on ) (LE) (LE) RM&LE (LE for 15 MW units + R&M for 50 MW unit ) RM&LE (LE for 3x15 MW & R&M for 3x15.45 MW R&M XIth Plan 15(U) (LE) 10. Obra, UPJVNL 3x (LE) 11. Rihand, 6x UPJVNL (LE) RMU&LE RM&LE RM&LE Page 90 of Chapter 1

175 Demand for Power and Generation Planning S. No Project, Agency Andhra Pradesh 12. Nagarjuna Sagar, (Ph.I) APGENCO Inst. Cap. (MW) 1x110+ 7x100.8 # Cost (Rs. in Crs.) Estima-ted Expend. Incurred (Till date) Benefits (MW) Category R&M & Refurbishment of Units 1, 2, 4 & 5 Appendix-1.14 (Page 2 of 2) Completion Schedule Upper Sileru, APGENCO 4x R&M XIth Plan 14. Srisailam RB, APGENCO 7x R&M Karnataka 15. Nagjhari, 3x135 $ RM&U U-4to6, KPCL (U) 16. Sharavathy 10x R&M Ph.B, KPCL 17. Supa, KPCL 2x R&M Nagjhari, U1 to 6, KPCL 3x R&M x135 $ (as on ) 19. Lingnamakki, KPCL 2X (as on ) Kerala 20. Sabirigiri*, KSEB 6x (as on ) (LE) (U) Tamil Nadu 21. Sholayar-I, TNEB 2x (U) (LE) Orissa 22. Hirakud-II*, OHPC 3x West Bengal 23. Jaldhaka St.I*, WBSEB 3x Maharashtra 24. Koyna St.I & II, MSPGCL (Incl for Sw. Yd.) (as on ) (as on 6/2006) 60.34(for P.H.) & 0.34 (for Sw. yd.) (as on ) Manipur 25. Loktak*, NHPC 3x (Res) - R&M RMU&LE RMU&LE (LE) RM&LE (LE) RM&LE R&M R&M + Res Total $ [205.0 (U) (LE) (Res.)] $ - Installed Capacity of Nagjhari (U-4 to 6) at Sl. No. 15 not included in the total, as the same has already been accounted for at Sl. No. 18. Page 91 of Chapter 1

176 Demand for Power and Generation Planning Appendix-1.15 (Page 1 of 2) State wise List of Hydro RM&U Projects programmed for completion in the 11 th but works of which are yet to be taken up for implementation (Phase I Projects* & Phase II Projects) Plan S.No. Project, Agency Himachal Pradesh 1. Dehar,(Ph-A) BBMB Inst. Cap. (MW) Estimated Cost (Rs. in Crs) Benefits (MW) Category As on Completion Schedule 6x R&M Giri, HPSEB 2x (LE) RM&LE XI th Plan Jammu & Kashmir 3. Ganderbal, J&KPDC 2x3+2x (LE) RM&LE Uttaranchal 4. Dhakrani, UJVNL 3x (LE) RM&LE Dhalipur, 3x (LE) RM&LE UJVNL 6. Tiloth, UJVNL 3x (LE) RM&LE Khatima, 3x (LE) RM&LE UJVNL 8. Pathri, UJVNL 3x (LE) RM&LE Kulhal, UJVNL 3x (LE) RM&LE Ramganga, UJVNL 3x (Res) R&M+Res Andhra Pradesh 11. Hampi, 2x9(St.I) & (LE) RM&LE XI th Plan APGENCO 12. Machkund *, APGENCO 13. Tungabhadra, APGENCO 14. Nagarjuna Sagar, Ph.II APGENCO 15. Upper Sileru, Ph.II APGENCO 2x9(St.II) 3x17(St.I) & 3x21.25 (St.II) (U) (LE) RMU&LE XI th Plan 4x (LE) RM&LE XI th Plan 1x x100.8 # R&M & Refurbishment of Units 3,6,7 & 8 XI th Plan 4x R&M XI th Plan Page 92 of Chapter 1

177 Demand for Power and Generation Planning S.No. Project, Agency Inst. Cap. (MW) Estimated Cost (Rs. in Crs) Benefits (MW) Category Completion Schedule Karnataka 16. Bhadra, KPCL 2x (LE) RM&LE Kerala 17. Sholayar, KSEB 3x (LE) RM&LE XI th Plan 18. Poringal-kuthu*,KSEB 4x (LE) RM&LE XI th Plan Tamil Nadu 19. Periyar,TNEB 4x RMU&LE (LE) (U) 20. Moyar, TNEB 3x (LE) RM&LE XI th Plan 21. Kundah St.I, TNEB 3x (LE) RM&LE XI th Plan 22. Kundah St.II, TNEB 5x (LE) RM&LE XI th Plan 23. Kundah St.III, TNEB 3x (LE) RM&LE XI th Plan 24. Kundah St.IV, TNEB 2x (LE) RM&LE XI th Plan 25. Kundah St.V, TNEB 2x (LE) RM&LE of XIth Plan Unit-1 & R&M of U Kodayar Ph.I, TNEB 1x (LE) RM&LE XIth Plan Jharkhand 27. Subernrekha, JSEB 2x (LE) RM&LE XI th Plan (Being Revised) 28. Panchet, 1x (LE) RM&LE U-1*, DVC Orissa 29. Balimela, OHPC 6x (LE) RM&LE XI th Plan 30. Hirakud-I* U5&6, 2x (LE) RM&LE OHPC West Bengal 31. Maithon U1&3, DVC 2x (LE) RM&LE XI th Plan Maharashtra 32. Koyna-III, MSPGCL 4x (LE) RM&LE XIth Plan Assam 33. Kopili, NEEPCO 2x50 + 2x (Likely to be Rev.) - R&M & Refurbishm-en of Units 1 & 2 XI th Plan Meghalaya 34. UmiumSt.II*, MeSEB 2x (LE) RM&LE Kyrdemkulai*, MeSEB 2x (U) RM&U XI th Plan Total # [49.25 (U) (LE) (Res.)] Appendix-1.15 (Page 2 of 2) Page 93 of Chapter 1

178 Transmission Planning & National Grid Chapter-2 TRANSMISSION PLANNING AND NATIONAL GRID 2.0 INTRODUCTION The transmission system facilities had earlier been planned on regional basis with provision of inter-regional link to transfer regional surplus power arising out of diversity in demand. The generation resources in the country are unevenly located, the hydro in the northern and north-eastern states and coal being mainly in the eastern part of the country. Development of strong National Grid has become necessity to ensure reliable supply of power to all. The planning & operation of the transmission system has thus shifted from regional to national level. Formation of a strong National Power Grid has been recognized as a flagship endeavour to steer the development of Power System on planned path leading to cost effective fulfilment of the objective of Electricity to All at affordable prices. A strong All India Grid would enable exploitation of unevenly distributed generation resources in the country to their optimum potential by providing enhanced margins in inter-regional transmission system. These margins, together with open access in transmission, would facilitate increased trading in electricity leading to market determined generation dispatches thereby resulting in supply at reduced prices to the distribution utilities and ultimately to consumers benefit. 2.1 REVIEW OF TRANSMISSION SYSTEM DURING 10 TH PLAN The development of transmission system requirement during the 10 th Plan was taken up along with the development of the generation programme for 10 th Plan. The transmission system required for evacuation of power from each of the generation project, as per the planning criteria adopted, had been identified as well as the system required for strengthening of the network for delivery of power to the load centres had also been identified. The identified transmission programme has been reviewed from time to time to take into account any revision in the generation programme and variations in development of load at various load centres in the State systems. Generally, there had been no constraint in intra-regional transmission systems. However, need of more capacities in the inter-regional systems was increasingly felt. Transmission schemes for providing more inter-regional capacities had already been initiated in the 9 th Plan and the programme was accelerated during 10 th Plan. This has resulted in consolidating the National Grid. The inter-regional transmission capacity at 200kV and above increased from 5050 MW at the beginning of 10 th Plan i.e. by March 2002, to 11,450 MW by August 2006, and against revised target of 16,450MW it is likely to reach 15,450 MW by the end of 10 th Plan (i.e. by March 2007). Based on the list of generation projects corresponding to the programme of 41,110 k transmission requirements at 132 kv level and above including the power evacuation system as well as network strengthening were identified. This transmission programme became the basis for taking up detailed planning exercise and finalizing Page 1 of Chapter 2

179 Transmission Planning & National Grid of their transmission development programme by the Central Transmission Utility and the State Transmission Utilities corresponding to the actual pace of 10 th Plan development happening in generation and the actual area-wise load growths. Accordingly, the 10 th Plan transmission programme had to be reviewed and targets reworked to match the generation programme. Apart from changes in associated transmission system corresponding to deferred/slipped/changed generation, transmission strengthening in power delivery networks had also to be reviewed to take care of variation in projected demand growth and the actual/updated projections of demand growth. Accordingly, the transmission programme taken-up for execution was revised as per the actual needs matching with generation projects Achievements in Transmission during First Four Years of 10 th Plan At the end of 9 th five year Plan, corresponding to the total installed generation capacity of 105 GW as on 31 st March 2002 and peak demand of 73 GW, the transmission system in the country at 765/HVDC/400/230/220/132/110 kv stood at 257 thousand circuit kilometres (Tckm) of transmission lines and 292 GVA of substation capacity. The corresponding sub-transmission system and distribution system stood at 302 Tckm and 115 GVA at 66/33/22kV, 1758 Tckm at 15/11/6.6/3.3/2.2kV, 176 GVA of distribution transformers and 3680 Tckm of LT lines. [Ref: General Review 2002, CEA] Summary of updated 10 th Plan transmission programme targeted based on actual progress during the first four years and the updated targets for the remaining year, is tabulated below: Table 2.1 Transmission System Type / Voltage Class Unit As at the end of 9 th Plan i.e. March 2002 * Added during (four years) Achieved as at the end of i.e. March 2006 To be added during Target for the End of 10 th Plan i.e. March 2007 TRANSMISSION LINES (a) 765 kv ckm (b) HVDC ± 500kV ckm (c) 400 kv ckm (d) 230/220kV ckm (e) HVDC 200kV ckm Total of (a), (b), (c),(d) & (e) ckm SUBSTATIONS (a) 765 kv MVA (b) 400 kv MVA (c) 230/220 kv MVA Total of (a), (b) & (c) HVDC (a) Bi-pole link capacity MW (b) Back-to back capacity MW (c) Mono-pole link capacity MW Total of (a), (b) & (c) MW [* General Review 2002, CEA] Page 2 of Chapter 2

180 Transmission Planning & National Grid Programme of Inter-Regional Transmission Capacity in 10 th Plan At the end of the 9 th Plan, the inter-regional transmission capacity at 200kV and above was 5050 MW. The original programme corresponding to X Plan generation programme of 41,000 MW was to add MW during 10 th Plan. The revised target programme for 10 th plan is to add MW out of which 4400 MW has been added during the first four years that is MW and 7000 MW is the target for so as to achieve MW in the end of 10 th plan. Out of this target of 7000 MW, Muzaffarpur-Gorakhpur 400kV D/C quad line with TCSC of 2000 MW was added in August However, as per the progress, likely achievement is expected to be 1000 MW less due to slipping of Ranchi-Sipat 400kV D/C line. With this, the interregional transmission capacity by the end of 10 th Plan is anticipated to increase to MW by The Inter-Regional transmission capacities programmed for the 10 th Plan are: HVDC Back to-back stations at Gazuwaka (500 MW), HVDC Back to-back station at Sasaram (500MW), Talcher-Kolar HVDC Bipole (2000 MW), and Rourkela-Raipur 400kV D/C line with TCSC (1400 MW) Muzaffarpur-Gorakhpur 400kV D/C quad line with TCSC (2000 MW) (* This line was charged on , thereby establishing synchronous connections between NER-ER-WR-NR.) Biharshariff-Balia 400kV quad line (1200 MW), Patna-Balia 400kV quad line (1200 MW), Agra-Gwalior 765kV line operated at 400kV, and Ranchi-Sipat 400kV D/C line with 40% series compensation (1000 MW) Development of HVDC Systems during 10 th Plan: Talcher Kolar HVDC + 500kV Bipole of 2000 MW capacity, Sasaram HVDC backto-back of 500 MW capacity and Gazuwaka HVDC back-to-back second module of 500 MW capacity were added during the X Plan. A summary of development of HVDC systems in India during first four years and also programme for the last year i.e is given at Appendix Development of 765kV Systems during 10 th Plan: Currently all of the 765 kv systems in the country are operated at 400kV, the transmission system for Sipat that would be completed in , would be operated at 765kV, thus setting a new milestone in development of transmission system in the country. A summary of development of 765kV transmission system in India during first four years and also programme for the last year i.e of 10 th Plan is given at Appendix Development of Regional Grids during 10 th Plan List of major transmission schemes completed and programmed under the development plan of the Regional Grids and National Grid during the 10 th Plan are given at Appendix to Appendix Page 3 of Chapter 2

181 Transmission Planning & National Grid Fund Requirement and Utilization during 10 th Plan Initially, based on the 41 GW generation addition programme for 10 th Plan, a total of Rs crore was estimated for transmission schemes in 10 th Plan. Out of this, a sum of about Rs crore was to be spent for development of Regional grids and Nation grid by Powergrid on its own and also through joint venture schemes. However, because of slippage/deferment of generation programme over the span of 10 th plan and consequent reduction in the transmission programme, only about Rs Crore (Rs crore by PGCIL alone and Rs 1912 crore through joint venture) would be spent during X plan. Under state sector, the estimate was to spend Rs crore for 66kV and above schemes (this estimate does not include the schemes in J&K, Sikkim, Goa, Mizoram and Uttaranchal). Based on current estimate, about Rs crore would be spent by the state utilities. (These estimates are for 220kV above schemes and do not include states of J&K and Sikkim). Thus with the updated generation addition estimate of about 31 GW in five years of X Plan, an amount of Rs crore would be spent Difficulties and constraints in implementation of Transmission Schemes It may mentioned that due to sustained efforts by Central PSUs and States, and close coordination by Ministry of Power/CEA with CPSUs and States the transmission Schemes meant for evacuation of power from Generating stations, strengthening schemes and sub-transmission schemes etc for absorption of power from Generating Stations by the states had been commissioned well in time. Hence by and large there was no bottling up, as such, of power from Generating stations and the States were capable of absorbing the additional power capacity added during these years. Not withstanding the above, transmission utilities faced some difficulties in implementation and completion of their schemes. A case-wise analysis of difficulties and constraints experienced by them is detailed in following paragraphs. The CPSUs and States had experienced difficulties during construction of transmission schemes. Noticeably, in case of Dhauliganga- Bareilly 400 kv D/C line, Dadri- Panipat, 400kV S/C line, LILO of 400 kv Dadri-Ballabgarh D/C line at Noida, Tehri Meerut 765kV S/C line, Pykara-Arasur 230 kv D/C line some difficulties were experienced. In case of Dhauliganga(NHPC)- Bareilly (initially to be charged at 220 kv), progress in Ascot wild life area adversely affected since October, 2003 due to refusal of permission for working in Ascot Wild Life Sanctuary. In case of Dadri-Panipat 400 kv S/C line, there were severe Right of Way constraints and law & order problems. The problems were resolved through the intervention of Senior Govt. Officials of Uttar Pradesh and the line was commissioned in March 06. In case of LILO of 400 kv Dadri-Ballabgarh at Noida, work was held as clearance was not received from NOIDA Authority in NOIDA. Matter pursued Page 4 of Chapter 2

182 Transmission Planning & National Grid with NOIDA Authority /State Administrator to resolve the issue. Line is being re-routed and work has re-commenced.. Tehri-Meerut 765kV Ckt.-I was completed in August 2004 ahead of generation project i.e. Tehri Stage-I HEP(4x250 MW). But, the Tehri-Meerut 765kV S/C Ckt.-II, was completed in March Work in Rajaji National Park was not allowed by forest authorities until clarification was received from Hon ble Supreme Court, In case of Pykara-Arasur 230 kv D/C, the proposal for transmission line falling in forest area the clearance from Hon ble Supreme Court received on 30th Jan There was further delay due to large scale tree cutting under the direct supervision of Regional Conservator of Forests. 2.2 NATIONAL GRID Introduction Formation of a strong National Power Grid has been recognized as a flagship endeavour to steer the development of Power System on planned path leading to cost effective fulfilment of the objective of Electricity to All at affordable prices. A strong All India Grid would enable exploitation of unevenly distributed generation resources in the country to their optimum potential by providing enhanced margins in inter-regional transmission system. These margins, together with open access in transmission, would facilitate increased real time trading in electricity leading to market determined generation dispatches thereby resulting in supply at reduced prices to the distribution utilities and ultimately to consumers benefit Emergence of Inter-Regional Systems During the 1980s, the regional grids developed with construction of power evacuation lines planned and implemented as associated transmission system of central sector generation schemes for benefits within the regions. The initial set of inter-regional links developed under the Centrally sponsored programme for building inter-state infrastructure of State utilities, was utilized to facilitate exchange of operational surpluses among the various Regions in a limited manner because the Regional Grids operated independently and had different operational frequencies and the power exchanges on these inter-regional links could take place only in radial mode. In 1989, transmission wings of Central generating companies were separated to set up Power Grid Corporation of India (POWERGRID) to give thrust to implementation of transmission system associated with Central generating stations and inter- Regional transmission programme based on perspective planning done by CEA. Considering the prevailing operational regime at that time, it was decided to establish initially asynchronous connection between the Regional Grids to enable exchange of regulated quantum of power and asynchronous HVDC back-to-back links of 500MW between the Northern Region and the Western Region at Vindhyachal, 1000MW between Western Region and Southern Region at Bhardawati, 1000MW between Page 5 of Chapter 2

183 Transmission Planning & National Grid Eastern Region and Southern Region and 500MW between Eastern Region and Northern Region at Sasaram were provided during 90s and early 2000s Formation of National Grid The Eastern Region and the North-Eastern Region have been operating in parallel since 1992 being connected by a 220 kv double circuit transmission line and more recently by a 400 kv D/C transmission line. Western Region was interconnected to ER-NER system synchronously through 400kV Rourkela-Raipur D/C line in 2003, operationalising the Central India system consisting of ER-NER-WR. With installation of TCSC, the transmission capacity of Rourkela-Raipur 400kV D/C line was increased to 1400MW. The Northern region, which till August 2006 had asynchronous radial mode and HVDC back-to-back inter-regional transmission connectivity of 600 MW with the Eastern region, and 1000 MW with the Western region, was also synchronously integrated with the ER/NER/WR system with commissioning of the 400kV Muzaffarpur-Gorakhpur line on 26 th August The Muzaffarpur Gorakhpur 400kV D/C quad line with fixed series capacitor and TCSC has added 2000 MW to the ER-NR inter-regional transmission capacity. Towards the Southern region, asynchronous interconnections of 1700 MW between SR and WR and 600 MW between SR and ER providing a total of 2300 MW of interregional transmission capacity was existing at the beginning of the X plan. With 2000 MW Talcher-Kolar HVDC Bipole line, and second 500 MW HVDC back-to back module at Gazuwaka, both between SR and ER, the total inter-regional capacity connecting to SR has increased to 4800 MW. As of now all inter-regional transmission links of the Southern region are either asynchronous radial mode lines or HVDC inter-connections. Synchronous integration of the Southern region with rest of Indian grid would be firmed up after having experience of synchronous operation of NR+ER+NER+WR system. One point AC interconnection through Parli Raichur 400kv link supplemented with HVDC links has been proposed for this. The target is to firm up this scheme in the first year of 11 th Plan so that synchronous interconnection of All India system could be realized with in the 11 th Plan period Programme of Development of National Grid As on today, the inter-regional transmission capacity of 11,450 MW is existing and inter-regional energy exchanges of more than 12 billion kwh in a year thus contributing to greater utilization of generation capacity. The program is to achieve inter-regional capacity of MW by the end of 10 th Plan and about 37,150 MW by the end of 11 th Plan. Additional 3000 MW through creation of Siliguri HVDC terminal on Bishwanath Chariyali Agra 800kV HVDC bi-pole line is also being considered during 11 th Plan itself. This would increase the target of inter-regional capacity by from MW to MW. The table given below gives the programme of Inter-regional Transmission Capacity up to Page 6 of Chapter 2

184 Transmission Planning & National Grid Details of inter-regional transmission Existing, under construction and Planned: Table 2.2 Name of system ER SR : Gazuwaka HVDC back to back Balimela-Upper Sileru 220kV S/C Power Transfer Capacity (MW) At the end of 9 th Plan i.e. end of Additions during 10 th Plan At the end of 10 th Plan i.e. end of Additions during 11 th Plan At the end of 11 th Plan i.e. end of Talcher-Kolar HVDC Bipole Upgradation of Talcher Kolar HVDC bipole ER-SR total ER NR : Muzaffarpur - Gorakhpur 400kV D/C (Quad Moose) with series comp Dehri-Sahupuri 220kV S/C Sasaram HVDC back to back Biharshariff-Balia 400kV D/C quad increased loadability with series capacitor in associated lines in NR sys Patna-Balia 400kV D/C quad increased loadability with series capacitor in associated lines in NR system Barh-Balia 400kV D/C quad increased loadability with series capacitor in associated lines in NR system Sasaram Fatehpur 765kV S/C (40% SC) Page 7 of Chapter 2

185 Transmission Planning & National Grid Name of system Sasaram-Balia 400kV D/C quad increased loadability with series capacitor in associated lines in NR sys At the end of 9 th Plan i.e. end of Additions during 10 th Plan At the end of 10 th Plan i.e. end of Additions during 11 th Plan At the end of 11 th Plan i.e. end of ER-NR total ER - WR : Rourkela-Raipur 400kV D/C (without SC) TCSC on Rourkla-Raipur 400kV DC Budhipara-Korba220kV D/C+S/C Ranchi-Sipat 400kV D/C (40% SC) Ranchi-Rourkela-Raipur kV D/C North Karanpura-Sipat kV S/C ER-WR total ER - NER : Birpara-Salakati 220kV D/C Malda-Bongaigaon 400kV D/C Bongaigaon-Siliguri 400kV D/C Quad ER-NER total NR - WR : Vindhychal HVDC back to back Auria-Malanpur 220kV D/C Kota-Ujjain 220kV D/C Agra-Gwalior 765kV S/C line-1 400kV op Agra-Gwalior 765kV line kV op Agra-Gwalior 765kV line Kankroli-Zerda 400kV D/C RAPP-Nagda 400kV D/C NR-WR total Page 8 of Chapter 2

186 Transmission Planning & National Grid Name of system WR-SR : Chandrapur HVDC back to back Barsur L.Sileru 200kV HVDC mono pole Kolhapur-Belgaum 220kV D/C Ponda Nagajhari 220kV At the end of 9 th Plan i.e. end of Additions during 10 th Plan At the end of 10 th Plan i.e. end of Additions during 11 th Plan At the end of 11 th Plan i.e. end of D/C Parli-Raichur 400kV D/C WR-SR total NER-NR/WR : Bishwanath Chariyali Agra HVDC bi-pole 800kV NER-NR/WR total TOTAL ALL INDIA Additional 3000 MW through creation of Siliguri HVDC terminal on NER-NR/WR inter-connector, which would increase the target of inter-regional capacity by from MW to MW Transmission System for Evacuation of Power from Hydro Projects in NER, Sikkim & Bhutan North Eastern Region, Sikkim and Bhutan have vast untapped hydro potential which is planned for development during 11 th plan and beyond. A major component of this power will be utilised by deficit states in the northern and western region and for which reliable evacuation system is planned to be developed. The requirement of transmission system for evacuation of NER hydro power has been estimated corresponding to the capacity of hydro projects which may be feasible to develop say in the next about 20 years. This generation is estimated to be about MW in NER, about 8000 MW in Sikkim and about MW in Bhutan. Taking local development at accelerated pace resulting in demand within the NER, Sikkim and Bhutan to be in the range of MW (presently it is about 1500 MW), the transmission requirement through the chicken neck works out to be of the order of MW. The total requirement including additional circuits for meeting the contingencies and reliability needs, would work out to 7 or 8 numbers of 800 kv HVDC bi-pole lines and 4 or 5 numbers of 400kV double circuit lines a total of 12 numbers of high capacity transmission corridors passing through the chicken neck. For this, RoW requirement would be about 1.5 Km in width considering minimum distance between adjacent towers to be such that fall of any tower does not affect the adjoining line. The first 800kV HVDC bi-pole line has been planned from a pooling substation at Biswanath Chariyali in North-eastern Region to Agra in Northern region. Page 9 of Chapter 2

187 Transmission Planning & National Grid This is being programmed for commissioning matching with Subansiri Lower HEP in Regional system matching with inter-regional transmission system Transmission systems within the regions to support the above inter-regional transmission capacity is also planned. For example, together with Muzaffarpur- Gorakhpur 400kV D/C line, Siliguri-Purnia-Muzaffarpur 400kV D/C in the Eastern region and Gorakhpur-Lucknow 400kV D/C and Bareilly-Mandola 400kV D/C lines in Northern region have also been provided. Similarly, together with inter-regional transmission lines that would bring power from Kahalgaon and Barh in Eastern region to Balia in Northern region, transmission system from Balia onwards towards western part of Northern region has been planned. In the Western region, major system strengthening scheme has been programmed for onwards transmission of power to be received through ER-WR inter-regional links. Similarly, transmission system has also been planned on both sides of inter-regional links between NR and WR and between ER and SR Implementation of National Power Grid Financing and Tariff Issues The plan for National Power Grid and the schemes have been identified. Implementation of these schemes would require, apart from investment decisions and arranging finances, urgent needs for addressing transmission tariff related issues. The total transmission charges payable to the Central Transmission Utility are worked out on cost plus basis. In case of transmission system through private participation on competitive basis, this would be as per bid-based tariff. The present method of apportionment of the total transmission charges among the beneficiaries is to allocate the regional pooled transmission charges in proportion to their shares in Central Sector generation. This mechanism was evolved during the late seventies when major Central initiatives were taken in generation and associated regional transmission system. The formula has, by and large, worked satisfactorily. With each addition in generation resources and associated transmission system in Central Sector, the States had been getting their shares in more or less same ratio as the allocations that existed prior to the incremental additions. However, with shift towards market determined allocations, new dimensions have been added on account of - (a) surpluses in Eastern region, (b) higher deficit in Northern region and Western region; and (c) coming up of generation projects for cross-regional benefit and (d) merchant generation plants without long-term power allocations or PPAs and intending to sell on short-term basis to different customers utilizing open access in transmission. Consequently, allocation of Central sector generation is no more taking place as per earlier practice/formula. In this changed scenario, the existing methodology of apportionment of Central Transmission Charges among the beneficiaries on regional pool basis is causing distortion. As the cost of incremental facilities is generally substantially higher than that of existing facilities, beneficiaries seeking lower or no allocation from new Central generation see this transmission charge pooling and apportionment arrangement to be disadvantageous to them, while the beneficiaries seeking higher shares in new generation capacities find it advantageous to them. Consequently, the States getting lower share in new Central generation are reluctant to commit transmission charges for the incremental transmission system. This difficulty is severe for those elements of transmission network which go towards Page 10 of Chapter 2

188 Transmission Planning & National Grid improved system reliability and margins for open access and for supporting noncommitted transaction such as utilization of operational surpluses and incremental cost merit based dispatch optimization. This gets further complicated in case of projects with cross-regional or multi-regional benefits. It is also important that the finances for the Transmission Schemes of the National Grid are arranged at low cost. With focus on system reliability and building margins for open access in the transmission system, the per unit investment in transmission system at Regional and National level is set to increase considerably. This would further increase on account of harnessing remotely located Hydro resources in the Northern Region and North-Eastern Region. The impact of harnessing North-Eastern Region Hydro resources would be much more as the power would have to be transmitted across the North-Eastern and Eastern Regions to bring it to Northern/Western/Southern Regions where it can be actually absorbed. As such, the transmission charges may go up considerably Synchronous Inter-Connection of Southern Region with rest of Indian Grid Integration of the Southern region with rest of Indian grid was considered to be programmed during 11 th Plan period. The proposal is to connect SR and WR synchronously through one 400kV D/C quad line between Parli and Raichur. Fixed Series Capacitor as well as TCSC would also be provided on this link. The link would have transmission capacity of the order of 2000 MW per quad D/C line under system contingency with normal transmission capacity limited to 1000 MW, due to this being only synchronous inter-connection between Southern region and rest of Indian grid. The balance inter-regional transmission capacity for SR would come from existing and future HVDC links. POWERGRID is of opinion that further 11 th Plan links to Southern Region should be through HVDC and synchronous interconnection of Southern Region with rest of the Indian grid should be considered after having a few years of experience of operating the NR-WR-ER-NER system synchronously. Synchronous inter-connection of Southern region with rest of Indian grid would be of advantage to all as it would enable widening of real time power market allowing optimization of generation resources on all India level. For realizing this at the earliest, the proposal is being discussed so as to firm-up the scheme and achieve synchronous interconnection of Southern grid within 11 th Plan. 2.3 ELEVENTH PLAN PROGRAMME Assessment of Transmission Capacity Requirement The focus of transmission system development programme for the XI Plan is to provide adequate inter-regional and intra-regional transmission capacity so as to consolidate and strengthen the National Grid network towards a strong All India Grid. The inter-regional power exchange requirement has been assessed from possible scenarios of regional surpluses and deficits for the peak and off-peak conditions of winter, summer and monsoon months. The surplus/deficit projections based on Page 11 of Chapter 2

189 Transmission Planning & National Grid programme of generation and anticipated demand aims at estimating the transmission requirement at the inter-regional level. Grid expansion plan evolved based on this projection would be able to cater to the needs of various feasible operating scenarios and also provide required margins to support market oriented power exchanges. Transmission system programme for 11 th Plan have been worked out based on this methodology Transmission System Programmes for 11 th Plan For the development of transmission system in the country, the following programmes have been identified to be taken-up during the 11 th Plan: Central Sector Schemes: Transmission schemes for inter-state transmission system Load dispatch schemes for National and Regional dispatch centres National level Power Exchange Comprehensive upgrading of protection system for total integrated system for security of National and Regional grids Evolving perspective transmission plan for the 12 th Plan period Augmentation of test facilities State Sector Schemes: Transmission schemes for intra-state transmission system Load dispatch schemes for State and Area dispatch centres Schemes for upgrading of protection systems for security of State grids Evolving the Perspective Transmission System for 11 th Plan In transmission system development in the country, the focus of 11 th plan programme is formation of the national power grid. A strong all India grid would enable exploitation of unevenly distributed generation resources in the country to their optimum potential. The transmission capacity together with the margins provided for required redundancies as per planning criteria would provide a reliable transmission system. this would meet the firm transmission needs and with open access in transmission, would facilitate increased real time trading in electricity leading to market determined generation dispatches thereby resulting in supply at reduced prices to the distribution utilities and ultimately to the consumers. Development of national grid has been necessitated by the large thermal generation potential in eastern part of the country and equally large hydro generation potential in northeastern part. It has also been spurred by the opportunity provided by open access, variation in hydrology / hydro potential and diversity of load across the country Assessment of National and Regional Transmission Requirements For assessing the inter-regional power exchange requirements, possible scenarios of regional surpluses and deficit corresponding to each year upto the end of 11th plan (i.e. Each year upto ) has been projected for the peak and off-peak conditions of winter, summer and monsoon months. The projection based on Page 12 of Chapter 2

190 Transmission Planning & National Grid programme of generation and anticipated demand aims at estimating the transmission requirement at the inter-regional level. The national grid system evolved on this projection would be able to cater to the needs of various feasible operating scenarios and also provide required margins to support market oriented power exchanges. Region-wise assessment of import(-)/export(+) need based on projection of availability and demand corresponding to various seasonal scenarios of , which forms the basis for assessing the transmission requirement and evolving of the national grid network is summarized in the following table: Table 2.3 Assessment of Regional Exchange of Power (All Figures in MW) Winter Winter Off Peak Winter Peak Regions Availability Surplus(+) Availability Surplus(+) Demand Demand Deficit (-) Deficit (-) Northern Western Southern Eastern North-Eastern Total Monsoon Monsoon Off Peak Monsoon Peak Regions Availability Surplus(+) Availability Surplus(+) Demand Demand Deficit (-) Deficit (-) Northern Western Southern Eastern North-Eastern Total Summer Summer Off Peak Summer Peak Regions Availability Surplus(+) Availability Surplus(+) Demand Demand Deficit (-) Deficit (-) Northern Western Southern Eastern North-Eastern Total Page 13 of Chapter 2

191 Transmission Planning & National Grid Identification of Transmission Systems for 11 th Plan Identification of transmission expansion plan was done based on power system studies corresponding to the scenario at the end of 11 th plan. The implementation programme was subsequently worked out matching the evacuation and strengthening schemes with associated generation and load growth. Most of the 11 th plan schemes have been discussed and firmed-up in the regional standing committees on transmission planning. Investment approvals for some of the schemes have also been obtained and construction started. Some of the schemes are in investment approval stage. Some of the schemes are under final stages of firmingup Inter-Regional System It is envisaged to add during the XI Plan period new inter-regional capacities of MW at 220kV and above. This would increase the total inter-regional transmission capacity of national power grid at 220kV and above from MW of XI Plan beginning to MW by Additional inter-regional transmission capacity of 1200 MW by enhancing transmission capacity of each of the Barh-Balia, Patna-Balia and Biharsharif-Balia 400kV quad D/C lines from 1200MW to 1600MW by provision of series compensation and SVC in Northern region and Eastern regional system has also been planned kV Transmission System Existing 765kv transmission system at the beginning of 11 th plan would be: Table kV Transmission Lines Anpara-Unnao (UPPCL) S/C ckm 409 Kishenpur-Moga L-1(W) S/C ckm 275 Kishenpur-Moga L-2(E) S/C ckm 287 Tehri-Meerut Line-1 S/C ckm 186 Tehri-Meerut Line-2 S/C ckm 184 Sipat-Seoni Line-1 S/C ckm 336 Sipat-Seoni Line-2 S/C ckm 336 Agra-Gwalior Line-1 S/C ckm 140 TOTAL ckm kV Sub-stations 765/400kV Sipat Generation 2x1000 MVA 2000 Seoni 2x1500 MVA 3000 TOTAL MVA 5000 Page 14 of Chapter 2

192 Transmission Planning & National Grid 765kV transmission line and substation programme for the 11 th Plan period is: Table kV Transmission Lines ckm / MVA Sasaram-Fatehpur S/C ckm 400 Fatehpur-Agra S/C ckm 330 Agra-Gwalior Line-2 S/C ckm 140 SipatPP-Seoni Line-3 S/C ckm 340 SipatPP-Sipat S/C ckm 30 Seoni-Bina S/C ckm 330 Seoni-Wardha Line-1 S/C ckm 210 Seoni-Wardha Line-2 S/C ckm 210 Gwalior-Bina Line-1 S/C ckm 300 Gwalior-Bina Line-2 S/C ckm 300 Sasaram-North K. Pura S/C ckm 180 North K. Pura-SipatPP S/C ckm 350 TOTAL kV Sub-stations 765/400kV Unnao (UPPCL) MVA 2000 Agra MVA 3000 Meerut MVA 3500 Fatehpur MVA 3000 Gwalior MVA 3000 Bina MVA 2000 Seoni 3 rd transformer MVA 1500 Wardha MVA 4500 Sasaram MVA 2000 TOTAL * In State Sector (UPPCL) HVDC Transmission System HVDC Bi-Pole, Mono-Pole and Back-to-Back transmission at the beginning of 11 th Plan: Table 2.6 HVDC Bi-pole System ckm (2xroute km) MW Capacity Chandrapur-Padghe(MSTCL) ± 500kV Rihand-Dadri ± 500kV Talcher-Kolar ± 500kV TOTAL HVDC bi-pole HVDC Monopole Barsur-Lower Sileru 200kV HVDC Back-to-back Vindhachal 500 Page 15 of Chapter 2

193 Transmission Planning & National Grid Chandrapur 1000 Gazuwaka 1000 Sasaram 500 TOTAL back-to-back 3000 HVDC transmission system programme for the 11 th Plan period is: 11 th Plan Programme ckm (2xroute MW HVDC Bi-pole System km) Capacity Balia-Bhiwadi ± 500kV Biswanath-Siliguri-Agra ± 800kV TOTAL Inter-State Transmission Schemes Status All of the 11 th plan inter-state transmission schemes to be commissioned by 2009 have already been firmed-up and are under execution. Most of schemes required by have also been evolved, discussed in the regional standing committees on power system planning, firmed-up and are to be taken-up for execution so as to complete and commission as per the target. However, a few transmission schemes, particularly those required for evacuation system and regional system strengthening schemes corresponding to those newly identified/uncertain generation projects where execution/beneficiaries are yet be firmed-up are yet to be firmed-up. Process to firmup these remaining 11 th plan transmission schemes which may be required for completion towards the last years of the 11 th plan is under way. List of 11 th Plan Inter-State Transmission Scheme is given at Appendix Other Related Important Schemes in the Central Sector Load dispatch schemes for National and Regional dispatch centres With integrated operation of all-india system, state of art load dispatch system at the national level would need to be established. The regional level load dispatch would also require up-gradation, both qualitative as well as quantitative, to meet the requirement of growing size of the system and emerging complexities of power system operation. Comprehensive upgrading of protection system for total integrated system for security of National and Regional grids A unified scheme covering comprehensive upgrading of protection system for total integrated system is proposed under the 11 th Plan programme. This scheme to be taken-up in the Central sector for implementation by Power Grid Corporation of India would provide for overhaul and upgrading of protection system and equipment covering all the system elements including those in the States' system, which have direct bearing on the security of the National and Regional grids. Page 16 of Chapter 2

194 Transmission Planning & National Grid National Power Exchange System For facilitation trading through double-sided bidding on a national platform towards optimum utilization of generation resources, establishment of a Power Exchange at National level is envisaged to be implemented during the early years of 11 th Plan. Evolving perspective transmission plan for the 12 th Plan With freer market system and number of merchant generation plants increasing, transmission planning for the 12 th Plan period would pose new challenges. Transmission system would have to be evolved with much higher uncertainty in projected generation-demand match-up scenario. Towards meeting this challenge, it is proposed to take-up the transmission planning for 12 th Plan as a planned scheme in which the system evolved by the in-house expertise with in the country would be discussed with utilities of other developed and fast developing countries and international experts before firming-up the development program. In this scheme, software for Power System Planning would also be upgraded to the state of art software. Augmentation of test facilities Augmentation of facilities for testing of transmission equipment within the country is needed for enabling timely procurement of reliable equipment in transmission based on improved and tested designs Transmission System under State Sector A well planned and reliable transmission system at the National and Regional level would need to be complemented with development of matching transmission system at 220kV and 132kV and also the sub-transmission and distribution system so as to cater to the load growth and ensure proper utilisation of development in generation and transmission facilities for the ultimate goal of delivery of the services up to the end consumers in the country. Inadequate development of sub-transmission and distribution system facilities in the States of NER has been adversely affecting the reliability of power supply to the consumers and also hampering the load growth in the region. The transmission, subtransmission and distribution systems of states require major strengthening/upgradation. Transmission lines that are under outage require speedy restoration for bringing them into operation so that the states could avail their central sector shares as well as utilize their own generation without any constraint. Inadequacies in the transmission and distribution system had been on account of slow implementation of schemes due to various factors such as time consumed in E&F clearances, land acquisition, RoW constraints, fund limitation, organizational difficulties of state utilities, lack of vendor response due to locational factors, law and order, terrain specific difficulties, etc. Due to limited funding capabilities of state utilities, most of the required transmission projects are generally funded by NEC or by NLCPR under DONER and investment/funding approval of scheme so funded also takes additional time. All these issues need to be addressed to achieve the accelerated demand growth in NER. Page 17 of Chapter 2

195 Transmission Planning & National Grid Transmission schemes for intra-state transmission system, load dispatch schemes for state and area dispatch centres and schemes for upgrading of protection systems for security of state grids are also required to be firmed-up by the state transmission utilities. Intra-state transmission schemes for evacuation of power from generation schemes in the state sector are given at Appendix TECHNOLOGY DEVELOPMENT Needs for Technology Development Indian Power System is growing at a rapid pace with the mission to achieve Power to all by For transfer of power from the generation resources to unevenly distributed major load centres, Regional grids have been developed and integration of all the five (5) Regional Grids to form a strong National Grid is also going on with increasing pace. Today, National Grid of 11,500 MW inter-regional capacity is under operation, which shall be enhanced to about MW by end of XI Plan i.e Except Southern Region, all the other four regions are now connected synchronously, thus forming a 88 GW synchronous grid. To ensure secure and reliable operation of the large integrated grid on a real time basis use of latest technology and search and development of new technologies to inevitable. Five regional load dispatch centres equipped with modern State-of-the-Art technology along with dedicated communication facilities are in operation and work on a National Load Dispatch centre is in progress. Establishment and real time operation of large T&D infrastructure of present day technology poses challenges for conservation of eco-sensitive Right of Way, environment & forest, implementation time, automation of substation, project cost and grid management. Therefore, it is necessary to modernize the power transmission network by integrating latest technologies suitably into the development plan to ensure maximum utilization of existing transmission infrastructure, provision of open access, phase-wise generation development and implementation in a time bound and cost effective manner Adopting New Technologies in Transmission System New technologies should be adopted and implemented in a proactive manner to achieve the objective of optimum utilization of the available transmission assets as well as conservation of Right-of-Way, reducing transmission costs, reduction of losses etc. Some of the new technologies adopted/being adopted in its transmission system include: High capacity 6000MW +800kV HVDC system 765kV AC Transmission System Ultra High Voltage AC Transmission System(1000kV) Application of Series Compensation Flexible AC Transmission System (FACTS) Upgradation/Uprating of transmission line Page 18 of Chapter 2

196 Transmission Planning & National Grid High temperature endurance conductor Tall/Multi-circuit & Compact tower High Surge Impedance Loading Line (HSIL) Remote operation of substation, substation automation and Gas Insulated substation (GIS) All Aluminium Alloy Conductors (AAAC) and Polymer/Composite Insulators. Development of disc insulators of 320kN & 420kN indigenously for both AC & HVDC applications, as import substitution. Indigenous development of semi-conducting glazed insulators (Offering better pollution performance) Introduced source/process inspection of equipment to ensure zero defect Airborne Laser Terrain Mapping (ALTM) for detailed route survey Thermo-vision scanning of the lines and sub-stations Conditional monitoring of equipment Preventive maintenance of Transformers using State-of-art Oil testing laboratories set up by the company Emergency Restoration System (ERS) For modernization of transmission system through latest technology integration, two pronged strategies have been envisaged as under: Enhance capacity and reliability of existing systems through: Suitable technology for new systems keeping the long term perspective Modernisation of Existing Transmission Infrastructure To ensure maximum utilization of existing infrastructure, a number of technologies have been implemented. Series compensation and facts Upgradation of lower voltage to higher voltage line Re-conductoring of transmission line Technology adoption for new transmission system Enhancement of conductor maximum temperature limits High capacity 400kV multi-conductor and 765kV system Compact towers High capacity HVDC system Ultra high voltage (1000kV) AC transmission system Modern line route survey technique Substation compaction, GIS, automation and remote operation High surge impedance loading line(hsil) Fault current limiting reactor Grid operation and management Intelligent Grid Wide Area Monitoring System(WAMS) Page 19 of Chapter 2

197 Transmission Planning & National Grid Search for New Technologies New technologies are also needed to find solution to some the problems being faced in the transmission system. Currently important issues are stability enhancement, engineering and design for the next higher voltage, and reduction of right of way requirement for transmission lines. FACTS and PSS tunings should be considered in this context. The failure of extra high voltage transformers is also a matter of concern. Power transformers and converter transformers have failed in large numbers in the country and through appropriate research and development input, this is required to be corrected Open Access It is also important that the finances for the Transmission Schemes of the National Grid are arranged at low cost so that required reliability and margins for open access could be provided in the transmission system with in acceptable costs. The evolved transmission system expansion plan provides sufficient transmission capacities with inherent margins for trading transactions. This also meets the intraregional transmission needs. Taking-up the execution of the transmission schemes for timely completion would depend on timely tie-up of pre-construction activities and thereafter construction being ensured within specified time period. Agreement on the proposal together with commercial tie-up for payment of transmission charges based on long-term open access application becomes a critical issue in this context. As the Merchant plants would basically be long term-user of the transmission system, the transmission system for their connectivity and meeting their primary transmission needs can be planned and taken-up for construction based on commitment for the transmission charges by the developers of the Merchant plants. The process for longterm open access application and tying-up the transmission schemes should be done at the earliest as building the transmission system including obtaining necessary approvals, pre-construction and construction/commissioning activities for the transmission schemes require almost same time, if not more, as that for implementation generation projects. 2.5 TRANSMISSION REQUIREMENTS FOR OPEN ACCESS AND TRADING Assessment of Transmission Capacity Requirement The focus of transmission system development programme for the XI Plan is to provide adequate inter-regional and intra-regional transmission capacity so as to consolidate and strengthen the National Grid network towards a strong All India Grid. The inter-regional power exchange requirement has been assessed from possible scenarios of regional surpluses and deficits for the peak and off-peak conditions of winter, summer and monsoon months, and projections assessed. The projection based on programme of generation and anticipated demand aims at estimating the transmission requirement at the inter-regional level. Grid expansion plan evolved based on this projection would be able to cater to the needs of various feasible Page 20 of Chapter 2

198 Transmission Planning & National Grid operating scenarios and also provide required margins to support market oriented power exchanges Transmission Capacity for Trading The above method adopted for evolving the transmission system expansion plan provides sufficient transmission capacities which would have inherent margins for trading transactions. Transmission system implemented on the basis of the expansion plan evolved in this manner would enable trading across the regional boundaries towards optimal utilization of generation resources in the country for ultimate benefit of the consumer. As the system is evolved based on extreme dispatches, it would facilitate trading most of the time without congestion, and occasionally, under outage contingencies or severe loading condition with some degree of congestion which should be acceptable. Currently, trading is taking place through short-term bilateral contracts. With introduction of Power Exchange at National level, which is being envisaged to be in place in near future, trading would also take place through Power Exchange which would be day ahead contracts. All the short term as well as Power exchange transaction would need transmission capacity which would come out of the spare capacity inbuilt in the transmission system. The reliability and operational margins in the planned and implemented transmission system corresponding to the committed long-term transmission needs would provide the transmission capacity for trading of power Pre-construction tie-ups are Critical The comprehensive transmission system evolved on national basis and also meeting the intra-regional transmission needs, has been assigned under various schemes power evacuation schemes matching with generational capacity addition programme and system strengthening schemes matching with anticipated growth in demand in the various areas. Agreement on the proposal together with commercial tie-up for payment of transmission charges based on long-term open access application becomes a critical issue in this context. Generation capacity used for trading transactions should have commitment for long-term transmission charges The short-term or Power exchange transactions may take place out of generation capacities for which transmission system have been provided based on commitment of long-term transmission charges to be paid either by the generator or by the identified beneficiary having long-term PPAs from such generation. The short-term or Power exchange transactions may also take place out of generation capacities for which there is no commitment of long-term transmission charges. The transactions of the second kind would reduce the reliability margins of the transmission system provided based on long-term commitments. Inter-regional trading transactions out of generation capacities for which transmission system is provided only in the region where the generation is located and not in the region where the transacted power is sold are also akin to the second kind for the importing region as well for the interregional transmission. In a developing system, depletion or reduction of reliability of the transmission system by generators intending to sell through short-term trading without tying-up and committing for the transmission charges corresponding to their Page 21 of Chapter 2

199 Transmission Planning & National Grid full requirement would be harmful. As such, it would be necessary that all generation capacities intended to be utilization through trading transactions should provide commitment for long-term transmission charges Transmission Charges for Short-Term Open Access Levy of open access transmission charges at reduced rates would be justified for short-term or Power exchange transactions of the first kind that is those taking place out of such generation capacity for which long-term transmission charges have also to be paid. However, levy of open access transmission charges at reduced rates may not be justified for short-term or Power exchange transactions of the second kind, that is those taking place out of such generation capacity which are created without commitment for long-term transmission charges Transmission Capacity Margins Transmission capacity through creation of additional transmission system could be provided based on long-term commitment for the transmission charges. It has been estimated that reliability and operation margins would be generally of the order of 25-30% of the transmission capacities required for meeting the firm transmission needs of the long-term committees. This level of redundancy would generally provide sufficient margins for trading needs. However, it should be noted that short-term open access (STOA) transactions operating on these margins, even if curtailable, cause reduction in the security level. Therefore, unless margins are increased by design, the system operator would have tendency to keep cushions by underestimating the operational margins. As the system security is of paramount importance, creation of increased margins by design becomes essential for accommodating STOA. This involves costs which are in addition to the cost of incremental losses caused by STOA. Both these costs should be recovered from STOA customers. Lesser charges for STOA would dissuade long-term commitments for transmission charges leading to retarded growth in transmission system Transmission System for Merchant Plants Merchant plants would sell their power to customers who are not predetermined through Power exchange contracts. However, they are long term-user of the transmission system. The transmission system for the connectivity of the merchant plant as well as for meeting their transmission needs is required to be planned and built matching with the implementation of the merchant generation plant. Also, some of the generation plants have only a part of their generation capacity tied-up in longterm bi-lateral PPAs. When such plants seek long-term open access only for a part of their full generation capacity, they inherently also seek connectivity for the remaining capacity which would be available with them as a merchant plant capacity. As the transmission system in both the cases would be required to be planned and implemented corresponding to the full requirement, they are long-term beneficiary of the transmission system. For proper planning and implementation of transmission system, the merchant generators need to inform about region(s) in which they would generally sell their power, so that transmission system requirement for evacuation of their power and transmitting it to identified load centres could be assessed and any additional capacity required could be planned. As building the identified transmission Page 22 of Chapter 2

200 Transmission Planning & National Grid schemes including obtaining necessary approvals by the identified transmission company /companies would generally require almost same time as that for implementation generation projects, firming up of sellers and assessment of transmission requirement should be started at the earliest Need for Revising Transmission Tariff Design As, the merchant plants would not have long-term commitments for selling of their power, a transmission tariff design is needed in which such generators could share the transmission charges proportionate to their generation capacity. Also, there is an urgent need for National concept in transmission tariff so as to address the issue of high transmission charges in the North-eastern region as well enabling expeditious development of long-haul inter-regional transmission corridors. However, National pooled transmission tariff should not be on flat postage stamp method. We know that the flat postage stamp method applied in the regional pooled transmission tariff puts the load centric generation at a disadvantage, but is acceptable in the regional system on account of its simplicity and generation resources within the region being fairly dispersed and thus moderating the effect of distortion. However, application of flat postage stamp method in National pool tariff would totally distort the economics of load centric generation as the physical disposition of generation resources in the country is quite uneven and the transmission distances quite large. Also, the techno-economic considerations highlight the need of directional sensitivity in transmission tariff design. A pragmatic change in the transmission tariff design is needed so as to capture the sensitivity of locating and dispatching the generation resources and give proper tariff signals towards optimizing the choices. Zonal Matrix Transmission Tariff design suggested by CEA should be considered in this context. Regulations for connectivity of merchant generation capacity, transmission capacity of Power exchange and need for new transmission tariff design are all related issues which seek a comprehensive solution towards facilitation trading coupled with optimal choices in locating and dispatching generation and also attracting investments in strengthening transmission network that would be needed to top-up the system reliability effected by market determined transactions. 2.6 POWER EXCHANGE WITH NEIGHBORING COUNTRIES India has bilateral cooperation for power exchange with Nepal and Bhutan. The terms of co-operations with Bhutan also includes development of hydro power projects and power system in Bhutan which has fructified in accelerated development of the projects in Bhutan. With other South Asian Nations, namely Bangladesh, Pakistan, Myanmar, Thailand and Sri Lanka, discussions have been held from time to time on possible road map for co-operation between the South Asian Nations in the forum of SAARC and BIMSTEC initiatives. The discussions have covered many areas including power. However, as yet, there is no agreed cooperation for exchange of power with any other Nation except Bhutan and Nepal. Page 23 of Chapter 2

201 Transmission Planning & National Grid India-Bhutan India and Bhutan have terms of cooperation for development of hydro generation and power system in Bhutan and power supply to India for mutual benefit of both the countries. Hydro Projects at Chukha (336 MW), Kurichu (60 MW) and Tala (1020MW) in Bhutan have been implemented with technical and financial assistance of India. Transmission system for export from Bhutan to India has also been developed with these hydro generation projects. The transmission system developed with these projects is: 220 kv Chukha (Bhutan)-Birpara (India) (3 circuits) and 132 kv Kurichu-Gelphu (Bhutan) Bongaigaon/Salakati (India) (single circuit) lines. Tala HEP (6x170 = 1020 MW) is also being implemented with Indian technical and financial assistance. As the internal demand in Bhutan is much less as compared to capacity of the generation projects, most of power from Tala HEP would also be exported to India. Two nos. of 400 kv double circuit lines from Tala HEP (Bhutan) to Siliguri (India) have been provided along with the generation project. The first unit of 170 MW at Tala HEP has been commissioned on and the other units are being commissioned progressively and it is expected that all units at Tala HEP will be commissioned by the end of this year. Phunatsanchhu-I (1000MW), Phunatsanchhu-II (1000MW) and Mangdechhu (600MW) hydro electric projects in Bhutan have also been envisaged to be developed with Indian cooperation and investigation/dpr activities have been takenup. Comprehensive transmission system for power evacuation from these projects have been tentatively evolved and would be firmed-up and developed in a phased manner matching with phased development of the generation projects. Commissioning of these projects is being tentatively programmed during Power imported from these projects would be pooled at Siliguri and further transmission to the stated of Northern region and Western region is planned through HVDC system. India also exports power to Bhutan during winter period when there is reduced hydro generation in Bhutan. Power import from Bhutan in the last 3-years is as under: Year Total power import by India from Bhutan (MU) Following transmission lines are existing between India and Bhutan: 400kV 2xD/C Tala(Bhutan) Siliguri(West Bengal, India) 220 kv,1xd/c, Chukha(Bhutan)-Birpara ( West Bengal, India) 220 kv,1xs/c, Chukha(Bhutan) -Birpara( West Bengal, India) 132 kv,1xs/c, Kurichu(Bhutan) -Gelephu(Bhutan)-Salakati (Assam,India) Page 24 of Chapter 2

202 Transmission Planning & National Grid 33kV(operated at 11kV),1xS/C,Tamulpur(Bhutan)-Rangia(Assam, India) 11 kv, 1xS/C,Udalguri(Bhutan) -Daifam(Assam, India) 11 kv, 1xS/C,Banarhat(Bhutan) -Samtse(West Bengal, India) 11 kv, 1xS/C,Jaldhaka(Bhutan) - Sibsoo(West Bengal,India) India-Nepal India has terms of co-operation for exchange of power with Nepal. The inter-border exchange of power between India and Nepal has been taking place for mutual assistance in supplying to border areas of the two countries. Bilateral exchange of power between India and Nepal is taking place since 1971, between contiguous areas on the border of India and Nepal. These bilateral exchanges between India and Nepal take place through various interconnecting lines at 11 kv, 33 kv and 132 kv between Nepal and the bordering States of India viz. Bihar, Uttaranchal and U.P. The exchange of power between the two countries is taking place between Nepal Electricity Authority (NEA) and U.P. Power Corporation Ltd (UPPCL), Uttaranchal Power Corporation Ltd (UPCL), Bihar State Electricity Board (BSEB). Only Bihar has bi-directional exchanges with Nepal. While UP and Uttaranchal only export power to Nepal. Quantum of power exchange between the bordering States of India and Nepal during the last three years is the following:- BSEB (Bihar)-NEA (Nepal) Year Import from Nepal (MU) Export to Nepal (MU) UPPCL (Uttar Pradesh, India NEA (Nepal) Transmission lines between Nepal and Bordering States of India BSEB(Bihar)- Nepal: 132kV Gandak- Ramnagar 132kV Bhantabri Duhabi 132kV Gandak east Gandak 33kV Bhadrapur Thakurganj 33kV Birganj Raxaul 33kV Kataiya Biratnagar Year Export to Nepal (MU) Page 25 of Chapter 2

203 Transmission Planning & National Grid 33kV Kataiya Rajbiraj 33kV Sitamarhi Jaleshwer 11kV Biratnagar Jogbani 11kV Jainagar Siraha 11kV Birgania Gaur UPPCL(UP)- Nepal: 33kV Pallia-Dhangarhi 33kV Itwa-Krishnanagar 33kV Anandnagar-Bhairwan 33kV Nanpara-Nepalganj 11kV Tulsipur-Koilabasa UPCL(Uttaranchal)- Nepal: 33kV Lohiahead Mahendranagar 11kV Pithoragarh Baitadi 11kV Dharchula Jaljibe 11kV Dharchula Pipale India-Pakistan No transmission link is existing between India and Pakistan. During , Government of India considered a proposal from Pakistan for export of power from Pakistan to India. However, no progress was made as the talks got bogged down on issues relating to tariff for power to be purchased from Pakistan India-Bangladesh No transmission link is existing between India and Bangladesh. During proposal for exchange of power between India and Bangladesh was considered under the aegis of ADB. Though couple of meetings was held in the past between the two governments no progress/agreement has since then taken place India-Sri Lanka No proposals have been formally discussed between the two countries. A study on viability of inter-connection with Sri Lanka was carried out in 2002 by M/s Nexant under USAID, SARI/E program. Recently, Nuclear Power Corporation of India Limited has mooted a proposal for supply 400 MW to Sri Lanka for which HVDC inter-connection has been proposed. However, there has been no discussion with Sri Lanka on these proposals India-Myanmar Talk of co-operation had been in reference to Tamanthi HEP (tentative 1200 MW) in Myanmar from which power was also proposed to come to India. Page 26 of Chapter 2

204 Transmission Planning & National Grid Formation of SAARC Grid SAARC has number of technical committees to implement, coordinate and monitor the programmes in their respective areas of co-operation. There is a technical committee for co-operation on energy. First meeting of SAARC technical committee was held in Dhaka on Nov in which various issues including possibility of creation of regional power grid between India, Bhutan, Nepal and Bangladesh was discussed. The Indian position in this regard was that creation and growth of cross border transmission links depended on identification of commercially viable electricity flows from generating stations to load centres. The flows through the Indian grid could take place through displacement. The meeting recommended that the matter might be discussed further between the countries of India, Nepal, Bhutan and Bangladesh with a view to evolving suitable arrangements in that regard. No progress/agreement has since then taken place BIMSTEC BIMSTEC (Bay of Bengal Initiative for multi-sectoral technical & economic cooperation) has members from Bangladesh, Bhutan, Nepal, Myanmar, India, Sri Lanka, and Thailand. The first BIMSTEC Energy Ministers Conference was held in New Delhi on 4 th October Subsequently, a workshop on BIMSTEC Energy Centre was held in New Delhi on January, 2006 as per the agreed Plan of Action for energy co-operation in BIMSTEC. The concept note on BIMSTEC Energy Centre is under consideration. It is proposed that the India would be the host country for the BIMSTEC Energy Centre. Draft MoU for the BIMSTEC grid interconnection circulated during the task force meeting for BIMSTEC Power Exchange and development Project held on th March 06 in Bangkok inter-alia included principles and objectives, institutional arrangements which would form a framework for the member countries to cooperate works towards the implementation of grid interconnection for the trade in electricity in the BIMSTEC region. The next (second) BIMSTEC Summit is likely to be held in February RELIABILITY ISSUES AND GRID OPERATION Planning for a Reliable Power System The key to a reliable power system is made up of the following levers: Adequacy of the provisions with planned level of redundancies sufficient to deliver the desired reliability Secured operation maintaining sufficient margins at all times so as to maintain system loading within such limits that contingencies do not lead to loss of system integrity Best practices in maintenance both preventive as well as restorative To facilitate orderly growth and development of the power sector and also for secure and reliable operation of the grid, adequate margins in transmission system should be created. A Reliable power system can be planned through centralised planning of Regional and National grid systems coupled with matching development in the State grid systems. This would require adequate Page 27 of Chapter 2

205 Transmission Planning & National Grid and timely investments with coordinated action for implementing the schemes. The needs are: Augmenting transmission capacity matching with generation additions Adequate redundancies as per specified criteria to provide the desired reliability margins Development of transmission system for power evacuation as well as system strengthening 11 th Plan transmission plan/programme has been evolved meeting the above requirement. Transmission capacities have been planned to cater to the specified redundancy levels as per the planning criteria adopted in line with international standards and practices. The major highlights of transmission planning criteria in are: The transmission system planned in an integrated manner optimizing the total network including that under the CTU as well as that for the STU(s). Criteria for mesh/loop network: 'N-1' adopted in general. 'N-2' adopted for transmission system from large generating complex (3000 MW or above) and multi line corridors (3 D/C lines or more), on case to case basis. In 'N-1' system adequacy without necessitating load shedding or rescheduling of generation during steady state operation. In 'N-2' system adequacy without necessitating load shedding but could be with rescheduling of generation during steady state operation. 'N-1' withstand without necessitating load shedding or rescheduling of generation during steady state operation Outage of a 132kV D/C line, or Outage of a 220kV D/C line, or Outage of a 400kV S/C line, or Outage of single Interconnecting Transformer, or Outage of one pole of HVDC Bipole line, or Outage of a 765kV S/C line without series compensation. 'N-2' withstand without necessitating load shedding but could be with rescheduling of generation during steady state operation - Outage of a 400kV S/C line with TCSC, or Outage of a 400kV D/C line, or Outage of both poles of HVDC Bipole line, or Outage of a 765kV S/C line. The above contingencies considered with a pre-contingency system depletion (Planned Outage) of another 220kV D/C line or 400kV S/C line in another corridor and not emanating from the same substation. Operation of all the Generating Units within their reactive capability curves and the network voltage profile within voltage limits specified. For requirement of reliability, planning criteria for evacuation system for Nuclear power station is to consider outage of one circuit assuming precontingency depletion of another circuit from the same station. This is effectively N-2 without rescheduling but with no other pre-contingency. 'N-2' also for large cities with a power demand of 2000 MW or above Page 28 of Chapter 2

206 Transmission Planning & National Grid Inter-regional transmission capacity based on requirement arising on account of regional variation in surpluses and deficits during the peak and off-peak hours of different seasons viz.: Summer Peak Load; Summer Off-peak Load; Winter Peak Load; Winter Off-peak Load; Monsoon Peak Load; Monsoon Off-peak Load; Dispatch scenarios for maximizing transfer in specific inter-regional corridors considered to determine the adequacy of transmission system to take care of requirement of regional diversity in inter-regional export / import. Sensitivity in respect of generation dispatch or load demand causing increased burden on transmission system considered Growth Objectives A well planned and reliable transmission system will ensure not only optimal utilization of transmission capacities but also of generation facilities and would facilitate achieving ultimate objective of cost effective delivery of power. Development of the transmission system thus planned would meet the following objectives: Similar level of development of transmission system across the country Transmission system for optimally utilizing the hydro-thermal mix of generation resources taking into account the concentration of coal in the eastern part of the country and hydro power sources in the north - eastern and northern parts of the country. Obtaining the advantages of diversity based exchanges of power; that is, exchanges on account of regional variations in generation and demand pattern arising due to geographical, seasonal, time of day and operational diversities. Formation of National Power Grid that would enable exploitation of unevenly distributed generation resources in the country to their optimum potential. For the full utilization of the generating capacity in the eastern part of the country, an adequate transmission system has been planned linking the North-eastern and Eastern part of the country with the Northern, Western Southern regions aiming that no generating capacity is rendered idle due to transmission constraints. Continued development of Regional Grids so as to meet the transmission needs within each of the regions catering to the power evacuation from generation capacity additions and strengthening in the regional grids addressing requirements of specific areas. Transmission system strengthening schemes to overcome the deficiencies and provide a reliable transmission grid that has margins for open access and also provides to cater to changes in the pattern of power flows for interstate transmission arising on account of capacity additions for intra-state benefits Development Needed in State sector A well planned and reliable transmission system at the National and Regional level would need to be complemented with development of matching transmission system at 220kV and 132kV and also the sub-transmission and distribution system so as to cater to the load growth and ensure proper utilisation of development in generation and transmission facilities for the Page 29 of Chapter 2

207 Transmission Planning & National Grid ultimate goal of delivery of the services up to the end consumers in the country Timely Implementation to Ensure Delivery of a Reliable Power System to the System Operators If the desired reliability is to be achieved, all the utilities, both in the Central sector as well as State sector would need to ensure timely implementation of the schemes. A task force under the chairmanship of Member (Power Systems), CEA constituted by Ministry of Power, in its report of August 2005 has recommended the following: (1) Parallel Processing of Activities A transmission project involves various activities from concept to commissioning. The Task Force observed that major reduction in project implementation schedule is possible by undertaking various preparatory activities (viz. surveys, design & testing, processing for forest & other statutory clearances, tendering activities etc.) in advance/parallel to project appraisal & approval phase and go ahead with construction activities once Transmission Line Project sanction/approval is received. (2) Packaging Concept Total transmission project should be broken down to clearly defined packages such that the packages could be procured & implemented requiring least co-ordination & interfacing and at same time it attracts competition facilitating cost effective procurement. The size & scope of the different packages will therefore depend on magnitude & location of project. However, the packages should be few and supply-cum-erection type contracts should be preferred to avoid co-ordination problems. The Task Force suggested typical packages for procurement / construction of Transmission system. (3) Standardization of Designs To avoid repetitive work and uncertainties during testing, the tower designs should be standardized. It is desirable that the designs are standardized and development by Utilities prior to floating of tenders for tower fabrication and construction so that 6-12 months or more time can be saved in project execution. Standardization of designs/drawings for other transmission line materials & substation structures, equipments, control room building etc. also should be standardized to the extent possible. (4) Qualifying requirements for Vendors/Bidders In order to select contractors of appropriate capability & capacity it is required that Qualifying requirements in respect of technical resources, financial capability, production capacity, tools & plants etc are stipulated in bidding documents and contractors are selected accordingly. (5) Bidding Document & Bidding Philosophy The bidding documents should furnish all information necessary for a prospective bidder to prepare a bid for the goods and works/services to Page 30 of Chapter 2

208 Transmission Planning & National Grid be provided. The technical specifications and conditions of contract need to be unambiguous. Considering volatility of the input cost, it is desirable that contracts are invited with suitable price variation provisions such that contract price is adjusted based on published indices of raw materials & labour. Single stage bidding may be practiced for transmission line & substation works with appropriate packaging and qualification requirement. (6) Route Alignment, Detailed Survey & Soil Investigations It is desirable that the project is defined to finer details to the extent possible at the FR / Notice Inviting Tender (NIT) stage for effective planning and scheduling of project(s) besides optimization of resources. New technology/ techniques such as use of satellite imagery, GPS, total stations, computer-aided tower spotting etc. for getting realistic information/details leading to selection of optimum route alignment and facilitating realistic estimation of bill of quantities have been suggested. To avoid large quantity variations during execution stage, which can be a cause of dispute/delay, it would be desirable to carryout detailed survey before NIT. (7) Mechanization in Construction, Quality Management System etc. Thrust is to be given towards use of new technologies & mechanized means for construction of transmission projects to reduce time. Besides implementation of standardized Manufacturing & Field Quality Plans, utilities should also adopt prompt and transparent Inspection Management System for smooth implementation of the project. (8) Environment, Forest Clearance and Rehabilitation & Resettlement (R&R) Advance action should be taken for processing forest clearances. With adoption of modern survey t9chniques, it is possible to minimize the infringement with forest as various alternatives can be analyzed. It is also helpful in convincing the concerned Authorities for expediting clearances, as better evaluation of forest involvement is possible. It is also desirable that Environment & Social Policy & Procedures (ESPP) are required to be framed by utilities through consultative process. Such initiatives would assist in settlement of R&R and environmental issues expeditiously and avoid delays on this account. (9) Vendor Development A large number of projects would be taken up by many utilities concurrently for construction due to the large transmission programme to be implemented in limited time frame. It is, therefore, recommended that active vendor development initiatives are to be taken by all utilities so that indigenous capabilities are effectively developed and adequate supplier/ vendor base is created to have competitive prices and timely completion of projects. Page 31 of Chapter 2

209 Transmission Planning & National Grid (10) Project Monitoring A master network for the entire project from concept to commissioning need to be prepared and monitored regularly with reference to the target and required actions are taken. Similar detailed network is also to be prepared for each package for monitoring activities at micro level. Regular reviews should be done at Project Manager level and quarterly review at Chief Executive level also is recommended. (11) Various aspects as brought out above were deliberated in depth by the Task Force, however, project authorities need to review and adopt depending upon the size nature, location and complexities of the project on case-to-case basis. A reasonable time schedule for a specific project is required to be tailor-made for each project element like transmission line, substations, HVDC terminals etc. depending on its size, nature & complexity. Further, in case of large projects where many such project elements are involved, suitable time periods need to be provided for each element and the overall project completion schedule is to be accordingly decided Load Dispatch and Communication Facilities The availability of adequate load dispatch and communication facilities is necessary for the smooth interconnected operation of the power system. The would require a full fledged National Load Dispatch Center apart from upgrading the existing Regional Load Dispatch Centers and State Load Dispatch Centers. For enabling him to operate the system in a secured and reliable manner, the load dispatcher should be provided with state of art tools equipped with required telemetry, communication, computerized real-time data acquisition systems and necessary supervisory control facilities for efficient operation of the power system. At the National level, practically all the system starting from the functional specification, is to be developed picking the telemetry from Regional systems and building all the application functions needed for the National Load Dispatch Center. At the regional level though considerable data acquisition and communication facilities have been created, these are not yet sufficient for implementation of state of art functions such as state-estimation/data validation, contingency evaluation, optimal load flow, security margin estimation, etc. For improving the operational reliability while utilising the system to its fullest potential, it is necessary to upgrade the Regional load dispatch system to the state of art. At the state level there are deficiencies in many cases which require to be quickly removed so as to facilitate smooth integrated operation of the power system. System reliability also depends on quick restoration following any contingencies. In case there is partial or total system collapse, re-energisation and restoration of the system would be possible in a short time only if adequate load dispatch and communication facilities were available. As there would be a large number of organizations whose power systems would be connected in parallel efficient voice communication facilities would also be needed between the load dispatch centers and the control rooms of the various utilities. When Power exchange is put in place, necessary Page 32 of Chapter 2

210 Transmission Planning & National Grid communication facilities linking the Power exchange and the National Load Dispatch Center as well as Regional Load dispatch centers would also be needed Protection System Power systems operating in synchronism should be provided with adequate defence measures such as islanding schemes and automatic load shedding schemes, so that following major incidents in the system, the system could continue to operate without cascade failure leading to black out in large areas. The protection schemes for the transmission lines, transformers, bus bars, generators and other important power equipments should be of the highest quality and should be properly coordinated. In order to cater to contingencies of loss of generation, under - frequency relays for load shedding (both flat frequency relays and rate of change of frequency relays) should be provided for shedding load automatically. Inter-regional flows should also be used for triggering appropriate protective action. This would prevent distress in the system from spreading. In case a part of the power system is under acute distress, it should be isolated out automatically from the remaining healthy part of the system in such a way that as much a part of the system as possible continued to operate. With such schemes, procedures for reconnecting the power systems in actual operation would also have to be devised. In this regard, the international experience of operating vast power systems in synchronism should also be drawn upon. It has been noted that there would be heavy power flow from the north - eastern and eastern parts of the country and the hydro-electric projects in the northern part of the country to other parts of the country. With integration of systems in synchronous mode creating combined system of large power number, the parameters determining level of grid security have changed. The variation in grid frequency has reduced and therefore, in integrated NR/ER/NER/WR system the frequency of 49.5 is like the frequency of 49.0 of the NR or WR system. Therefore under-frequency relays need to be reset at higher frequency cut-offs and the system should be considered in Alert state at those frequencies which were not so critical in earlier regional system operation. Also, the inter-regional and inter-area tie-line flows have become critical parameters for monitoring the security of the grid and the grid security is now to be judged more by the power flows rather than frequency. The system operators should therefore realign their strategies accordingly. The synchronous interconnection has also thrown open a vast horizon of operational opportunities for dispatch optimization utilizing inter-regional diversities. There is paradigm shift in system operation requiring a new set of practices and procedures for operational planning, scheduling, monitoring and grid security etc. which have to evolve with consolidation of experience of operating the large synchronously interconnected system Grid Operation and Management In view the growing complexities and change in market mechanism, it is necessary to continuously upgrade and modernize the Grid operation & control and communication facilities to operate large grid on real-time basis Page 33 of Chapter 2

211 Transmission Planning & National Grid dynamically with safety, security and reliability. Towards this, it is envisaged to develop Intelligent Grid with State-of-the-art features like wide area measurement, adoptive islanding, probabilistic assessment, Dynamic Stability Assessment (DSA) & Voltage Stability Assessment (VSA) technique, self healing grids etc. on a pilot scale Best practices in Maintenance The transmission utilities should maintain a high level of system availability and at the base level of system availability by adopting best practices. Emphasis should be given on both preventive as well as restorative maintenance. Emphasis should also be give to R&M programme, Residual Life Assessment and restoration efficiencies in Transmission. 2.8 FUND REQUIREMENT DURING 11 TH PLAN FOR TRANSMISSION SYSTEM DEVELOPMENT AND RELATED SCHEMES Total Fund requirement for transmission system development and related schemes has been estimated as following: Rs Crore Central Sector (Inter State Transmission System) State Sector (State Transmission System) TOTAL Fund Requirement during 11 th Plan Central sector schemes Development of National and Regional grids and related systems would require the following types of schemes: XI Plan Transmission Schemes for power evacuation and system strengthening for Central sector generation capacity requiring inter-state transmission Transmission schemes for IPP Generation Capacity seeking open access from CTU for inter-state transmission Spill over expenditure of X Plan transmission schemes and advance action for XII Plan transmission schemes Other related important schemes in Central sector Fund requirement for above types of schemes during XI plan is estimated to be as following: Page 34 of Chapter 2

212 Transmission Planning & National Grid Rs Crores Estimated Requirement XI Plan Transmission Schemes for MW of Central sector generation capacity requiring inter-state transmission Transmission schemes for IPP Generation Capacity of MW seeking open access from CTU for inter-state transmission Spill over expenditure of X Plan transmission scheme And 7000 advance action for XII Plan transmission schemes Total Central Sector Transmission Schemes Other related important schemes in the Central Sector Load dispatch schemes for National and Regional dispatch centres 500 Comprehensive upgrading of protection system for total integrated 200 system for security of National and Regional grids National Power Exchange System 50 Evolving perspective transmission plan for the 12 th Plan 10 Augmentation of test facilities 40 Total other related important schemes in Central Sector 800 Total Central Sector Fund Requirement during XI Plan State Sector Schemes Development of State grids and related systems would require the following types of schemes: XI Plan Transmission Schemes of STUs for evacuation of state sector generation including intra-state open access to IPP Generation in state sector STUs transmission schemes at 220kV, 132kV and 66kV to meet the transmission needs of growth in demand Spill over expenditure of X Plan transmission scheme and advance action for XII Plan transmission schemes Other related important schemes in the State sector for Renovation and modernization of aging transmission system, State/Area load dispatch system, Protection system up-gradation, and Software for planning and management information system. Fund requirement for above types of schemes during XI plan is estimated to be as following: Page 35 of Chapter 2

213 Transmission Planning & National Grid Rs Crore Estimated Requirement XI Plan Transmission Schemes for MW of State sector and IPP generation capacity requiring intra-state transmission. STU transmission schemes at 220kV, 132kV and 66kV to meet the transmission needs of growth in demand. (State-wise details of normative assessment is given at Appendix 2.10) Transmission schemes for 220kV, 132kV and 66kV 6000 system in states of Assam, Nagaland, Bihar, Jharkhand, Goa and Uttar Pradesh for strengthening of transmission system in these states so that these states may cater to a demand level of at least 50% of National average. (Details of this assessment is also given in Appendix 2.10) Spill over expenditure of X Plan transmission scheme and 7800 advance expenditure on XII Plan transmission scheme Other related important schemes in the State sector for 8000 Renovation and modernization of aging transmission system, State/Area load dispatch system, Protection system up-gradation, and Software for planning and management information Total State Sector Transmission Schemes Total 1,40,000 ********** Page 36 of Chapter 2

214 Transmission Planning & National Grid Appendix-2.1 HVDC Transmission Bipole, Back-to-back and Monopole lines and terminal station Existing at the end of 9th Plan and programme for 10th Plan HVDC Bipole Line As at the end of 9th Plan i.e. 3/ As at the end of 10th Plan i.e. 07 3/2007 Chnadrapur-Padghe ± 500kV MSEB ckm Rihand-Dadri ± 500kV PGCIL ckm Talcher-Kolar ± 500kV PGCIL ckm TOTAL HVDC Bi-pole Transmission Capacity Chnadrapur-Padghe bipole MSEB MW Rihand-Dadri bipole PGCIL MW Talcher-Kolar bipole PGCIL MW TOTAL HVDC Back-to-back Transmission Capacity Vindhachal b-t-b PGCIL MW Chandrapur b-t-b PGCIL MW Gazuwaka b-t-b PGCIL MW Sasaram b-t-b PGCIL MW TOTAL HVDC Monopole Line Barsur-Lower Sileru 200kV CSEB/ APTRAN SCO ckm TOTAL HVDC Mono-pole Transmission Capacity Barsur-Lower Sileru Monopole CSEB/ APTRAN SCO MW TOTAL Page 37 of Chapter 2

215 Transmission Planning & National Grid Appendix-2.2 Transmission lines and sub-station at 765kV Existing at the end of 9th Plan and programme for 10th Plan kV Transmission Lines As at the end of 9th Plan i.e. 3/ As at the end of 10th Plan i.e. 3/2007 Anpara-Unnao S/C UPPCL ckm Kishenpur-Moga L-1(W) S/C PGCIL ckm Kishenpur-Moga L-2(E) S/C PGCIL ckm Tehri-Meerut Line-1 S/C PGCIL ckm Tehri-Meerut Line-2 S/C PGCIL ckm Agra-Gwalior Line-1 S/C PGCIL ckm Sipat-Seoni Line-1 S/C PGCIL ckm Sipat-Seoni Line-2 S/C PGCIL ckm TOTAL kV Sub-stations (765/400kV) Seoni PGCIL MVA Sipat PGCIL MVA TOTAL Page 38 of Chapter 2

216 Transmission Planning & National Grid Appendix-2.3 Northern Region In Northern Region following inter-state transmission schemes have been planned and are under execution for benefit during X plan. S. Name of Scheme N. 1. Series Comp + TCSC on Kanpur-Ballabhgarh 400kV S/C 2. System Strengthening in Singrauli-Vindhyachal corridor 3. Transmission system associated with Dhauli Ganga 4. Northern Region System strengthening scheme-i 5. Northern Region System strengthening scheme-ii 6. Transmission system associated with Dulhasti Scheme Description In this scheme 40 % fixed series compensation and 15 % variable compensation is proposed on Kanpur-Ballabhgarh 400 kv S/C line. This would increase the power transfer capability from Eastern to Western part of Northern Grid and improve stability of Northern Grid. a) Opening of existing 400 kv line between Vindhyachal-Kanpur at Vindhyachal end and connecting it to Singrauli end so as to form Singrauli- Kanpur 400 kv S/C (3 rd ckt) b) Singrauli-Vindhyachal 400 kv S/C (2 nd ckt) to utilize the vacant bay as created above a) Dhauli Ganga- Bareilly 400 kv D/C (initially operated at 220 kv) a) Kanpur-Auraiya 400 D/C b) Bareilly Switching station of PG, 400kV c) LILO of Lucknow-Moradabad 400 kv S/C at Bareilly (PG) d) LILO of Bareilly-Mandola 400kV D/C at Bareilly (PG) 2xD/C e) Bareilly (PG)-Moradabad 400kV S/C f) LILO of Sultanpur-Lucknow 400kV S/C at Lucknow PG a) Fixed series compensation of 40% on Allahabad- Mainpuri 400 kv D/C line designed for 95 o C b) Agra-Jaipur 400 kv DC c) Wagoora 400/220 kv, 3rd transformer a) Dulhasti-Kishenpur 400 kv S/C b) Kishenpur-Wagoora 400 kv D/C c) Kishenpur 315 MVA 400/220 kv S/S Page 39 of Chapter 2

217 Transmission Planning & National Grid S. Name of Scheme N. 7. Transmission system associated with Rihand-II 8. Northern Region System strengthening scheme-iii 9. Transmission system associated with Sewa-II 10. Transmission system associated with Parbati-II 11. Transmission system associated with Koteshwar 12. Northern Region System strengthening scheme-iv 13. Transmission system associated with RAPP-5&6 14. Northern Region System strengthening scheme-v 15. System strengthening in Roorkee 16. Additional transformers at Moga and Amritsar Scheme Description a) Rihand-Allahabad 400 kv D/C b) Dadri - Panipat 400 kv S/C - 2nd ckt c) Patiala- Malerkotla 400 kv S/C d) LILO of 400 kv Nalagarh -Hissar one Ckt at Kaithal S/S e) LILO of 400 kv Nalagarh -Hissar one Ckt at Patiala S/S f) Rihand- Mainpuri-Ballabgarh 400 kv D/C g) Kaithal 630 MVA 400/220 kv S/S h) Patiala 630 MVA 400/220 kv S/S i) Mainpuri 315 MVA 400/220 kv S/S (Aug.) j) Abdullapur 315 MVA 400/220 kv S/S 3rd ICT (Aug.) a) Malerkotla Ludhiana-Jullundhar 400kV S/C b) LILO of one ckt Moga-Hissar 400kV D/C c) Ludhiana 400/220kV S/, 2x315 MVA d) Fatehabad 400/220kV S/, 2x315 MVA a) Sewa -Hiranagar 132 kv D/C b) Sewa - Khatua 132 kv via Mahanpur a) Parbati-Nalagarh 400 kv 2xS/C (Quad) a) Koteshwar-Tehri PoolingPoint 400 kv D/C line b) LILO of Tehri-Meerut at Tehri PP c) Series comp. of 50% on TehriPP-Meerut 2xS/C d) Tehri GIS Pooling Station a) Provision of SVC support in NR system. (Total quantum of compensation, their size and location would be identified after further studies.) a) RAPP-Kankroli 400 kv D/C b) RAPP-Kota 400 kv S/C c) Kota 400/220 kv 3x250 MVA S/S d) Kankroli 400/220 kv 3x315 MVA S/S a) LILO of 400 kv Hissar-Jaipur at Bhiwadi b) Bhiwadi-Agra 400kV D/C c) Bhiwadi-Moga 400kV D/C a) Establishment of Roorkee 1x315 MVA 400/220 kv S/S by LILO of Rishikesh- Muzaffarpur S/C line at Roorkee S/S a) Moga 400/220 kv 1x250 MVA (Aug) 3 rd transformer b) Amritsar 400/220 kv 1x315 MVA (Aug) 3 rd transformer Page 40 of Chapter 2

218 Transmission Planning & National Grid S. Name of Scheme N. 17. Tala Transmission System for NR 18. Tala Supplementary Transmission System in NR 19. Supplementary Transmission system associated with RAPP- 5&6 20. Associated Tr. System of Kahalgaon-II Phase-I(2x500 MW) and Phase-II (1x500 MW) in NR Scheme Description a) Gorakhpur-Lucknow (new) 400 kv D/C b) Lucknow (New)-Unnao 400 kv D/C c) Bareilly- Mandola 400 kv D/C d) LILO of 400 kv Dadri-Samaypur D/C line at Maharani Bagh-2xD/C e) Gorakhpur (new)-gorakhpur (UP) interconnection 400 kv D/C f) Gorakhpur 1x315 MVA 400/220 kv S/S (new) with 2x63 MVAR L/R g) New Lucknow 1x315 MVA 400/220 kv S/S(new) h) Maharani Bagh 2x315 MVA 400/220 kv S/S (new) a) Jullandhar-Amritsar 400kV S/C line and 400/220kV 1x315 MVA s/s at Amritsar b) Bahadurgarh 400/220kV 1x315 MVA s/s by LILO of Bawana-Bhiwani 400kV line c) 2 nd 315 MVA 400/220kV transfrmr at Gorakhpur a) Kota-Merta 400 kv D/C b) Kankroli-Jodhpur 400 kv S/C a) Balia-Mau 400 kv D/C b) Balia-Lucknow (PG) 400 kv D/C with ser cap c) Lucknow (PG)-Bareilly (PG) 400 kv D/C. Page 41 of Chapter 2

219 Transmission Planning & National Grid Appendix-2.4 Western Region In Western Region following inter-state transmission schemes have been planned and are under execution for benefit during X plan. S. N. Name of Scheme Description 1. Associated Transmission a) Tarapur-Boisar 400kV D/C System of TAPP 3&4 b) TAPP(Extn.)-Boisar 220kV S/C (For start up power) c) Tarapur-Padghe 400kV D/C d) LILO of Gandhar-Padghe 400 kv S/C at Vapi (PG) e) LILO of Gandhar-Padghe 400 kv S/C at Boisar (PG) f) Vapi (PG) 2x315 MVA 400/220 kv S/S g) Boisar (PG) 2x315 MVA 400/220 kv S/S 2. Raipur-Bhadrawati 400kV D/C a) Raipur-Bhadrawati 400 kv D/C 3. Bhadrawati-Chandrapur 400kV a) Bhadrawati-Chandrapur 400kV D/C D/C 4. Associated Tr. System of Vindhyachal-III (2x500 MW) a) Vindhyachal-Satna-Bina 400 kv D/C b) LILO of both ckts of Rourkela-Raipur 400 kv D/C line at Raigarh c) LILO of both ckts of Satna-Bina (MPSEB) 400 kv D/C line at Bina (PG) d) Raigarh 2x315 MVA 400/220 kv S/S e) Bina (PG) 400/220kV Switching sub-station a) Vindhyachal-Korba 400 kv S/C line (2 nd ckt.) 5. Vindhyachal-Korba 400 kv S/C line (2 nd ckt.) 6. Bina-Nagda 400 kv D/C line a) Bina-Nagda 400 kv D/C line 7. Associated Tr. System of Sipat-I (3x660 MW) 8. Associated Tr. System of Sipat- II (2x500 MW) a) Sipat-Seoni 765 kv 2X S/C b) Seoni-Khandwa 400 kv D/C (Quad AAAC) c) Nagda-Dehgam 400 kv D/C d) LILO of Korba-Raipur at Sipat 400 kv D/C e) LILO of Satpura-Bhilai at Seoni 400 kv D/C f) LILO of both ckts of S. Sarover-Nagda 400 kv D/C line at Rajgarh g) Seoni 7x500 MVA 765/400 kv and 2x315 MVA 400/220 kv S/S h) Rajgarh 2x315 MVA 400/220 kv S/S a) Khandwa-Rajgarh 400 kv D/C b) Bina-Gwalior 765 kv S/C (initially op. at 400 kv) c) Seoni 765/400 kv 3x500 MVA (Aug.) d) LILO of 400 kv Korba-Raipur 400 kv line at Bhatapara. e) Bhatapara 2x315 MVA 400/220 kv S/S 9. Sipat-Raipur 400 kv D/C line a) Sipat-Raipur 400 kv D/C Page 42 of Chapter 2

220 Transmission Planning & National Grid S. N. Name of Scheme Description 10. Transmission System a) Gandhar (NTPC)-Rajkot (GEB) 400 kv D/C associated with Gandhar-II b) Gandhar (NTPC)-Kawas 400 kv D/C (1350 MW) c) LILO of both circuits of Bina-Nagda 400 kv D/C line at Shujalpur d) Establishment of 2x315 MVA 400/220 kv substation 11. Transmission System associated with Kawas-II (1350 MW) 12. To provide direct linkage to DNH and Daman & Diu from regional Vapi 400/220 kv s/s. 13. Sipat-II Supplementary Transmission Scheme at Shujalpur a) Kawas-II-Vapi (PG) 400 kv D/C Quad b) Vapi (PG)- Navi Mumbai 400 kv D/C c) LILO of Lonikhand Kalwa 400 kv S/C line at Navi Mumbai, d) Vapi (PG)-Khadoli (DNH) 220 kv D/C e) Establishment of 400/220 kv 2x315 MVA S/S at Navi Mumbai (GIS in case adequate land is not available). f) LILO of Apta-Kalwa and Kharghar-Kandalgaon 220 kv D/C lines at Navi Mumbai. (LILO works under preview of MSEB, 220 kv bay provision at Navi Mumbai by PGCIL) g) Installation of 400/220 kv 1x315 MVA 3 rd transformer at Vapi Construction of multi circuit 2xD/C line between Vapi (PG) and line alignment of the 220 kv lines from Bhilad- Kharadpada & Bhilad-Magarwada thereby creating Vapi (PG) Magarwada 220 kv D/C and Vapi (PG) Kharadpada 220 kv D/C line by bypassing both the lines at Bhilad. a) Seoni-Wardha, 765kV S/C line (initially op. at 400kV) b) Wardha-Akola, 400kV D/C line c) Akola-Aurangabad, 400kV D/C Page 43 of Chapter 2

221 Transmission Planning & National Grid Appendix-2.5 Southern Region In Southern Region following inter-state transmission schemes have been planned and are under execution during X plan. S. N. Name of Scheme Description 1. Talcher-II evacuation System in a) Kolar-Hoody 400kV D/C SR that is 40okV System for b) Kolar-Chennai(SPBudur) 400kV S/C power dispersal from Kolar c) Kolar-Hosur-Salem 400kV S/C d) Salem-Udumalpet 400kV S/C e) LILO of Cuddapah-Somanhalli at Kolar f) 400kV s/s at Hosur 2x315 MVA 2. Series Comp on Nagarjuna Sagar-Cuddapah and Gooty- Neelnamangla 400 kv lines g) 400kV Kolar s/s 2x315MVA a) 50% series compensation on both the circuits of Gooty-Bangalore 400 kv 2xS/C and Nagarjuna Sagar-Cuddapah 400 kv D/C 3. Kaiga-Narendra 400 kv D/C a) Kaiga-Narendra 400 kv D/C 4. Establishment of Narendra 400/220 kv S/S a) Establishment of 2x315 MVA 400/220 kv S/S at Narendra 5. Southern Region System strengthening scheme-iv a) LILO of Nagarjunasagar-Raichur 400 kv S/C line at Mehboobnagar b) LILO of both the circuits of Nellore-Sriprumbudur 400 kv D/C line at Alamatti 400kV S/S 6. Neelamangla-Mysore a) Neelamangala-Mysore 400 kv D/C line transmission system b) Mysore 2x315MVA 400/220 kv S/S 7. Madurai-Thiruvananthapuram a) Madurai-Thiruvananthapuram 400 kv D/C line b) Thiruvananthapuram 400/220kV 2x315MVA substation 8. Transmission system associated with Ramagundam- III 9. Southern Region System strengthening scheme-v 10. Southern Region System strengthening scheme-iii 11. Southern Region System strengthening scheme-vi a) Ramagundam-Hyderabad 400kV D/C line b) Hyderabad-Kurnool-Gooty 400kV S/C line c) Khammam-Nagarjunasagar 400kV S/C line d) Gooty-Neelamangala 400kV S/C line a) Augmentation of Transformer capacity by 1x315 MVA at Munirabad, Cuddapah, Gooty, Khammam, Gazuwaka and 3x167 MVA at Kolar 400 kv Substations b) 1x80 MVAR Bus reactor at Nellore 400kV S/S a) Raichur-Gooty 400 kv D/C (Quad) line b) Neelamangala- Somanahaly 400 kv D/C a) LILO of both the circuits of Gazuwaka-Vijayawada 400kV D/C line at Vemagiri 400 kv S/S b) 2 nd 1x315 MVA 400/220kV Transformer at Vijayawada Page 44 of Chapter 2

222 Transmission Planning & National Grid Appendix-2.6 Eastern Region In Eastern Region following inter-state transmission schemes have been planned and are under execution during X plan. S. N. Name of Scheme Description 1. LILO of Silliguri-Gangtok 132 kv line at Melli a) LILO of one ckt of Silliguri-Gangtok 132 kv D/C line at Melli 2. Installation of 2nd ICT at a) Indravati 1x315 MVA 400/220 kv 2 nd Trf. (Aug.) Indravati OHPC 3. LILO of Rangit-Silliguri at a) LILO of one ckt of 132 kv Rangit-Silliguri at Gangtok Gangtok 4. Tala Transmission System (ER) a) Bhutan border to Siliguri 400kV 2xD/C b) Siliguri-Purnia 400kV quad D/C c) Purnia-Muzzafpur 400kV quad D/C d) Muzaffarpur 400kV s/s with inter-connection to 220kV s/s 5. Transmission system associated e) Teesta-Silliguri 400 kv D/C with Teesta-V 6. Tala Supplementary Scheme for a) Biharsharif Muzaffarpur 400kV D/C-129km ER b) 2x315 MVA, 400/220kV S/S at Subhasgram 7. Associated Tr. System of Kahalgaon-II Phase-I(2x500 MW) and Phase-II (1x500 MW) in ER c) 2 nd 315 MVA, 400/220kV ICT at Siliguri a) Kahalgaon-Patna 400 kv D/C quad b) Maithon (PG)-Ranchi 400 kv D/C c) 2x315 MVA 400/220 kv Patna s/s d) 2x315 MVA 400/220 kv Ranchi s/s Page 45 of Chapter 2

223 Transmission Planning & National Grid Inter-Regional Schemes Appendix-2.7 The following inter-regional transmission schemes have been planned and have been commissioned and/or are under execution during X plan. S. N. Name of Scheme Description Status 1. ER-WR a) Rourkela-Raipur 400kV D/C completed interconnection b) TCSC on Rourkela-Raipur 400kV D/C 2. ER-NR a) Sasaram HVDC back-to back 500MW completed interconnection b) Biharsharif-Sasaram 400kV D/C 3. Talcher-II evacuation System 4. ER-SR link strengthening 5. ER-NR interconnector with Tala Transmission System 6. Associated Tr. System of Kahalgaon-II Phase-I(2x500 MW) and Phase-II (1x500 MW) c) Sasaram-Allahabad 400kV D/C a) Talcher-Kolar 2000 MW HVDC bi-pole line b) Increasing capacity of Talcher-Kolar HVDc bipole line from 2000MW to 2500MW a) Second 500MW HVDC back-to back at Gazuwaka b) b) Series Capacitors on 400kV lines in ER for increasing transmission capacity to Gazuwaka a) Muzaffarpur-Gorakhpur 400kV quad D/C with TCSC a) Patna-Balia 400kV D/C quad b) Biharsharif-Balia 400kV D/C quad c) Ranchi-Sipat 400 kv D/C with 40 % series compensation d) Agra-Gwalior 765 kv S/C (initially op. at 400 kv) completed completed completed Under construction Page 46 of Chapter 2

224 Transmission Planning & National Grid INTER-STATE TRANSMISSION SCHEMES FOR THE XI PLAN Appendix-2.8 Region Scheme/ scheme group Transmission system NR EVACUATION SYSTEM FOR KOLDAM (800 MW), PARBATI- II (800 MW) AND PARBATI-III (520 MW) TRANSMISSION SYSTEM FOR KOLDAM 1. Koldam-Nalagarh 400 kv D/C Quad. 2. Koldam-Ludhiana 400 kv D/C line TRANSMISSION SYSTEM FOR PARBATI II 1. Parbati II - Koldam 400 kv S/C (quad) 1 st ckt 2. Parbati II to Koldam 400 kv S/C (quad) 2 nd ckt 3. Opening of one ckt Koldam-Nalagarh 400 kv D/C line at Koldam and joining with Parbati II-Koldam 2 nd ckt so as to form i) Parbati II-Nalagarh 400 kv S/C line ii) Parbati II-Koldam 400 kv S/C line NR NR NR Evacuation System for Chamera- III (231 MW) Evacuation System for Uri-II HEP (240 MW) Evacuation System for Rampur HEP (434 MW) TRANSMISSION SYSTEM FOR PARBATI III 1. LILO of Parbati II-Koldam 400 kv S/C line at Parbati III 2. Establishment of switching station at Panarsa by LILO of Parbati II Nalagarh 400 kv line and by LILO of Parbati III-Koldam 400 kv S/C line at Panarsa 3. Panarsa-Amritsar 400 kv D/C line 1. CREATION OF 400/220 KV POOLING STATION NEAR HAMIRPUR 2. Chamera III-Chamera Pooling Station 220 kv D/C line 3. Chamera Pooling Station-Jullundur 400 kv D/C line 1. URI-I- URI-II 400 KV S/C 2. Uri-II-Wagoora 400 kv S/C line 1. LILO of Nathpa Jhakri - Nalagarh 400 kv D/C at Rampur HEP 2. Ludhiana - Patiala 400 kv D/C 3. LILO of Patiala -Hissar 400 kv line at Kaithal 4. LILO of Nalagarh - Kaithal 400 kv line at Patiiala Page 47 of Chapter 2

225 Transmission Planning & National Grid NR NR NR NR NR NR NR Evacuation System for Tehri PSS (1000 MW) & Koteshwar (400 MW), Lohari Nagpala HEP (600 MW) Evacuation System for Tapovan Vishnugad HEP (520 MW) Evacuation System for RAPP U 5&6 APP (440 MW) Evacuation System for Sewa-II (120 MW) Evacuation System for Nimboo Bazgo (45 MW) Evacuation System for Chutak (44 MW) Evacuation System for Lakhwar Vyasi (420 MW) With Koteshwar 1. Establishment of 400kV GIS Tehri Pooling Station 2. LILO of Tehri Meerut 765kV at Tehri Pooling Point 3. Koteshwar Tehri Pooling Point, 400kV D/C line 4. Series Compensation 50 % on the Tehri Meerut 765kV 2xS/C lines (charged at 400kV) WITH TEHRI PSS 1. TEHRI TEHRI POOLING STATION, 400KV S/C (QUAD) LINE 2. LILO OF BAREILLY MANDAULA 400KV D/C LINE AT 400KV MEERUT S/S 3. Charging Tehri Pooling Stn Meerut line at 765kV 4. Tehri Pooliong Station (GIS) 765/400kV, 3x1500MVA 5. Meerut S/S (GIS) 765/400kV, 3x1500MVA 6. Modification of Series capacitors on the Tehri-Meerut lines for 765kV operation With Lohari Nagpala 1. Lohari Nagpala HEP Tehri/Koteshwar Pooling Point 400kV D/C line (triple moose) 2. Meerut Agra 765kV S/C line 3. Second 765/400kV transformer at Agra 765kV S/S 1. Tapovan Vishnugad Roorkee 400kv D/C line (the line to be routed via Kuwari Pass where a 400/132kV pooling station is proposed) 1. Rapp kankroli 400kv d/c line 2. Rapp kota 400kv s/c line 3. Kota 400/220kv s/s 2x315 mva 4. Kankroli 400/220kv s/s, 3x315 mva Supplementary regional schemes to match with RAPP 5&6 1. Kota Merta 400kV D/C line 2. Kankroli Jodhpur 400kV S/C line 1. Sewa-Hira Nagar 132 kv D/C 2. Sewa-Khatua 132 kv D/C one ckt via Mahanpur 1. Nimboo Bazgo-Leh 33 KV 2XD/C 1. Chutak-Kargil 33 KV 2XD/C 1. Lakhwar Vyasi-Dehradun 220 KV D/C Page 48 of Chapter 2

226 Transmission Planning & National Grid NR NR NR NR NR NR NR NR NR NR Evacuation System for Kotlibhel st-ia (195 MW), Kotlibhel st-ib (320 MW), Kotlibhel st-ii (440 MW), Evacuation System for Vishnugarh Pipalkoti (400 MW) Evacuation System for Lata Tapovan (162 MW) Evacuation System for Barsinghsar (250 MW) & Barsinghsar Extn. 250 MW Northern Region System Strengthening -VI Northern Region System Strengthening -VII Northern Region System Strengthening -VIII Northern Region System Strengthening -IX Northern Region System Strengthening -X Northern Region System Strengthening -XI With Kotlibhel ST-IA 1. LILO Kotlibhel-ST1B-Roorkee 1st CKT at Kotlibhel- ST1A 400 KV D/C With Kotlibhel ST-IB 1. Kotlibhel-ST1B-Roorkee 400 KV D/C With Kotlibhel ST-II 1. LILO Kotlibhel-st1B-Roorkee 2nd ckt at Kotlibhel-st II 400 kv D/C 1. LILO one ckt Kuwari Pass-Pithoragarh line at Vishnugarh Pipalkoti 400 kv D/C 1. LILO of one ckt of Vishnuprayag-Muzzaffar Nagar D/C line at Kunwari Pass 400 kv D/C 2. Lata Tapovan-Kunwari Pass 220 kv D/C 1. Barsingsar-Nagaur 220 kv 2xS/C 2. Barsingsar-Phalodi 220 kv S/C 3. Barsingsar-Bikaner 220 kv S/C 1. Establishment of 400/220 kv 2x315 MVA GIS at Gurgaon by LILO of Samaypur-Bhiwadi 400 kv S/C line 1. Augmentation of Ludhiana S/S by 3 rd 315 MVA transformer 2. Augmentation of Wagoora S/S by 4 th 315 MVA transformer 1. Establishment of 400/220 kv 2x315 MVA S/S at Bhinmal by LILO of both ckts of Kankorli-Zerdai 400 kv D/C line 2. Augmentation of Hissar S/S by 3 rd 315 MVA transformer 1. Establishment of 400/220 kv S/S at Roorkee by LILO of Rishikesh-Muradnagar 400 kv S/C 2. Opening of Roorkee-Muzzaffarnagar portion of Roorkee-Muradnagar line from location near Muzzaffarnagar and extending it to Meerut so as to form Roorkee-Meerut 400 kv S/C line and Meerut- Muzzaffarnagar S/C line (under Tehri stage-i) 1. Kankroli-Jodhpur 400 kv S/C 2. Kota-Merta 400 kv D/C /220 kv 315 MVA 3 rd Trf. at Amritsar (Aug.) /220 kv 315 MVA 3 rd Trf. at Moga (Aug.) Page 49 of Chapter 2

227 Transmission Planning & National Grid NR NR NR NR NR system Strengthening Scheem (formerly part of Tala Supplementary Scheme) System Strengthening Scheme in Uttaranchal System Strengthening Scheme in Singrauli-Vindhyachal corridor NR- Strengthening (For increased import due to Tala HEP) JV of PGCIL with TATA Power 1. Jullundhar-Amritsar 400 kv S/C-65 km 2. LILO of Bawana-Bhiwani 400 kv S/C at Bahadurgarh-9 km 3. Establishment of 1x315 MVA 400/220 kv S/S at Amritsar 4. Establishment of 1x315 MVA 400/220 kv S/S at Bahadurgarh 5. Augmentation of Gorakhpur 400/220 kv S/S by 1x315 MVA trf. 1. LILO of one ckt of Dhauliganga-Bareilly 400 kv D/C (charged at 220 kv) at Pithoragarh 2. LILO of one ckt of Tanakpur-Bareilly 220 kv D/C line at Sitarganj 3. Establishment of 6x33.3 MVA 220/132 kv S/S at Pithoragarh 4. Establishment of 2x100 MVA 220/132 kv S/S at Sitarganj 1. Singrauli-suitable LILO point near existing Vindhyachal-Kanpur 400 kv S/C line 400 kv D/C. The existing Vindhyachal-Kanpur 400 kv S/C line would be opened up at LILO point and one end be connected to one ckt going towards Kanpur and other toward Vindhyachal 2. Diversion of existing Vindhyachal-Singrauli 132 kv S/C line 1. Gorakhpur-Lucknow (new) 400 kv D/C 2. Lucknow (New)-Unnao 400 kv D/C 3. Bareilly-Mandola 400 kv D/C 4. LILO of Dadri-Samaypur 400 kv D/C line at Maharani Bagh-2xD/C 5. Gorakhpur (new)-gorakhpur (UP) interconnection 400 kv -D/C 6. Gorakhpur (new) 400/220 kv 315 MVA S/S with 2x63 MVAR L/R 7. Lucknow (New) 400/220 kv 315 MVA S/S 8. Maharani Bagh 400/220 kv 630 MVA S/S 9. Bareilly (new) 400/220 kv 315 MVA S/S with 2x50 MVAR L/R Page 50 of Chapter 2

228 Transmission Planning & National Grid Region Scheme/ Scheme Group Transmission System WR Evacuation System for Sipat- II+I ( MW) ATS with Sipat-I (3x660 MW) 1. Sipat-Seoni 765 kv 2X S/C 2. Seoni-Khandwa 400 kv D/C (Quad AAAC) 3. Nagda-Dehgam 400 kv D/C 4. LILO of Korba-Raipur at Sipat 400 kv D/C 5. LILO of Bhilai-Satpura at Seoni 400 kv D/C 6. Seoni 765/400 kv 7x500 MVA and 400/220 kv 2x315 MVA s/s 7. Rajgarh 400/220 kv 2x315 MVA s/s by LILO of both ckts of Sardar Sarovar-Dhule D/C line ATS with Sipat-II (2x500 MW) 1. Khandwa-Rajgarh 400 kv D/C 2. Bina-Gwalior 765 kv S/C (initially op. at 400 kv) 3. Seoni 765/400 kv 3x500 MVA (Aug.) 4. Bhatapara 400/220 kv 2x315 MVA s/s by LILO of Korba-Raipur line WR Evacuation System for Kawas-II ( MW) and Gandhar-II ( MW) Sipat-II Supplementary Tr. System 1. Seoni-Wardha 765 kv S/C (initially op. at 400 kv) 2. Wardha-Akola 400 kv D/C 3. Akola-Aurangabad 400 kv D/C 4. Wardha 400/220 kv 2x315 MVA s/s ATS with Gandhar-II 1. Gandhar (NTPC)-Rajkot (GEB) 400 kv D/C 2. Gandhar (NTPC)-Kawas 400 kv D/C 3. LILO of both circuits of Bina -Nagda 400 kv D/C line at Shujalpur 4. Establishment of 2x315 MVA 400/220 kv substation at Shujalpur ATS with Kawas-II 1. Kawas-II-Vapi (PG) 400 kv D/C Quad 2. Vapi (PG)- Navi Mumbai 400 kv D/C 3. LILO of Kalwa-Pune (PG) 400 kv S/C line at Navi Mumbai, 4. Vapi (PG)-Khadoli (DNH) 220 kv D/C 5. Establishment of 400/220 kv 2x315 MVA S/S at Navi Mumbai (GIS in case adequate land is not available). 6. LILO of Apta-Kalwa and Kharghar-Kandalgaon 220 kv D/C lines at Navi Mumbai. (LILO works under preview of MSEB, 220 kv bay provision at Navi Mumbai by PGCIL) 7. Installation of 400/220 kv 1x315 MVA 3 rd transformer at Vapi Page 51 of Chapter 2

229 Transmission Planning & National Grid WR WR WR Western Region System Strengthening Scheme -II Western Region System Strengthening Scheme -IV Evacuation System for Omkareshwar (520 MW) For absorbing import in eastern and central part of WR grid 1. Seoni-Wardha 765 kv S/C (2nd ckt 400 kv operation). 2. Raipur-Wardha 400 kv D/C with series compensation of 25% fixed. 3. Bhadrawati-Parli (PG) 400 kv D/C 4. Wardha-Parli (PG) 400 kv D/C Quad 5. Parli (PG)-Parli (MSEB) 400 kv D/C. 6. Parli (PG)-Pune (PG) 400 kv D/C 7. LILO of Lonikhand-Kalwa 400 kv line at Pune (PG) near Chinchwad) 8. Pune (PG)-Aurangabad 400 kv D/C 9. Powergrid 400/220 kv 2x315 MVA substation at Pune. For regional strengthening in southern Maharashtra 1. LILO of Sholapur-Karad at Sholapur (PG) 400 kv D/C 2. Sholapur (PG) 400/220 kv 2x315 MVA s/s. 3. Parli (PG)- Sholapur (PG) 400 kv D/C 4. Sholapur (PG)-Kolhapur 400 kv D/C For regional strengthening in Gujarat 1. Rajgarh-Karamsad 400 kv D/C line with 25% fixed series compensation 2. Limbdi-Ranchhodpura-Zerda 400 kv D/C. For regional strengthening in northern Madhya Pradesh 1. Korba-Damoh-Bhopal 400 kv D/C. 1. Powergrid 400/220 kv, 2x315 MVA substation at Damoh. 1. LILO of Barwaha-Khandwa D/C at Omkareshwar 220 kv 2xD/C 2. Omkareshwar-Sanawad 220 kv D/C Page 52 of Chapter 2

230 Transmission Planning & National Grid Region SR SR Scheme/ Scheme Group Evacuation System for Kudankulam U1&2 (2000 MW) Evacuation System for Kalpakkam PFBR (500 MW) Transmission System 1. Kudankulam (NPC) Tirunelveli (PG) 400kv 2XD/C line-i & II (quad) 2. tirunelveli (pg) udumalpet 400kv d/c line 3. Tirunelveli (PG) Edamon (KSEB) 400kV D/C line, (multi circuit line) 4. Edamon Muvattupuzha(PG) 400kV quad D/C line 5. Muvattupuzha North Tricur (PG) 400kV quad D/C line 6. LILO of both circuits of Madurai (PG) Trivendram (PG) 400kV D/C line at Tirunelveli /220kV S/S at Tirunveli, 2x315 MVA /220kV S/S at Muvattupuzha, 2x315 MVA 9. Trivendram 400/220kV S/S Extn. 3 rd 1x315 MVA transformer 10. Udumalpet 400/220kV S/S Extn. 3 rd 1x315 MVA transformer 11. 2x63 MVAR bus reactor at Tirunveli and 1x63 MVAR bus reactor at Muvattupuzha 400 kv S/Ss 12. 1x63 MVAR line reactor at each end of each circuit of Tirnuveli Muvattupuzha 400kV D/C line 13. 1x63 MVAR switchable line reactor at each end of each circuit of Tirnuveli Udumalpet 400kV D/C line 1. KPFBR Kancheepuram 230kV D/C line 2. KPFBR Arni 230kv D/C line 3. KPFBR Sirucheri 230kV D/C line 4. KPFBR MAPS 230kV S/C (with one spare phase) Cable link Page 53 of Chapter 2

231 Transmission Planning & National Grid SR SR SR SR Evacuation system for Kaiga U3&4 ( MW) Evacuation System for Neyveli TPS II (500 MW) Evacuation System for Kayamkulam II LNG (1950 MW) For Talcher-II back-up in ER 1. Narendra (PG) Davanagere (KPTCL) 400kv D/C line 2. Mysore (PG) Kozhikode (PG) 400kV D/C line 3. Lilo of Kolar Sriperumbudur (PG) 400kvVs/c at melakottaiyur (PG) 4. Melakottaiyur 400/220kV s/s 2x315 mva 5. Kozhikode 400/220kV S/S 2x315 mva 6. Hiriyur 400/220kv S/S extn- 1x315 mva 7. Narendra 400/220kV S/S bay extn. 8. Mysore 400/220kV S/S bay extn. 9. Davanagere 400/220kV S/S bay extn x50 mvar switchable line reactor at melakottaiyur end of kolar sriperumbudur 400kV S/C line to be LILOed at melakottaiyur 1. neyveli ts-ii expansion (nlc) neyveli ts-ii existing (nlc) 400kv 2xs/c line 2. neyveli ts-ii(nlc) pugalur (pg) 400kv d/c line 3. Pugalur (PG) Madurai (PG) 400kV D/C line 4. Udumalpet Arasur (PG) 400kV D/C line 5. LILO of Neyveli Sriperumbudur 400kV S/C line 6. LILO of Ramagundam Khammam 400kV S/C line at Warangal (PG) 7. Pugalur 400/220kV S/S 2x315 MVA 8. Warangal 400/220kV S/S 2x315 MVA 9. Arasur 400/220kV S/S 2x315 MVA 10. Pondicherry 400/220kV S/S 2x315 MVA 11. Madurai 400/220kV S/S bay Extn. 12. Udumalpet 400/220kV S/S bay Extn x50 MVAR switchable line reactor for each circuit, at Pugalur end of Neyveli Pugalur 400kV D/C line. 1. LILO of Tirunelveli-Muvathapuzha (Quad) at Kayamkulam 400 kv 2xD/C 2. Kozhikode-Trissur 400 kv D/C 3. Kayamkulam TPS 400/220 kv 2x315 MVA S/S 4. Kayamkulam TPS-Kayamkulam 220 kv D/C TENTATIVE 1. Talcher-II Rourkela 400 kvd/c 2. Baripada-Berhampur-Gazuwaka 400 kv D/C Page 54 of Chapter 2

232 Transmission Planning & National Grid SR SR SR SR SR Southern Region System Strengthening Scheme IV Southern Region System Strengthening Scheme V Southern Region System Strengthening Scheme VI Southern Region System Strengthening Scheme VII Neelamangala-Mysore Transmission scheme 1. LILO of Nagarjunasagar (AP)-Raichur 400 kv S/C line at Mehboobnagar (AP) 2. LILO of both the circuits of Nellore (AP)- Sriprumbudur (TN) 400kV D/C line at Alamatti 400 kv S/S (TN) 1. Augmentation of Transformer capacity by 1x315 MVA at Munirabad, Cuddapah (AP), Gooty(AP), Khammam (AP), Gazuwaka(AP) and 3x167 MVA at Kolar 400 kv Substations 2. 1x80 MVAr Bus reactor at Nellore (AP) 400kV S/S 1. (LILO of both the circuits of Gazuwaka (AP)-Vijayawada (AP) 400 kv D/C line at Vemagiri 400 kv S/S (AP) 2. 2 nd 1x315 MVA 400/220kV Transformer at Vijayawada (AP) 1. LILO of one circuit of Talaguppa- Neelamangala 400kV D/C line at Hassan 2. Hassan 400/220 kv 2x315 MVA substation 3. LILO of one circuit of Madurai (TN)-Trichy (TN) D/C line at Karaikudi (TN) 4. Karaikudi 400/220 kv 2x315 MVA substation 1. Neelamangala-Mysore 400 kv D/C line /220 kv 2x315 MVA S/S at Mysore Page 55 of Chapter 2

233 Transmission Planning & National Grid Region ER ER Scheme/ Scheme Group Evacuation System for North Karanpura (1980 MW) and Maithon RB (1000 MW) Evacuation System for Barh (1980 MW) Transmission System With North Karanpura: 1. North Karanpura Sasaram 765kV S/C line with 2x1500MVA, 765/400kV s/s at Sasaram 2. North Karanpura Ranchi 400kV D/C line 3. North Karanpura WR pooling Station near Sipat 765kV S/C line with 2x1500MVA, 765/400kV s/s at WR pooling station near Sipat 4. WR pooling station near Sipat Sipat 765kV S/C line 5. WR pooling station near Sipat Seoni 765kV S/C line With Maithon RB: 1. Maithon RB-Maithon PG 400kV D/C line 2. Maithon RB Ranchi 400kV D/C line 3. Biharsharif Sasaram 400kV D/C line With North Karanpura or Maithon RB for the Northern Region: 1. Sasaram-Fatehpur 765kV S/C line 2. Fatehpur-Agra 765kV S/C line kV Agra s/s, 2x1500 MVA 765/400kV kV Fatehpur s/s, 2x1500 MVA 765/400kV & 2x315 MVA 400/220 kv 5. LILOs of Singrauli/Allahabad Kanpur/Mainpuri 400kv lines at Fatehpur. 6. Sasaram Balia 400kV quad D/C 1. LILO of Kahalgaon Patna 400kV D/C quad line at Barh 2. Barh Balia 400kV D/C quad line 3. Balia Bhiwadi 2500 MW + 500kV HVDC Bipole line 4. Seoni Bina 765kV S/c line (to be initially operated at 400kV) 5. Balia 400kV S/S extn 6. Bhiwadi 400kV S/S extn 7. Seoni 400kV S/s extn 8. Bina 400kV Sw. Stn. Extn. 9. Balia and Bhiwadi HVDC Converter Stations Page 56 of Chapter 2

234 Transmission Planning & National Grid ER Evacuation System for Teesta Low Dam III &IV (292 MW) 1. Teesta Stage III New Jalpaiguri, 220kV S/C line with Twin-Moose conductor. 2. Teesta Stage III Teesta Stage IV S/S, 220kV S/C line with Moose conductor. 3. Teesta Stage IV New Jalpaiguri, 220kV D/C line. (These lines would be constructed by WBSEB, as the whole of the power would be absorbed by West Bengal.) 1. LILO of one ckt of Mangan-Melli 400 kv D/C at Teesta IV 1. Existing system adequate ER Evacuation System for Teesta IV (495 MW) ER Evacuation System for Farakka III (500 MW) ER System Strengthening-I 1. Higher capacity conductr on Siliguri-Purnia ER System Strengthening-II 1. Purlia-Jamshedpur 400kV D/C 2. Jamshedpur-Baripada 400kV D/C 3. Baripada Mendhalsal (Bhuwanashwar) 400kV D/C ER ER ER ER For Talcher-II back-up in ER Evacuation System for Bokaro (500 MW) Evacuation System for Kodarma (500 MW) Evacuation System for Hirma-II (2000 MW) TENTATIVE 1. Talcher-II Rourkela 400 kvd/c 2. Baripada-Berhampur-Gazuwaka 400 kv D/C TENTATIVE 1. Bakaro-North Karanpura 400 kv D/C Quad TENTATIVE 1. Kodarma-Sasaram D/C 400 kv D/C Quad TENTATIVE 1. Hirma II-Raipur 400 kv 2xD/C (Quad) 2. Hirma-Sipat PP 2xD/C (Quad) Page 57 of Chapter 2

235 Transmission Planning & National Grid Region NER NER NER NER NER Scheme/ Scheme Group Evacuation System for Kameng HEP (600 MW) Evacuation System for Ranganadi II (130 MW) Evacuation System for Dikrong (110 MW) Evacuation System for Subnasiri Lower HEP (2000 MW) System Strengthening Sch-I Transmission System 1. LILO Ranganadi-Balipara at Biswanath Chariyali 400 kv 2xD/C 2. Kameng HEP-Biswanath Chariyali 400 kv D/C 3. Biswanath Chariyali -Bongaigaon 400 kv D/C 1. Ranganadi HEP I-Ranganadi HEP II 132 kv S/C 2. LILO of Ranganadi HEP I-Ziro at Ranganadi HEP II 132 kv D/C 1. Dikrong-Ranganadi HEP-I 132 kv D/C 1. Biswanath Chariyali to be developed as a pooling station in NER 2. Subansiri Biswanath Chariyali 400kV 2xD/C Quad lines. 3. Biswanath Chariyali Agra, HVDC Bipole, +/- 600kV, 4000 MW kV and 132kV works for Aizwal, Dimapur, Kopili, Khandong Page 58 of Chapter 2

236 Transmission Planning & National Grid Appendix- 2.9 STATES TRANSMISSION SCHEMES FOR THE XI PLAN EVACUATION SYSTEM FOR GENERATION PROJECTS States of Northern Region Gen. Project HP UHL-III (100MW) KASHANG I & II (126MW) SAINJ (100 MW) SHONGTONG KARCHAM (402 MW) HARYANA YAMUNA NAGAR U1&2 (500 MW) UP ANPARA C (1000 MW) ROSA (600 MW) RAJASTHAN GIRAL U-1&2 (250 MW) CHHBRA TPS (500 MW) KOTA U-7 (195 MW) UTTARANCH AL State sector generation projects Transmission scheme/proposal UHL-Bassi 132 kv D/C UHL-Hamirpur D/C LILO of Bhabha-Kunihar S/C at Kashang 220 kv D/C Through Parbati Transmission system Shongtong Karcham-Karcham Pooling Station 400 kv D/C Karcham Pooling Station-NR load centers to be decided after firming up of generation in the complex Yamuna Nagar TPS-Yamuna Nagar 220 kv 2xD/C Yammuna Nagar TPS-Tepla 220 kv D/C Yammuna Nagar -Ladwa 220 kv D/C Ladwa-Nissing 220 kv D/C Ladwa 220/132 kv 100 MVA S/S Charging of Anpara-Unnao 765 kv S/C line at 765 kv Anpara 765/400 kv 2x630 MVA S/S Unnao 765/400 kv 3x630 MVA S/S Rosa-Shahjahanpur 220 kv 2xS/C Rosa-Hardoi 220 kv D/C Rosa-Badaun 220 kv S/C Hardoi 220/132 kv 2x100 MVA S/S Giral-Barmer 220 kv D/C LILO Barmer-Amar Sagar at Giral 220 kv D/C Chabra TPS-Swaimadhopur 400 kv D/C Swaimadhopur 400/220 kv 2x315 MVA S/S Step up generation voltage at 220 kv Split existing KTPS bus with U 6&7 on one section and rest on other section KTPS 6&7 section-kota (PG) 220 kv D/C with twin moose Page 59 of Chapter 2

237 Transmission Planning & National Grid TUINIPALASU (42 MW) BAWALA NAND PRAYAG (132MW) PALAMANERI (480 MW) Gen. Project HP ALLAN DHUNGAN (192MW) KARCHAM WANGTOO (1000MW) DHAMVARI SONDA (70MW) SAWARA KUDDU (110 MW) Punjab GOVINDWAL SAHEB (500 MW) UTTRANCHAL VISHNU PRAYAG (400 MW) LILO one ckt Arakot Tuni-Mori at Tuinipalasu 220 kv D/C Bawala Nand Prayag Karanpryag 132 kv D/C line LILO one ckt Lohari Nagpala-Tehri Poling Point at Palamaneri 400 kv D/C Private sector generation projects Transmission scheme/proposal ALLAIN DHUANGAN NALAGARH 220 KV D/C LILO OF BASPA NATHPA JHAKRI D/C LINE AT KARCHEM WANGTOO KARCHEM WANGTOO ABDULLAPUR 400 KV D/C BEYONG ABDULLAPUR TR. SYSTEM HAS TO BE EVOLVED DHAMWARI SUNDA - MALIANA 2XS/C+D/C NOT YET IDENTIFIED GOINDWAL-TATHASAHIB 220 KV D/C GOINDWAL-TARNTARAN 220 KV D/C LILO OF JAMSHER-VERPAL D/C AT GOINDWALSAHIB-220 KV 2XD/C GOINDWAL 220/132 KV 100 MVA S/S NOT YET IDENTIFIED Page 60 of Chapter 2

238 Transmission Planning & National Grid States of Western Region Gen. Project GUJARAT UTRAN CCGT (350MW) PAGUTHAN ( MW) Sikka Repl. Ext. (500MW) Surat Lignite Ext. (250MW) MP & GUJ. MALWA (1000 MW) MAHARASHTRA PARLI EXT. STAGE-II (250 MW) PARAS EXT. U- II (250 MW) KHAPER KHEDA EXT (500MW) CHHATISGARH KORBA WEST EXT (600MW) State sector generation projects Transmission scheme/proposal UTRAN-KOSAMABA 220 KV 2XD/C PAGUTHAN-KASOR 400 KV D/C PAGUTHAN-FEDRA 400 KV D/C SYSTEM STRENGTHENING BELOW FEDRA 400 KV S/S YET TO BE IDENTIFIED BY GETCO TRANSMISSION SYSTEM YET TO BE IDENTIFIED TRANSMISSION SYSTEM YET TO BE IDENTIFIED TRANSMISSION SYSTEM YET TO BE IDENTIFIED LILO OF BOTH CKTS OF PARLI-BEED D/C LINE AT PARLI EXTN. 220 KV 2XD/C LILO OF NANDED-GIRWALI LINE AT PARLI EXTN. 220 KV D/C LILO OF BOTH CKTS OF AKOLA-CHIKLI D/C LINE AT PARAS EXTN. 220 KV 2XD/C PARAS EXTN.-AKOLA 220 KV D/C LILO OF CHANDRAPUR-KORADI S/C LINE AT KHAPERKHEDA 400 KV D/C KHAPERKHEDA 400/220 KV 1X315 MVA S/S KHAPERKHEDA II- KHAPERKHEDA 220 KV D/C KORBA (W)-BHILAI (KHEDAMARA) D/C KORBA (W)- BHILAI (KHEDAMARA) 400 KV D/C BHILAI (KHEDAMARA)-RAJNANDGARH 220 KV D/C BHILAI (KHEDAMARA)-BEMATARA 220 KV D/C RAJNANDGAON 220/132 KV 1X160 MVA S/S Page 61 of Chapter 2

239 Transmission Planning & National Grid MARWA (1000 MW) MATNAR (60 MW) BODHGHAT (500 MW) IGTPP BHAYTHAN (1320 MW) GUJARAT AKHAKHOL- PAGUTHAN (730MW) ESSAR-HAZIRA EXT. (1460MW) BHAVNAGAR (NIRMA JV) (250 MW) MAHARASHTRA VILE-TATA (1000 MW) MARWA-RAIPUR (NEW) 400 KV D/C LILO OF KORBA-KHEDAMARA S/C AT MARWA 400 KV D/C MARWA 400/220 KV 1X315 MVA S/S RAIPUR (NEW) 400/220 KV 1X315 MVA S/S MAHASAMUND-GURUR 220 KV D/C RAIPUR (NEW)-DOMA 220 KV D/C RAIPUR (NEW)-SILTARA 220 KV D/C RAIPUR (NEW)-URLA 220 KV D/C RAIPUR (NEW)-MAHASAMUND 220 KV D/C MARWA-MOPKA 220 KV D/C DOMA 220/132 KV 1X160 MVA S/S DOMA (220 KV)-KACHNA 132 KV D/C DOMA (220 KV)-KURUD 132 KV D/C EVACUATION AT 132 KV LEVEL BODHGHAT (BARSOOR)-KHEDAMARA 400 KV D/C BHAIYATHAN-BILASPUR 400 KV D/C BILASPUR-RAIPUR 400 KV D/C BHAIYATHAN-BISHRAMPUR 220 KV D/C BILASPUR-MOPKA 220 KV D/C BHAIYATHAN-PENDRAROAD-BAIKUNTHPUR 220 KV D/C MOPKA-MUNGELI 220 KV D/C BHAIYATHAN 400/220 KV 1X315 MVA S/S BILASPUR 400/220 KV 1X315 MVA S/S MUNGELI 220/132 KV 1X160 MVA S/S BAIKUNTHPUR 220/132 KV 1X160 MVA S/S MUNGELI (220 KV)-MUNGELI 132 KV D/C BAIKUNTHPUR (220 KV)-BAIKUNTHPUR 132 KV D/C PRIVATE SECTOR GENERATION PROJECTS LILO OF KAWAS-GANDHAR 400 KV D/C AT AKHAKHOL AKHAKHOL-DEHGAM 400 KV D/C TRANSMISSION SYSTEM YET TO BE IDENTIFIED TRANSMISSION SYSTEM YET TO BE IDENTIFIED TRANSMISSION SYSTEM YET TO BE IDENTIFIED Page 62 of Chapter 2

240 Transmission Planning & National Grid CHHATISGARH RAIGARH (750MW) PATHDI TPS- LANCO (1200MW) MP TRANSMISSION SYSTEM YET TO BE IDENTIFIED TRANSMISSION SYSTEM YET TO BE IDENTIFIED MAHESHWAR (400MW) Maheshwar-Pithampura 220 kv D/C Maheshwar-Rajgarh 220 kv D/C Maheshwar-Julwania 220 kv D/C States of Southern Region Gen. Project AP VIJYAWADA TPP (660MW) JAURALA PRIYA (195MW) N. SAGAR TP DAM (50MW) KARNATAKA BIDADI (1400MW) NAGARJUNA TPP (1015 MW) RAICHUR U-8 (210 MW) BELLARY EXT. (500 MW) GUNDIA EXT. (300 MW) KERALA ADIRAPALLI (163MW) State sector generation projects Transmission scheme/proposal VTPS - Yeddumailaram 400kV D/C VTPS - Narasaraopeta 400kV D/C Tadikonda - Narasaraopeta 400kV S/C 1x315 MVA, 400/220 kv Transf at VTPS switchyard Jurala HEP- Mehboobnagar 220kV D/C Existing system YET TO BE IDENTIFIED Nagarjuna TPP-Hassan 400 kv D/C Hassan-Bidadi 400 kv D/C LILO 2nd ckt Talaguppa-Neelamangla at Hassan 400 kv D/C Existing system adequate YET TO BE IDENTIFIED YET TO BE IDENTIFIED YET TO BE IDENTIFIED Page 63 of Chapter 2

241 Transmission Planning & National Grid TAMIL NADU BHAWANI KATHLAI U2 (60MW) Gen. Project AP BHOPALPALLI (500MW) Existing system adequate Private sector generation projects Transmission scheme/proposal YET TO BE IDENTIFIED States of Eastern Region Gen. Project State sector generation projects Transmission scheme/proposal WEST BENGAL PURULIA PSS ( MW) SAGARDIGHI-II (1000MW) BAKRESHWAR U5 (210MW) DPL TPS (500 MW) BAKRESHWAR U6 (210MW) Katwa TPP (1000 MW) JHARKHAND TENUGHAT EXT (630MW) Purulia-Bidhannagar 400 kv D/C Purulia-Arambag 400 kv D/C LILO of Farakka-Jeerat-Subhashgram 400 kv S/C at Sagardighi TPS. Sagardighi TPS-Durgapur 400 kv S/C Existing 400kV and 220kV transmission system will be adequate. DPL-Durgapur 400 kv D/C Bakreshwar-Jagatballavpur 400 kv S/C Jagatballavpur 400/220 kv 2x315 MVA S/S Jagatballavpur-Domjur 220 kv D/C Katwa-Maithon 400 kv D/C Tenughat TPS-Ranchi 400kV D/C-200ckms. Existing TenughatTPS-Biharsariff 400kV S/C line will be charge at 400 kv. Page 64 of Chapter 2

242 Transmission Planning & National Grid Gen. Project Private Sector Generation Projects ORISSA IB STAGE-II U 5 & 6 (2X250MW) JORDA NUELPOI, CESC (500 MW) AURANGA TPP, TATA POWER (1000 MW) WEST BENGAL BUDGE BUDGE EXTN. WB+CESC JV (250 MW) IB TPS-Meramundali 400 kv D/C 400kV operation. (THE LINE IS TO BE INITIALLY OPERATED AT 220KV UNDER STAGE-I. THE LINE IS UNDER CONSTRUCTION) Jorada Nuelpoi-Ib TPS 400 kv D/C Auranga TPP-Maithon (PG) 400 kv D/C Existing system adequate States of North-Eastern Region Gen. Project State sector generation projects Transmission scheme/proposal ASSAM LAKWA W. H. (38 MW) MEGHALYA MYNTDU STAGE-I (84MW) EXISTING SYSTEM ADEQUATE MYNTDU-KHLIEHRIAT 132KV D/C LINE. Gen. Project TRIPURA TRIPURA GAS ONGC (1050MW) Private Sector Generation Projects TRIPURA GAS-SILCHAR 400 KV D/C QUAD SILCHAR-BONGAIGAON 400 KV D/C QUAD BONGAIGAON-SILLIGURI 400 KV D/C QUAD PURNEA-BIHARSHARIF 400 KV D/C QUAD TRIPURA GAS 400/132 KV SWITCHYARD AND 132 KV LINES TO GRID SILCHER 400/132 KV S/S AND 132 KV LINES TO GRID Page 65 of Chapter 2

243 Transmission Planning & National Grid STATE-WISE DETAILS OF NORMATIVE ASSESSMENT Appendix-2.10 REGION STATE Peak Demand Peak Demand level at 07 at start end of XI of XI Plan Plan Increase in peak demand during the XI Plan period Projected population in 2012 Additional demand growth to come up to atleast 50% of National average Normative Investment needed in States' 220,132,66kV System for trend growth Investment needed in States' 220,132,66kV System for accelerated growth to come up to 50% of National average Total investment needed in States' 220,132,66kV System Northern MW MW MW Number in crores MW Rs Crores Rs Crores Rs Crores Delhi Haryana Himachal Pradesh Jammu and Kashmir Punjab Rajasthan Uttar Pradesh Uttranchal Chandigarh Northern Region NR Peak With Diversity Western Chhattisgarh Goa Gujarat Madhya Pradesh Maharastra Dadar & Nagar Haveli Daman & Diu Western Region WR Peak With Diversity Southern Andhra Pradesh Karnataka Kerala Tamil Nadu Pondicherry Southern Region SR Peak With Diversity Eastern Bihar DVC Jharkhand Orissa Sikkim West Bengal Eastern Region ER Peak With Diversity Page 66 of Chapter 2

244 Distribution Including Village & Household Electrification Chapter- 3 DISTRIBUTION INCLUDING VILLAGE AND HOUSHOLD ELECTRIFICATION 3.0 OVERVIEW Distribution is the key segment of electricity supply chain. The distribution sector caters to rural and urban areas. Rural distribution segment is characterized by wide dispersal of net work in large areas with long lines, high cost of supply, low paying capacity of the people, large number of subsidized customers, un-metered flat rate supply to farmers, non metering due to high cost and practical difficulties, low load and low rate of load growth. Urban distribution is characterized by high consumer density, and higher rate of growth of load. The consumer mix in urban areas is mostly commercial, residential, and industrial, whereas consumer mix in rural areas is mainly agriculture and residential. Both segments are distinct with different problems and issues. Electricity Act 2003 has recognized Rural Electrification as a separate entity. The biggest challenge of the power sector is the high T&D losses. A combination of technical and non-technical factors is contributing to high Transmission and Distribution losses. Lack of consumer education, political interference, and inefficient use of electricity is further aggravating the problem. As T&D loss figures did not capture the gap between the billing and the collection, the concept of Aggregate Technical & Commercial (AT&C) loss was introduced in to capture total performance of the utility. The AT&C losses are presently in the range of 18% to 62% in various states. The average AT&C loss in the country is at 34%. There is wide variation of losses among the states and variation among the Discoms within the states. The major portion of losses are due to theft and pilferage, which is estimated at about Rs.20, 000 crore annually. Apart from rampant theft, the distribution sector is beset with poor billing (only 55%) and collection (only 41%) efficiency in almost in all States. More than 75-80% of the total technical loss and almost the entire commercial loss occur at the distribution stage. It is estimated that 1% reduction in T&D losses would generate savings of over Rs.700 to Rs.800 crores. Reduction of T&D loss to around 10% will release energy equivalent to an additional capacity of 10,000-12,000 MW. Page 1 of Chapter 3

245 Distribution Including Village & Household Electrification Table 3.1 State-wise AT&C Losses Less than 20% Between 20-30% Between 30-40% Above 40% Goa Andhra Pradesh Karnataka Delhi Tamil Nadu Gujarat Kerala Uttar Pradesh West Bengal Assam Bihar Himachal Pradesh Rajasthan Jharkhand Maharashtra Haryana Madhya Pradesh Tripura Meghalaya Arunachal Pradesh Punjab Chhattisgarh Manipur Uttaranchal Mizoram Nagaland The Sub-transmission and Distribution systems have been the thrust areas during 10 th Plan. The reduction of AT&C losses with improvement of quality and reliability were given special attention during the 10 th Plan. In line with this, Accelerated Power Development and Reform Programme was launched with thrust on AT&C loss reduction through techno-commercial interventions to achieve commercial viability. For rural areas Rajiv Gandhi Grameen Vidyutikaran Yojna has been launched in April 2005 with 90% grant to achieve 100% electrification of villages. 3.1 KEY ISSUES IN ELECTRICITY DISTRIBUTION SECTOR The problems in Distribution sector have accumulated over the years mainly due to lack of investment, commercial orientation, excessive T&D losses, distorted tariff policies etc. Following are the key issues / key factors effecting overall performance of the distribution sector: State Government related Uncertain commitment of State Governments is key impediment to the ongoing reform process. This includes delay in unbundling and restructuring of State Electricity Boards, minimal/no financial support to unbundled utilities during transition period, inadequate financial support for providing subsidised power to domestic and agricultural consumers, inadequate administrative support in curbing theft of power etc. Frequently changing policies of the State Governments in regard to subsidies/free power to farmers adversely affecting the revenue recovery and cost coverage of utilities Regulatory process related issues SERCs are inadequately staffed with poor infrastructure. Due to lack of competency and resources in Discoms, tariff filings are often delayed. In several cases, SERC asks Discoms to revise their filings on account of data gaps or improper information. There is no central repository of data in electronic form which leads to delay in filing petitions and responding to queries from the regulator. The distribution licensees have not been able to fully implement regulations and directives due to various reasons like lack of skilled human resources, resource constraints or inadequate training/awareness. Page 2 of Chapter 3

246 Distribution Including Village & Household Electrification Corporate governance and institutional issues Most of the distribution companies formed as a result of unbundling of SEB are still not fully autonomous. In many cases, unbundling is limited to operational and technical segregation. Segregation of accounts, cash flow, human resources is not complete. Successor companies are highly dependent on their parent company (i.e. residual SEB or single buyer/trade co or Transco) for financials/cash flow, human resources, investment decisions and other administrative matters and therefore, the focus on efficiency improvement from respective entities is lacking. Due to in-adequate network expansion commensurate with load growth, many power transformers, distribution transformers, 33kV lines and 11kV feeders are overloaded. Reinforcement of existing network in the form of new transformers, new lines and augmentation of existing transformers and lines is poor. Most of the distribution networks in India are quite old which results in to reduced reliability, increased R&M expenses and poor quality of supply. The system also suffers low HT/LT ratio. The consumer awareness about Demand Side Management (DSM) is limited which results in to higher consumption and increased losses. DSM initiatives such as local reactive power compensation, use of energy efficient devices, Time of Day tariff, use of renewable sources etc. are lacking Commercial issues Commercial losses are primarily due to improper energy accounting and billing processes, faulty metering, under-billing, theft and pilferage of energy and lack of accountability within the organization. Commercial losses are estimated at about Rs. 26,000 crore during and theft of electricity is estimated to cost the country at about Rs. 20,000 crore per year (Source: MoP). The chart shows overall T&D losses in India. % Losses FY 92 FY 94 FY 96 FY 98 FY 00 FY 02 FY 04 Source: MoP Presentation July 19, 2005 Only 87% of the total consumers in India are metered (Source: Mop, ). Many states have undertaken 100% metering programs, but not yet completed. The chart below indicates consumer metering level in some of the states. This does not include defective meters. Page 3 of Chapter 3

247 Distribution Including Village & Household Electrification 100% 80% 60% 40% 20% 0% Consumer metering till FY 05 AP MP Raj. UP Mah Kar States All India 100% 80% 60% 40% 20% 0% High AT&C losses are due to high T&D losses coupled with low collection efficiency. Low level of collection is attributable to lack of employees accountability, inadequate collection facilities, limited usage of advanced systems and technology (e.g. payment through ECS, credit/debit cards, special centres like e-seva centres), billing errors, political/administrative interference etc. The chart below shows level of collection efficiency in select Discoms. 100% 80% 60% 99.7% 90.0% 91.3% Collection Efficiency (%) ( ) 62.3% 78.5% 92.4% 60.3% 94.8% 99.5% 96.7% 97.0% 40% 20% 0% BRPL BYPL NDPL Agra Lucknow Meerut Varanasi CPDCL EPDCL NPDCL SPDCL Delhi Uttar Pradesh Andhra Pradesh Source: PFC Report on Performance of the State Power Utilities for the Years to Operational issues Due to inadequate metering and data collection system in place, utilities have not been able to conduct energy audit, which is crucial for any energy business. Discoms do not have proper load monitoring and control mechanisms (e.g. SCADA, Distribution Control Centre, telecommunications etc.), which results in to haphazard control of the demand and often leads to loss of revenue and inconvenience to the consumers Human resources and training issues In many of the state owned utilities, recruitment has been either stopped or restricted since last 15 years. Average age of employee in most SEBs is more than 50 years. Lack of fresh talent and domain expertise (e.g. in area of IT, communication, SCADA) impedes development of the sector and efficiency improvement. Induction of new technology in the field and office level also needs proper training for staff for efficient Page 4 of Chapter 3

248 Distribution Including Village & Household Electrification handling. Discoms need to undertake training need analysis and roll out training programmes for employees working in different areas. In a typical SEB, ratio of field staff to support/office staff is 54:46. However, customer facing staff is inadequate. Also, ratio of meter readers to consumers on the other hand ranges from 1:3000 to 1: No. of Distribution Employees per lakh consumers AP UP Source: Companies Annual Report for FY'05 Rajasthan MP Orissa Assam Productivity of the employees: The chart below shows some of the key parameters of select entities / state to assess productivity of the employees in distribution sector. (Note: Pink bar indicates private player, blue bar indicates government owned Distribution Company) (Source: Websites/Tariff Orders of respective utilities) 300 Private players Versus State owned Thousands Rs Rs./Unit and MU/Employee BSES Yamuna BSES Rajdhani NDPL AP UP MP Orissa Expense per employee MU sold per employee Expense per unit sold Technological issues Many of the distribution utilities in India are still lacking most basic requirements consumer database and asset database which can be addressed through IT and communication solutions. Utilities do not have complete record of all consumers, which results in to direct revenue loss. Most utilities maintain manual records of consumers (in the form of register) especially in rural areas. Electromechanical meters, manual reading of meters, manual bill preparation and delivery and inadequate bill collection facilities result in to overall delay in revenue collection and revenue leakage. Conventional complaint handling process results in delayed redressal and increased dissatisfaction among customers. Page 5 of Chapter 3

249 Distribution Including Village & Household Electrification Regular monitoring and testing of critical assets such as 11kV feeders, 11/0.4kV distribution transformers and 415V feeders etc. are very important in ensuring reliable supply. Monitoring of consumer energy metering systems is critical to overall revenue. Asset database is crucial in efficient management of assets and claiming depreciation under annual revenue requirement. Almost all distribution companies do not have real-time monitoring system and typically use phone or radio communication for demand management. Most Discoms do not have distribution control centre which can manage load shedding and instructions from SLDC. Discoms need to plan implementation of SCADA in long term keeping in view capital cost and benefits. 3.2 DISTRIBUTION REFORMS In the power sector reform process, the significant initiatives during 10th Plan are enactment of Electricity Act 2003, notification of National Electricity Policy, Tariff Policy and Rural Electrification Policy. Distribution segment was identified as the key area for reform for putting the sector on the right track. Distribution Reforms involve System up-gradation, Loss reduction, Theft control, Consumer orientation, Commercialization and adoption of I T Six Level Intervention Strategy In order to achieve commercial viability, Ministry of Power has formulated a six level intervention strategy that encompasses initiatives at national level, state level, SEB/ utility level, distribution circle level, feeder level and consumer level as part of distribution reforms. These are: i) National level intervention-relates to policy, legislation frame work, uniform standards, energy conservation, accounting etc. ii) State level intervention-formation of SERCs, issuance of regular tariff order, providing legislative support, removal of Tariff anomalies, subsidies and budgetary support. iii) SEB level intervention-restructuring, accountability, commercial accounting, integrated MIS, benchmarking of parameters, Grid discipline and TOD metering. iv) Distribution Circle level intervention-in the billing, reducing energy handling cost, circle to function as independent business unit v) Feeder level intervention-100% metering at 11 kv feeder, total accounting of energy & quality power supply vi) Consumer level intervention-mandatory metering including billing, consumer satisfaction & energy conservation. 3.3 NEW LEGAL AND POLICY FRAMEWORK Electricity Act 2003 Electricity Act-2003 was notified in June 2003 with Competition, Protection of Consumers interests & Power for all Areas, as objectives. The Act provides liberal framework for power development and creates competitive environment to facilitate private investment. It has de-licensed generation and in rural areas, stand alone Page 6 of Chapter 3

250 Distribution Including Village & Household Electrification generation and distribution has been de-licensed. It provides for multiple licensing in Distribution and stringent provisions for controlling theft of electricity. It obliges states to restructure Electricity Boards. The Regulatory Commissions will determine tariffs. It provides for open access in Transmission from outset and open access in Distribution to be allowed by State Electricity Regularity Commissions (SERCs) in phases. The cross subsidies will have to be gradually phased out. Trading has become a distinct licensed activity to promote development of electricity market. Electricity Act-2003 provides for notification of National Electricity Plan by Central Electricity Authority for short-term framework of 5 years while also projecting a 15- year perspective Energy Conservation Act, 2001 Energy Conservation Act was enacted on October 1, The Act lays down concrete measures to ensure efficient use of energy and its conservation. The Act came into effect on March 1, The Bureau of Energy Efficiency (BEE) has been set up to make wide ranging regulations to further the objectives of the Act. The Central and State Governments have been empowered to facilitate and enforce efficient use of energy and its conservation. 3.4 POLICY INITIATIVES In compliance with provisions of the Electricity Act 2003, National Electricity Policy, National Tariff Policy and National Rural Electrification Policy as have been notified by the Ministry of Power National Electricity Policy (2005) The National Electricity Policy aims at laying guidelines for accelerated development of the power sector, providing supply of electricity to all areas and protecting interests of consumers and other stakeholders. The policy envisages multi-year tariff; private sector participation in distribution, open access in distribution, segregation of technical and commercial losses through energy audits, standards for reliability and quality of supply in line with an international practice by year 2012, implementation of modern information technologies system on priority basis with special emphasis on consumer indexing and GIS mapping, promotion of HVDS system, sub-station automation and effective implementation of anti theft provisions of Electricity Act The National Tariff Policy (2006) The National Tariff Policy has been notified in January As per the policy all future requirement of power needs to be procured competitively by distribution licensees except in cases of expansion of existing projects or where there is a State controlled/owned company developer. It provides framework for performance based cost of service regulation in respect of aspects common to generation, transmission as well as distribution. Multi-year tariff framework is to be adopted for tariff to be determined from April 1, The policy envisages suitable performance norms of operations with incentives and dis-incentives along with appropriate arrangement for sharing the gains of efficient operations with the consumers. Electricity is to be made available for 24 hours particularly for those consumers who are willing to pay tariff Page 7 of Chapter 3

251 Distribution Including Village & Household Electrification which reflects efficient costs. The policy emphasizes giving subsidy in transparent and targeted manner and the cross subsidies for different consumers should be brought within the range of +20% of average of the supply by the end of the year The tariff fixation should ensure sustainable use of ground water resources. The cross subsidy surcharge to be computed in a way so that open access becomes a reality Rural Electrification Policy (2006) The Rural Electrification Policy envisages provision of access to electricity to all households by the year 2009 and minimum lifeline consumption of 1 unit per household per day as merit good by year 2012, promotion of decentralized distribution generation, rural electrification plan by State Governments to achieve the goal of providing access to all households, setting up of the District Committees, implementation of Franchisee system as mandated by RGGVY for distribution management, If state Government / SERC decides to permit licensee to use assets created with subsidy the benefit of capital subsidy to be passed on to consumers. Government of India to evolve model schemes in consultation with NABARD and RBI to encourage widespread participation by lending community in RE initiatives, Energy efficiency to be promoted as mass campaign in rural areas. Government of India should evolve programmes for encouraging use of economically viable energy efficient farm equipment irrigation pumpsets and use of IT for supply of electricity should be encouraged Integrated Energy Policy (IEP) Some of the important recommendations relate to the following areas: Transparent and targeted subsidies; Improved efficiencies. On the power sector the key high priority recommendations of the energy policy relate to power sector reforms to focus on controlling aggregate technical and commercial losses of the transmission and distribution utilities. In order to reduce AT&C losses the Committee recommended APDRP to be restructured to ensure energy flow auditing at the distribution transformer level through Automated meter reading, Geographical Information System (GIS) mapping of the network & consumers and separation of feeders for agricultural pumps. Investment in developing a Management Information System (MIS) that can support a full energy audit for each distribution transformer is essential for reduction in AT&C losses. This will also fix accountability and provide a baseline which is an essential prerequisite to management reform and/or privatization. Introduce time-of-day pricing with shift to electronic meters. For all loads above say 50 kwh, introduce intelligent meters that permit real time and remote recording of data and allow remote control over the power Page 8 of Chapter 3

252 Distribution Including Village & Household Electrification supplied by each meter. This would help effective management of connected load and the reported pilferage by large consumers. The improvements listed above and the base line data generated as a result would bring greater transparency in the process of privatization (if pursued) and provide a better estimate of the transition funding needs under outcome driven privatization models that seek to restore the viability of distribution. All central assistance to state governments for the power sector must be linked exclusively to loss reduction and improved viability. The restructured APDRP can, in the very least, help create an authentic base line. The revised APDRP will provide incentives to State Electricity Boards (SEBs) that are linked to performance outcomes and will also include incentives to staff for reduction in AT&C losses. The Committee also recommended that liberal captive and new captive regime foreseen under the Electricity Act 2003 be realized to derive economic benefits from availability of distributed generation. It will also set competitive wheeling charges to supply power group to captive consumers. This will pave the way for open access to distribution networks. To achieve these objectives, the Committee feels that it is essential to separate the cost of pure wire business carriage to energy business content in both transmission and distribution at different voltages. The wires business within the distribution segment is also a natural monopoly and must be regulated. The Committee recommended introduction of availability based tariffs (ABT) for intra-state sales and upgradation of state load dispatch centres to the technical level of regional load dispatch centres. Committee recommended that gross subsidy surcharge; wheeling charge and back-up charges are set properly to make the utilities viable after high value paying customers migrated to new suppliers due to Open Access. These charges need to be periodically revised and independently regulated. Committee recommended that the regulators should set Multi Year Tariff. To make RGGVY sustainable the committee recommended that, a business plan with a viable revenue model needs to be elaborated. A clear pricing and subsidy policy and the mission s target to be announced soon and the franchisees should run the local network. The Committee suggested generation of electricity through wood gasifier or by burning surplus bio-gas from the community bio-gas plants. Such distribution generators may be able to take electricity to villages sooner than the grid and tariff should be formulated for such distributed generation for both household and productive uses including agriculture. The Committee has emphasized energy efficiency and demand side management. The Committee feels that with an aggressive pursuit of energy efficiency and conservation, it is possible to reduce India s energy intensity up Page 9 of Chapter 3

253 Distribution Including Village & Household Electrification to 25% from the current level. Some of the recommended initiates of the Committee for quick yield returns are as follows: Regulatory commissions can allow utilities to factor EE/DSM expenditure into the tariff. Each energy supply company/utility should set up an EE/DSM cell. All utilities should introduce TOD tariffs for large industrial and commercial consumers to flatten the load curve. Utilities should support load research to understand the nature of different sectoral load profiles and the price elasticities of these loads between different time periods to correctly assess the impact of differential tariffs during the day. Enforce mandatory purchase of electricity at fixed prices from co generators (at declared avoided costs of the utility) by the grid to encourage cogeneration. Improving efficiency of industrial, municipal and agricultural water pumping. Instituting an efficient motors programme. This initiative should focus on manufacturers/rewinding shops and target market transformation, by providing incentives to supply energy efficient motors. Instituting an efficient boiler programme. Promoting Solar Hot Water Systems. This programme should aim at both industrial and household needs of hot water. Undertaking efficient lighting initiative. Making energy audits compulsory for all loads above 1 MW The Group agrees with recommendations of the IEP and some of the implementation strategies are contained in this report. 3.5 DISTRIBUTION OF POWER IN URBAN AREAS Accelerated Power Development and Reforms Programme (APDRP) Accelerated Power Development Programme (APDP) programme is part of the six level intervention strategies for accelerating distribution reforms. In 2001, the Government of India introduced the Accelerated power development programme (APDP), with the objective of initiating a financial turnaround in the performance of the State owned power sector. The Programme was formulated to finance specific projects for up-gradation of sub-transmission and distribution (ST&D) network and Renovation and Modernization R&M) of power projects (Thermal & Hydro). During the year and , the Government has provided budgetary allocation of Rs.1000 crore and Rs.1500 crore respectively to the State Governments as Additional Central Assistance under APDP. In project costing Rs crore were sanctioned and the Government released Rs crore in one installment. The utilities have utilized Rs Crore. In the year the programme was rechristened as Accelerated Power Development and Reforms Programme (APDRP) and the assistance was linked to Page 10 of Chapter 3

254 Distribution Including Village & Household Electrification reforms. Initially the programme covered 63 distribution circles including 3 circles in Delhi out of the 400 distribution circles in the country. Later the focus has shifted to densely electrified zones i.e. urban and industrial areas. The programme aims at strengthening and up-gradation of the Sub-transmission and Distribution system in the country with the objective of reducing Aggregate Technical and Commercial (AT&C) losses, improving quality of supply of power, increasing revenue collection and improving consumer satisfaction. The strategy envisages technical, commercial, financial and IT intervention, organization and restructuring measures and incentive mechanism for reducing T&D and cash loss reduction The expected benefits from the programme are as follows: i) Reduction of AT&C losses from the existing around 60% to around 15% in five years to begin with in the urban areas and high density/ consumption areas. ii) Significant improvement in revenue realization by reduction of commercial losses leading to realization of an additional Rs.20, 000 Crore approximately over a period of 4-5 years. iii) Reduction of technical losses would result in additional energy equivalent to nearly 6,000 7,000 MW to the system, avoiding the need of 9,000 to 11,000 MW of fresh capacity addition besides avoiding investments to the tune of Rs.40,000 to Rs.60,000 Crore; iv) Quality of supply and reliable, interruption- free power will encourage usage of energy efficient equipments / appliances, which will further lead to improvement in availability of energy. v) Reduction in cash losses on a permanent basis to the tune of Rs.15, 000 Crore. vi) Distribution reform as envisaged above will help States to avoid heavy subsidies, which are given to SEBs / State Utilities by State Governments Financial Progress The total fund planned under APDRP in the 10 th Plan is around Rs. 40,000 crores with investment component estimated to be around Rs 20,000 Crores and incentive for cash loss reduction at Rs.20, 000 crores.. Under investment component 583 projects were sanctioned with cost of Rs Crore against this Rs crores were released. The Counter-Part funds tied up were Rs Crore and funds drawn were Rs Crore and Funds utilized were Rs Crore. Incentive for reduction of cash loss amounting to Rs Crore has been paid to Andhra Pradesh, Gujarat, Haryana, Kerala, Maharashtra, Rajasthan, West Bengal and Punjab for showing cash loss reduction of Rs crore. Page 11 of Chapter 3

255 Distribution Including Village & Household Electrification Table 3.2 Allocation of Funds Under APDP (Rs. in Crore) Year BE RE Actual Expenditure Investment Incentive Total (Grant only) - Investment Incentive Total Investment Incentive Total Investment Incentive Total The details of the cash loss reduction and incentives released to various states under APDP are given in Table 3.3 (As on 31 st March 2006) : Table 3.3 Cash Loss Reduction & Incentives REleased (Rs. in Crore) Sl. No. State Year Cash loss reduction Incentive released 1 Gujarat Maharashtra Haryana Rajasthan Andhra Pradesh 6 West Bengal Kerala Punjab Total ACHIEVEMENTS UNDER APDRP Reduction in AT&C losses: The AT&C losses which were about 36.81% in the year have reduced to % in the year Power Utilities in the states of Andhra Pradesh, Arunachal Pradesh, Delhi, Goa, Haryana, Himachal Pradesh, Karnataka, Page 12 of Chapter 3

256 Distribution Including Village & Household Electrification Maharashtra, Mizoram, Nagaland, Orissa, Punjab, Sikkim, Tripura, Uttar Pradesh and West Bengal have shown reduction in their AT&C loss. 313 towns covered under APDRP have shown reduction in the AT&C loss. 212 APDRP towns have brought down AT&C losses below 20 percent. 169 towns have shown loss below 15% and 38 towns have achieved AT&C loss between 15 & 20% (AP-96, TN-36, Karnataka-31, Punjab-11, Gujarat-11, Chattisgarh-2, HP-6, Maharashtra-8, Kerala-4, Rajasthan-3, Goa-1, Tripura-1). The overall commercial loss (without subsidy) of the utilities reduced from Rs. 29,331 Crore during to Rs. 19,722 Crore during However, the same increased to Rs. 22,126 Crore during Cash loss reduction of Rs.3447 crores was achieved by states of AP, Gujarat, Kerala, Maharashtra, Punjab, Rajasthan and West Bengal. The states which are still incurring high losses are Assam, Bihar, Haryana, Jharkhand, J&K, Karnataka, Punjab, Rajasthan, Tamilnadu and Uttar Pradesh Progress of Metering (a) 11 kv feeders metering: At national level 96% feeders have been metered as of now, as against 81% metered during % feeder metering has been achieved in 18 states namely in Assam, Delhi, Goa, Gujarat, Haryana, Karnataka, Kerala, Madhya Pradesh, Maharashtra, Meghalaya, Punjab, Rajasthan, Sikkim, Tamilnadu, Tripura, Uttar Pradesh, Uttaranchal & West Bengal. Union Territories of Chandigarh, Daman & Diu and Pondicherry have also achieved 100% feeder metering. (b) Distribution Transformer Metering: The distribution transformer metering is a prerequisite for carrying out energy audits and identifies the high loss area in the LT system. The overall DT metering in the country is still low in most of the states. The maximum extent of DTR metering is around 25% for the states of Karnataka and Maharashtra. (c) Consumer metering: During the consumer metering was at 78%. It has now increased to 92% during , 100% consumer metering has been achieved in the states of Delhi, Himachal Pradesh and Kerala. Union Territories of Chandigarh and Daman & Diu have also completed 100% consumer metering. Andhra Pradesh, Assam, Goa, Gujarat, Haryana, Mizoram, Rajasthan, Sikkim, Uttar Pradesh, West Bengal and Pondicherry have achieved more than 90%. Majority of the un-metered consumers belong to agriculture and flat rate categories Control of theft and pilferage Anti theft provisions were introduced in Electricity Act states have set up special courts and five states have set up special police stations to deal with theft. AP, Assam, Delhi, Gujarat, HP, Karnataka, MP, Maharashtra, Orissa, Rajasthan, UP, Utrtaranchal, WB have set up special courts. Gujarat, Karnataka, Orissa, Rajasthan, Page 13 of Chapter 3

257 Distribution Including Village & Household Electrification WB have set up special police stations. Around 12 lakh cases were detected, and in about 10,000 cases conviction and about Rs.600 crores were realized Other initiatives and improvements 24 states have constituted Electricity Regulatory Commission and 20 have also issued tariff order (AP, Assam, Chhattisgarh, Delhi, Gujarat, Haryana, HP, Jharkhand, Karnataka, Kerala, MP, Maharashtra, Orissa, Punjab, Rajasthan, TN, Tripura, UP, Uttaranchal, WB). 13 states have unbundled, restructured and corporatized SEBs (AP, Assam, Delhi, Gujarat, Haryana, Karnataka, MP, Maharashtra, Orissa, Rajasthan, Tripura, UP, Uttaranchal). Computerized billing was introduced in most of the states; Spot billing machines for issuing bill at the time of meter reading were introduced in several states (AP, Assam, Bihar, Delhi, Goa, Gujarat, Haryana, HP, Karnataka, Kerala, Maharashtra, Orissa, Punjab, TN, UP, Uttaranchal). Customer information about metering billing and collection on websites introduced in AP, Delhi, Maharashtra, Karnataka, Tamil Nadu. Customer care centres opened in several states (AP, Assam, Delhi, Goa, Gujarat, Haryana, HP, Jharkhand, Karnataka, Kerala, Maharashtra, MP, Orissa, Punjab, Rajasthan, TN, Tripura, Uttaranchal, UP, WB). A number of Distribution utilities mobile repair vans have been launched in AP and Delhi. In number of states headquarters, SCADA has been introduced (Hyderabad in AP, NDPL in Delhi, Vadodara in Gujarat, BEST & REL in Maharashtra, Chennai in TN, Jaipur in Rajasthan, Trivandrum in Kerala). Introduction of consumer index linking along with geographical information system has started in some of the states. Local communities like self help groups, gram vidyut pratinidhi, franchisees, and local entrepreneurs are involved in distribution of electricity Capacity Building Capacity building of utilities personnel at all levels has been taken up to train them in latest technologies and methods of operation and maintenance, project formulation, project management etc. PMI (NTPC) & NPTI have trained more than 1800 personnel from various utilities. Training of around 25,000 utility personnel has been taken up under Distribution Reform Up-grade Management (DRUM) in association with USAID. The training themes include AT&C loss reduction, O&M practices, demand side management, Safety aspects, performance benchmarking, quality management, financial management, project development etc. An MBA course for the distribution managers was introduced under the DRUM training programme at MDI, Gurgaon Addition to sub-transmission and distribution network during 10th Plan The extent of Sub transmission and Distribution systems at the beginning of 10 th plan on an all India basis was km of lines and MVA of distribution transformer capacity. This has increased to Km of 33 kv, 11 kv and LT lines and MVA of Distribution transformation capacity by 31 st March Page 14 of Chapter 3

258 Distribution Including Village & Household Electrification This is an increase of Km of lines and MVA Distribution transformer capacities. It will further increase by the end of 10 th plan with completion of ongoing schemes. The addition envisaged by the Working Group on 10 th Plan was km of 33 KV, 11 kv and LT lines and 65505MVA of Distribution transformer capacity Independent evaluation of APDRP Schemes The Ministry of Power got the evaluation of APDRP carried out through independent agencies namely TERI (The Energy Resource Institute), SBI Capitals, Tata Consultancy Services, Indian Institute of Management Ahmedabad (IIMA) and ASCI (Administrative Staff College of India), Hyderabad to assess the benefits accrued from APDRP projects vis a vis- expected benefits from the APDRP programme. In the first phase, evaluation has been carried out for 66 projects, where more than 50% work has been completed. The evaluating agencies suggested that information technology should be used effectively to enhance the benefits, funds should be released directly to the Utility / SEB concerned, to cut down approval & disbursement time, funding from the Govt. must be linked to achievement of specific benchmark parameters, rather than based on the incurred expenditure, project plan with time schedule for different activities should be pre-defined at DPR stage only, project implementation should be done on turnkey basis and measures for increasing accountability and measuring performance should be the main focus areas for attaining commercial turnaround. In accordance with the above recommendation emphasis is given to GIS based consumer indexing and distribution transformer based energy auditing for increased accountability, adoption of information technology for efficiency improvement, focused monitoring on key performance parameters, to cover all district headquarters under the programme on priority and establishment of consumer care centers/ Bijlee Seva Kendras Task Force on APDRP The ministry of power has constituted a Task Force under the Chairmanship of Shri P. Abraham, Chairman, Maharashtra State Power Generation Co. Ltd comprising of Members from utilities from different zones and other eminent persons with the following terms of reference: i) To assess the current efforts under APDRP; ii) iii) iv) Analyze the current reforms initiatives that are being pursued by the states with reference to the objectives of APDRP; To assess the need for modifications in the light of independent evaluations and other feed back; Suggest measures to achieve the objectives of APDRP Page 15 of Chapter 3

259 Distribution Including Village & Household Electrification The observations of Task Force The Task Force observed that some of the utilities adopted feeder approach to make field officers accountable and measuring their performance achieved very good results in the form of improvement in all the key performance indicators. The monitoring of achievements has improved expenditure in many utilities. The Task Force observed that increase in commercial loss of utilities has not only been arrested but there is downward trend at the national level. Though reduction in AT&C losses and DT failure rate has been reported in most of the towns where APDRP work has been considerably completed the significant reduction was only in few states. In the feeders where augmentation has been done and the energy accounting has started outages have reduced and significant improvement has been achieved in respect of AT&C losses and DT failure rate. The Task Force observed that AT&C losses of 5.06% was reduced at national level during 3 years i.e. 1.68% reduction per year as against a target of 9% per year and this achievement can not be considered as small, as actual implementation after the programme started quite late. The Task Force observed that improvement in billing and collection efficiency has taken place in most of the utilities. The Task Force felt that APDRP is still at initial stage and the full benefits of the programme can not be expected at this stage. The assessment of benefits from the programme should be made after covering all the district headquarters at least and when sufficient work has been completed Summary of Recommendations of the Task Force The recommendations of the Task Force are: a. ARPDP to be continued in XI th plan with focus on auditing and accounting and reducing AT&C losses in major town and cities It interventions, technological up gradation, control of theft and pilferage, GIS and consumer indexing and establishment of Bijlee Sewa Kendra. b. The conditions for availing assistance under the programme may be made more stringent with an objective to make States/Utilities to adopt reforms. The primary conditions as mentioned in the report will have to be fulfilled by the states for becoming eligible for the APDRP. The states will also have to commit achievement targets for secondary conditions as approved by the Ministry, which will be based on the present performance level of the Utilities. c. The APDRP assistance, both investment and incentive component, may be extended to the Private Distribution Utilities also. The incentive for loss reduction by the private utilities may be given to the State instead of the utility. d. The Task Force recommends following targets for reduction in AT&C losses by the Utilities: i) Utilities having AT&C losses above 40%: Reduction by 4% per year; ii) Utilities having AT&C losses between 30 & 40%: Reduction by 3% per year; iii) Utilities having AT&C losses between 20 & 30%: Reduction by 2% per year; iv) Utilities having AT&C losses below 20%: Reduction by 1% per year. Page 16 of Chapter 3

260 Distribution Including Village & Household Electrification e. The projects taken up under the programme should be aimed at reducing AT&C losses, improvement in quality and reliability of power and improvement in consumer services. f. Utilities should prepare a roadmap with priorities for works to be taken up under the investment component and execute the work by adopting best practices. g. Each Distribution Company may be considered for calculation of incentive against cash loss reduction. Ministry may devise additional methods also for incentivizing Utility and Utility employees for improvement in performance. h. Under the investment component of the programme, the grant may be increased to 50% of the project cost for the general category states. i. In order to keep the focus of the states and Utilities towards reforms and the improvement in the sector, Government should commit sufficient non-lapsable fund for the programme. j. The programme may be converted into a Central scheme for speedy implementation. k. The assistance under the programme should focus mainly on such activities, which will help in quick reduction of AT&C loss and improvement in customer services, l. The programme should have a provision of 5% for training the Utility personnel, hiring consultants, undertaking studies, project evaluation etc. m. The DPRs for the new projects should be made more realistic. The tender documents and specifications should be standardized by the AcCs in consultation with the Utilities. It should contain a quality plan and also provisions for price variations during execution. A variation of plus or minus 10% to 15% may be allowed in quantity or value of items within overall sanctioned cost of the scheme. n. Execution of all the schemes should be on turnkey system only by adopting standard specifications, except in cases where approval of the Ministry is taken in advance. o. Utilities, AcCs and Ministry of Power should closely monitor the implementation of APDRP projects and progress of the Utilities towards achievement of the set targets. 3.7 DISTRIBUTION OF POWER IN RURAL AREAS - INITIATIVES IN 10 th PLAN During the first four years of the 10 th Plan, the PFC has sanctioned financial assistance of Rs crore to various States under various schemes for rural electrification. A number of initiatives were taken during the X plan period, successively for household and village electrification viz (i) Kutir Jyoti Yojana, , (ii) Pradhan Mantri Gramin Yojana , (iii) Minimum Needs Programme , (iv) Accelerated Rural Electrification Programme , Page 17 of Chapter 3

261 Distribution Including Village & Household Electrification (v) Accelerated Electrification of One Lakh Village and One Crore Households (vi) Rajiv Gandhi Grameen Vidyutikaran Yojna was launched from April 2005 and all the above mentioned schemes were merged in it. Definition of Village Electrification At the advent of this scheme, the definition of village electrification was changed. A brief history of these definitions of village electrification is as follows: Prior to October 1997 A village should be classified as electrified if electricity is being used within its revenue area for any purpose whatsoever. In 1997, the definition of village electrification was modified to provide for the use of electricity to village habitations. Accordingly, the new definition said: After October 1997 A village will be deemed to be electrified if the electricity is used in the inhabited locality, within the revenue boundary of the village, for any purpose whatsoever. In Feb. 2004, the definition was made even more encompassing as also target specific. New Definition ( ) A village would be declared as electrified if: (i) Basic infrastructure such as distribution transformer and distribution lines are provided in the inhabited locality as well as the dalit basti/hamlet where it exists. (For electrification through Non-Conventional Energy Sources a distribution transformer may not be necessary) (ii) Electricity is provided to public places like schools, panchayat offices, health centres, dispensaries, community centres etc. and (iii) The number of households electrified should be at least 10% of the total number of households in the village. With each change of definition, the number of electrified and unelectrified villages was set to change Progress of rural electrification during X Plan Out of a total of inhabited villages as per 2001 Census in the country, villages have been electrified by February Similarly, against the potential of 196 Lakhs irrigation electric pumpsets, 148 lakhs pumpsets have been electrified as on Page 18 of Chapter 3

262 Distribution Including Village & Household Electrification In the X Plan document it was proposed to electrify all the balance unelectrified villages i.e. 97,559 during the Plan. However, in the first four years of the Plan only 19,460 villages have been electrified. Year wise achievement of villages electrified and pumps sets energized during first four year of X Plan are given in Table 3.4: Table 3.4 Village Electrified & Pump sets Energised Years Villages electrified Pump sets energized Total Implementation of RGGVY : RGGVY had originally envisaged electrification of (based on 1991 consensus) unelectrified villages 7.8 crore in unelectrified households (including 2.34 crore BPL households) in the country. The estimated cost of RGGVY was to be Rs. 16,000 crore, of which Rs crore (90%) was expected to be subsidy component. Out of the total of 29 States in the country, 27 States agreed to participate in RGGVY (except State of Goa and Delhi). The participating States have concluded the necessary arrangements amongst REC, State Governments, State Power Utilities and CPSUs Achievements Under the scheme, works for the electrification of 9819 unelectrified villages in the States of Bihar, UP, West Bengal, Rajasthan, Uttranchal and Karnataka and 350 electrified villages (intensive electrification) in the States of Karnataka have been completed during and 9151 unelectrified villages have been electrified during as on September 30, Table 3.5 Achievements under RGGVY (As on ) DPRs Sanctioned for 218 districts in 24 States covering 219 Projects Un-electrified villages Electrified villages Households BPL Households Total Project Cost Rs cr. Page 19 of Chapter 3

263 Distribution Including Village & Household Electrification Quantum of major works covered under sanctioned projects New 33/11 kv Sub-stations 352 Aug. of existing 33/11 kv S/Stns. 527 New 33 kv Lines (km) 6171 New 11 kv Lines (km) New Distribution Transformers New LT Lines Metered Connections (BPL HH) Turnkey contracts awarded Un-electrified Villages Electrified villages Households Total Project Cost Rs cr. Total Awarded Cost Rs cr Need for continuation of RGGVY RGGVY has truly become the engine of rural electrification programme in all States of India., DPRs from all States are going to be available by Works have been started in 153 districts. RGGVY should be continued in the XI plan to achieve the objective of Power to all by DEVELOPMENT OF REVENUE SUSTAINABILITY - FRANCHISEES RGGVY scheme envisages management of rural distribution through franchisees who could be NGOs, User Associations, and individual entrepreneurs, cooperatives or Panchayats. As per the Electricity Act, a Franchisee means a person authorized by a distribution licensee to distribute electricity on its behalf in a particular area within its area of supply. Deployment of input based Franchisees is a requirement under RGGVY scheme to receive funds under the scheme. Fifteen State Governments have taken action for deployment of franchisees. About thirty eight thousand villages are covered under franchisee arrangement till October The majority of these franchisees are in Karnataka, West Bengal, Assam, Uttaranchal, Uttar Pradesh, and Nagaland. Other states including Bihar, Rajasthan, Chhattisgarh, Haryana etc. are at various stages of deployment of Franchisees. Uttar Pradesh has engaged consultants for 6 pilot projects and 15 transaction projects to develop Input Based Franchisees. These franchisees are mostly revenue based where the activities are limited to meter reading, billing, bill distribution, revenue collection, attending to complaints, maintenance of records, minor repairs etc. The states have committed to convert revenue based franchisees to input based franchisee. Page 20 of Chapter 3

264 Distribution Including Village & Household Electrification Franchisee Experience in the states The institutional design and structure of Franchisee models vary from state to state. In Nagaland, the traditional structure of Village Council has been used to form a sub-committee called Village Electricity Management Board (VEMB) to function as a Franchisee. Electricity is billed to VEMB on Single Point Metering (SPM) basis. The objective of SPM is to reduce Technical and Commercial losses and to involve village community to work as business partner with Power Department. The VEMB gets 20% financial benefit on the every unit of energy they sold. The tariff fixed by Govt. for VEMB is Rs per unit and VEMB in turn Rs per unit to village consumers. To get full financial benefit VEMB has to ensure that whatever is the energy supplied through SPM is billed from consumers in the village, this has resulted in reduction of theft and other commercial losses in the supply area of VEMB. At present VEMBs are in place in 452 villages. In Karnataka, Gram Panchayats have been involved to identify Grameen Vidyut Pratinidhi (GVP) to function as Franchisee. The GVP is a local unemployed youth from the same Panchayat. They are working as revenue franchisee and there is a provision of commission on amount realized above baseline targets apart from retainer ship fee for achieving the baseline targets. At present 3425 GVPs are already working in 5605 Panchayats falling under all the five ESCOMs covering villages. In Assam, the utility initiated the Single Point Supply Scheme (SPSS) and appointed input based franchisees and collection franchisees at distribution transformers. The Single Point Power Supply (SPPS) through franchisee was first introduced in Digboi division in upper Assam and looking to the success of the programme it was extended in the entire State. Initially 22 villages with distribution transformers ranging from 16 KVA to 100 KVA were taken-up for the programme where 80% of the connected load is in domestic category, now the programme is in place for 816 villages and efforts are being made to engage franchisees for another 816 villages. The franchisee can be NGO, user s association, a village body or an individual. The mechanism of payment to franchisee is very simple 10% distribution losses and 15% commission is allowed. In West Bengal and Uttaranchal, women Self-Help Groups (SHGs) have been engaged to function as Franchisee. These are at present revenue franchisees. The franchisee and people working with franchisee are mostly resident of the same locality. In Uttaranchal 5321 villages are under franchisee arrangement and in West Bengal this number has reached to 1169 villages. Deployment of franchisee is in progress in other states like Uttar Pradesh, Bihar, Haryana, Rajasthan, Madhya Pradesh etc. Page 21 of Chapter 3

265 Distribution Including Village & Household Electrification Impact of Franchisees While there is a variation in the institutional design of Franchisees across the states, most of the operational Franchisees at present are either Collection Franchisee or Input Based Franchisees. Since the formation of the Franchisees in the states, no systematic evaluation has been undertaken to assess the impact of these on improvement in management of rural electrification. It is therefore critical to undertake an Independent Verification and Evaluation study. However, there has been to some extent documentation of the experiences and internal review of the Franchisee experience in the state these are summarized below: (i) Improvement in Collection Efficiency Experience from all the states shows that the collection efficiency in these states where Franchisee either as Collection or as IBF has been implemented has improved. (ii) Improvement in customer services Customer services in the rural areas have improved since the formation of Franchisees. The improvements pertain to billing and collection and services of minor repair and maintenance. Since the franchisee and the people working with the Franchisee are mostly residents of the same locality, there is saving in time and money for the customer. (iii) Employment Generation Deployment of Franchisees has also resulted in employment generation in the local areas. The key lessons identified from Franchisee experience which are important for developing future course of replication and up-scaling Franchisee implementation in the states are: (i) Simple Arrangement Works - One of the key reason for rapid expansion in implementation of SPSS scheme in Assam was ease of implementation arrangement, it was easy to understand (the calculation of commission, standardized loss levels) and standardized across franchisees. The simplicity of the arrangement made it easier for the Franchisees to comprehend that irrespective of the distribution transformer they adopt, the allowed loss would be 10% and the commission would be 15%. This helped in quick implementation. (ii) Pre-implementation Financial viability of Franchisee Essential - There is a need for pre-project studies to evaluate the financial viability of the franchisee. Review of the Franchisees in Assam shows that there are disputes on "Permissible Loss Levels" and some of the franchisees have started surrendering their areas. The key reason for the dispute in loss levels is that, initially when they signed the agreement, only a few were involved in any kind of activity related to the electricity business. It is only after taking over of the transformers that the Franchisees realized the actual condition of the distribution system. Also some of the franchisees have reportedly suffered losses due to following reasons: The franchisees that are not technically sound, find it difficult to identify issues such as meter bypass and unauthorized hooking. Page 22 of Chapter 3

266 Distribution Including Village & Household Electrification In few Franchisee areas, Franchisees are not powerful enough to take action against those whom they know are getting unauthorized power. Similar lessons have also been drawn from review of GVPs in Karnataka. (iii) Franchisee Management Information System (FMIS) is required - Development of a FMIS to track franchisee performance, learn from experience, their adherence to contractual requirements and to take early corrective actions is required. None of the states which have set-up Franchisees have such MIS system. A similar FMIS is also required to be developed for REC to monitor the performance of Franchisees across the country. (iv) Up scaling from Collection Franchisee to Input Based Franchisee (IBF) necessary Review of Franchisee implementation by most of the states show that they have opted for Collection Franchisee. While the choice of Franchisee model is left open, it has been emphasized that eventually the most effective model would be an IBF model Capacity Building of franchisee REC has circulated guidelines for formulating the franchisee system and has prepared a comprehensive document on the possible franchisee models, field experience shows that in the absence of any formal training, existing franchisees are facing technical and managerial problems during actual operation. Apart from the technical aspects of electricity distribution, it is imperative for prospective franchisees to understand the business opportunities in the system, its management and keep it profitable. In order to ensure that the franchisee model is sustainable in the long run, it becomes critical to build capacities of these franchisees. A national programme for training and capacity building targeted at enhancing the skill set of existing and potential franchisees and trainers to enable them to play a proactive role in improving rural electricity access in the country may, therefore, be launched during XI plan period. Capacity building should go in tandem with electrification of villages so that adequate numbers of trained people are available to take up franchisees in the newly electrified and other electrified villages. Capacity building should precede awareness campaign to educate people about franchisee system for management of rural distribution and its potential. 3.9 ROLE OF PANCHAYATI RAJ IN FRANCHISEE DEVELOPMENT The Franchisee Guidelines issued by REC envisage that the Panchayati Raj Institutions (PRIs) would have a supervisory / advisory role in management of rural distribution through franchisees. The state Government could also encourage the Panchayati Raj Institutions to take on responsibility of franchisee as and when such institutions have developed to the extent that they can undertake contractual obligations, raise resources from market and can discharge associated legal responsibilities. PRIs may also be closely associated with the franchisee arrangement as link between the franchisee and the villagers / consumers as well as concerned state authorities. As the PRIs are going to play the key role in development of franchisees for management of rural distribution, participation of Ministry of Panchayati Raj in Page 23 of Chapter 3

267 Distribution Including Village & Household Electrification capacity building at all levels is imperative. Keeping this in view, the committee recommends that: The Ministry of Power in collaboration with Ministry of Panchayati Raj may formulate an integrated capacity building plan including franchisee development with the scope of wide application across the country to meet the national goal consistent with the RGGVY scheme. The capacity building plan may include all aspects of energy/power sector covering primary education on electricity / energy, energy efficiency, repair and maintenance of rural electricity infrastructure, metering arrangement, social engineering, legal and regulatory aspects, MIS for effective monitoring & control, commercial operations of utility viz. meter reading, billing, revenue collection, book keeping, disconnections, theft control etc. For taking up the programme at the country level, establishment of institutions in each state with regional headquarters and branches at district level may be considered. For 11th Plan, target should for creation of such institutions in at least 20 states in different regions and 115 district centers in collaboration with Ministry of Panchayati Raj and Ministry of Rural Development. For kick start, established institutions in the area of providing technical education like ITI, Polytechnic etc. at regional level may also be involved. In association with established institutions, Certificate courses on such subjects may also be formulated so as to provide this education on continual basis. Appointment of a specialized agency / consultant like TERI, Productivity Council, CBIP, PWC, E & Y, etc. for preparation of course modules / training capsules on above mentioned aspects with proper documentation of course material may also be considered. Special attention may be paid to the desired operational skills for franchisee. The course material should be more illustrative, inter-active and computer friendly. These materials should be available for use in any part of the country. A comparative analysis of the various franchisees in different states be included in the course module. Initially, the core groups at state level may be trained as trainers through a specialized agency / consultant which in turn may provide training to trainees in identified institutes in various states / districts. Association of power utilities should also be encouraged to make this programme a success and necessary training should also be provided to the field officers/staff of utilities associated with franchisee management for effective implementation of franchisee system. Once the franchisee is appointed, they may be provided on the job operational training by the field officers of the utilities Page 24 of Chapter 3

268 Distribution Including Village & Household Electrification 3.10 POWER DISTRIBUTION IN RURAL AREAS THROUGH DDG Definition of DDG Decentralized Distributed Generation (DDG) is defined as installation and operation of small modular power generating technologies that can be combined with energy management and storage systems, and used to improve the operations of the electricity delivery systems at or near the end user. These technologies can be utilized for off-grid as well as grid based. DDG programme is relevant for India to cover cent percent village and household electrification in order to meet peak load shortages and to supply quality power at more economical rate on cost to serve basis. For meeting the rural developmental needs various types of DDG schemes are required. Each type of DDG caters to a specific need of an area for which technological solutions may be different and they call for different institutional arrangements and financing policies Potential for DDG There is a potential to add 10,000 to 15,000 MW capacity through decentralized distributed generation in 11 th and 12 th plan. The DDG projects would help both in electrifying the villages and households and also in generating local employment. Approximately 2000 substations can be linked with 2-5 MW DDG projects, adding a capacity of MW during 11 th plan. The total cost involved will be Rs crore approximately Challenges for DDG Projects DDG is yet to be tried on a large scale in rural electrification projects. There are still many barriers technical, financial, regulatory, and institutional that need to be addressed adequately. In other words, a clear and well-established framework is required to design, implement, and encourage DDGs as these are expected to be aligned to the following policy/programme guidelines: - Universal access to electricity in India. - All BPL families to be provided single point free connection. - Revenue sustainability through SEBs /franchisees. - Affordable power to remote areas through cost effective DG projects. - Utilization of locally available, environmentally benign renewable energy - Sources for providing power either to the grid nearer the load or on standalone basis. - Gainful utilization of the infrastructure created under RGGVY Hour power supply through reliable quality power. - Facilitate development of rural load at an accelerated pace. - Creation of viable and sustainable franchisee development. - Availability of low cost funds and International acceptance of REC standards. Page 25 of Chapter 3

269 Distribution Including Village & Household Electrification 3.11 SHORT TERM STRATEGIES FOR DDG SCHEMES a. Stand Alone i) These projects to be implemented by MNER/REC through NTPC, IREDA or other agencies by setting up Joint Ventures or by any other agency independently or any other acceptable mode. ii) The funds available under RGGVY be utilized for the same for village electrification and / or household electrification etc. iii) All available technologies of bio diesel/ SPV/ biomass/ mini-micro hydel/ micro turbines etc. could be considered to provide affordable power to rural areas. iv) Involvement of local bodies like panchayat, NGOs, SHG or VECs etc in managing the DDG projects in rural areas. v) Selection of Rural Electricity Supply providers/ franchisees. vi) Cost of electricity to be based on cost to serve or avoided cost basis and affordability. vii) viii) Capital Subsidy for DDG projects. Manufacturers of equipment may install and operate the plants for a fixed duration. b. Grid Interconnected Central and State level Government Agencies may participate in the equity of the grid-connected projects, along with established Private Agencies to form a Public Private Partnership in setting up various projects in the country. Independent power producers may also set up such projects. The ownership of the DDG Projects will rest with the project promoters/ equity holders. The following method may be adopted for construction: 1. BOT 2. BOOT 3. BOLT At least 100 Pilot Projects in various states of the country should be commissioned during the first 2 years of the 11 th plan to give large scale impetus to DDG programme. These Pilot Projects should be driven by Public Private Partnership programme. DDG project owners should be offered the distribution activity in the vicinity by the leasing of the distribution network to achieve efficiency, cutting losses and adding to project viability All projects be selected from the predetermined areas and offer for PPP on competitive, transparent basis with any or all of attributes: 1. These schemes may range up to 5 MW in order to meet the supplementary power demand in rural and semi- urban areas. 2. Corporate agencies be encouraged to undertake such projects 3. Suitable standardized size packs may be used in order to reduce production costs. Page 26 of Chapter 3

270 Distribution Including Village & Household Electrification 4. All available commercialized technologies whether conventional or nonconventional may be utilized. 5. Cost of electricity to be on Cost to Serve/ Delivered Cost or Avoided cost basis for working out viability. Life Cycle Costs Approach can also be considered. 6. Multifuel technologies may be adopted for sustainability. 7. Exemption to be given for income tax, customs and excise duties etc. 8. All concessions extended by states for industrial development also to be extended for DDG projects. 9. Viability gap funding may be appropriate methodology. 10. Financial Institutions support for energy plantations. Which would meet the feedstock needs of biomass power/ bio fuels/ bio- diesel plants. For the pilot projects, support also needs to be extended for R&D efforts and preparation of DPRs 3.12 MEDIUM TERM AND LONG TERM STRATEGIES 1. R&D on fuel Cell technology to considerably bring down the costs. 2. R&D on all existing technologies to improve the product quality as well as efficiency levels of the systems to make them more durable and affordable cost of power. 3. Training of local youth in maintenance of the DDG equipment locally. 4. Improvement in the quality and life of batteries. 5. Biomass cultivation and development of short duration (cycle) high yield varieties of biomass suitable for bio- methanation / gasification / direct combustion/ bio-fuels production 3.13 COST TO SERVE/ DELIVERED COST The shortage of electricity leads to larger power cuts in rural areas due to more than double the quantity required to be fed in the grid for a particular delivered quantity and quality of Power in far off rural areas due to heavy transmission, distribution and collection losses. In order to bridge the gap between rural and urban areas, extension of grid through RGGVY is under implementation which only takes care of the infrastructure issues but does not address the issue of quality and quantity of power supply. One of the options in this regard is the supply of electricity through Decentralized Distributed generation method whether off grid or through the grid nearer the load centres ROLE OF STAKEHOLDERS i. State Government Provide an enabling framework for streamlined implementation and operation of the DDG scheme. Publicize and make aware the stakeholders about potential sites/ locations for implementing the DDG schemes. Target for and incentivise for taking up the DDG schemes in potential areas including development of supply providers. Make necessary provisions in the State Budget suitably. To provide land on nominal lease. Page 27 of Chapter 3

271 Distribution Including Village & Household Electrification Maintain system of constant checks and controls through local administration with involvement of the beneficiaries for more participative interaction. ii. State Utility/Discom Assist the Supply provider during identification and execution of the scheme. Support the supply provider during the initial operations and stabilization period. Lease/sell the substation infrastructure to DDG operators iii. Local Administration Act as trustee of beneficiaries interest w.r.t the investments made, security of assets, continuity of the system and stakeholders. Provide for quality of service measures and controls ensuring streamlined operation of the system without any undue interference. iv. Supply Provider a) Technical Operation and Maintenance of the main plant and equipment. Breakdown maintenance and repairs of HT & LT lines. Maintenance of Transformers and other equipments. Maintaining the reasonable stock of line and sub-station materials required for repairs. Replacement of failed transformers and equipments. Install meters to all unmetered installations. Attend to consumer s complaints and grievances. Prevent pilferage and thefts of energy Receive application for new connect ions. Prepare feasibility report and estimate for new connections. Sanction estimates for new connections as per norms and approved policies/procedures. Prepare estimates and drawings for extension and improvement works to bring down energy losses to acceptable levels, check theft and energy accounting. Servicing of new installation with meters. Execution of improvement works. Identify inefficient pumpsets and arrange for replacement with efficient pumpsets by bringing in necessary investments. Submission of prescribed reports to the Distcom/Government. Identifying unauthorized installations and take suitable action. To follow the provisions relating to safety and electricity supply. b) Revenue Meter Reading Billing Collection Page 28 of Chapter 3

272 Distribution Including Village & Household Electrification Maintenance of records Submission of monthly accounts and statistics to respective Discom/ Government. Reply to audit queries. Use necessary hardware/software for issuing computerized billing and generating reports. Collecting government charges/ levies and paying the same to the Government. c) General To educate consumers in its jurisdiction on the efficient use of equipments such as lighting, pump sets etc. for conserving energy. EDUCATE COMMUNITY ON SAFE USE OF ENERGY 3.15 ROLE OF REC REC may be declared the nodal agency for DDG schemes to provide single window support during project formulation, seeking clearances, appraisal, approval and even ensuring financial closure. It will assist in selection of rural electricity supply provider, training of village youth and vendor development for providing reliable services. Commercially viable projects in DDG sector will be either directly financed by REC or through the route of refinance facility to banks, state Corporations, RRBs, State Cooperative Banks, SIDBI etc REC may also take up nation wide survey of various sources of energy available in the villages & towns in a time bound manner by engaging State/ private agencies in different zones. REC may accordingly select suitable sites, setup pilot projects at its own cost and subsequently transfer them on BOT, BOOT or BOLT basis. REC may also engage itself in Public Private Partnership to setup such projects. REC may suitably engage various consultants and construction agencies 3.16 INSTITUTIONAL AND FINANCIAL MODELS The programme should provide medium and long-term financing to private project developers, non-governmental organizations (NGOs), micro financing institutions (MFIs) and community cooperatives etc. for decentralized distributed electrification schemes. The funds are to be made available to private enterprises, NGOs, MFIs and community cooperatives for projects up to about 5 MW. The different financial models may be based on: Capital subsidy/ Viability Gap funding Revenue subsidy Bundling of services Linkages with existing programme Page 29 of Chapter 3

273 Distribution Including Village & Household Electrification 3.17 SPECIAL FOCUS AREAS FOR 11 TH PLAN Separation of Agriculture Feeders It involves installing a separate feeder to supply to the agricultural load as distinct from the feeder supplying the non-agricultural loads in rural areas. This facilitates proper accounting and removes distortions in loss measurement due to un-metered agricultural loads and load management during peak hours. Andhra Pradesh, Gujarat and Punjab have initiated steps to separate agriculture feeders. The working group recommends that a programme should be launched for separation of feeders in those states where the percentage of agriculture consumption is more than 20% of power. In other states single phasing of rural mixed load feeders may be taken up which involves use of change-over switches at sub-stations. The approach envisages supplying single phase rural lighting load through three nos. of single phase transformers. During the normal operation, the agricultural load continues to be supplied from the three phase transformers. On operation of the changeover switch, there will be no supply to the 3-phase load on the 11 KV distribution network whereas single phase supply is available to the lighting and fan load. On revising changeover switch, normal 3-phase supply shall be restored. Cost and time go in favor of this approach. Integrated energy Policy also recommends bifurcation of agriculture pumping load from the non-pumping load in all rural feeders. It further recommends using of available technological options to limit and measure the amount of agriculture pumping energy provided. There is also an urgent need to improve the efficiency of the pumpsets by way of changing over to high quality BIS certified pumpsets. Farmers have to be educated on the benefits of efficient pumps. They should be provided necessary finance for replacement of pumpsets Metering of Agricultural Consumers The system of un-metered supply at flat rates for agricultural consumers is a major stumbling block in the way of accountability and improvement in efficiency of distribution system. This system makes it difficult to have estimates and actual consumption and precise estimate of losses. This effects two sectors, power and water resources. Un-metered supply leads to unrestricted exploitation of the ground water and rapid depletion of the water table. In most of the states it is difficult to segregate rural electricity consumption on the basis of its use in agricultural, commercial, domestic and industrial segment in the absence of appropriate metering system. Although agricultural consumption is the most significant one, reliable data on agricultural consumption is not available. There are 1,44,45,014 pumpsets/tubewells in the country as on 31 st March The average capacity and electricity consumption per pump set was 3.91 KW and 6131 KWh per annum respectively. The electricity consumption during in agriculture sector is third highest being 22.93% of total consumption of electricity in the country. Whatever is not billed in domestic, commercial and industrial categories is often treated as consumption under agriculture. Power theft is hidden under agricultural consumption. Utilities may also deliberately overestimate the un-metered Page 30 of Chapter 3

274 Distribution Including Village & Household Electrification agricultural consumption to get higher subsidy from the State Govt. and also project reduction in losses. One study has found that owners of electric tube-wells paying flat rate tariff operated their pumps for 40% 250% greater hours per year as compared to diesel tube-well owners which proves the fact that flat rate leads to wastage of electricity with adverse impact on the water table. Metering of agricultural consumption allows quantifiable supply to agriculture which is a necessary condition for transparent subsidy mechanism. Though new legal framework provides for compulsory metering of electricity supply, most of the agricultural consumers are supplied un-metered power on flat rate basis (Rupees/HP/Month). Unmetered supply on flat rate basis has adverse implications for accounting and auditing of energy besides inefficient use of power and over exploitation of ground water resources. Section 55 of the Electricity Act provide that No licensee shall supply electricity, after the expiry of two years from the appointed date, except through installation of a correct meter in accordance with regulations to be made in this behalf by the Authority: Provided further that the State Commission may, by notification extend the said period of two years for a class or classes of persons or for such area as may be specified in that notification. Despite all these provisions, power supply to agriculture continues to be un-metered on flat rate basis in most of the states. Besides, resistance for installation of meters, the cost and practical difficulties in regular billing and collection are the stated reasons for not providing meters for agricultural consumers. In this context there is a need for alternative approaches for metering agricultural consumers. It also requires full support from the Government/ Political establishments. The working group recommends that power supply for agricultural purposes should be hundred percent metered in phased manner to remove distortion in the data regarding consumption, losses, and subsidies Conversion to HVDS System Over the years, large scale expansion of urban system and rural electrification program in the country, has resulted in considerable expansion of Low Tension distribution network. To meet the increasing demand due to load growth, size of the DTR s has been constantly increasing. As a result the lengthy of LT lines/circuits is also increasing resulting in high load losses in LT lines, excessive voltage drops and frequent faults on LT network and higher rate of failure of distribution transformers. It is estimated that for the same power demand or load, the current in LT system is 28 times in the 11 KV system. Thus, with switchover to 11 KV systems, load losses are scaled down 800 times and voltage drops are reduced to a negligible level. High Voltage Distribution System (HVDS) envisages running 11 KV lines right up to the loads and setting up small sized distribution transformers and extend supply with least LT lines. Many states are introducing HVDS system. The benefits of HVDS system are, theft control, sharp reduction in system losses, effective utilization of transformer capacity as it would free the transformation capacity from feeding the Page 31 of Chapter 3

275 Distribution Including Village & Household Electrification power losses in the downstream LT lines, reduction in voltage drops, reduction in failure rate of DTR due to large transformers, long lines and weak load monitoring. Reduction in DTR failure rate results in enormous savings in cost and time for repairs, replacement and outages. Since HVDS caters to 5-6 consumers it gives a sense of ownership to the consumers and the system is well secured. Several studies revealed that distribution losses can be brought down considerably by this system. Though, large scale implementation of HVDS would entail huge investment, the benefits from it are huge, immediate and sustainable and they offset the investment burden given the high level of losses and the potential of HVDS to reduce losses. This system is best suited to meet the problems associated with scattered loads and to effectively deal with theft of energy by hooking directly from LT lines which is very common in rural and urban areas. Already states of AP, Delhi, Gujarat, Maharashtra, UP, WB and Karnataka are implementing HVDS. The 11 th plan should focus on switching over to HVDS system through a suitable investment strategy in a phased manner in order to bring down the HT: LT ratio to 1: 1 from the present estimate level of 1:2.5. Attempts should be made to avail CDM benefits from the scheme Priority to IT Applications There is a need for widespread application of IT in the power sector with a focus on distribution. Ministry of Power has set up IT Task Force with a view to use IT as a strategy to improve commercial and operational performance of distribution and for its effective implementation. Today, a number of utilities are using IT applications to improve their commercial and operational performance. However, adoption of IT as a tool for automation and efficiency improvement is sporadic and lacks focus. There is a wide variation in the states in application of IT tools. The Task Force recommended creation of comprehensive IT blue print for the Indian power sector that incorporate the global best practices. The task force suggested a 3-5 years IT implementation road map with both short term and long term IT initiatives. In short term, priority should be use of IT in commercial process and in improving the quality of supply in selected areas. The long term area should cover the business process. Asset and work management, outage management and distribution automotive should be implemented in parallel. Material management and support process such as human resource, finance, accounts, should be IT enabled in the phase. The task force also felt that SEBs should also have an effective management information system for decision, support, improved decision making. The committee suggested that implementation should be done by accredited agencies. No concerted effort has been made to implement the recommendations of the Task Force. The Task Force recommendation should be implemented in the 11 th Plan. The electricity Act, 2003,National Electricity Policy and Tariff policy envisage development of Open Access, ABT and Energy Accounting at the state level. These involve emergence of new market mechanisms having complex commercial arrangements. IT application will facilitate implementation of such complex commercial arrangements. Therefore priority should be given to set up IT infrastructure at various levels in the distribution business in the 11 th Plan. The blue print for IT of the utilities should take into account the future market structure, the Page 32 of Chapter 3

276 Distribution Including Village & Household Electrification operational requirement and have IT as a key component of business strategies in the long term business plans. There is need for complete mapping of IT usage in the Distribution Segment of the country. The working group recommends that a comprehensive IT blue print should be prepared and the focus should be on integrated approach to get the best results from the IT applications. Under APDRP, utilities should spend the incentive grant on cost effective IT related solutions in the distribution sector. The states/ utilities that have made significant advance in IT applications should move towards complete integration of various subsystems and for adopting the best international practices. Implementation of IT based billing and collection systems should be introduced to obtain immediate results in commercial loss reduction. A comprehensive Business Process Re-engineering (BPR) of all commercial processes needs to be done to ensure tapping of all revenue leakages and systematic implementation of IT based tools. Many states have employed these tools and gained significant improvements. From customer point of view, customer information is very important which usually includes billing and accounting functions. Priority should be given to improve customer care through IT solutions. Andhra Pradesh has set up 336 customer service centres which handle services such as new service connection, additional loads, name change, category change, line shift, DTR shift, billing complaints, meter problems, broken poles etc. The cost of one CSC to serve 2 lakh customers is 15 lakh one time and Rs.84,000 recurring cost per month. The working group recommends all utilities should set up customer service centres in all the towns on priority. The total urban population of the country as per 2001 census is crores. If we assume that household has five persons, there are 5.67 crore urban households. To cover entire urban population with customer service centres on the lines of Andhra Pradesh, the cost would be around Rs. 42 crores Consumer Indexing and GIS Based Database Geospatial database developed through GIS based Consumer Indexing and asset codification integrated with business processes of utility provides the utility a wherewithal to reengineer business process for transparent and quick decision making process. It helps in addressing metering and billing issues, new connection release, fuse off call etc. under the aegis of customer care centre. Surveyed and validated Feeder overlaid on satellite imagery with landmarks would enable preparation of correct estimated works and consequently faster implementation without contractual litigations. Many utilities have used GIS for improvement in performance. What is required is integrated solutions. In the 11 th Plan integrated GIS mapping and Consumer Indexing should be given priority in all the towns Reliability Monitoring of Power Distribution Systems Normally power is generated at a voltage of kv AC in a power station and stepped up by power transformer to a transmission voltage of 132/220/400 kv for transmission through transmission lines, to a power sub-station near the load centre. Page 33 of Chapter 3

277 Distribution Including Village & Household Electrification In this sub-station, power is then stepped down to 66/33/11 kv level. From this substation, 33 kv/11 kv feeders are laid for supplying power to the high voltage consumers or to distribution transformers, which convert it to medium voltage level of 415 V, for providing service connections to consumers at 415 V (3 phase) or to low voltage consumers at 230 V (1 phase) through a combination of 415 V lines up to the pole and then on through service connections to the consumers by underground cables/overhead cables Reliability Index This is defined as the ratio of Customer-hours available over a given period of time to the total number of Customer-hours that should have been available over the same time period. At present CEA carries out reliability monitoring of power distribution systems of Distribution Companies (Discoms)/State Electricity Boards ( SEBs), in terms of outages of 11 kv feeders, on monthly basis, in respect of State Capitals and major urban agglomerations. The reliability monitoring is based on the following two parameters relating to an outage. Outage indicates all No supply conditions due to grid constraints, planned shut downs and forced shut downs including momentary shutdowns: 1. Outage duration per outage ( in Hours), which is the ratio of total outage duration of the 11kV feeders to the number of outages of 11 kv feeders and indicates the No Supply Duration of an Outage. This is analogous to CAIDI. 2. Number of outages per feeder, i.e. total number of outages of feeders divided by total number of 11 kv feeders, thereby indicating the Average number of Outages of an 11 kv feeder in the system. This is analogous to SAIFI. The reliability monitoring is to be gradually brought in line with the world practice i.e. to measure the outage in terms of consumer hours and number of consumer interruptions. The reliability monitoring will become more fruitful once Consumer Indexing i.e. linking of every consumer to the feeder is completed by all the Discoms/ (SEBs) and will provide a direct index for customer satisfaction Akshay Prakash Yojana Maharashtra Distribution Company has launched Akshay Prakash Yojana (APY). The programme is based on collective responsibility of the inhabitants of the village and is carried out voluntarily for ensuring better quality of supply and other social benefits. The villages are not pre identified and the adoption of APY entirely depends on the initiative and awareness of the persons staying in villages. Under the scheme, villagers voluntarily restrict the use of any 3 phase load during 5 pm 11 pm on week days. Only lighting load is utilized. During 5 pm 11 pm the load is restricted to 20% of full load. Page 34 of Chapter 3

278 Distribution Including Village & Household Electrification Load restrictions are supplemented by removal of hooks and unauthorized heavy consumption devices like heaters and hotplates. Apart from this the scheme envisages adoption of energy saving lighting, pumps and use of capacitors. Surveillance committees for monitoring electricity use (Veej Dakshata Committee - VDC) are formed by the villagers. These committees supervise removal of all unauthorized connections. Patrol are organized by villagers to uncover theft and misuse of power. All the consumers voluntarily adopt metered connections. The villages bodies like Gram Sabhas pass resolutions to carry out the activities required for implementation of the scheme. Awareness levels in villages is the most important factor that enables adoption of APY by villages. Communicating effectively to the villagers that electricity is a scarce commodity and stressing on the need for conservation has been crucial for the success of the scheme. The scheme has support of the top management of the utility and the State Government Programme on Decentralised Distributed Generation (DDG) DDG for village electrification in remote areas and also for overcoming shortage of power. Supplementary Power supply needs are essential for protecting the already created infrastructure under RGGVY. This programme will cater to all such needs. Pilot projects should be set up initially to gain experience and to instill confidence. Thereafter, a National Programme on DDG be launched under the PPP. REC/PFC may introduce reform to result programmes by extending large value, long term loans as the mutually agreed reform conditionality. DDG be offered capital subsidies or viability gap funding under the PPP programme. REC to set up a wing to lay down the specifications / standards for the equipment suppliers. REC/PFC may finance the power equipment manufacture in their modernization and expansion plans. REC/PFC may float a Venture Capital Funds to encourage manufacture of critical quality components used for power infrastructure and provide ready market for such products at competitive rates Mobile vans with GSM connectivity This will enable prompt communication and detection of faults and speedier restoration of supply. Five thousand vans can be inducted to start with. More numbers can be added to have a target of atleast 10,000 such vans in the country in the 11 th plan to start with e- Seva / Bijli Seva Kendra/ Customer Care centre Page 35 of Chapter 3

279 Distribution Including Village & Household Electrification These are tools for better customer service and to bridge the digital divide in the rural areas for providing access through Information technology for services to the people living in rural areas. These type of centres can offer different services like payment of bill/ taxes, registration of complaints, providing of information, booking for connections etc. These kinds of centres can solely be managed by women through self help groups Energy Accounting and Auditing Measurement of technical and commercial losses is the first step in the direction of reducing T&D losses. Energy accounting is essentially a tool for energy management and helps in breaking down the total energy consumption into all its components. Energy auditing would provide the means to identify the areas of leakage, wastage or inefficient use. This would help in identifying high loss areas and measures suitable for reduction of T&D losses. Preparation of an effective energy account will be possible only if: Meters are installed on both sides of each element of the network. All the consumer installations are installed with accurate energy meters. Energy meter readings are taken at sending end and at all the consumer installations. Similar accuracy class meters are installed both for measuring input to system and energy sales. Meters are regularly tested and calibrated. Electronic trivector meters with data logging facilities are provided on the 11 KV feeders/ secondary side of distribution transformers to record load curve which facilitates assessment of load factors and loss load factors. The following energy audits will be essential for targeting loss reduction initiatives: Sub-Transmission system losses Voltage level wise losses Geographical area wise up to smallest Administrative unit loss measurement (/ Zone/ Circle/ Division/ Sub-Division etc. depending on the terminology in use by the utilities) 11 KV Feeder wise losses Distribution Transformer wise losses For proper measurement of losses, metering is very critical. The biggest constraint today is absence of 100% metering at various stages. Though in the 10 th plan there has been significant improvement in metering at consumer level and 11KV level, the metering at Distribution transformer level, which is primary requirement for effective energy auditing metering, is very poor even in progressive states like AP (less than 9%) and Karnataka (24%). Many states have taken various steps for energy audit by providing inter-phase metering but still the proportion of units billed on metering basis as percentage of total energy input is about 50% in most of the states. In Andhra and Maharashtra it is 52 %, in Gujarat and Karnataka it is below 50%, in Rajasthan it is 42% and Punjab it Page 36 of Chapter 3

280 Distribution Including Village & Household Electrification is 54% and in Haryana it is 44% to mention a few important states. Kerala however has 74% metered sales. The high percentage is mainly because of unmetered sale to agricultural consumers. Another issue is replacement and repair of defective meters promptly to ensure proper accounting of energy. It is important to ensure installation of high precision tamper proof electronic meters. Any meaningful energy accounting and auditing is possible only if these conditions are met. The focus of the 11 th Plan should be to standardize energy accounting and auditing practices and incentivising efforts of utilities undertaking complete accounting and auditing exercise. The metering at various levels and providing a code to each consumer will give complete and accurate baseline data. By the end of 11 th Plan Utilities should put in place complete Energy Accounting and auditing practices by ensuring metering at all levels Load Management The current installed capacity in India is around 1,26,800 MW which is inadequate to meet the increasing demand. Today we are having energy and peak power shortage. With targeted annual GDP growth of 8% the energy requirements of the country are expected to go at a higher pace. In this scenario load management is important to ensure supply to feeders feeding critical emergency loads and curtail supply to other loads. Load management will also enable supply of power to higher revenue feeders while curtailing supply to low revenue feeders. It is also critical for system stability. For effective load management, utility should adopt load management at 11 KV feeder level rather than 33 KV feeder level. The distribution automation is a key requirement for load management. SCADA is an important tool for load management. Some distribution utilities have already drawn plans for introduction of SCADA. Hyderabad city is now fully controlled through SCADA system. SCADA also helps in fault localization, facility management and trouble call management. In the 11 th Plan all the million plus cities (27) should be covered under SCADA. The cost per introduction of SCADA in Hyderabad was Page 37 of Chapter 3

281 Distribution Including Village & Household Electrification estimated Rs. 40 crores which has a population of lakhs as per 2001 census. If we introduce SCADA in all the million plus towns, the total fund requirement would be around Rs.1000 crores. Other tools for load management such as microprocessor based load limiters to restrict supply to agricultural feeders and Automated Meter devices to monitor feeder, DTR or consumers for consumption curve analysis should be encouraged NEW PROGRAMMES/SCHEMES FOR 11 TH PLAN Special Scheme for Urban Poor In the urban areas people below poverty line live in slums census has provided slum demography based on actual count. It is based on areas notified as slums by the state / local Government, recognized as slums by state / local Government and those areas which have at least population of 300 living in congested tenements in poor living conditions. As per the Census 640 cities/towns in 26 states/union territories have reported slum population. Andhra Pradesh has the largest number of towns (77) reporting slums followed by Uttar Pradesh (69), Tamil Nadu (63) and Maharashtra (61). A total of 42.6 million Population live in slums. This constitutes 15 per cent of the total urban population of the country and 22.6 percent of the urban population of the states/union territories reporting slums million Slum population has been reported in the 27 cities with million plus population. Most of the slum dwellers are living below poverty line and can not afford the initial cost of electric connection. There is need for a special scheme to provide assistance to the urban poor. Most of the people in slums are living in unauthorized colonies. There are 4.62 crore slum dwellers. Assuming that the average family size is five the total households will be lakhs. If we assume that fifty percent of them do no have electricity in their dwelling units the total targeted households for providing free electric connection will be lakh households. At the present rate of Rs 1500 per household connection as per RGGVY norm, the total cost for providing free electric connection along with a meter will be Rs 693 crores. The Working Group recommends that a special scheme should be introduced in the 11 th plan to provide 100% subsidy for the urban poor for electric connection. The scheme should cover all those families living in regularized colonies and in the houses provided under Valmiki Ambedkar Awas Yojana (VAMBAY) scheme of ministry of urban employment and poverty alleviation One MW Power Plants for Distribution of Electricity in the Rural Area Rural areas have been recognized as distinct entity in the Electricity Act, 2003 for electricity supply. More than 70% of the population lives in rural areas and very large part of the rural population are without access to electricity. There is wide regional variation among the states regarding access to electricity. The Electricity Act mandates the Government to endeavor to supply electricity to all areas including villages and hamlets. The important provisions relating to rural supply are : Section 13 license exempted for any local authority, Panchayat Institution, users association, cooperative societies, non-governmental organizations and franchisees to supply in the rural areas. Page 38 of Chapter 3

282 Distribution Including Village & Household Electrification Section 14 - No license required to generate and distribute in a notified rural area. Rural areas to be notified by the State Government. Most of state government have delayed in notifying rural areas. However the redeeming feature is now most of the state governments have notified rural area. Now the efforts have to be made to promote generation and distribution of electricity in the rural areas by private enterprises and other bodies. To start with power plants with optimum one MW capacity should be encouraged in the rural areas. In line with Rural Electrification policy these projects should get automatic approval for land use change pollution clearance, safety clearance on the basis of certification. They should also get priority for grid connectivity if requested. REC should frame schemes for promoting optimum 1 MW power plants for providing necessary technical and financial support. Suitable subsidy has to be built into the scheme to make it attractive and viable. Efforts should be made to align these schemes with Waste Land Development schemes of Rural Development and Forest and Environment Ministries to ensure coordinated approach Centres of Excellence for Distribution of Power The Electricity Act has opened new avenues for bringing private participation in the distribution sector. The proviso to Section 14 of the Electricity Act states that: in a case where a distribution licensee proposes to undertake distribution of electricity for a specified area within his area of supply through another person, that person shall not be required to obtain any separate license from the concerned State Commission and such distribution licensee shall be responsible for distribution of electricity in his area of supply Accordingly, a person who undertakes the distribution of electricity for a specified area on behalf of the Distribution Licensee will not be required to obtain any separate license from the concerned State Commission. Legal frame-work is in place for variety of actors to participate in electricity distribution business. There is a need for setting up centres of excellence for distribution in various parts of the country. These centres should be provided complete support to emerge as models for other intending players in electricity distribution, particularly in the rural areas. Today, REC is the nodal agency for implementing RGGVY scheme. REC has a long experience in financing and providing other technical support to the state utilities in the rural sector. REC is in a sound financial position with a paid up share capital of Rs.780 crores and net worth of Rs.3779 crores and it figures among the top ten PSUs in the country. The business per employee ratio of REC is crores and it has paid highest dividend of 30% during REC s contribution in village electrification is well known. It has contributed for electrification of more than 5 lakh villages and energisation of 143 lakh pumpsets. Cumulatively, Rs.44, 550 crores disbursed under REC financed schemes up to 31 st March To capture the new opportunities, REC should play a major role in electricity distribution business. The Committee recommends that REC should set up centres of excellence for distribution in all the states to take up Page 39 of Chapter 3

283 Distribution Including Village & Household Electrification rural distribution by setting up a subsidiary company. In the 11 th Plan 500 such centres should be set up GRICULTURE SECTOR - SUBSIDIES AND CROSS SUBSIDIES Agricultural consumption constitute substantial portion of consumption of electricity. The tariff for agriculture consumers is one of the most contentious issues. In the prereform period, State Government determined virtually all tariffs to be levied by the state owned vertically integrated State Electricity Boards even though legally, utilities were empowered to determine their own tariffs. Agricultural tariff is politically sensitive in nature. As a result, most of the State either heavily subsidize agricultural consumption or provide free power. More than 23 percent of total energy sale of the utilities goes to Agricultural consumers. It is estimated that against average cost of supply of Rs. 3.60/KWh for energy made available to the consumers, average price of Electricity to Agriculture consumers is barely 42 Paise/KWh. Cross Subsidy on energy sales has been increasing over the years because of the policy of the some of the states to provide electricity at subsidized rates to agriculture and domestic consumers. While some state governments partly compensate the SEB s for the subsidized sales of electricity to agricultural and domestic sectors, others do no provide any compensation at all. It is recovered through the cross-subsidy mechanism. Subsidy to agricultural consumers will continue to be the major issue in the sector as it has political implications. Since subsidies are likely to continue in the near future, the focus should be on efficient administration of subsidies by using prepaid metering technologies including smart cards to provide life line energy to the poor section. The subsidies should be administered by the irrigation or agriculture departments of the states WATER ENERGY NEXUS Efficient use of water in Agriculture could result in considerable saving in energy. The agriculture sector in India uses 85% of the country s available fresh water. However, irrigation efficiency is only 20-50%. In other words, Indian agriculture Page 40 of Chapter 3

284 Distribution Including Village & Household Electrification wastes up to half of the country s fresh water supply. Although from a basin perspective, much of the wasted water is reused, significant amount of water is wasted primarily due to irrigation inefficiencies. There are inefficiencies on the energy front as well. Agriculture accounts for about 24% of the total electricity consumption in India. The consumption is somewhat higher in the states like Andhra Pradesh, Gujarat, Madhya Pradesh, Uttar Pradesh, Karnataka, and Haryana, where agricultural electricity use is between 35-45%. However, sale of this electricity amounts to no more than 5-10% of the state electricity boards revenues. The adoption of flat rate pricing for agricultural power is cause for this perverse state of affairs. Under this system, a farmer pays a fixed price per horsepower per month for electricity. Therefore the marginal cost of pumping water is zero. This leads to energy wastage, over-pumping and inefficient selection of crops. Flat rate pumping also masks the true cost of power to farmers. The tariff structure and the poor combination of technology and management are responsible for water loss, unsustainable exploitation of groundwater and the high energy losses associated with the distribution and end-use of electricity in irrigation water pumping. Significant energy losses are associated with the distribution of electricity and in the poor selection, installation, maintenance and operation of the electrical motor pump system. A vicious cycle operates two sub-systems in tandem: the electrical distribution system and the water pumping system. The performance of the Indian power sector is increasingly dependent on how efficiently irrigation water is used and paid for. Water withdrawal is an energy intensive operation performed throughout the agricultural sector that results in a third of the power consumption in the country being used for the roughly 50% of the national irrigation consumption extracted from groundwater resources. Highly subsidized power supply policies for agriculture have major implications for the overall condition of the power sector and associated water resource. The level of attention paid to water use efficiency is directly proportional to the prices charged for water servicing. Rising prices lead to increasing attention to water use and, in the long run, more efficient use of water. Addressing water and energy use efficiencies in the Indian agricultural sector requires a strategic combination of several interdependent components. There has to be central and state policy dialogue on power and water sector reform to develop an energy and water framework. Commercial practices have to be introduced in rural power distribution in order to expand the domain of power planning beyond the customer side of the electrical meter to encompass the water well, the exploitation and recharge of aquifers and the management of the watershed as a whole. It is also essential to involve the rural consumer in partnership to advance energy and water use efficiency, thereby improving reform prospects. The approach paper of the planning commission for 11 th plan indicates a growth of 4% in Agriculture from 2% at present. This would mean large scale exploitation of irrigation potential. Special efforts are needed for better utilization of ground water potential especially in U.P., Uttaranchal, Jharkhand, Bihar, Orissa and West Bengal. Page 41 of Chapter 3

285 Distribution Including Village & Household Electrification In areas where level of ground water exploitation is nearing saturation point or where there is a need for conservation of power and water, a new approach is called for. Fixing the quantum of water required for raising crops in relation to areas cultivated, power needed to draw out ground water from varying depths could help set standards in conservation of water and power. There is a case for levy of a combined charge for water and power to secure water conservation and energy use efficiency. The priority sector status available to REC for the energisation of Agricultural pumpsets etc was recently withdrawn which should be restored in order to enhance the pumpset energisation programme during the 11 th plan to at least 35 lakh pumpsets. Diesel pumpsets presently being utilized should be substituted by biofuels so that use of diesel is avoided. The bio fuels can be produced locally and a road map may be set up by the States for cultivation of Jatropha or other plants for producing biofuels for substitution which are renewable and environment friendly. CDM benefits could also be claimed. Feeders for Agriculture should be separated and to counter the inductive loads, capacitor banks may need to be installed. Feeder separation would allow regulation of operation hours of the pumpsets. The subsidy extended on Agricultural tariff should be fully compensated by the states. Free power if extended by the states should target small and marginal farmers only. The Agricultural pumpsets should be of international standards with focus on energy efficiency and the benchmark standards of the indigenous equipment should be raised accordingly and use of the same to be made mandatory/ obligatory wherever free power or subsidized power is made available. Relaxation may be permitted only if the consumers are ready to pay a suitable minimum tariff. In the Agricultural Sector, the pumpsets of high quality and the water delivery system engineered for high efficiency would be promoted Motors and drive systems are the major source of high consumption in Agricultural and Industrial sector. Stringent check on the pumpset installation, sealing of the units installed and strict penalties may bring discipline in this sector. This would call for utmost political will. Command area development using drip and sprinkler irrigation for water management should go hand in hand with the pump sets energisation policy of the States OPEN ACCESS IN DISTRIBUTION The two critical areas for private sector investment are open access and multi-year tariff principle to give certainty to tariffs principles. Open access in distribution has not materialized though regulations have been issued by SERCs. Multi-year Tariff which has been provided in the Electricity Act would be an important structural incentive in minimizing risk for utilities and consumers. Access to transmission and distribution network is one of the most important elements of Electricity Act 2003 and National Electricity Policy At the retail level that consumers with a minimum requirement of 1 MW are to be granted the right to avail open access by 2009 in a phased manner. A consumer allowed open access Page 42 of Chapter 3

286 Distribution Including Village & Household Electrification under the regulations is therefore free to choose any electricity supplier other than the distribution licensee of its area. Competition in Generation and Distribution can be successful only through the access to the Transmission and Distribution networks. The provision of open access would allow generating companies to sell directly to multiple distribution and trading licensees and to the consumers. This will enable development of power market with participation from multiple buyers and sellers in competitive environment. Electricity Act 2003 makes open access mandatory. It has also been envisaged that the amount of cross subsidies charged and additional surcharge to be levied from consumers who are permitted open access should not become so onerous that it eliminate competition. It is important for open access that the distribution network is adequate. The current state of distribution system which often operates at low frequencies limits operation of Open Access. The upgradation and augmentation of the grid is therefore necessary. Though distribution licensees have an obligation to provide non-discriminatory open access to the network, there is no obligation on the licensees to expand their network capacity to accommodate demands. Under the Electricity Act, the Regulatory Commission s role is to develop regulations permitting open access, to determine commercial parameters such as charges for wheeling of power and surcharges applicable to open access customers and to resolve any technical disputes on availability of transmission capacity. In order to meet the rising demand for electricity, especially from industrial consumers, the Act provides incentives for captive and cogeneration plants. Captive power plants are given open access to transmission and distribution lines to carry power from the captive generating plant to the destination of their own use without the payment of surcharge, which is to be paid by other open access users as provided in the Act and used to meet the cost of cross-subsidies. The major issue in making open access operational is the level of cross-subsidy and other charges applicable to open access consumers. If the charges are set at a level which works out expensive than the grid tariff the whole purpose of providing open access will be defeated. Another factor that influence price of power through open access is the rate at which power is available from the generators. Even if various charges are set at higher level, the consumers may be able to get power supply at a competitive price from a cheap source and find it cheaper than the tariff of the licensee MULTI-YEAR TARIFF The system of cost plus approach for tariff determination has not been very effective in providing the utility with adequate incentive to improve its performance. Cost based approach provides a rate of return to SEBs/Utilities based on costs that include inter-alias, fuel and power purchase, investments in the network and energy losses. In this system SERCs found it difficult to arrive at appropriate level of energy losses that could be allowed as part of tariff fixation process which is done annually. The main draw-back of this approach is uncertainty of tariffs. Performance based regulation through Multi Year Tariff (MYT) framework, is an important incentive to minimize risks for utilities and consumers, promote efficiency Page 43 of Chapter 3

287 Distribution Including Village & Household Electrification and rapid reduction of system losses. It would also bring greater predictability to consumer tariffs by restricting tariff adjustments to known indicators. Multi-year tariff provides regulatory certainty on cost of tariff which is essential for investor interest in utilities. Electricity Act 2003, National Electricity Policy and National Tariff Policy envisages introduction of Multi-year tariff framework. As per Tariff policy, MYT framework is to be adopted for any tariffs to be determined from April 1, The MYT framework covers capital investments and an incentive framework to share the benefits of efficiency improvement between the utilities and the beneficiaries. One of the challenges before the regulators is the determination of efficient targets for the utilities as part of performance based tariff setting. Another problem regulator faces is obtaining accurate historic data and information regarding utility operation. The key issues in MYT approach is determination of key parameters to be monitored for programme and the constraints in determining an efficient level of operation for utilities. In the public utilities the question arises as how to motivate the management for improving performance in performance based approach. Another question is how the quality of supply provided to the consumers should be factored into performance based framework for regulation. Benchmarking should be properly adopted after adequate studies to establish the desired performance standards. Regular review of the performance levels also need to be suitably undertaken. Subsidies in the tariff given by the State Governments should be fully compensated upfront instead of cross subsidies PUBLIC PRIVATE PARTNERSHIP Development of power sector requires large investment that can not be met solely by public finance. Electricity Act 2003 has provided a legal frame-work to attract private sector participation in the power sector. However, the present conditions prevailing in the power sector, particularly in the distribution segment are unlikely to attract private investment unless reform pace accelerates. In this context, the distribution sector should focus on public private partnership model for resource mobilization and efficiency gains. The strengths of both public and private sector should be combined to achieve the ambitious goals set in the National Electricity Policy. A private participation could help to bring technical and managerial expertise for improving operating efficiency and customer orientation, besides supplementing the efforts of the Government to invest in the sector. A public private partnership is already emerging in the form of franchisees in rural areas where villages have been electrified under Rajiv Gandhi Grameen Vidyutikaran Yojna (RGGVY). But, on a larger scale, to meet the huge investment and efficiency gaps in the distribution sector, there is a need to create right environment for public private partnership in the 11 th Plan. The State Government should provide necessary ground for smooth implementation of public private partnership. For this necessary legal and regulatory frame-work should be designed. Since distribution sector is exclusively within the purview of the State Government, a strong political support is necessary for introducing PPP model in the distribution sector. State Governments support is also required in aspects such as law and order, land acquisition, Page 44 of Chapter 3

288 Distribution Including Village & Household Electrification rehabilitation and resettlement, shifting of utilities and forest and environment clearances. In the distribution sector, the availability of information and huge gaps in data is a major challenge for promoting public private partnership. The major issue in promoting PPP model in power distribution sector is the commercial viability due to high subsidies to certain categories of consumers which at present the State Governments are not able to fully compensate to utilities due to their poor finances. Consensus building is also vital to the success of PPP. It is important to mobilize support from all the stakeholders for effective implementation of PPP models. A clear path has to be laid addressing various issues in successful implementation of PPP model in the power distribution. The risks to the private players and the utilities have to be clearly identified and allocation of risks has to be done in a rational and the contractual document should suitably incorporate them. In the 11 th Plan efforts should be made to introduce PPP model in major urban areas along with surrounding rural areas in the proximity. The State Government should be encouraged to implement PPP in select towns. The model for PPP should learn from successful PPPs like NDPL of Delhi IMPACT OF POWER SECTOR REFORMS SUCCESS STORIES Andhra Pradesh Andhra Pradesh has been in the fore-front of power sector reform. It has achieved significant improvements in transmission & distribution loss reduction and brought about significant improvements in the functioning of power sector. Transmission & distribution losses have reduced by about 12% in the last five years and collection efficiency has increased to 100% level which helped in financial turn around of the sector in the year Andhra Pradesh is consistently campaigning against theft and initiated strict action against theft cases. In the financial year 2003 more than one lakh prosecutions relating to theft of electricity were done. Similarly, in the year 2004 about 90,000 prosecutions have been done. Distribution transformer failure rate have substantially reduced from 29% in 2001 to 11% in Karnataka Karnataka has also reduced losses from 38% in the financial year 2000 to 31% in Collection efficiency has improved from 91% in the financial year 2002 to 99% in the financial year The financial health of the Corporation has improved with a decline in revenue deficit per unit from 109 paise to 73 paise. Orissa In Orissa the trend of T&D losses is towards reduction for all the Discoms. It varies from 41% to 36% in the case of WESCO, 44 % to 41% in the case of NESCO 42% to 40% in the case of SOUTHCO and 45% to 40% in the case of CESCO from the year 2000 to Page 45 of Chapter 3

289 Distribution Including Village & Household Electrification Delhi NDPL Experience Aggregate technical and commercial losses have reduced and collection efficiency has reached 100% after privatization of Delhi Discoms. The losses have reduced from 51% to 35% from 2002 to Similarly, the collection efficiency has gone up from 92.80% to % during the same period. Other states have also started showing improvement due to number of initiatives at various levels BEST PRACTICES Certain actions are required as a prerequisite for attaining the AT&C loss reduction which have given the best results. List of such best practices which can be adopted across the country are listed below: 1) Consumer Indexing 2) Assets Codification 3) GIS mapping & integrating GIS with other business process 4) Spot billing 5) Automated Meter Reading 6) Meter reading through computerized meter reading instruments 7) Web based billing & collection 8) Online collection for depositing bills at any counter 9) Collection through ATM equipments 10) Online payment through credit cards 11) Cheque drop boxes 12) Preventive Maintenance 13) Overhead/underground routine maintenance 14) DTC maintenance 15) Turn Key execution 16) Project Management Teams 17) Quality Management through ISO/TQM 18) S/stn.Data logging/scada/dms 19) Online Material Management & Inventory Management 20) Out sourcing of O & M activities 21) Rural franchisee. 22) HVDS 23) 100% metering 24) Energy accounting & auditing 25) Theft control 26) Management Information Systems. 27) Identification & monitoring through Key Performance Indicators 28) Call Centers 29) Customer Facilitation Centre Out of the above list the best practices adopted by some of the states utilities are given below. All these states have been successful in reducing the AT&C loses. Page 46 of Chapter 3

290 Distribution Including Village & Household Electrification Best Practices ANDHRA PRADESH (AP DISCOMS) 1) Consumer Indexing 2) Key Performance Indicators (KPIs) for monitoring performances 3) GIS mapping 4) Automated Meter Reading 5) Meter reading through computerized meter reading instruments 6) Collection through computerized meter reading instruments 7) HVDS 8) 100% DTC metering 9) MIS System 10) SCADA 11) Call Centre 12) Customer Care Centre 13) Spot billing Best Practices NEW DELHI (NDPL) 1) HVDS 2) Capacitors 3) Standardization of cable sizes 4) GIS mapping 5) Distribution automation 6) Use of planning software tools 7) Electronic meters 8) Customer Care & Cash Collection Centers 9) Mobile Maintenance crews 10) Mobile Transformer unit 11) Replacement of Cable: Ring Mains Unit 12) Use of Package Sub-stations 13) Meter Installations: Outsourced 14) Computerisation of all activities 15) Commercial wing separate from maintenance wing 16) Sampark Communication with Consumer. 17) Sarthi communication with employers 18) Automated Meter Reading (AMR) Best Practices KARNATAKA (BESCOM) 1) Energy Accounting at DTC level with synchronized meter reading schedule 2) System improvement work 3) 11kV and LT re-conductoring 4) Rural load management system 5) HVDS 6) Gram Vidyut Pradinithi 7) Distribution of CFL lamps in DSM program Best Practices RAJASTJAN (Jaipur Vidyut Vitaran Nigam Ltd.) 1) Creation of more 33 kv Sub-stations 2) Renovation of existing 11 kv feeders 3) Establishment of Consumer Grievance Redressal mechanism Page 47 of Chapter 3

291 Distribution Including Village & Household Electrification 4) Releasing new connections within time frame 5) Reduction of AT & C losses 6) HVDS for rural areas 7) Energy metering of 100% consumers 8) Meters mounted on base of meter boxes & cover having push fit arrangement after making electric connections 9) Meter box to have number seal Best Practices CESC Limited (West Bengal) 1) Development of consumer database with pilferage history and ongoing IT based monitoring of their consumption pattern. 2) Installation of meter pillar boxes in pilfer-prone pockets. 3) Blocking of service cutouts and installation of cutout less service with MCCBs. 4) Holographic seal and imported ferrule seal on all meters. 5) 24 hours monitoring and surveillance by Loss Control Engineers against theft/pilferage of electricity particularly through night drives. 6) IT based surveillance against theft and pilferage of electricity. 7) Meter reading of all the HV & CT operated MV meters by computerized meter reading instrument. 8) Monthly meter reading and billing of 100% consumers with rotation of meter readers in each cycle. 9) Energy auditing and accounting in MVAC distribution transformers through Automated Meter Reading (AMR). 10) Very high collection efficiency with intensive follow-up for outstanding realization. 11) Fully computerized consumer indexing system (CIS). 12) Documented maintenance and operation practices with ISO certification for Distribution Office Operation. 13) Extensive training facility at distribution training institute to hone up the technical skills and impart the training on best practices to ground staffs, supervisory level and Engineer / Sr. Engineer level. 14) Diagnostic fault analysis to prevent recurrence. 15) Installation of Compact Sub-stations with Gas-insulated Switchgears. 16) Fully mobile maintenance crews with mobile communication equipment operating round the clock. 17) GIS covering of HVAC & MVAC network. 18) Integration between Commercial and Engineering database with ERP software. 19) Fully integrated 1 GBPS intranet optical fiber communication backbone network. 20) Application of Six Sigma for improvement of operations. 21) Structured Grievance Redressal Mechanism with computer aided monitoring. 22) Unified Call Centre operation for all supply related complaints. 24 hours help desk for all consumers. 23) Dissemination of consumer awareness messages at regular intervals along with the consumption bills and periodic visits to target segments. Page 48 of Chapter 3

292 Distribution Including Village & Household Electrification THRUST OF THE 11th PLAN IN DISTRIBUTION AND RURAL ELECTRIFICATION Urban Areas EXPECTED OUTCOMES 1. Consumer Indexing towns 2. House holds will have access to electricity - 100% (Including urban poor) 3. Development of PPPs Major towns 4. Customer Care Centres to cover all urban consumers - All towns 5. SCADA in - 27 cities 6. IT usage - all Towns Rural Areas 1. Villages to be electrified - 100% 2. Households will have access to electricity -100% 3. One or more 33/11 kv ( or 66/11 kv) substations in every Block 4. One or more Distribution Transformers in every village 5. SC/ST bastis to be electrified - 100% 6. BPL households to be electrified -100% 7. Schools, Panchayat offices, health centres, dispensaries, Community centres to be electrified - 100% 8. Street Lights in every village - 100% 9. DDG schemes through grid inter connections Nos. 10. Setting up e-seva centres/ customer care centres Nos. 11. Direct employment generation - 1 million 12. Development of Franchisees - 2,50,000 villages 13. Centres of Excellence in rural distribution Losses 1. Reduce AT&C losses - up to 15-20% Urban Areas - 15% Rural Areas - 20% Feeder separation in states which consume high energy for agriculture for improved load management & proper accounting. Improved T&D network in all NE states Introduction of HVDS system to bring down HT:LT ratio Energy Accounting & Auditing In all Utilities. 2. Metering all feeders - 100% all distribution transformers - 100% all industrial consumers - 100% domestic consumers -100% Page 49 of Chapter 3

293 Distribution Including Village & Household Electrification prepaid metering system pilot projects in all states for rural areas and urban areas. Energisation of Pumpsets 1. Agricultural Pumpsets to be energized - 35 lakhs Turnaround Targets for State Utilities 1. Reform process and perceptible turnaround of State Utilities - 50 utilities 2. Energy Conservation and Demand Side Management on Priority Time of the Day metering - 15 States Management 1. Public Private Partnership Towns & Cities Villages - 2,50, Inclusive growth Supervisory role for all gram Panchayats/ local bodies Other Reforms 1. Open Access operational In all states 2. Multi Year Tariff In all states 3. Integration of IT applications In all states Human Resource Development 1. Human Resource Development Upgrading CIRE Hyderabad into National Training Centre for distribution related activities. 2. Establishment of Training centres for capacity building20 state level 115 district centres A. The requirement of funds for sub transmission and distribution have been worked out on the following assumptions: 1. The total capacity addition planned during 11 th plan has been taken as 70,000 MW and the transformer capacities have been worked out on that basis for an appropriate system with proper loading pattern. 2. The total line length adopted is based on the actual progress achieved up to and the rate of growth per year to estimate the likely achievement in 10 th plan. The quantities have been increased by over 10% for the 11 th Plan. 3. Since access has to be provided to all households has been taken for estimation purpose. Similarly other quantities have been assumed. 4. The costs adopted in various states are different under various schemes and as such a reasonable cost has been assumed also keeping in view escalation over next five to six years. B. Under APDRP balance amount has been estimated at Rs crores at the end of 10 th plan. Agricultural pumpsets connections for about 35 lakhs pumpsets have been Rs /- per pumpsets including additional infrastructure requirements. Accordingly, a provision of Rs crores has been estimated. Page 50 of Chapter 3

294 Distribution Including Village & Household Electrification C. A total of 4000 MW under DDG has been Rs. 5 crore/ MW and accordingly the estimate worked out to Rs crores. D. Reforms process is to continue during the 11 th plan and a suitable provision has been considered for transitional finance. A modest provision of Rs crore has been kept accordingly. Table 3.6 Sl. I Name of Segment Units Physical Financial (Rs. Lakhs) Lines (i) 33 KV Ckt Kms (ii) 11 KV Ckt Kms (iii) LV Ckt Kms II Sub-Station (i) 33/11 KV MVA (ii) 11/0.4 KV MVA III Capacitors MVAR IV V Service Connections to (i) Domestic Installations Nos (ii) Commercial Installations Nos (iii) Industrial Installations (a) HT Nos (b) LT Nos (iv) Public Light Nos (v) Agriculture Nos Total (I to IV) A. Reconductoring of Lines (i) 33 KV Ckt. Kms (ii) 11 KV Ckt. Kms (iii) LV Ckt. Kms Total V (A) B. Augmentation of S/Ss (i) 33/11 KV MVA (ii) 11/0.4 KV MVA Total V (B) Total (V) Grand Total Page 51 of Chapter 3

295 Distribution Including Village & Household Electrification 3.26 REQUIREMENT OF FUNDS Table 3.7 Rs. Crore 1. Sub Transmission & Distribution for Urban & 1, 97,000 Rural areas RGGVY 40,000 2, 37, APDRP & Other Schemes (pumpsets etc.) 40, Decentralised Distributed Generation 20, Others 10,000 TOTAL 3,07, RECOMMENDATIONS APDRP 1. APDRP should be continued beyond the 10 th plan and all the recommendations made by the Task Force under the Chairmanship of Shri P. Abraham, Chairman, MSPGCL need to be implemented. 2. APDRP should mainly focus on Class 1, 2 and 3 towns comprising of total The 11 th Plan should target at reducing AT&C losses to 15% in 1000 (first three categories of towns.) 4. In order to give the push to the APDRP programme like in case of RGGVY, REC should be made the nodal agency. AT&C Losses 1. Development and Implementation of Distribution System Plan should be regularly pursued. 2. The following steps are required to be taken for reducing the AT&C loss level : I. Introduction of new and improved materials and equipment (e.g. AAA conductors, amorphous core transformers, gas insulated switchgear, Arial Bunched Cables, better quality joints, SF6 Breakers etc.) II. In order to move ahead with the implementation of anti-theft regulations the State Governments need to set up Special courts, Special Police Stations and appoint assessing officers and compounding officers. III. Introduction of High voltage distribution system (HVDS) and installation of large number of lower capacity distribution transformers at the consumer load centers. IV. Installation of capacitors to improve power factor/ voltage profile and to reduce energy losses in the system. V. Installation of Electronic Meters (with AMR for 15 KVA & above consumers) for all consumers including Agricultural connections and Street lighting points. VI. The utilities need to increase enforcement activities, deploy adequate flying squads, carry out timely meter testing, conduct downloaded meter data analysis, conduct new connection camps in theft prone areas, Metering in Page 52 of Chapter 3

296 Distribution Including Village & Household Electrification Pillar Box based systems and conduct awareness campaigns in targeted areas. Energy Audit and Accounting & GIS 1. The focus on the 11 th Plan should be to standardize energy accounting and auditing practices and incentivizing efforts of utilities undertaking complete accounting and auditing exercise and metering. 2. GIS and consumer indexing in distribution system needs to be introduced in all utilities. IT Intervention 1. IT Blue print should be prepared and focus on integrated approach to get the best results. 2. Installation of SCADA and distribution automation is to be taken up in all major cities/towns. 3. Improvement in billing by using modern meter reading technologies (AMR, CMRI etc.), billing database correction/ strengthening, and implementation of IT based Billing system. 4. Mobile van with GSM connectivity needs to be introduced in all districts. 5. e-seva Kendra s to be set up in all districts. 6. Customer service centers should be introduced in all urban areas. Reliability Index 1. All reliability indices for quality and reliability of supply should be adopted and measured. 2. Standards of performance to be enforced by SERCs. 3. Proper trouble calls management to be adopted in all States by the end of 11 th Plan. Distribution Reforms 1. Unbundling of SEBs, Privatization of loss making utilities, and handing over of high loss feeders need to be pursued further. RGGVY Programme 2. The programme requires continuous support from all the agencies concerned, with regular flow of funds and constant monitoring to ensure that the envisaged benefits reach the rural masses well before the targeted date. 3. To develop an appropriate Monitoring and Evaluation (M&E) framework with measurable indicators for implementation and long-term sustainability of RGGVY. 4. To benchmark procedures and practices for designing sustainable projects. 5. There is also need to introduce wide spread use of prepaid cards, hand held meters for the spot billing, anti theft microchip devices in meters and metering at distribution transformer level so as to enhance collection efficiency in rural distribution and to reduce theft and pilferage. 6. Use of energy saving lamps e.g. CFL be encouraged. Page 53 of Chapter 3

297 Distribution Including Village & Household Electrification Franchisee Development 1. Various avenues for financial support to franchisee which should include financial support from rural banks, cooperative banks and other financial institutions. 2. Loans given to franchisee can be refinanced by Apex bank, NABARD and model schemes could be developed in consultation with RBI in order to encourage wide spread participation by lending community. 3. Rural Infrastructure Development Fund (RIDF) of NABARD provides funds to States for infrastructure development purposes. Franchisees should be given funds from RIDF at a concessional interest rate, for financing expenditure involved in collection of bills, O&M etc. 4. Micro-financing agencies nowadays are providing small loans to the tune of around Rs. 20,000/- without security. These agencies may be empanelled and made known to franchisees so that whenever they require funds they can approach these agencies. 5. Corporate sector can play an important role in handholding the franchisees. Not only power sector CPSUs, which have network all over the country but also corporate leaders like Infosys, Wipro, Reliance, HLL, L&T etc. be encouraged to help SHGs in the development of franchisees. Capacity Building 1. It is essential that institutes are identified at Central and State level for undertaking capacity building in a systematic manner. 2. Proper human resource development and capacity building requirements to be given special attention for a sustainable development. Decentralized Distributed Generation 1. DDG scheme implementation should be taken up on a mission mode. Stand Alone 2. Stand alone projects up to 1 MW size to be implemented by MNES through NTPC, IREDA or other agencies by setting up Joint Ventures. 3. The funds available under RGGVY can be utilized for such stand alone schemes with a capital subsidy. Grid Inter Connected 4. Grid Interconnected Schemes to be implemented for supplementary power needs. These schemes may be up to 5 MW capacity. 5. Corporate Agencies may take up such grid interconnected DDG schemes on competitive bidding basis. Public Private Partnership to be encouraged. Viability Gap funding may be adopted. Cost 6. Cost of electricity should be based on cost to serve/ avoided cost. Technologies 7. All available commercial technologies (both conventional and non conventional) may be utilized. 8. Suitable standard size packs may be used in order to reduce production costs. Page 54 of Chapter 3

298 Distribution Including Village & Household Electrification 9. Multi-fuel technologies may be adopted for sustainability of DDG projects. Biomass Plantation 10. Biomass cultivation and development of short duration (cycle) high yielding varieties of biomass for combustion/ gasification/ bio-fuels be encouraged with minimum support price. 11. Financial Institutions should support bio-diesel plantations, consultancy, R&D, DPR preparation etc. Policy Issues 12. DDG projects should be exempted from income tax, excise duties or customs duties or accelerated depreciation benefits be provided. 13. All concessions extended by States for Industrial development may be given for DDG projects. 14. Clear allocation of power for rural areas be ensured, so that there is no discrimination in the hours of supply between rural and urban areas. 15. A separate Rural Electricity Agency (REA) may be considered for each state to look into needs of rural areas. 16. The State Govts., State Utilities/ Discoms and Local administration should create proper enabling atmosphere to encourage DDG projects. 17. Priority Sector lending status and long term loans up to 25 years through International Agencies may be provided for DDG projects. Survey 18. Urgent need for comprehensive survey of available resources in each village should be taken and be completed in eighteen months. R&D 19. R&D on fuel cells, efficiency of other existing systems etc be encouraged by extending financial support or Income Tax benefits. 20. Improvement in quality and life of batteries is very essential; R&D is required in this area. Capacity Building 21. Suitable capacity building measures be adopted like training of local youth in the maintenance of DDG equipment at local levels. Nodal Agency 22. REC should act as Nodal Agency for Grid Interconnected DDG schemes and Survey of villages. Other issues 23. All subsidies to be based on outcomes and not outlay. 24. Carbon Credit benefits to be utilized by use of DDG projects. 25. The electricity should be provided through Rural Electricity Supply Providers/ franchisees. Local Management & Monitoring Page 55 of Chapter 3

299 Distribution Including Village & Household Electrification 26. District Committees be strengthen & empowered suitably. Local Institutions like Panchayats, NGOs, Cooperatives, SHGs may be activated to coordinate or participate in the DDG projects. Other Issues on Distribution Open Access 1. Open access in distribution should be fully operationalised including phasing out cross subsidy surcharge by end of 11 th plan. Tariffs 2. Multi year tariff framework to be adopted by all states. 3. Benchmarking for MYT should be properly adopted after adequate studies to establish the desired performance standards. Regular review of the performance levels also need to be suitably under taken. 4. The subsidy for agriculture needs to be reduced in line with the National Electricity Policy to a level of + 20% of average cost of supply by However, it needs a strong political will. 5. Combined tariff for electricity and water may need to be considered for judicious use and conservation of both. Agriculture 6. Mandatory/ obligatory requirement to be made for international standard Agricultural pumpsets based on least energy requirements. 7. Command area development using drip and sprinkler irrigation for water management should go hand in hand with the pumpsets energisation policy of the States. 8. Diesel pump sets should be replaced by non-conventional sources of energy including bio-fuels. 9. Agriculture Feeder separation programme to be launched. 10. Agriculture consumers to be metered. Other Issues 11. The priority sector status available to REC for the energisation of Agricultural pumpsets etc was recently withdrawn which should be restored in order to enhance the pumpset energisation programme during the 11 th plan to at least 35 lakh pumpsets. 12. Wherever applicable Carbon credit benefits be obtained. 13. India must improve their equipment standards by raising the benchmark levels to that of international standards in order to reduce technical losses and no. of outages. New Programmes for Introduction in the 11th Plan In order to implement various recommendations there is a need to adopt comprehensive schemes on the following besides continuation of APDRP and RGGVY. 1. One Megawatt Power plant Programme for Rural electricity supply 2. Setting up of Centres of Excellence for Rural Distribution Page 56 of Chapter 3

300 Distribution Including Village & Household Electrification 3. Consumer awareness programme on the lines of Akshay Prakash Yojana of Maharashtra 4. Special Programmes for Capacity Building of franchisee 5. Special Agriculture Pumpset Energisation Programme 6. Special Schemes for Urban Poor 7. Special Programmes for Development of North East 8. Programme on Decentralized Distributed Generation (DDG) for village electrification in remote areas and also for overcoming shortage of power. Supplementary Power supply needs are essential for protecting the already created infrastructure under RGGVY. This programme will cater to all such needs. Pilot projects should be set up initially to gain experience and till instill confidence. Thereafter, a National Programme on DDG be launched including under the PPP model. 9. REC/PFC may introduce reform to result programmes by extending large value, long term loans as the mutually agreed reform conditionality. 10. REC to set up a wing to lay down the specifications / standards for the equipment suppliers. 11. REC/PFC may finance the power equipment manufactures in their modernization and expansion plans. 12. REC/PFC may float Venture Capital Funds to encourage manufacture of critical quality components used for power infrastructure and promote ready market for such products at competitive rates. ********** Page 57 of Chapter 3

301 Demand Side Management & Energy Efficiency Chapter- 4 DEMAND SIDE MANAGEMENT AND ENERGY EFFICIENCY 4.0 INTRODUCTION In rapidly growing economy of India, the energy requirements have been increasing at a very fast pace. Indian economy has been gradually reforming itself with the developments taking place in the dynamic global energy scenario as well as with the advancements in technologies worldwide. The Government of India at the highest level is giving top priority to the attainment of nation s long-term energy security. India ranks 5 th in the world in terms of primary energy consumption, accounting for about 3.5% of the world commercial energy demand in the year The total commercial energy consumption of various sectors stood at 218 million toe ( ).The share of energy by different end-use sectors is given in Figure (14%) 15 (7%) 20 (9%) 26 (12%) 35 (16%) 93 (42%) Agriculture Industry Transport Residential Other energy uses Non-energy uses Figure 1. Sectoral share of commercial energy consumption (mtoe) ( ) If it perseveres with sustained economic growth, achieving 8-10% of GDP growth per annum through 2030, its primary energy supply, at a conservative estimate, will need to grow 3 to 4 times and electricity supply by 5 to 7 times of present consumption. Its power generation would increase to 780,000 MW from a current level of about 120,000 MW and annual coal demand would be in excess of 2000 million tons from a current level of 350 million tons. This extraordinary growth in energy demand will place great stress on the financial, managerial and physical resources of the country. For meeting desired growth rate of the economy, the country faces formidable challenges in meeting its energy needs and in providing adequate energy in various forms to users in a sustainable manner and at reasonable costs. While it is essential to add new power generation capacity as well as ensure availability of substantial commercial fuels to meet the nation s growing energy requirements, it is equally important to look out for options that help in reducing energy demand by various enduse sectors. The need for enhancing energy conservation efforts has become very important. Page 1 of Chapter 4

302 Demand Side Management & Energy Efficiency 4.1 THE ENERGY CONSERVATION ACT The planning process so far has been leaning heavily towards the supply side strategies. Efforts made to implement DSM, energy conservation and energy efficiency measures were symbolic, lacked continuity due to absence of a well knit institutional mechanism at the national and state levels. The 10 th plan period ( ) is marked by enactment of the Energy Conservation Act, 2001 and setting up of the Bureau of Energy Efficiency (BEE) at the national level. The Act has given mandate to BEE to implement the provisions of the Act, and spearhead the improvement in energy efficiency of the economy through various regulatory and promotional measures. Some key activities that BEE is pursuing include the development of energy efficiency labels for refrigerators and other mass produced equipment, certification of energy managers and auditors, assisting industry in the benchmarking of their energy use, and energy audits of prominent government buildings. A beginning has been made by the State Governments in designating agencies to oversee implementation of the Energy Conservation Act and deliver energy efficiency services including through public-private partnership. BEE was provided with a one-time grant of Rs.50 Crores and it utilizes the interest earned on the same to institutionalize energy conservation activities by the Government of India. The Planning Commission in its recent report on an Integrated Energy Policy (IEP) laid out a vision of providing energy security to all citizens. IEP emphasizes energy efficiency & demand side management as essential components of the natural energy strategy. The Group report focuses on operationalizing and implementing the recommendations of the integrated energy policy. 4.2 ENERGY SAVING TARGET AND ACHIEVEMENT OF 10 TH PLAN Energy Conservation Target The 10th Five Year Plan ( ) targeted energy savings of 95 BU(13% of estimated demand) in the industrial, agricultural, domestic and commercial sectors against the expected electricity demand of 719 BU in the terminal year of the Plan i.e The 10th Plan highlighted the need for institutional arrangement to coordinate different programmes on energy conservation. It also stressed the mobilization of resources for funding the energy conservation programs. The 10th Plan however did not provide any specific budget allocation to meet and validate the energy saving targets. ( Planning Commission, Government of India (2006), Report of the Expert Committee on Integrated Energy Policy) Energy Conservation in the 10 th Plan Authentic and updated database is not available due to which it is difficult to assess the potential and achievements made. A rough attempt to assess energy savings achieved during , puts this figure at 1170MW comprising of 508 MW from electric power savings achieved in industrial sector (participating units of National Energy Conservation Award for the years , and 04-05), 181 MW from supply side in Power Sector and 481 MW due to penetration of energy efficient CFL & 36W tube lights. Page 2 of Chapter 4

303 Demand Side Management & Energy Efficiency Authentic and updated database of energy consumption patterns and energy saving potential are not available for majority of the energy consuming sectors. The data availability is limited to a few units/sub-sectors based on some specific studies or interventions and thus can not be extrapolated to arrive at national figures. Such database is vital for providing direction to policy makers and other stakeholders with regard to augmentation of additional capacity requirements in generation and transmission. The centrally available database would also be useful for other stakeholders who are directly or indirectly involved in the end-use consuming sectors (industry, transport, buildings, agriculture). There is a need to develop and implement energy conservation programmes, setting up of energy saving targets and an effective monitoring of energy savings achievements periodically. 4.3 ENERGY CONSERVATION STRATEGY IN THE 11 TH FIVE-YEAR PLAN The basic aim of the energy conservation strategy in the 11 th Five Year Plan will be to prioritize and implement the provisions under the EC Act 2001 by decentralizing the energy conservation programmes at the State level. The strategy will strengthen the existing institutional linkages, and pursue the task of consolidating the energy conservation information, trends and achievements and create a market for energy conservation and for energy efficient goods and services. Keeping in view the provisions of the Act, an appropriate institutional mechanism and energy database will be developed in the 11 th Plan by BEE. As a part of the mechanism, a fully dedicated Energy Conservation Information Centre (ECIC) with Information Technology facilities will be set up within BEE and Central Energy Conservation Fund as mandated under EC Act will be established by the Government of India Energy Conservation and Information Centre (ECIC) at BEE Information/ database availability on sectoral/ sub-sectoral trends on energy consumption and energy conservation potential is not readily available at a centralized place for all the sectors of Indian economy. As mentioned earlier, this can be mainly attributed to the absence of any institutional mechanism that enables collection of the information from various users and then to undertake detailed analysis that can feed into decision-making processes at the policy level. Substantial resources (manpower, infrastructure, funds and time) will be required if the information on energy conservation related activities is to be made available at national level from a single source. Collection of such information is a mammoth task and requires systematic handling and coordination of efforts of various agencies Strengthening of BEE and SDAs In the 11 th Five Year Plan, BEE will be strengthened as a nodal organization at the national level, and will be empowered to provide direction to the energy conservation programmes in the States. An appropriate institutional mechanism and a fully dedicated Energy Conservation Information Centre (ECIC) will be set up within BEE to analyze energy consumption trends and monitor energy conservation achievements in the country on the basis of data received from the states through Page 3 of Chapter 4

304 Demand Side Management & Energy Efficiency State Development Agencies (SDAs, notified by the State Governments under the Act). BEE will also take the responsibility of disseminating information in the public domain. To carry out these tasks, BEE will be strengthened with additional professional staff and expertise. Supporting organizational set-up will also be strengthened at SDAs in various States and Union Territories (UTs). For this, a matching grant support from Central Government restricted to the contribution made by the respective States/UTs Governments will be extended to establish State Energy Conservation Fund as mandated under EC Act. To facilitate various functions of BEE and SDAs, a national level network of institutions will be developed by BEE Institutional Network BEE will strengthen its existing institutional linkages with SDAs, and formalize its association with various other national level institutions such as PCRA, NPC, TERI, CEA, energy centres in academic institutes/universities, etc. with a view to utilize their expertise and knowledge in the field of energy conservation. In its institutional network, BEE will also include a number of sector specific associations and research institutions, and private organizations in various states, and will delegate specific tasks to facilitate the implementation of energy conservation programmes. Funding support proposed is Rs. 320 Crores (for BEE Rs 150 Crores and for SDAs Rs. 170 Crores). Details are furnished in Cl Energy Conservation Programmes in the Targeted Sectors In the 11 th Five Year Plan, BEE will focus energy conservation programmes in the following targeted sectors: Targeted sectors (a) Industrial Sector (Energy Intensive Industries). Industry sector offers maximum potential for energy conservation. The Government of India has recognized this when a number of energy intensive industries have been included as designated consumers in the EC Act. To bridge the efficiency gaps in the various units within the same industrial sub sector, BEE in association with SDAs, industry associations and research institutions, will develop 15 industry specific energy efficiency manuals/guides for the following sectors: Aluminum, Fertilizers, Iron &Steel, Cement, Pulp & Paper, Chlor Alkali, sugar, textile, chemicals, Railways, Port trust, Transport Sector ( industries and services), Petrochemical &Petroleum Refineries, Thermal Power Stations &hydel power stations, electricity transmission companies & distribution companies. The manuals will cover Specific energy consumption norms as required to be established under the EC Act, energy efficient process and technologies, best practices, case studies etc. Follow up activities will be undertaken in the States by SDAs. and manuals will be disseminated to all the concerned units in the industries. Page 4 of Chapter 4

305 Demand Side Management & Energy Efficiency Funding support proposed is Rs.21.8 Crores (BEE Rs.15 Crores and SDAs Rs. 6.8 Crores). Details are furnished in Cl.4.5 (b) Small and Medium Enterprises (SMEs) Many of the energy intensive SMEs clusters located in various states of the country are said to have large potential for energy savings. In quantitative terms, there is very little authentic information and data is available with respect to their energy consumption and energy saving opportunities. SDAs in consultation with BEE will initiate diagnostic studies in 25 number of SMEs clusters in the country, including 4-5 priority clusters in North East Region, and develop cluster specific energy efficiency manuals/booklets, and other documents to enhance energy conservation in SMEs. Clusters tentatively proposed for these activities are: Warn gal (AP) rice mills, Bhimavaram (AP) ice plants, Surat (Gujarat) textile, Jamnagar ( Gujarat) Brass, Jagadhri (Haryana) Plywood, Sambalpur (Orissa) rice mills, Bhubneshwar (Orissa) utensils, Pali (Rajsathan) textile, Jodhpur (Rajsathan) textile, Balhotra (Rajasthan) textile, Kota (Rajasthan) textile, Jaipur (Rajasthan) textile, Tripur (TN) textile, West Coast (TN) rice mill, Coimbatore (TN) foundry, Kanur (UP) textile, Bhadoi (UP) carpet, Bundre (UP) khandsari, Dehradun (Utranchal) Plywood, Howrah (WB) foundry, Agra (UP) foundry, Ferozabad (UP) Glass, Bodhjungnagar (Tripura) agriprocessing, Kamrup (Assam) forest/agro based industry, Dibrugarh (Assam) light engineering, Dimapur (Nagaland) Timber-bamboo products Funding support proposed is Rs.19.3 Crores (BEE Rs.12.5 Crores and SDAs Rs. 6.8 Crores). Details are furnished in Cl.4.5 (c) Commercial Buildings and Establishments Government and public buildings constitute a very large sub-sector but so far very little organized efforts have been put in to save energy in the same. In the 11 th Plan, BEE will initiate comprehensive studies in selected buildings/establishments such as office buildings, hotels, hospitals and shopping malls to prepare building specific energy efficiency manuals covering Specific energy consumption norms, energy efficient technologies, best practices, case studies, model energy performance contracts, model monitoring and verification protocol for implementation of ESCO projects etc. As a follow up, SDAs in association would initiate energy audits and their implementation in 10 Government buildings in each state and 1-2 buildings at UT level. BEE will also assist SDAs in the establishment and promulgation of energy conservation building codes (ECBC) in the States, and facilitate SDAs to adapt ECBC to the local conditions and make them ready for implementation at municipal levels. In addition, BEE will also strengthen a few test laboratories for testing of building materials and building utility systems for ECBC compliance. Funding support proposed is Rs.41 Crores (BEE Rs.14 Crores and SDAs Rs. 27 Crores). Details are furnished in Cl.4.5 Page 5 of Chapter 4

306 Demand Side Management & Energy Efficiency (d) Residential/Domestic sector BEE has been working to introduce energy efficiency standards and labeling programme to facilitate consumers in selecting energy efficient domestic appliances. For promoting energy efficiency programmes in this sector, SDAs will actively involve Electric Utilities/ Distribution Companies. Emphasis would be to encourage the consumers to adopt energy efficient lighting systems, air conditioners, refrigerators, water heating systems and other domestic appliances. BEE will enlarge its on-going energy labeling programme for frost free refrigerators and tubular fluorescent lamps to 10 other appliances - Air conditioners, Ceiling Fans, Agricultural pump-sets, Electric motors ( general purpose), CFLs, FTL 61cm (2ft), Television sets, Microwave ovens, Set top boxes, DVD players, Desk top monitors To facilitate this, 10 testing laboratories will be strengthened, and consumer awareness will be enhanced nation wide. Funding support proposed is Rs. 84 Crores (BEE Rs. 50 Crores and SDAs Rs. 34 Crores). Details are furnished in Cl.4.5 (e) Street Lighting & Municipal Water Pumping Street lighting and municipal water pumping put excessive pressure on electric utilities. Quite a few of studies/projects have been successfully demonstrated in some states. In the 11th Plan, such projects will be identified, documented and disseminated nation wide. Further, to promote such projects in various states, SDAs in association with State utilities will initiate pilot energy conservation projects in selected municipal water pumping systems and street lighting to provide basis for designing state level programmes. Funding support proposed is Rs.10.5 Crores (BEE Rs.2.0 Crores and SDAs Rs. 8.5 Crores). Details are furnished in Cl.4.5 (f) Agriculture Sector Increasing energy consumption trend is being seen in irrigation systems in the sector. Due to low power tariff for the sector in majority of the States, it is not in the farmers financial interest to buy efficient pumps, but it may be in the utility s interest to promote their use. In the 11th Plan, SDAs will collect, document and disseminate information on successful projects implemented by some states, launch awareness campaign in all regional languages in print and electronic media and follow up work in initiating state level programmes along with utilities. SDAs with assistance of concerned institutions will also develop suitable energy conservation models which will take into consideration measures like introduction of subsidy in replacement of inefficient pump sets with efficient ones, power factor improvement by installation of capacitor banks, rebate for optimum usage of pumps, energy efficiency labeling of pumps, etc. These models will be subsequently Page 6 of Chapter 4

307 Demand Side Management & Energy Efficiency promoted through the electricity utilities/distribution companies and SDAs with involvement of State Regulatory Commissions. Funding support proposed is Rs. 10 Crores (BEE Rs.5.0 Crores and SDAs Rs 5.0 Crores). Details are furnished in Cl.4.5 (g) Transport Sector The sector is mainly dependent on the petroleum products. In the 11 th Five-Year Plan, SDAs will develop linkages with State Road Transport Undertakings and private enterprises owning large fleet of trucks/buses to establish the status of energy consumption and conservation in the sector. SDAs with assistance of concerned institutions/agencies will conduct diagnostic studies to support urban bodies and transport research organizations in adopting multi modal public transport system which shall shift demand from personalized to public transport. SDAs will develop linkages with the state transport undertakings to establish the status of energy consumption and conservation potential and support studies to promote public transportation systems. BEE will also set up norms for specific fuel consumption for a few automobile and Transport models (Services/ Public transport). Funding support proposed is Rs 10.5 Crores (BEE Rs. 2.0 Crores and SDAs Rs 8.5 Crores). Details are furnished in Cl Demand Side Management Programmes DSM programmes driven by State Utilities has made a beginning in India, though these are yet to pick up momentum. In the 11 th Plan, BEE in association with SDAs will facilitate State Utilities to pursue DSM options more intensely by focusing on the following: Orientation workshops for awareness building on DSM amongst the State Electricity Regulatory Commissions (SERCs) and the chief executives and senior engineers of utilities/ DISCOMs. Setting up of DSM cells in utilities to conceive and implement DSM programs. Support load research and studies to rationalize the tariff structures to encourage options such as time-of-use rates or interruptible rates to capture the needs and opportunities of different market segments. Initiation of DSM programmes especially in the sectors (such as residential, agricultural pumping, municipal water works & street lighting) where customers are paying tariff far below the marginal cost of power Utilization of private sector energy service providers to market DSM program to consumers to maximize uptake, participation and Implementation of DSM programmes through ESCO route Development of pilot tariff based incentive schemes to reward utilities/ DISCOMs through Megawatt (Watts saved) through Ministry of Power for Megawatt savings implemented (actual realized after implementation & verification by SERCs). Utilities that have established appropriate DSM cells would be rewarded by state electricity regulators for initiatives involved in DSM bidding, load research studies, impact monitoring while fixing tariffs. Page 7 of Chapter 4

308 Demand Side Management & Energy Efficiency For supplementing DSM programs, supply side initiatives such as segregation of feeders, high voltage distribution system (HVDS), etc will be taken up with support under the state funding and other programs such as Accelerated Power Development and Reform Program (APDRP) on a case-to-case basis. For DSM programs, Funding support proposed is Rs. 15 Crores (BEE and SDAs). Distribution companies are expected to be supported by electricity regulators through tariff fixation as well as use ESCO route for implementing the programs. Details are furnished in Cl Human Resource Development Programmes There is a vast potential for energy savings through human intervention. BEE and SDAs have a major responsibility for stimulating a major change in the energy efficiency ethos and practices (energy modesty) by directing the national energy conservation campaign as a mass movement and seeking wide support. In the 11 th Plan, BEE will continue with their campaigns. In addition Central government will partially fund the SDAs for their respective campaigns in the States. The following initiatives will be taken in the area of HRD: I. Capacity building: a) Officials of BEE & SDAs in abroad/ India; b) Code officials from SDAs, urban & municipal bodies for promoting & enforcement of energy conservation building codes; c) Orientation programs every year for senior officials from Central & State Govt. departments to review the achievements, impediments and strategies to step up the tempo of energy conservation. II. Capacity building for new breed of professionals: a) energy managers/auditors being developed under the EC Act from 2003 by BEE through National Certification Examination by offering Refresher training modules for life long training for Energy Auditors & Managers; b) Tutorial /help-line support for prospective candidates in the national examination for energy managers/auditors. III. Demonstration centers in 2 industrial estates to show case and convince the entrepreneurs & plant engineers/technicians for industrial energy efficiency products /technologies IV. Orientation workshops on energy efficiency for top management, middle level executives and shop floor operating personnel V. Farmers training by display of energy efficient pump-sets & other relevant products VI. Training to drivers in road transport on fuel efficient driving VII. Nationwide campaigns: a) through media; b) awareness programs for general public & institutions in state capitals and other locations; c) painting competition for school children; d) Eco clubs activities for youth clubs VIII. Introduction of the modules on energy efficiency/ DSM in the curricula of a) schools b) technical institutes engineering colleges c) other degree/ post graduate courses including MBA programs. For HRD programs, funding support proposed for HRD programs to be administered by BEE and SDAs is Rs Crores. Details are furnished in Table below: Page 8 of Chapter 4

309 Demand Side Management & Energy Efficiency Table 1 Fund Requirements during 11 th plan - HRD for DSM, EE & EC Sl No Description Nos Rate Rs. Lakhs 1 Capacity building Amount Rs. Cr. Purpose 1a Capacity building of officials of BEE alternate years abroad/ India 1b Training of State Nodal Agency officers (34) 1d Code officers training for ECBC 1e Orientation programs Central Govt. officials 1 f Orientation programs State Govt. officials 2a Refresher training and continuing education for Energy Auditors & Managers, 2b Support for prospective candidates for energy managers/auditors 3 Knowledge Network through internet for implementation of Energy Efficiency- 3c Top Management awareness workshops 3d Middle Management awareness workshops 3e Operator level Awareness x Rs. 1 crore/year Partial funding Supplementary efforts to be reviewed every year partial funding 100 programs partial funding Partial funding & Training programs 4 Energy efficiency Additional demonstration centres support from industry also to be sought 5. Farmers training 30 events Additional support from industry also to be sought 7. Drivers training 200 programs Publicity campaigns to Every year sponsors to Page 9 of Chapter 4

310 Demand Side Management & Energy Efficiency create awareness in public & institutions, painting competition for school children, Eco clubs 9. Introduction of DSM, EE and EC concepts in School and College Curricula. One project Total supplement efforts also needed 4.4 POLICY RESEARCH FOR ACCELERATING ADOPTION OF ENERGY EFFICIENCY AND DSM PROGRAMS The energy conservation Act does not have specific provisions regarding an Energy Efficiency Policy Research. Such a program, however would complement the other provisions and thereby support the basic objective of the Act itself. Key among these includes legislative amendments, establishing norms, policy interventions including fiscal and non- fiscal measures. Among key result areas include: Legislative measures So far, enforcement of the EC Act has not been pursued during the tenth five year plan. These efforts would have to be intensified during the eleventh five year plan. There is a perceived need to have a fresh look at the EC Act to review the implementation of various provisions. A review committee consisting of professionals, legal experts and concerned agencies /stake holders will be constituted by BEE to look into this. It may be established on a continuing basis with a mechanism to receive feedback from the stake holders on the EC act and suggestions for improvement. BEE will also adequately support the activities to establish &review energy consumption norms for the notified designated consumers Identify the barriers for improving energy efficiency and propose fiscal and other measures Business firms often claim that that they do not have the financial means to implement the EC measures and consequently the government should provide financial assistance. Lack of access to capital, perceived uncertainty concerning savings, a high private discount rate and limited avenues to vet the energy efficiency measures and inadequacy of a reliable measurement and verification regime are the major barriers impeding implementation of energy efficiency projects. Customers are unwilling to invest their own funds in what is considered a non-core activity. Financial institutions are unfamiliar with energy efficiency investments and perceive them as risky. Energy services organizations are inadequately funded. Creation of an energy efficiency fund can provide needed resources to implement pilot or demonstration energy efficiency projects, help reduce risk perceptions, stimulate the ESCO market, and fund projects in the public sector. Page 10 of Chapter 4

311 Demand Side Management & Energy Efficiency Financing and information programs can play a central role in promotion of energy efficiency. To promote energy efficiency, there is an imperative need to create an appropriate set of incentives through pricing and other policy measures. For a chronically electricity-short situation, short-turnover-period technologies should be the primary candidates for implementation followed by the planting of energy efficiency seeds that will yield longer term benefits. Short term measures can be supported by public policy measures such as information & demonstration, standards and labeling, R&D, market transformation, taxes/tariffs. Long term measures can be fostered & promoted on business line by demonstration/pilots, Energy Performance Contracting in Govt. buildings, aggregation of projects (similar to approach being followed for bundling small CDM projects), demonstration/pilots and standard ESCO contracts. Financial institutions would be roped in for promoting ESCO businesses. Among non- fiscal measures may be award schemes similar to national energy conservation awards recognizing performing units. A rating scheme may also be evolved to rank the performance of units other than best performers and publicize the same to the share holders of the company Other strategies Among other strategies include the following: Track emerging trends in energy efficient technologies and device plans to support research, development and deployment by end users in the designated consumer and other sectors Encourage planners & regulators related to energy sector to adopt integrated resource planning in the entire value chain of activities, right from extraction or procurement, conversion to final end use. Rationalizing pricing for various forms/sources of energy to encourage promoting efficient choices and appropriate substitution in tune with the Electricity Policy, Tariff Policy and Rural Electrification (RE Policy ) of Govt. of India. Funding support proposed for the policy measures is Rs 10 Crores (BEE). It does not include provision for fiscal measures. 4.5 BUDGET OUTLAY FOR THE 11 TH PLAN The total budget requirement for a period of five years for the overall establishment and functioning of the identified activities/ projects on DSM, EE and EC has been estimated to be Rs 653 Crores and the details of the same are given below: Page 11 of Chapter 4

312 Demand Side Management & Energy Efficiency Funds Requirements - 11 th Plan No. Focus Area/Sector 1. Strengthening of Institutional Set up in BEE and SDAs Activity Establishment of Central Energy Conservation Funds under EC Act Organizational strengthening of BEE, and Establishment of Energy Conservation and Information Centre (ECIC) within BEE Establishment of State level Energy Conservation Funds under EC Act Funds Requirements in Rs. Crores At At Total BEE SDAs EC Programs in targeted sector A Industrial Sector (Energy Intensive industries as covered in the EC Act) B Small & Medium Enterprises Comprehensive Studies in 15 sub-sectors including development of specific energy consumption norms Comprehensive Studies in 25 clusters sub-sectors, including 3 clusters in North Eastern Region ) C Commercial Buildings & Establishments Comprehensive Studies in commercial buildings covering office buildings, hotels, hospitals and shopping malls d Domestic/Residential Sectors Expertise development of energy auditors, architects, builders, municipalities, etc for promotion /development of ECBC in states, Undertaking of studies by SDAs to efficient appliances, labeling of 10 more appliances/equipment, Strengthening of 10 testing labs, Awareness campaigns on labeling program by BEE and SDAs Page 12 of Chapter 4

313 Demand Side Management & Energy Efficiency E Street lighting and Municipal water pumping Dissemination of information on successful projects implemented by some of the states, Pilot energy audits and projects in states and follow up work in initiating and implementation of state level EC programmes F Agriculture Sector Collection, documentation and dissemination of information on successful projects implemented by some states, launching of awareness campaign in all regional languages in print and electronic media and G Transport Sector Setting up of norms for specific fuel consumption for automobile and Transport (Services/Public transport) and promotional studies for public transportation systems DSM PROGRAMS Orientation Programs for regulators & DISCOMs -, Design of pilot scheme for Negawatt savings for DISCOMs 15 (for BEE and SDAs) HRD PROGRAMS Orientation programmes for 75(for Government departments/ BEE Ministries, Cadre for energy managers/auditors, and SDAs) Programmes and awareness campaigns for schools, colleges, farmers, NGOs, Public, industrial operators, drivers, etc. (Details at Table- 1) 5 Policy Research Policy Research for Accelerating Adoption of Energy Efficiency and DSM Programs Total Page 13 of Chapter 4

314 Demand Side Management & Energy Efficiency 4.6 RECOMMENDATIONS The target of additional electricity savings which may accrue to the national economy at the end of 11 th Five year plan as a consequence of intensive energy conservation and DSM drive is expected to be about 5% of the anticipated energy consumption level in the beginning of 11 th Plan. BEE will device a suitable mechanism for assessing these savings. The outlay for various strategies and programs as proposed is Rs. 652 Crores. Out of this proposed allocation, Rs crs is the estimated requirement for BEE at the centre and the balance Rs crs as the assistance for strengthening the institutional structure at the State level for effective implementation of EC Act. These initiatives will also seek funding support from state governments, other complementary programs, user industry, financial institutions, and other donor agencies besides innovative financing options. ******* Page 14 of Chapter 4

315 Research & Development Chapter 5 RESEARCH & DEVELOPMENT 5.0 INTRODUCTION With the twin cries of depletion of energy resources and environmental pollution, it has become more crucial to develop efficient & clean power plants and their delivery system. These plants should be capable of effective utilization of resources such as coal, natural gas & other sources of energy. Thus, in order to meet India centric requirements, various sectors related to the field of energy have been identified for segregating different research avenues. The depletion of fuel resources has resulted into the need of exploring renewable power generation. Similarly, the application of distributed power generation may be useful for electrification of remotely located unelectrified villages. Apart from this, application of new technologies in the field of generation, transmission & distribution also needs to be given utmost emphasis. In view of the above, it is proposed to categorize the R&D initiatives into three different sectors, viz. Generation, Transmission and Distribution. Generation will have 7 Subgroups. Necessary emphasis is given to each sector. In each sector various technologies will be taken up for demonstration & development. The list of different sectors can be enumerated as below: 1. Generation Sector Thermal Hydro Fuel Environment Renewables Distributed Generation Nano materials 2. Transmission sector 3. Distribution sector Considering that certain overlaps between different sectors such as fuel, environment and renewables are unavoidable, they have been put under one head of Generation. 5.1 OVERVIEW OF R&D R&D in the power sector is presently in the domain of following organizations: i) R&D wings of Corporations like the NTPC, NHPC, PGCIL and other units of the Ministry of Power (MoP). Page 1 of Chapter 5

316 Research & development ii) iii) iv) Applied R&D under MoP schemes like RSoP, in-house Research projects of CPRI and the National Perspective Plan projects recommended recently. R&D laboratories of CSIR working on energy related areas and sponsored projects of DST. Industrial R&D by organizations like BHEL and other equipment manufacturers. In the generation sector commendable work has been done by NTPC and BHEL in the areas of stabilization of 210 and 500 MW units, development of pulverized coal fired boiler for coal with high ash content, efficiency improvement of Thermal Power Plants, control, instrumentation and loss minimization. Similarly in the hydro generation, BHEL, NHPC and other hydro utilities have contributed in uprating of old units, improving turbine design etc. In transmission, PGCIL and BHEL have introduced many new technologies like Series Compensation, Thyristor Controlled Series Capacitor, Controlled Shunt Reactor, etc. PGCIL have contributed to the development of high temperature conductors, development of insulators, introduction of 800kV AC and planning for ± 800 kv DC first time in the country. Many of the developments by PGCIL and NTPC have come through project route in the county and although their R&D units have not shown substantial expenditure on R&D, the organizations have encouraged new technology. It is noticed that where as some of the available technology abroad are being introduced in the country, commensurate R&D efforts to get it improved and sustained through available inhouse resources, has not been pursued. As a result, there is no technology breakthrough that has actually taken place in power sector through indigenous route. 5.2 TECHNOLOGY DEVELOPMENT IN POWER SECTOR The in-house R&D setups of major utilities like NTPC, NHPC and PGCIL address introduction and absorption of new technology primarily through project routes. Major manufacturers like BHEL, Crompton Greaves have their own R&D set up, focusing on product development. Central Power Research Institute (CPRI) is provided with capital funds from the Ministry of Power for inhouse research as well as disbursement of research funds to utilities, industries and academic institution. Central Electricity Authority has a role in identification of appropriate new technology for the country. Recently a few projects under National Perspective Plan on R&D have been taken up which are collaborative research projects involving more than one organisation. The R&D policy of the Government is to promote R&D projects that help the nation to become self reliant in technology. R&D by the PSUs has so far been at a low level. It is only in late 10 th Five Year Plan NTPC and PGCIL have taken up a few good research projects mainly oriented towards performance improvement of generating stations and National grid. Government initiative in the distribution under APDRP scheme and in the area of renewables has initiated good research work by many organizations involving academia, utilities, NGOs, equipment suppliers and research laboratories. This spur in R&D in the field of distribution of power which is attributed to a large investment in this area could also pave way for higher R&D initiative in transmission and generation. Page 2 of Chapter 5

317 Research & Development Looking at the R&D expenditure in India it is learnt that the R&D expenditure by organizations like the NTPC with turn over of more than Rs crore and profit above Rs crore is less than Rs.7 crore in last 2 years. PGCIL s R&D expenditure is still less. BHEL has been spending on R&D 1.0% of its turn over for the last 2 to 3 years and plans to increase it to 1.5% The expenditure by CPRI in the Xth Plan is around Rs. 67 crore. The RGGVY scheme of MOP launched in 2005 has earmarked Rs.160 crore amounting to Rs.1% of scheme cost, for enabling activities including technology development. The expenditure on R&D incurred by Coal India Ltd. during the X Plan was Rs.7.5 crore and none of the work undertaken by it was related to Power Sector. 5.3 IDENTIFIED PROJECTS FOR 11 TH PLAN BY CENTRAL UTILITIES An interaction was made with NTPC, BHEL, PGCIL, DSIR to find out their R&D plan for the XI Plan period. The projects identified by Central Sector Units viz. NTPC, Powergrid, BHEL and CSIR are listed below: NTPC has identified a few projects for inhouse research where they would involve other research institutes like BARC, CPRI, CSIR and other consulting houses. The list of projects identified by NTPC is as follows: 1. Development of Flue gas heat recovery system for a 200 MW Unit. 2. IGCC technology demonstration project. 3. Development of Automated boiler tube inspection system (robotics application). 4. On line condition monitoring of power transformers. 5. Modelling & design of natural draft cooling tower assisted flue gas dispersion. 6. Technology demonstration for suitable capacity solar (Thermal). 7. Development of 10 KW sterling engine based TDP suitable for distributed generation. PGCIL has also identified a number of inhouse projects for research which are as follows: 1. Technology Development for +/- 800 kv HVDC system for transfer of 6000 MW power from NER to NR 2. Aerial route survey using Air borne laser terrain (ALTM) along with National Remote Sensing Agency (NRSAR) 3. Development of High surge impedance loading line (HSIL) 400 kv Purnea Biharshariff D/C 4. Development of Fault current limiter at 400 kv level 5. Indigenization of polymer insulator 6. Specification of suitable oil for transformer 7. Intelligent grid 8. Design of Converter transformer 9. Development of Converter transformer-less HVDC system 10. Development of 1000 / 1200 kv EHVAC 11. Residual life assessment of transmission system Page 3 of Chapter 5

318 Research & development 12. Indigenous development of GIS 13. Real time digital simulator and studies 14. Indigenous development of high strength insulators like 320 / 420 kv AC & HVDC 15. Development of 400kV compact line 16. Lightening mapping BHEL has identified a few broad based projects in generation, transmission and distribution which are given as under: 1. Clean coal technologies. 2. Super critical boilers. 3. Ultra High Voltage Equipment. 4. IGBT based drives and controls. The laboratories of CSIR who also carry out basic and applied research have identified following inhouse research programmes related to Power Sector for the 11 th plan: 1. R&D on Photovoltaics and other solar energy applications (NPL, New Delhi) 2. Energy for cleaner and greener environment (CECRI, Karaikudi). 3. Bio energy technology: Strategy designing of Jatropha curcas for bio diesel (NBRI). 4. Development of gas to liquid (GTL) processes for fuels (NCL). 5. Hydrogen economy initiative (NCL, Pune). 6. Development of coal to liquid (CTL) technology for synthesis of liquid from hydrocarbons (CFRI, Dhanabad). 7. Development of a composite approach suitable for clean coal initiatives (CMRI, Dhanabad). 8. Development of Underground coal gasification and IGCC Technology in India (CMRI, Dhanabad). 5.4 R&D PROJECT PROVISIONS AND TEST FACILITIES FOR CPRI CPRI, Bangalore has proposed various in-house & collaborative research activities. Budget allocation for carrying out such functions & developing a world class test labs along with the enabling infrastructure has already been proposed. CPRI proposes an allocation in the range of Rs. 731 crores to be made available in 11I th Five Year Plan. The detailed break up is: Page 4 of Chapter 5

319 Research & Development A Investment on Dielectric Material, Diagnostic Rs crores Testing & Simulation Techniques B R&D Projects (In-house, RSoP and National Rs crores PowerPlan) C Facility addition to upgrade laboratories to test Rs crores 400 kv breakers, etc. D Expenditure on Spill over schemes from X Plan Rs crores E High Power Test Facility Addition and Creation Rs crores of new facilities of CPRI F Upgradation of Ultra High Voltage Test Facility Rs crores at Hyderabad Total Rs crores Need for restructuring of CPRI CPRI was established to work as a nodal agency for power sector research but had a larger role assigned to work as a neutral testing laboratory. Although the organisation has contributed to encourage R&D in utilities, academic institutions and in its own laboratories, it has not been able to build up resources to work as a driver of R&D in the power sector. It is recommended that a restructuring of CPRI is necessary if it has to play a proactive role in collaborative research in the country. For this the following are suggested: a) Testing has to sustain on its own and as far as possible government grant should not be utilized for meeting test facility requirements. The beneficiaries of test facility, i.e., the manufacturing units and utilities should largely bear this burden. b) CPRI should be corporatised to reduce its dependence on Government funding and have better operational flexibility. This would help CPRI to be competitive and self reliant. The major utilities like NTPC, PGCIL, NHPC and PFC should come forward to make it happen. c) CPRI is to develop its ability to enhance industrial & system related consultancy work and get more sponsored projects for improving its financial health. 5.5 MAJOR PROJECT PROPOSALS FOR 11 TH FIVE YEAR PLAN IGCC Technology IGCC technology, using coal gasification, allows the environmental benefits of a natural gas fueled plant and the thermal performance of a combined cycle. Coal is gasified with either oxygen or air and the resulting synthesis gas (or syn. Gas) consisting primarily of hydrogen and carbon monoxide is cooled, cleaned and fired in Page 5 of Chapter 5

320 Research & development a gas turbine. The hot exhaust from the gas turbine feeds a heat recovery steam generator (HRSG) where it produces steam that drives a steam turbine. IGCC plants are reported to work well with bituminous coals (262 MW Wabash River, 250 MW Tampa USA and others). Other features are high sulphur removal, total volatile mercury removal, production of 40% lesser solid -products by and consume 40% less water compared to PC plants. Entrained flow gasifiers are used in IGCC plants abroad, which deliberately operates in the higher temperature slagging regime to avoid tar formation. Further it is noted from the reports that Wabash River IGCC plant showed a drop in the performance owing to reduction in fuel quality to sub-bituminous and lignite variety. The moisture content in the coal seems to play a role in slurry concentration combined with the increased ash content in the lower rank coals. The energy density of the slurry deteriorates markedly. Generally, it is felt that there is a greater need to demonstrate and improve the performance of IGCC for low rank subbituminous coal. While entrained flow gasifier appears to accommodate all ranks of coal there is a marked increase in cost and reduction in performance with low rank and high ash coals. For Indian conditions pressurized fludized bed gasification is preferred. Efforts are in progress in the country for the development of125 MW IGCC Unit (gross efficiency 39.5%). The technical approach to scale up is yet to be established and the commercial utility size IGCC Unit is likely to be operational by One IGCC Project on this route has already been launched and it is recommended that it should be speeded up, by NTPC with its own funds Steam Generator Condition Assessment Model Through Neutron Activation Techniques The objective of the proposal is to development of a comprehensive Boiler Condition & Performance Assessment. Boiler Condition asessment shall be done through a combinatorial program of Neutron Activation Technique, Electro-Mechanical Acoustic Transducer, Fiber Optic embedded Raman Scattering Technique. The entire proposal is to be executed in an integrated manner. The nature of the project is such that the elements mentioned below are neither modular nor discreete, rather they are intrinsically intermingled and interdependent and hence cannot be taken up in a serial manner. Though interdependent, the main elements of technology development in the project shall be following: It would involve complete, identify the required competence areas and potential collaborating institutes for each of the following technologies and initiation of its execution: i. Neutron Activated Tomography for scanning of Boiler Tube Thickness. ii. Electro-Mechanical Acoustic Transducer based scanning of Boiler Tube Thickness. iii. Fiber Optic embedded Raman Scattering Technique or any other alternate technology for scanning of Boiler Tube Metal Temperature. iv. Neutron Activation based combustion visualization technology. Page 6 of Chapter 5

321 Research & Development Technologies are available for boiler condition assessment. However the major issue involved is to make it suitable & approachable, when it comes to real life situation in a boiler. The main deliverable for the project is to demonstrate these technologies in an integrated manner for true assessment of boiler condition Advanced RLA methodologies (Robotic corrosion mapping, phased array technology, remote eddy current, temper embrittlement and electro magnetic acoustic transducers) Robotic based Corrosion mapping system for water wall tubes through Magnetic Inductance Bridge based robotic system. The water wall tubes in the primary pass of thermal power plant boiler are subjected to severe corrosion problems especially in the burner zones leading to loss in thickness. The wall thickness of each tube needs to be monitored during annual shutdown periods for ascertaining their suitability for continued service and schedule for replacement if necessary. In view of the short shut down periods, it is not possible to measure the thickness of all tubes using conventional ultrasonic technique. In a robotic based system, the probe/magnetizing coil is supported on robotic device which can crawl along the whole length of the water wall tubes and maps the corrosion thickness. The high temperature boiler tube during service forms coherent oxide layer on the outer surface due to oxidation. The presence of this oxide layer on the outside of tubes interferes with ultrasonic wall thickness measurement and prevents proper sound coupling during conventional UT technique. The application of EMAT probes permits enables direct measurement without any surface cleaning of the boiler. When coupled with a robotic device, large no. of tubes and different elevations can be covered in a short shut down period. Phased array technique is a specialized type of testing that utilizes multi element array transducers and software controls for steering the ultrasonic beam. In view of complexity in shape & geometry of component of turbine components such as blades, rotor steeple and disk rim attachments, the conventional techniques suffer by reliability, accuracy & reproducibility. The advanced linear phased array ultrasonic technology wherein multiple UT probes mounted in a single holder is used to for this purpose and reported that the reliable and redundant results can be obtained in respect of defect detection, sizing and shape. HP / IP rotors suffer in-service degradation from rotor material temper embrittlement. The rotor material fracture toughness, which governs the size of the critical flaw for fracture, is hence adversely affected. A reliable assessment of the fracture toughness properties of steam turbine rotor requires sampling of material from inservice rotor. A miniature sample removal and small punch testing technique for direct estimation of fracture toughness provides a rational basis for reduction of conservatism during RLA of rotor. The remote eddy current/cctv system is capable of examining the trailing and attachment areas of L-0 and L-1 turbine blades without turbine disassembly. Eddy current tests have also been successfully used to detect cracks in the area of the satellite wear strips on the leading edge of last stage blades and for inspection of Page 7 of Chapter 5

322 Research & development turbine casing bolt and bolt holes. Critical turbine components must be evaluated to assure safe operation during their lifetime. The adoption of advanced RLA methodologies leads to the emergence of sophisticated practice in RLA with reliable and upgraded assessment technologies in the short time available during periodic maintenance, application of Robotics, improved deterministic routes and evolution of technology options. The project envisages development of state-of-art technology in the area and adopts them in a few thermal power stations. The project will support a number of spin off research in the related area Combustion modeling and technologies for utilization of fly ash unburnt carbon in pressurized fluidized bed gasifier The objective of the project is to demonstrate pressurized fluidized bed char combustor in a pilot scale facility & to explore other ways of separating char from fly ash of pressurized fluidized bed gasifier. Pressurized fluidized bed gasifier operating in a bubbling mode normally gives lower carbon conversion efficiency in the range of 90-91% only. The attributing factors are particle attrition & elutriation from the bed. Freeboard reaction is normally limited due to dearth of oxidant resulting in 15% combustibles in fly ash. The fly ash recycling is another option to reduce the overall combustible in ash. For high ash Indian coal, large amount of ash recycling is always a big threat in a pressurized system. Another option is to separate char from fly ash & utilize the char in a separate furnace. Various separation methodologies are still in developmental stage only. Tribo-electrostatic separation, & dry fluidization separation are among few technologies, which have been tried so far. However research work needs to be carried for demonstration of such technologies for Indian coal. The third option is to put the fly ash in a pressurized fluidized bed combustor to produce steam & the hot gases i.e. a mixture of nitrogen & carbon dioxide at around 1000C can be reintroduced back to main gasifier. The heat carried over with the flue gas will sustain the endothermic reaction & carbon dioxide can be used as a gasifying agent in the gasification process. The project would have deliverables in three stages. Modelling of the char combustor with actual fly ash constituent as an input would be the first deliverable. Next would be a development of a bench scale pressurized char combustor & final will be its integration with main gasifier. The cost of the project has been estimated as 19 crores & project is expected to be completed in six years. Page 8 of Chapter 5

323 Research & Development Carbon Dioxide Storage In Geological Formations The objective of the project is to study the possibility of long-term storage of CO2 in geological formations such as basalt & other sedimentary rocks for CO2 sequestration. Global warming, due to CO2 emission from different anthropogenic activities including power plants is one of the major environmental problems, the world is facing today. Carbon sequestration, consists of CO2 capture, transport and permanent storage, is one of the pathways to contain CO2 emission. Establishment of environmentally safe and permanent storage of CO2 is a major issue of the whole carbon sequestration activity. Geological storage is considered to be most available and safe for long term CO2 storage. CO2 storage in basalt or sedimentary formation will be explored to demonstrate the possibility of CO2 storage in these formations. Initially noninvasive technologies like 2D/3D & MT studies, bore hole sampling, physical and chemical characterization of formations, kinetic studies, wire logging for temperature & pressure profile, geological modelling etc. will be carried out to establish the feasibility of CO 2 storage in the identified formation. Subsequently CO2 will be injected at appropriate depth through bore hole and the movement of injected CO2 will be monitored through surface and subsurface measurement. Detailed modelling will be carried to predict the fate of CO 2 in geological storage system in long term. Final deliverable for the project would be to demonstrate the process in field. The cost of the project will approximately be 15 crores & duration is expected to be seven years Value Added Products Technology For Fly Ash Utilization The establishment of technology demonstration and production centers for value added products from fly ash at six thermal power plants in India shall involve introduction of state of art plant and machinery for manufacture of fly ash based building products to demonstrate the techno economic viability for commercialization. Certain separation and beneficiation facilities are also proposed to be established for the benefit of power plants in terms of adding value to fly ash as a raw material, which will lead to sale of fly ash as a commodity to various user industries. Facilities are also planned at these centres, to ensure quality assurance of fly ash products. The six centres proposed shall be at Ennore Thermal Power Station, Tamil Nadu, Vijayawada Thermal Power Station, Andhra Pradesh, Wanakbori Thermal Power Station, Gujarat, Koradi Thermal Power Station, Maharashtra, Badarpur Thermal Power Station, Delhi and Ropar Thermal Power Station, Punjab. The implementation of the project will lead to dissemination of home grown technologies and showcasing of product centers, revealing the features of fly ash products, promoting widespread use of indigenous plant and machinery, promoting energy efficient building concepts with fly ash products leading to zero energy philosophy. Industry Institute interactions for entrepreneur development, awareness, training programmes and workshops, organized from time to time at Page 9 of Chapter 5

324 Research & development these centers will lead to promoting environment friendly value added utilization of fly ash in India Fuel Cells: Demonstration Of Direct Alcohol/ Polymer Electrolyte Fuel Cell Plant There are many technical challenges, the fuel cell R&D work must cover wide application in distributed generation market, embodying co-generation. The positive technological implications, which would create the tendency towards more economical fuel cell systems, hold the key. Further the significant technical challenges with regard to integrating fuel cell system with available infrastructure, reducing the capital cost through volume manufacturing and achieving widespread use in various sectors needs to be addressed. The key points to be addressed regarding cost reduction include (i) materials, (ii) complexity of integrated systems, (iii) temperature constraints, (iv) manufacturing processes, (v) power density (footprint reduction), and (vi) benefit from economies of scale (volume) through increased market penetration. Under fuel flexibility the R & D topics are (i) nontraditional fuel storage (H2), (ii) transportation fuel reforming, (iii) renewable fuels processing (reforming, gasifying, clean-up), (iv) biogas operation, and (v) tolerance to gas supply variation. Further, the RD & D occurring today for specific systems and system integration include (i) power inventers, (ii) power conditioners, (iii) hybrid system designs, (iv) hybrid system integration and testing, (v) operation and maintenance issues, and (vi) robust controls for integrated systems. Direct Alcohol methanol based fuel cells are of interest as a future source of power, because of two reasons. These are in early stages of development. Firstly methanol is easier to transport, distribute and store than hydrogen. Secondly, when produced from biomass sources it is almost CO2 neutral to the environment. These are an excellent candidate for very small to mid-sized applications, such as cellular phones, PCs up to automobile power plants.the challenges in R&D are both at the level of system integration and also at the more fundamental level of researching better catalysts and membranes that are less leaky to the methanol. Cost optimization is also needed. Improvements are needed in expensive catalysts presently used. The R&D project shall address these concerns by using a multidisciplinary effort and suitable networking with CSIR labs and institutions abroad. The project includes integration of a two/five kw output fuel cell stack and its evaluation under various practical environmental conditions Distributed Generation Although substantial development is being carried out in various institutions with support from MNES and a number of designs based on biomass gasification, bio fuels, are available, the penetration into the India market has been poor. Small units of distributed generation in unit sizes of kw shall be able to complement village electrification but cannot be a stand alone reliable source of power supply. In order to contribute to power sector, the size has to be up to MW which would need to have connection to the grid. For large scale use of distributed generation using biomass gasification as primary method and its integration with other generation based on solar, diesel and grid, the scaling up issues, reliability issues, capacity building, revenue models, fuel linkages, etc. are to be addressed at a much larger scale. Page 10 of Chapter 5

325 Research & Development It is proposed to have a 2 stage implementation strategy during the. 11 th Five Year Plan. At the end of 1 st year of 11 th Plan, the package solution to Distributed Generation will be found for different alternatives which will suit the rural resource base (including solar energy). Five demonstration projects will be made fully functional with 100 to 1000 kw rating by end of 3 rd year. The R&D will address biomass generator efficiency improvement, biomass gasification, solar, diesel and grid connectivity and optimum use of the option for energy saving. The issues of fuel linkage and maintenance would also be addressed. The project shall support a number of small prototypes taken on experimental basis depending on R&D content. IIT, Guwahati and NIT, Silchar shall be associated in engineering and research activities of projects for North-East. The R&D programme in 1 st stage would be a confidence building exercise to refine and optimize the technology which would lead to mass production in 2 nd stage. Following schemes shall be designed and demonstrated: 1) Stand alone Biomass based generation 2) Biomass based generation connected to the grid 3) Biomass based generation that can be integrated with solar-pv, solar thermal based or diesel based generation by a suitable micro or mini grid. The above would have the benefits of being able to provide access to electricity, depending on local conditions in rural areas. A group of five to ten Distributed Generation units spread over different villages that are reasonably close together would form a cluster. This is aimed at providing necessary technology and service support to the individual villages. The service cum technology centre for a cluster would have necessary skilled manpower, tools instruments and spares. Good monitoring of individual projects during installation, and commissioning to achieve sustained operation would also be done. This approach is considered essential for the success of the programme. Typical project cost is between Rs. 2 crore to Rs. 20 crore and the total allocation for this scheme is estimated to be Rs. 75 crore Nano Material Applications For Power Sector Research on Nano materials in various fields of science is promising and needs to be directed towards practical and useful application. This project will be exploratory in nature to promote research in Nano materials for power system applications. Application 1 Super Capacitors : High energy storage compact super- capacitors are available for small energy long duration applications. It is expected that larger size capacitors would be available in market. Large number of capacitors in series and parallel can work for energy storage devices in voltage source converters which has a large number of application. In larger sizes, these capacitors can be substituted for super conducting magnetic energy storage devices (SMES) for providing grid stability. Page 11 of Chapter 5

326 Research & development Application - 2 Carbon fibers reinforced aluminum conductors for transmission line application could be promising for high temperature application. Research needs to be promoted in this areas. Application 3 Nano Composite Polymer and Ceramic research - In ceramic and polymer applications use of additives shows promise. Research in this area should be focused to practical power system application such as high strength ceramic insulators, dielectric material with high dielectric control for capacitors etc. Ceramic based nano material paint can work better than photo voltaic cells for solar power generation. Nano materials hold promise in CO 2 capturing and sequestration. Application 4 MEMS and Sensors Nano material application in sensor development has shown promise. Sensors of all types, temperature, pressure, strain gauges andfor electrical qualities can have much better efficiency using nano materials. Research in these areas have to be promoted and directed to Power System application. Although good work is being carried out in IITs and IISc the funding is too meagre to support useful research. The production technology of nano material is complicated and equipments are expensive. Unless high quality research is carried the institutions having good infra structure, the impact of the technology will not be substantial As knowledge in nano science grows, application in thermal power engineering ash handling, environment control, un-burnt carbon detection, etc. can be increased. Although Science & Technology Department would be focusing on Nano material research, it is felt that MoP should contribute to give it an application orientation. A budget of Rs.100 crores is proposed in the 11 th Plan for supporting Nano materials research for power system applications Advanced Power Electronics Technologies for Transmission There are a number of technologies under FACTS controllers which provide flexibility to power transmission and are considered important in view of open access being introduced. We have in India TCSC (Thyrister Controlled Series Compensation) already introduced. Other promising technologies are: i. Static Synchronous Series Capacitor (SSSC) ii. Static Compensator (STATCOM) iii. Unified Power Flow Controller (UPFC) iv. Thyrister Controlled Phase Angle Regulator (TCPAR) Page 12 of Chapter 5

327 Research & Development The design of equipments, controllers for these devices need extensive research. One major demonstration project is recommended to be taken up on R&D route with private participation AC/ DC Microgrid Demonstration Project By Deploying Various Distributed Energy Sources, Energy Storage Systems, Communication Systems, AMR, DVR, STATCOM, HVDC Light Distributed power generation system is emerging as a complementary infrastructure to the traditional central power plants. This infrastructure is constructed on the basis of decentralized generation of electricity close to consumption sites using Distributed Generation (DG) sources. The increase in DG penetration depth and the presence of multiple DG units in electrical proximity to one another have brought about the concept of the micro-grid. A micro-grid is a portion of a power system which includes one or more DG units capable of operating either in parallel with or independent from a large utility grid, while providing continuous power to multiple loads and endusers. The idea supporting the formulation of the micro-grid is that a paradigm consisting of multiple generators and aggregated loads is far more reliable and economical than a single generator serving a single load. India being geographically diverse country with habitation spread over all kind terrains such as, hilly inaccessible areas, desert lands, small islands etc, providing reliable power at affordable price is a challenging task. At the same time, India is endowed with different kinds of renewable sources like solar, hydro, bio-mass etc. Micro grid system encompassing locally available one or more resources for power generation could offer possible solution to the challenges of a nation to provide energy to the remote locations. The demonstration micro-grid project would also include energy storage systems to supply power to critical loads and also for emergency system start-up power. These projects incorporating concepts of microgrid would include suitable communication system required for AMR. Research on AMR technology is needed to optimize cost of overall distribution system. The advantages of VSC based HVDC system can be best utilized for applications like: Deep river crossings Power supply to isolated loads (supply to distant town, mine, island or even production platform in the sea needing power from main land), Feeding Power from small isolated generation (wind, small hydro, tidal solar etc.) to a grid or to a separate load without affecting power quality of receiving network. The implementation of technology developed in the area of power distribution is also envisaged. Here, power electronics devices such as DVR, STATCOM etc. based on VSC based converters would be developed. These would be included in the feeders to improve power quality. These demonstration systems would have suitable AMR Page 13 of Chapter 5

328 Research & development system to monitor energy supplied to customers. The deliverables from the project would result in demonstration of high quality power distribution systems. The selection and development of suitable power electronics devices and a field show casing as stated above forms an integral part of the project. The project would pave the way for design of future rural energy network, where distributed generation sources are likely to be deployed and would act as a benchmark. 5.6 SHORT LISTED SHORT TERM & LONG TERM PROJECTS The projects identified to be taken for R&D during the 11 th Plan are; Sr. No 1 Project Definition Sector Duration of the project Budget (in Crores) GENERATION SECTOR A THERMAL GENERATION 1.1 Generation technology, Fuels and Environment 1.1 Development of sensor systems for online fuel calorific value & unburnt carbon in ash measurement(deployment in 5 units) Generation Thermal Short term 3 * 1.2 Steam Generator condition assessment model through neutron activation techniques Generation Thermal Long term 20 * 1.3 Development of desalination technology with LP exhaust steam/ Solar heat source (10 cubic m/hr) Generation Thermal Short term 16 * 1.4 Advanced RLA methodologies (Robotic based corrosion mapping system Phased array ultrasonic technique Hydrogen embrittlement Remote eddy current technique Temper embrittlement of rotors Electromagnetic Acoustic Transducers for boiler inspection ) Generation Thermal Long term 25 * B HYDRO SECTOR Excavation of large size Caverns with 1.5 appropriate stabilization technology Generation Hydro Short term 1.5* Page 14 of Chapter 5

329 Research & Development Sr. No Project Definition Sector Duration of the project Budget (in Crores) 1.6 Soft rock tunneling Generation Hydro Short term 1.5* 1.7 Application of GIS / GPS in river inflow / discharge measurements, flood forecasting, etc. Generation Hydro Short term 1.5* C FUELS AREA Combustion modeling and technologies for utilizing unburnt 1.8 carbon in ash in PFB gasification Fuel Long term 19* Development of multiple feed 1.9 conditioning system for biomass fired boiler Advanced circulating pressurized 1.10 fluidized bed gasifier Fuel Fuel Short term Long term 2* 10* D ENVIRONMENTAL AREA Technology development of flue gas desulphurization system for NE high 1.11 sulphur coal through electron beam (SO2 to SO3 conversion) Environment Short Term 6* CO2 storage in geological formations 1.12 like Basalt and Sedimentary rocks Environment Long term 15* Value added products technology demonstration and 6 production centers for fly ash 1.13 utilization(production technology, state of art plant and machinery, fly ash beneficiation schemes, quality assurance measures) Emission control technologies for 1.14 NOx, SOx Environment Environment Long Term Short Term 20* 3* E RENEWABLES AREA Demonstration of direct 1.15 alcohol/polymer electrolyte fuel cell plant(5 kw/2kw) and exploratory work Renewables Short term 3* Page 15 of Chapter 5

330 Research & development Sr. No Project Definition on Deep coal beneficiation and Ultra Super Critical Technology Sector Duration of the project Budget (in Crores) Demonstration of LED lighting for 1.16 rural electrification of one model village Solar bio photovoltaic cells for generation of Hydrogen, methane 1.17 using hybrid organic / inorganic system Development of geothermal power 1.18 generation technology Renewables Renewables Renewables Short term Long term Long term 1* 10* 1* 1.19 Distributed Generation Major Project Distributed Generation Long term F NANOMATERIAL APPLICATIONS FOR POWER SECTOR Material Long term TRANSMISSION Wide area measurements for grid protection & control Transmission Long term 10* 2.2 Testing and simulation laboratory for SCADA (Complying with IEEE 61850) & demonstration projects Transmission Short term 7.5* 2.3 Development of online monitoring systems for substation equipments Transmission (like transformers, breakers, CTs, etc.) to get early warning of failures Short term 4* 2.4 Advanced power electronic technologies for transmission Transmission Long Term 48.5* 3 DISTRIBUTION AC / DC Micro-grid demonstration project by deploying various distributed energy resources, energy storage systems, communication systems, AMR, HVDC light, DVR, STATCOM, etc. for improving reliability and power quality Distribution Long term 20* Page 16 of Chapter 5

331 Research & Development Sr. No Project Definition Sector Duration of the project Budget (in Crores) Company % of R & D Net % of R&D % of R&D Net sales R&D R & D Exp R & D Exp Net sales Exp sales Exp Exp Exp GE (billion Dollar) Siemens (Billion Euro) Company Alstom (million Euro) Hitachi ( billion Yen) Mitsubishi Electric (million Yen) BHEL (million Rupee) 3.2 R & D Exp Net sales % of R&D Exp R & D Exp Net sales Energy storage schemes for improving the reliability of sensitive loads % of R&D Exp R & D Exp Distribution Net sales Short term % of R&D Exp NOTE: figures in last column with suffix * indicates sub components of the budget indicated for the area of research. 5* New Projects yet to be identified : Rs crores SUMMARY Total for Generation Total for Transmission Total for Distribution New Projects yet to be identified Total : Rs crores : Rs crores : Rs crores : Rs crores : Rs crores 5.7 R&D FUNDING R&D expenditures of some major utilities and manufacturers in the field of power are indicated below: It may be observed that most of the organizations spend between 1.8 to 6% of net sales on R&D depending upon the nature of their business. Compared to this, the R&D expenditure in India is very low. Page 17 of Chapter 5

332 Research & development NTPC has identified and taken up New Technology Development which started during the Xth Plan. About Rs. 400 crore in IGCC project was proposed out of which expenditure has been very little. NTPC has further envisaged to spend 0.5% of its profit (i.e. about Rs. 30 crore per year) in new R&D projects. The list of such project areas is given in para PGCIL has envisaged an expenditure of Rs.190 crore for R&D during in the areas of EHV transmission, monitoring of Substations, and power flow enhancement and grid availability. A list of projects identified by PGCIL is given in para. The provisions for R&D activities are built into the transmission projects to be taken up and do not reflect in separate R&D budget. BHEL s R&D efforts are directed towards development of technology in areas of their commercial /business interest BHEL have indicated that it is spending 1 to 1.5% of turn over on R&D and are prepared to participate in national level R&D projects in any of the following ways: a) If BHEL invests, they need some assurance of business and some relaxation in qualifying norms. b) BHEL shall participate in national level R&D without issues on commercial right or IPR provided that the entire funding is by the central government. BHEL s interest in R&D areas during 11 th plan is listed in para CSIR has identified a few projects for the XI Plan which are listed in para CSIR has a scheme New Millennium Technology Development Scheme in which it provides R&D funding to manufacturers without any IPR issues. At present, it is recommending funding to organizations like BHEL in technology development areas and IGCC. Coal India would continue its work on Coal Bed Methane(CBM) which was taken up through CMPDI during X Plan. The expenditure on R&D incurred by Coal India Ltd. during the X Plan was Rs. 7.5 crores and none of the work was in the areas related to Power Sector R&D Budget for 11 th Plan A substantial increase is recommended for the present level of R&D expenditure. As the investment in the Power Sector is going to be upwards of Rs.9 lakh crore, the Group recommends a budget approval of a modest 0.25% of it, which is around Rs crore in 5 years. The requirement of funds required for R&D during the 11 th crore. Plan would be Rs. Page 18 of Chapter 5

333 Research & Development Sl No Item Budget ( Rs in Crores) 1 R&D on Thermal& Hydro Generation, Fuels & Environment 2 Distributed Generation R&D and Demonstration Nano materials applications for power sector Transmission Distribution New Projects yet to be identified CPRI( Details in Para 5.4) TOTAL INTELLECTUAL PROPERTY RIGHTS A few of the IPR issues both in public & private domain have been reviewed. As a matter of fact, Government of India is the main funding agency & various institutions & industry are also contributing in terms of technical assistance, the IPR needs to be a shared model, specifically developed to match the present need. A general guideline of the proposed IPR model is given below. Since Government as such can t own the IPR, a corporate body is supposed to be constituted for the purpose. Complying with proposed institutional mechanism of project implementation, the IPR of individual research component (Sub project) will be owned jointly by the corporate body & individual research institute, carrying out the sub-project. If the executed project is a new technology demonstration, comprising of more than one research components involving system integration, the IPR for the developed technology as a whole will be owned by the corporate body & the project deploying agency (P1). The detailed mode of sharing the IPR & technology licensing for each project will be specific to the project & will be given a final shape only at the time of signing MOU between project implementation committee & individual research partners. 5.9 HUMAN RESOURCE DEVELOPMENT AND TECHNICAL COMPETENCE BUILDING India is on its accelerated path to become a global leader in power sector. It is not only anticipating additional capacity, but also expecting more competitive technologies both in terms of lower operating cost as well as lesser environmental pollution. In order to comply with the growth rate, it needs both skilled manpower for operating those plants as well as highly qualified research personnel to sustain a steady growth in technology development. The manpower requirement research centers are very specialized as fundamental research calls for a lot of dedication, clarity of concept, innovation and patience. It is very difficult to get this breed of researchers not only at induction level but also at middle and senior level. In order to match it research program, XI plan envisages certain expenditure for human resource development in power sector. Few of the proposed schemes are enumerated below. Page 19 of Chapter 5

334 Research & development Special fellowship scheme for research scholar employed for the purpose of carrying out research both at individual research centres as well as at project deployment stage. On completion of project, the researchers would be given an opportunity to get absorbed in the agencies, where the project would be deployed. Some of the research institutes should be assisted for developing them to Centre of Excellence (COE) with all required infrastructure. The success of the R&D projects will largely depend upon quality manpower, freedom for research and continuity of work. The budget for HRD is not specifically mentioned but included in the project cost. It is expected that project implementation authorities will have sufficient autonomy given to them for selection of research fellows RECOMMENDATIONS AND POLICY ISSUES. 1. Technology advancements and research & development have so far not been properly addressed. Major organizations like NTPC, NHPC, POWERGRID, on the generation side and BHEL, ABB, SIEMENS on the manufacturing side must enhance substantially their budget allocations for research and development. The utilities should aim at least about 1% of their profit to be utilized for research and development activities and the manufacturing organizations should consider 3-4% to be provided for technology development. 2. Networking of R&D resources and expertise would be an important strategy aimed at getting effective results. CPRI, apart from testing, must reorient its strategy and activities towards research. 3. Ultra Super Critical boiler technology, IGCC technology and oxy-fuel technology are well researched abroad but have to be developed for Indian coal. NTPC, the major Indian Central Sector utility should have its R&D centre strengthened to expedite the work started during 10 th plan on IGCC. It is recommended that this project may be given top priority and completed with the help of BHEL or with a private party if necessary. 4. There is a need to work with specialized S&T laboratories under CSIR & other space and nuclear establishments to develop material technology for advanced boilers, fuel cells, solar power, battery & super conducting material application in power sector. 5. For the projects of National interest to be taken upon collaborative research route the estimated R&D expenditure of 452 crores is recommended. It is also recommended that in future capital fund support for R&D should be reduced and utilities and industries should collaborate to fund R&D projects. 6. An institutional change in handling R&D is required. A suggestion is to have generation, transmission & distribution R&D units to be established as separate entities in the central sector undertakings or to set up a corporate technology centre for R&D activities in various areas of power sector Page 20 of Chapter 5

335 Research & Development 7. R&D import should be exempted from custom duty to encourage indigenous R&D 8. Power sector should seriously consider attracting young talents by offering them challenging opportunities. This will be possible by encouraging R&D and offering a good package, like many MNCs are offering at present. 9. A High Power Committee in R&D should monitor R&D projects and regulate funds. This will avoid duplication & ensure competitive R&D. 10. Organisations like CPRI and NPTI should be spared from manpower optimization rules where vacant positions are surrendered. This is in view of the depleting cadre of scientists and specialists in these organizations. ********* Page 21 of Chapter 5

336 Development of Power Sector in NER Chapter -6 DEVELOPMENT OF POWER SECTOR IN NORTH-EASTERN REGION 6.0 INTRODUCTION The North Eastern Region of the country comprises of 7 states; namely Arunachal Pradesh, Assam, Manipur, Meghalaya, Mizoram, Nagaland, Tripura and Sikkim. It is a land-locked region with ninety eight percent of its border being international. The land -locked area which constitutes 8 percent of the total area of the country is connected with the main land through chicken-neck across West Bengal. In view of the slow growth of the region, special focus has been laid on economic development of North-Eastern Region and Sikkim. Accordingly strategies have been formulated for removal of infrastructure bottlenecks and creating a conducive environment for overall progress of the region including private investment etc 6.1 STATUS AT THE BEGINNING OF 10 TH PLAN The Installed Capacity of North-Eastern Region was 2,230.3 MW at the beginning of 10 th Plan. This Installed Capacity comprises of MW from Hydro, 1,140.2MW from Thermal and 0.2 MW from Renewable Energy Sources. In addition, the Installed Capacity of Sikkim was MW including shares from Central Sector power stations at the beginning of 10 th Plan. State-wise details of Installed Capacity and Power Supply Position are given Table 6.1 and6.2 respectively: Table-6.1 Installed Capacity at the Beginning of 10 th Plan. (All figures in MW) Thermal Renewable State Hydro Coal Gas Diesel Total Energy Sources Total Assam Arunachal Pradesh Meghalaya Tripura Manipur Nagaland Mizoram Central Unallocated Total(NER) Sikkim Total (NER+Sikkim) Page 1 of Chapter 6

337 Development of Power Sector in NER State Table-6.2 Power Supply Position at the Beginning of 10 th Plan Peak Shortage / Surplus (MW) (%) Energy Shortage / Surplus (MU) (%) Assam Aru chal Pradesh Meghalaya Tripura Manipur Nagaland Mizoram Total(NER) Sikkim REVIEW OF generation CAPACITY ADDITION PROGRAMME DURING 10 TH PLAN Planning Commission had set a generation capacity addition target of MW in NER and 510 MW in the state of Sikkim during Tenth Plan. Out of these targets only 128 MW could be achieved during the 10 th Plan. Capacity addition of 100 MW is likely to be achieved during balance period of The State-wise details of capacity addition target and achievement during tenth plan is given in table 6.3 below: S. No. State/Central Sector Table 6.3 Generation Capacity addition (MW) Target Achievement From Expected Total to from to Assam Manipur Meghalaya Mizoram Tripura Arunachal Pradesh 7 Nagaland A State Sector B Central Sector C Total NER In addition to the target set by Planning Commission, Rokhia GT Ext. (21 MW) is also commissioned during 10 th plan Page 2 of Chapter 6

338 Development of Power Sector in NER INSTALLED CAPACITY AS ON The total Installed Capacity of NE Region (excluding Sikkim) as on was MW comprising MW hydro and MW thermal (including gas and diesel) and 46.9 MW from Renewable Energy Sources., The total installed capacity of Sikkim as on was MW comprising 44 MW hydro and 63 MW thermal (including gas and diesel) and 9.1 MW from Renewable Energy Sources. The State-wise details of Installed Capacity as on are given in Table 6.4 Table-6.4 (All figures in MW) Thermal Renewable Total State Hydro Coal Gas Diesel Total Energy Sources Assam Arunachal Pradesh Meghalaya Tripura Manipur Nagaland Mizoram Central Unallocated Total(NER) Sikkim Total (NER+Sikkim) ACTUAL POWER SUPPLY POSITION AS ON The State-wise actual power supply position as on is given in table 6.5 below: Table-6.5 Power Supply Position as on State Peak Shortage / Surplus Energy Shortage / Surplus (MW) (%) (MU) (%) Assam Arunachal Pradesh Meghalaya Tripura Manipur Nagaland Mizoram Total(NER) Sikkim Page 3 of Chapter 6

339 Development of Power Sector in NER 6.3 REASONS FOR SLOW PACE OF PROJECT EXECUTION Overall development of N.E region has been very slow. The basic infrastructure is inadequate and this is one of the reasons for development of various industries as well as power projects in this region. The sub-group deliberated on the reasons for the slow pace of power project execution, major ones is as follows: Difficulties faced in obtaining Environment & forest clearance, land acquisition, R&R issues. Hydro electric project sites are inaccessible and have very difficult approach/ maintenance of access roads. Lack of Infrastructural facility Inter State Aspects Geological surprises Inadequate Survey & Investigation Law and Order problems Shortage of Funds Inadequate organisational set in state sector for implementation of projects Decision of Arunachal Pradesh regarding type of Hydro schemes. 6.4 POWER DEMAND & SUPPLY ANALYSIS OF THE REGION An analysis has been carried out to assess the gap between power demand and supply position of the region. Data of the hourly generation and demand met has been examined and it is observed that there is shortage of power even during off peak hours of the winter season. It is estimated that by the year (at the end of 11 th plan) the demand of the North Eastern Region will be of the order of 2800 MW. To meet the peak shortages and even off-peak shortages during the winter season when the hydro availability is low, it is essential that NER should have base load generation capacity or alternatively allocation may be made from central thermal stations of the Eastern Region 6.5 GENERATING CAPACITY ADDITION PROGRAMME IN NORTH EASTERN REGION/ SIKKIM DURING 11TH PLAN Tentative capacity addition programme of 5615MW has been envisaged in North Eastern Region (including Sikkim) for the 11 th Plan. This comprises of 4055 MW hydro and 1560 MW of thermal power. Page 4 of Chapter 6

340 Development of Power Sector in NER Table-6.6 (Capacity in MW) N E Region 11 th Plan Total Hydro Thermal Coal Gas Diesel Total Assam Manipur Meghalaya Mizoram Ar. Pradesh Nagaland Tripura (*)750 Total(NER) Sikkim Total(NER+ Sikkim) The State-wise/Project-wise details are given at Annexure- 6.1 (*) It is learnt that power from this station will be sold to PTC 6.6 DEVELOPMENT OF TRANSMISSION SYSTEM IN NORTH EASTERN REGION Power System in NER The North Eastern Regional Power Grid comprises of transmission network of seven States of Arunachal Pradesh, Assam, Manipur, Meghalaya, Mizoram, Nagaland and Tripura with Central Sector system superimposed on it. Due to low magnitude of demand levels in most of the states, the growth and development of state transmission systems has been primarily at 132kV and 66kV levels. Due to its geographical location, Power System of Assam wheels power to other NER states through many of its transmission elements. The inter-state lines wheeling through Assam grid have been constructed as centrally sponsored schemes. Till regional grid of North-eastern region is developed to provide full connectivity to all the states, the wheeling of power to other states through Assam grid would continue Meeting the Power Supply Requirement of NER The power supply situation in NER remains better during monsoon period when availability from hydro-generating stations are good. During non-monsoon period and particularly during winters, shortage, both in terms of MW and MWh, are much higher due to low generation at hydro stations in the region. To meet the requirement of power in NER, it would be necessary that sufficient power from base load thermal stations located in Easter-region is allocated to the states of NER and major part of power from higher sized hydro station in NER such as Subansiri Lower (2000MW) and Kameng(600MW), is allocated to states outside NER. This would help the states of NER in two ways. While the additional allocation Page 5 of Chapter 6

341 Development of Power Sector in NER from thermal projects located outside NER to the states of NER would help in meeting their demand during low hydro generation period of winter months, allocation from hydro projects in NER to outside NER would help to regulate the surpluses during monsoon period when there is over-all higher availability in all the regions. Allocation from hydro projects in NER to states in NR/WR would also facilitate the development of the NER NR/WR inter-connecting HVDC transmission system. While considering allocation of power from generation projects in NER to outside NER and from thermal generation projects outside to NER to the states of NER, it needs to kept in view that the benefit of hydro development in NER is adequately passed on to the states of NER by leaving out sufficient surpluses with the NER states which they could trade profitably in the opened-up bulk power market. This would help in improving the commercial health of the NER states. However, if the surpluses are higher, and that too in monsoon period, trading of such power may not be profitable. Therefore, an optimum power allocation strategy needs to be adopted Regional Transmission System in NER Till 1984, the transmission network in the region was essentially comprised of 132kV and underlying networks, both in State as well as Central sector. Since then, with the planning of various hydro projects in the region, 220 kv transmission system was first commissioned in 1984 under Central sector for evacuation of power from Kopili Stage-I HEP (200MW). Subsequently, 400 kv Kathalguri-Mariani -Misa D/C line (operated at 220kV) and Misa-Balipara-Bongaigaon 400 kv D/C line as part of evacuation for Kathalguuri GBPP in Central sector, and Bongaigaon-Malda 400kV D/C line as an inter-regional line between ER and NER, were developed by This provided 400kV interconnectivity with the Eastern region. Subsequently, Ranganadi-Balipara 400kV D/C line was commissioned along with Ranganadi-I-HEP. Also, the Bongaigaon-Malda 400kV D/C line has been LILOed at Siliguri (one ckt in July 2002, other ckt in March 2005) and Purnea (one ckt in November 2003, other ckt in September 2005) in Eastern region.. The North-eastern regional grid has also been developed with 220kV and 132kV lines established in Central sector as associated transmission system for various generation projects viz. Loktak HEP, Agartala GBPP, Kopili HEP Extn, etc. Per unit cost of regional transmission in NER has been much higher as compared to other parts of the country. Five factors responsible for this are - (1) the cost of building transmission lines in NER is much higher due to uneven terrain and area specific factors; (2) the PLF of hydro stations, being inherently low, makes per unit cost of transmission higher; (3) higher cost in NER due to law and order problem; (4) due to delay in completion of Ranganadi-I HEP, while the 400kV Misa-Balipara- Bangaigaon lines were completed, the resulting under utilization of transmission system leading to higher per unit charges; and (5) 50% transmission charges for Bongaigaon-Malda 400kV D/C line on account of NER while Siliguri-Purnea-Malda section of the link utilized as part of eastern grid. It may be noted that factor (4) has since been addressed and (5) can also be addressed by appropriate revision of transmission tariff. Government and public efforts may also fructify to address the factor (3). However, factor (1) and (2) are inherent and would continue to push up the transmission tariff in NER. To the issue of higher transmission tariff in NER, Zonal Matrix Transmission Tariff method for location, distance and flow direction related Page 6 of Chapter 6

342 Development of Power Sector in NER allocation of National pooled transmission charges amongst the beneficiaries could be adopted as an effective solution. CERC has capped the regional transmission charges in NER at 35 paise/kwh. As a result, PGCIL is not recovering its full transmission charges. Due to non-recovery of its full transmission charges, PGCIL has not been making further investment in the NER transmission system and system strengthening in the regional/inter-state transmission system had been suffering. The issue needs to be addressed urgently. With intervention from MOP and CEA, urgent strengthening requirements in the regional system have been identified and taken-up for implementation by POWERGRID under scheme titled NER System Strengthening Scheme I. within existing transmission tariff ceiling of 35 paise/kwh. Works covered under this schemes are: NER System Strengthening Schemes I (i) (ii) 132 kv Kopili HEP Khandong HEP 2nd circuit Extension of Kopili S/S by 1x160 MVA, 220/132 kv transformer (3x53.3 MVA single phase units). (iii) LILO of Dimapur (Nagaland) Kohima 132 kv S/C at Dimapur (PG) (iv) Augmentation of Dimapur (PG) S/S by 1x100 MVA, 220/132 kv transformer Power Evacuation from North East Development of generation projects in NER envisaged during the XI plan period would add hydro as well as gas based generation capacity in NER. Generation from this capacity would be partly utilized locally to the extent of meeting the increasing load demands with development in the area and the balance, which would be the major part of the additional generation capacity, would need to be evacuated outside the region. For meeting power requirements for the states of NER, the component of allocation from these projects within NER would be utilized locally for which adequate transmission system with in NER both inter-state as well as intra-state would be required Transmission System Under State Sector Inadequate development of sub-transmission and distribution system facilities in the States of NER has been adversely affecting the reliability of power supply to the consumers and also hampering the load growth in the region. The transmission, subtransmission and distribution systems of states require major strengthening/upgradation. Transmission lines that are under outage require speedy restoration for bringing them into operation so that the states could avail their central sector shares as well as utilize their own generation without any constraint. Inadequacies in the transmission and distribution system had been on account of slow implementation of schemes due to various factors such as time consumed in E&F clearances, land acquisition, RoW constraints, fund limitation, organizational Page 7 of Chapter 6

343 Development of Power Sector in NER difficulties of state utilities, lack of vendor response due to locational factors, law and order, terrain specific difficulties, etc. Due to limited funding capabilities of state utilities, most of the required transmission projects are generally funded by NEC or by NLCPR under DONER and investment/funding approval of scheme so funded also takes additional time. All these issues need to be addressed to achieve the accelerated demand growth in NER. 6.7 EVACUATION OF POWER FROM MAJOR GENERATION PROJECTS IN THE NORTH-EASTERN REGION ALONG WITH POWER FROM PROJECTS COMING UP IN SIKKIM AND BHUTAN DURING THE 11TH PLAN AND EARLY 12TH PLAN PERIOD Generation projects of MW have been envisaged during the 11th Plan and early 12th Plan in the NER, Sikkim and Bhutan. The projects are Tripura Gas (750 MW), Bongaigaon Thermal (750 MW), Kameng HEP (600 MW), Subansiri Lower HEP (2000 MW), Siang Middle HEP (1000 MW), Tipaimukh HEP (1500 MW), Teesta- I, II, III, IV & VI HEPs in Sikkim (2700 MW), Phunatsangchu-I & II and Mangdechu HEPs in Bhutan (2600MW). The generation from these projects would be utilized in the NER, Sikkim and Bhutan, only to the extent of meeting the increasing load demands in the area. However, even with accelerated growth in local demand, substantial power from these projects would need to be exported to the power deficit regions that is the Northern Region and the Western Region. In order to have an optimum system and addressing the transmission corridor constraints in the chicken neck area (the chicken-neck refers to the area between Siliguri and Bidhan Nagar in West Bengal), a comprehensive transmission system has been evolved. The requirement of power evacuation through the chicken neck has been estimated corresponding to the capacity of hydro projects which may be feasible to develop say in the next years. This generation is estimated to be about MW in NER, about 8000 MW in Sikkim and about MW in Bhutan. Taking local development at accelerated pace resulting in demand within the NER, Sikkim and Bhutan to be in the range of MW (presently it is about 1500 MW), the transmission requirement through the chicken neck works out to be of the order of MW. With 800kV HVDC, each bi-pole line of 6000 MW capacity could be planned. The 400kV AC D/C lines with quad conductor in the hybrid system would be of 2000 MW transmission capacity. Multi-circuit of higher transmission capacity would also be considered in chicken-neck area. The total requirement including additional circuits for meeting the contingencies and reliability needs, would work out to 7 or 8 numbers of HVDC bi-pole lines and 4 or 5 numbers of 400kV double circuit lines a total of 12 numbers of high capacity transmission corridors passing through the chicken neck. For this, RoW requirement would be about 800 m and considering minimum distance between adjacent towers to be such that fall of any tower does not affect the adjoining line, a width of about 1.5 km would be needed. The option of 765kV transmission system has not found favor that besides a wider RoW, we have to take into account nature of hydro generation. While the system would need to be planned for full generation capacity, in winter months, when the generation would be much less and restricted to just peak hours, the lines can t be kept energized due to reactive power management and resulting high voltage problem. This would require frequent switching of the lines resulting in loss of Page 8 of Chapter 6

344 Development of Power Sector in NER reliability and also reduced life of equipment. Therefore 765kV bulk transmission would not be recommended choice in this case. The option of hybrid network of HVDC, and high capacity 400kV line has been found to be most suitable from cost, corridor, operational and phased development consideration. As the transmission distance from NER upto NR/WR is quite long kms, the requirement of keeping losses within reasonable and cost effective limits, suggests strongly in favor of adopting as high a HVDC transmission voltage as possible. At present the HVDC voltage for bi-pole transmission in India is 500kV. The highest HVDC system in world is at 600kV at Itaipu, Brazil, which is in operation since The next higher voltage of 800kV HVDC is under final stages of development. The first 800kV HVDC bi-pole line has been planned from a pooling substation at Biswanath Chariyali in North-eastern Region to Agra in Northern region. This is being programmed for commissioning matching with Subansiri Lower HEP in The transmission line would be for 6000 MW capacity and HVDC terminal capacity would be 3000 MW between Biswanath Chariyali and Agra and, for transmission of power from hydro projects at Sikkim and Bhutan pooled at Siliguri, another 3000 MW terminal modules would be added between Siliguri and Agra. It is envisaged to takeup the proposed 800kV, 6000MW HVDC bi-pole line from Biswanath Chariyali to Agra under a scheme titled Inter-regional Transmission system for power export from NER to NR/WR. This would the first scheme of its kind in the world and this would be a flagship endeavor towards a quantum leap in the Indian Power System. To supply the power from the various generation schemes catering to increasing demand within the North-eastern Region, system strengthening within the NER would also to be needed. The requirement of the system strengthening would depend on trend of demand growth in the states. The strengthening network in NER would also provide local anchoring of the network which would improve the reliability of the National Grid. Provision for system strengthening within NER would be kept in each of the generation related transmission schemes. 6.8 SPECIAL ATTENTION FOR DISTRIBUTION IN NE REGION The North East region is lagging behind in the development of the power sector compared to other regions. The region offers immense potential for the development of the electricity sector due to the huge hydro potential in the North East. The investments in and growth of transmission, sub-transmission and distribution systems have not matched the increase in generation capacity. As a result, there are constraints in electricity evacuation from generation stations. CEA has estimated that the share of the North East region is only 2.5%. In the consumer profile, domestic consumers accounted for 75% of the total consumers followed by commercial consumers which accounted for 11% of the total. Agricultural consumers accounted for 10% of the total while industrial consumers were 2.5%. As much as 40% of the Electricity consumers reside in Southern India, followed by Western India which accounts for 27% of the electricity consumers. Northern India accounts for 23% of the total electricity consumers while the East & Page 9 of Chapter 6

345 Development of Power Sector in NER North East together account for only 10% of the consumers. North East accounts for only 1.6% of all consumers. The above figures reflect the position of North East in the power sector development in the country. This regional imbalance needs to be corrected. In APDRP and RGGVY this region should get priority. In all the backward and north-eastern States the programme of electricity distribution projects need to be supported with low cost funds along with substantial portion of subsidy or grants. It is also felt that performing Middle/Senior level managerial personnel from the most progressive utilities may be deputed to utilities in North-eastern states to ensure quick deployment of initiatives already deployed in the progressive states. Also, personnel from Utilities in North-eastern states should be deputed in other utilities. All such deputation should range from a period of at least 6 months to 3 years. In all the backward and north-eastern States the programme of electricity distribution projects need to be supported with low cost funds along with substantial portion of subsidy or grants. Rural Infrastructure Development Funds (RIDF) available with NABARD should be utilized for the development of electricity distribution in the Northeastern and other backward regions of the country. For the System Improvement Schemes in these regions RIDF funds may be allowed to be utilized for making available cheaper credit for an accelerated development of these regions. 6.9 FUND REQUIREMENT The requirement of funds during XI Plan for generation projects has been estimated as about Rs. 15,375 crore. In addition, the matching Transmission and Distribution shall also need similar quantum of funds and thus overall requirement is estimated to be about Rs. 30,750 crore POLICY INITIATIVES AND RECOMMENDATIONS Following recommendations are made to overcome major problems being faced in project implementation in the N.E. Region and overcome the slow pace of development. The Survey & Investigation works, preparation of DPR, clearance from various organizations including MoEF have to be taken up and a time bound programme for clearance of hydro projects from various agencies including MoEF has to be formulated. A comprehensive plan for adequate road network be formulated taking into consideration various development projects including remote located hydro power station sites. Non availability of construction materials like cement steel etc and long procurement time makes the Hydro Projects costly and unviable. Setting up of Industries for construction material including Cement Industry may be encouraged in the North Eastern Region. Page 10 of Chapter 6

346 Development of Power Sector in NER Availability of power in NE Region reduces during winter season due to reduction in generation from hydro projects. Gap between demand and supply is of the order of MW. Therefore, NE Region has shortage of power during winters even during off-peak hours. Therefore, NE Region should have base load generation capacity i.e. thermal generation or allocation from central sector thermal stations of Eastern Region. For achieving accelerated load growth in NER, efforts are needed on all fronts. Specific efforts are needed in development in transmission at the regional level as well in the transmission, sub-transmission and distribution system at the state level. To supply the power from the various generation schemes catering to increasing demand within the North-eastern Region, system strengthening within the NER would be needed. The required transmission system in NER needs to be developed along with the power evacuation system. Hydro power development in NER would requirement of power to other regions through the chicken neck. The total requirement would be 7 or 8 numbers of HVDC bi-pole lines and 4 or 5 numbers of 400kV double circuit lines a total of 12 numbers of high capacity transmission corridors for which a total width of about 1.5 km in two or three corridors would be needed. The total right of way in chicken neck area needs to be reserved on priority. Establishment of manufacturing units for the electro-mechanical equipments in the region. This will help the region in establishment of a heavy industry, which will also generate considerable employment. ADB or any other suitable developmental agency to be engaged for comprehensive development of power projects in the NE Region. Extension of Rural Infrastructure Development Funds (RIDF) available with NABARD should be made available for the development of electricity distribution in the North-eastern and other backward regions of the country in order to get cheaper credit for an accelerated development of these regions. A national level training center for Distribution should be created in at least one of the North-eastern states by a Central Government Institution/body. ********** Page 11 of Chapter 6

347 Human Resource Development Chapter - 7 HUMAN RESOURCE DEVELOPMENT 7.0 BACK GROUND Human Resource Development and capacity building, in the present power scenario, demands a very comprehensive and pragmatic approach to attract, utilize, develop and conserve valuable human resources. Training, re-training and career prospects are some of the important elements of human resources development. The reforms in the power sector have led to change in the role of Senior Engineers from a purely Government controlled technical management to business management in a corporatised framework. Technically trained manpower comprising of skilled engineers, supervisors, artisans, and managers etc. is required in every sphere of the power supply industry. Growing concern over environmental degradation and depletion of the conventional energy sources has made the task of electricity generation even more challenging and therefore quality standard of the manpower is becoming increasingly essential. The technical knowledge acquired from engineering colleges, polytechnics, industrial training institutes and other technical institutions provides the basic foundation, but the same needs to be supplemented with applied engineering skills in the various spheres i.e. power generation, its transmission and distribution aspects. All these skills are to be regularly updated to cope with the rapidly advancing technologies and very often the speed of obsolesce overtakes the rate of acquisition of particular skill and knowledge. It has been noticed that due to the introduction of more sophisticated technology and automation, the Man/MW ratio is declining over the years. The Man/MW ratio in thermal sector has reduced from 4.71 in 6 th Plan to about 1.78 at the end of 9 th Plan; it is projected to touch 1.44 towards the end of 10 th Plan and is further expected to go down during the subsequent plans. The same trend is observed in the Hydro Power Sector also, where the Man/MW ratio of 6.04 in the Sixth Plan has come down to 2.2 at the end of Ninth Plan; it is expected to go down further to about 1.95 towards the end of 10 th Plan and even reduce in the subsequent Plans. The overall Man/MW ratio which was 9.42 at the end of 9 th Plan is expected to go down to 7.00 at the end of 10 th Plan and 5.82 at the end of 11 th Plan. This indicates the increasing importance of each individual, the man behind the machine. The HRD/Training needs of Technical, Non-Technical and Supporting Staff should be addressed keeping in view the National Training Policy for the Power Sector. In this Chapter, the existing manpower and training facilities in the Power Sector have been reviewed. A broad assessment has been made of the manpower requirements for construction, commissioning, O&M of Generation, Transmission, Distribution system during 11 th & 12 th Plans, taking into account present staffing pattern, requirements arising out of proposed capacity and network expansions, staff out turns on account of retirements and expected changes in technology etc. A Page 1 of Chapter 7

348 Human Resource Development review and assessment of training arrangements required have been made as well as measures for training of staff in various categories. have been suggested. The financial requirement of manpower planning and training arrangements during the 11 th & 12 th Plans have also been worked out. 7.1 ELEMENTS OF HRD PLANNING Comprehensive HRD planning involves the following elements: Organization: Organizational structure, position descriptions, responsibility and authority, delegation etc. Skills and Trades: Qualitative and quantitative assessment of skills and trades required at various points of time in future. Productivity and Performance: Utilization, control, performance appraisal, productivity development etc. Working Conditions and Facilities: Working environment, safety, health, fatigue, rest and facilities to workers, both inside and outside the factory. Salary and Wages: Working classification, wage structure, salary, administration, service conditions and fringe benefits. Recruitment: Recruitment, training, placement, phasing of recruitment and blending of requirements at different stages of construction, operation and growth. Motivation: Personnel development, promotion incentive, morale, satisfaction and attitudes. Industrial Relations: Trade Unionism, discipline, social, economic and political environment, group dynamics etc. 7.2 ASSESSMENT OF MANPOWER Capacity Addition Plan-wise Assessment of manpower during the plan periods is based on capacity addition during the respective plans and the norms for manpower. Besides this, 20% reduction of personnel during the plan period due to retirement, death, change of profession etc. and assumed 7.5% during the plan due to wastage, decommissioning etc is also made. Details of capacity addition during various Plans are furnished below: Page 2 of Chapter 7

349 Human Resource Development Sector End of 9 th Plan Addition in 10 th Plan End of 10 th Plan Table 1 Capacity in MW Additio n in 11 th Plan End of 11 th Plan Addition in 12 th Plan End of 12 th Plan Thermal 74,429 20,387 94,816 50,124 1,44,940 40, ,140 Hydro 26,269 8,854 35,123 15,585 50,708 30,000 80,708 Nuclear 2,720 1,400 4,120 3,160 7,280 12,000 19,280 Addition during the Plan Grand Total ,641 * 68,869 82,200 1,05,046 (1628 Wind ) 1,35,68 7 2,04,556 2,86,756 *- This includes 2578 MW on best efforts basis and further additional capacity of 2445 MW to require extra efforts. However in current scenario this capacity would slip to 11 th Plan and would therefore not change the capacity at end of 11 th Plan. As per latest indication, a capacity of 5,727 MW may slip to 11 th Plan because of various reasons including delay in supply and execution by BHEL Growth of Manpower Present Trend According to the National Electricity Plan, the total Manpower (Technical and Non- Technical) available at the beginning of 9th Plan i.e was of the order of 1,061.7 thousands. During the 9th Plan a capacity addition of 19,119 MW was achieved for which an additional manpower is estimated to be 60.9 thousands. The manpower available at the end of the 9th Plan i.e was of the order of thousands. This takes into account 20% reduction of personnel during the plan period due to retirement, death, change of profession etc. and assumed 7.5% during the plan due to wastage & decommissioning etc Manpower Assessment for 10 th Plan The actual capacity addition expected during the 10 th Plan is of the order of 30,641 MW*. The total manpower calculated at the end of 10 th Plan is estimated to be 9.50 lakhs for the total installed capacity of 1,35,687 MW. Details of calculations and assumptions are furnished in Tables 2 to Manpower Assessment for 11 th Plan Considering the proposed capacity addition of 68,869 MW during 11 th Plan (Table 1), the additional manpower requirement will be of the order of 3.44 lakhs out of which 2.62 lakhs will be technical and 0.81 lakhs Non-Technical. The total manpower at the end of 11 th Plan has been estimated at lakhs for the total installed capacity of 2,04,556 MW. Details of calculations and assumptions are furnished in Tables 9 to 16. Page 3 of Chapter 7

350 Human Resource Development Manpower Assessment for 12 th Plan Considering the proposed capacity addition of 82,200 MW during 12 th Plan (Table 1), the additional manpower requirement will be the order of 3.27 lakhs out of which 2.52 lakhs will be technical and 0.75 Non-Technical. The total manpower at the end of XII Plan has been estimated as lakhs. Details of calculations and assumptions are furnished in Tables 17 to 22. Table 2 Estimated manpower employees in power supply industry (utilities) as on (beginning of 10 th plan) (Figures in Thousands) S.No. Formation Technical Non- Total Technical 1. Thermal Generation* 2. Hydro Generation Nuclear Power System* Transmission Distribution Total These estimates do not include persons employed in civil construction works of power generation projects. *This includes steam, Gas and Diesel plants. **Personnel working in Transmission are considered 5% of the total working in Transmission and Distribution together. Table 3 Manpower available for the 10 th Plan after 20% reduction (due to retirement, death, change of profession 4% per year) (Figures in Thousands) Sl.No. Formation Technical Non- Total Technical 1. Thermal Generation 2. Hydro Generation Nuclear Power System Transmission Distribution Total Page 4 of Chapter 7

351 Human Resource Development Table 4 7.5% Manpower recouped during 10 th 1.5% per year (Figures in Thousands) Sl.No. Formation Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution Total Against the wastage of 4%, the intake will be of the order of 2% in view of improvement in quality, technology advancement and redundancy available in technical manpower at semi/unskilled level. It is also assumed that 0.5% of the total capacity is decommissioned annually and the manpower available from these units shall be utilized at other units thus the effective recouping of 1.5% every year. Table 5 Manpower available during the 10 th Plan after considering retirement of 20% and 7.5% recouping etc. (Figures in Thousands) Sl.No. Formation Technical Non- Technical Total 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution* - Hilly 10% Plains 90% Sub- Total Total *In Distribution 10% assumed for Hilly Terrains and 90% for Plains Table 6 Page 5 of Chapter 7

352 Human Resource Development Norms for Manpower (for 10 th Plan) Central & State Sectors per MW (Figures in Thousands) Sl.No. Formation Technical Non-Technical Central State Central State 1. Thermal (Total) 500 MW Unit < 500 MW Unit Gas/Liquid Fuel Hydro Nuclear Power System For Central & Private Sectors as per NTPC & NHPC For State Sector as per National Electricity Plan For T&D for 10 th Plan norms as per National Electricity Plan Table 7 Additional Manpower required due to capacity addition of 30,641 MW in 10 th Plan, T&D Line length of 8,26,863 ckt kms & 20 Crore consumers for Distribution Sl. No. 1. Formation Technical Centr al State (Figures in Thousands) Non- Total Technical State Central State Centr al Thermal Generation 500 MW Unit Below 500 MW Unit Gas/Liquid Fuel Hydro Generation Nuclear Power System Transmission(41443 ckm)* Distribution - Hilly - Plains Sub-Total Total Grand Total *Combined Lines of HV, EHV & UHV - Page 6 of Chapter 7

353 Human Resource Development Table 8 Total Manpower available at the end of 10 th Plan i.e. on (Figures in Thousands) Sl.No. Formation Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission(41,443 ckm) Distribution - Hilly - Plains Sub-Total Total Table 9 Manpower available during the 11 th Plan after 20% reduction (due to retirement, death, change of profession 4% per year) (Figures in Thousands) Sl.No. Formation Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution - Hilly - Plains Sub-Total Total Page 7 of Chapter 7

354 Human Resource Development Table % Manpower recouped during 11 th 1.5% per year (Figures in Thousands) Sl.No. Formation Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution - Hilly - Plains Sub- Total Total Table 11 Manpower available during the 11 th Plan after considering retirement of 20% and 7.5% recouping etc. (Figures in Thousands) Sl.No. Formation Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution - Hilly - Plains Sub- Total Total Page 8 of Chapter 7

355 Human Resource Development Sl. No. Table 12 Norms for Manpower (for 11 th Plan) (10% reduction due to Technological Achievements) (Figures in Thousands) Technical Non-Technical Central State Central State 1. Thermal (Total) 500 MW Unit & above Below 500 MW Unit Gas/Liquid Fuel Hydro Nuclear Power System Transmission Distribution - Hilly - Plains 1 Employee for 3.83 ckm 2.00 per 1000 Consumers 1.00 per 1000 Consumers Table 13-30% of the Technical Manpower Additional Manpower required due to envisaged Capacity Addition of 68,869 MW in 11 th Plan, HV, EHV, UHV Transmission Line lengths of about 1,00,000 Ct.kms and an estimated 16 crore Distribution Consumers for Central and Private Sectors (Figures in Thousands) Sl.No. Capacity (MW) Technical Non-Technical Total 1. Thermal 500 MW Unit & 34, above Below 500 MW Unit 13, Gas/Liquid Fuel 2, Hydro 15, Nuclear Power System Transmission Distribution Hilly Plains Sub-Total 1 lakh Ckms & 16 crore consumers considered do Total Page 9 of Chapter 7

356 Human Resource Development In Central & Private Sectors capacity addition through 500 MW and above is estimated at about 70% of total Thermal of Central & Private Table 14 Manpower required for State Sector (Figures in Thousands) Sl.No. Capacity (MW) Technical Non- Technical Total 1. Thermal (Total) > 500 MW Unit < 500 MW Unit Gas/Liquid Fuel Hydro In the State Sector Capacity Additions through 500 MW and above is estimated at about 30% of total Thermal in State Sector. Table 15 Additional Manpower required due to Envisaged Capacity Addition of 68,869 MW in 11 th Plan and HV, EHV & UHV Transmission Line Lengths of about 1,00,000 Ct.kms and an estimated 16 crores Distribution Consumers. (Figures in Thousands) Sl.No. Technical Non-Technical Total Central State Central State 1. Thermal Generation > 500 MW Unit < 500 MW Unit Gas/Liquid Fuel Hydro Nuclear Power System Transmission Distribution Hilly - Plains Total Page 10 of Chapter 7

357 Human Resource Development Table 16 Total Manpower required by the end of 11 th Plan (Beginning of 12 th Plan) i.e., on (Figures in Thousands) Sl.No. Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution - Hilly - Plains Sub-Total Total Table Hydro Generation Nuclear Power System Manpower available for the 12 th Plan after 20% reduction (Due to retirement, death, change of profession 4% per year) (Figures in Thousands) Sl.No. Technical Non- Total Technical 1. Thermal Generation Transmission Distribution Hilly Plains Sub- Total Total Page 11 of Chapter 7

358 Human Resource Development Table % Manpower required during 12 th Plan due to 1.5 per year (Figures in Thousands) Sl.No. Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution - Hilly - Plains Sub- Total Total Table 19 Manpower available for the 12 th Plan after 20% retirement and 7.5% (Figures in Thousands) Sl.No. Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Transmission Distribution - Hilly - Plains Sub- Total Total Page 12 of Chapter 7

359 Human Resource Development Table 20 Norms for 12 th Plan Sl.No. Technical Non- Technical 1. Thermal (Total) > 500 MW Unit < 500 MW Unit Gas/Liquid Fuel Hydro Nuclear Power System 1 Employee for 3.83 ckm 2 Employees per 1000 Consumers in Hilly Terrain 1 Employee per 1000 Consumers in Plains Norms for the 12 th Plan have been chosen as per the practice in CPSUs Table 21 30% of the Technical Manpower Additional Manpower in the 12 th Plan for the envisaged Capacity Addition of 82,200 MW, Transmission Ct. Kms of 63,000 and about 14 crore Distribution Consumers (Figures in Thousands) Sl.No. Technical Non- Total Technical Thermal Generation 1. Thermal 40, Hydro 30, Nuclear 12, Power System Total 82, Page 13 of Chapter 7

360 Human Resource Development Table 22 Manpower required at the end of 12 th Plan (Table ) (Figures in Thousands) Formation Technical Non- Total Technical 1. Thermal Generation Hydro Generation Nuclear Power System Total Based on the above estimation it is noted that the man/mw figure decreases as illustrated below Table 23 Man/MW Ratio during various Plan Periods End of Plan Period Overall Thermal Hydro Nuclear Power System 9 th th th th TRAINING Training is an organized activity for increasing the knowledge and skill of people for a definitive purpose. It should involve systematic procedures for transferring technical know-how to the employees for doing specific jobs with proficiency and to bring about improvement in their performance. It plays an important role in human resource development and is necessary, useful and productive for all categories of the organisation. Trained personnel are like valuable assets of an organisation and are responsible for the progress and stability of the organisation Training Strategy The Working Group has come to the conclusion that the most important component of the strategy should be Training for All irrespective of the level in the hierarchy. At least one week of training in a year must be provided to every individual. Five days Page 14 of Chapter 7

361 Human Resource Development training per annum per technical person based on National Training Policy is being implemented selectively at some utilities. This needs to be strictly implemented. The Strategy includes training at following levels: i) Induction level training for new recruits ii) Refresher/advanced training for existing personnel iii) Management training to the Senior Executives/Managers i) Induction Level Training: Induction level training is mandatory under Indian Electricity Rules for thermal and hydro power stations. Training is to be imparted in recognized training institutes and is of 52 weeks duration for Engineers, Operators, Technicians engaged in Thermal Generation. The training is of 39 weeks for Engineers and 26 weeks for Supervisors and Technicians working in Hydro Power Stations. In case of Power systems, the training is of 52 weeks for graduate Engineers and 26 weeks each for Supervisors and Technicians. ii) Refresher/Advanced Training The post employment training provides opportunities for personnel at different levels of organizations to gain new skills and take up new responsibilities and keep pace with advancement in technology. Also, specialized programs must be organized for improving the workmen s skill mainly in maintenance work. Training must be arranged for each individual on promotion, which calls for performing new/different roles and working conditions. Upgradation of skills at periodic intervals is necessary to keep pace with developments in the scientific world. This phenomena has entered into all areas of human life, but the need has been felt acutely, particularly in fields involving use of expensive, complex equipment like SCADA and for good O&M processes. The advent of automation and extensive use of computers has resulted in the creation of SIMULATORS. They have been found to be indispensable in periodic training of personnel in Thermal and Hydro Power Stations and also in Power System Networks. Simulators give a feel of the whole system to the trainee. Simulators need not necessarily be envisaged only for training in operation of equipment but also for systems, incorporating various experiences undergone by different personnel. Simulator happens to be a cost effective tool to provide highly interactive and high quality training to the operation personnel In view of the above the Working-Group recommends that Simulator training should be made compulsory for operation and maintenance staff of the Power Plants, including refresher training at suitable intervals. Page 15 of Chapter 7

362 Human Resource Development iii) Management Training Continuous development of Executives/Managers, specially at the transition period in their career and in the context of constantly changing business environment is of utmost importance. It has been noticed that while there are a large number of capable and knowledgeable engineers available in the Power Sector, their managerial ability needs to be improved. Due to process of reforms, restructuring, unbundling, privatization etc. the role of Managers have gained more importance. Executives in Finance and Management with non-technical background should also be provided technical orientation through suitable training programs. iv) Training for Nuclear Power Personnel Due to stringent safety requirements and other national and international regulations, every personnel working in Nuclear Power Sector is exposed to very specialized training. To meet the multi-disciplinary needs the Department of Atomic Energy (DAE) has built in-house training facilities both for professionals and Nonprofessionals and the well-established Nuclear Training Centre (NTC) at RAPS, MAPS and the TAPS. These Training Centres impart specialized training to their personnel. DAE has also established a few Nuclear Power Plant Simulators to impart specialized training to their personnel. Nuclear Power Corporation is fulfilling its training needs requirements in a long-term perspective. v) Training in Demand Side Management, Energy Efficiency And Energy Conservation There is a vast potential for energy savings through Human Resource Intervention. BEE has a major responsibility for simulating a major change in the energy efficiency ethos and practices (energy modesty) by directing the national energy conservation campaign as a mass movement and seeking wide support. In the 11 th Plan, BEE will continue with their campaigns. In addition it will guide and partially fund the SDAs for their respective campaigns in the states. A few target groups to be addressed by BEE include the Central Government Officials in the administrative Ministries and Departments by triggering ideas for accelerating energy conservation drive and addressing of Policy Barriers impeding the same. Round Tables on energy policy sponsored by MoP will be organized to deliberate on the related issues. At the state level, SDAs will develop synergistic partnerships to spread the activities in the interior locations with active involvement of the local community, chambers of industry and Commerce, DISCOMs, Professionals and the media. SDAs will organize energy conservation interactive meets and senior officials of the state Ministries and Govt. departments and state Govt. enterprises. The meets would Page 16 of Chapter 7

363 Human Resource Development focus on Policy support needed to step up the tempo of energy conservation movement in the states. Cadre of energy managers and energy auditors BEE is conducting examinations for certifying energy managers and energy auditors in collaboration with National Productivity Council. These efforts will be continued and periodically reviewed. BEE will also augment these efforts through distance learning programs, tutorial support to the prospective candidates for the national examination besides refresher programs to the certified energy managers/energy auditors. Orientation Programs: Top Level Industry personnel Energy efficiency improvement in India is still considered to be the engineer s domain, and CEOs and Chief Finance Officers are not yet aware that energy efficiency improvement has to improve the profitability of their companies. Industry bodies will be roped in by the SDAs for orienting top executives from the industry. Demonstrative Training operators SDAs may support skill development for operators on efficient energy use through demonstrative approach involving exposure of the participants to the best practices. This may also include setting up of two demonstration centers to show case energy efficient products through models, field visits and video presentations to simulate shop floor conditions. Farmers awareness programs Ministry of Power had mounted awareness programs with the support of manufacturers to demonstrate the energy efficient agricultural pumps in various Trade Fairs as well as local Fairs. Such efforts will be continued with the support of SDA, DISCOMs and other voluntary agencies. Drivers training PCRA has been very active in imparting drivers on fuel-efficient driving practices. It also has award schemes to motivate drivers and state transport agencies to achieve maximum fuel efficiency includes best kilometer per liter. These efforts will be extended. Campaign for General public & Youth National wide campaign on Energy Conservation will be mounted to publicize the simple ways of saving energy by involving the general public, the youth, government agencies, public and private sector, professionals. BEE will utilize mass media effectively for conveying the message of energy conservation. Yardsticks for evaluation of awareness campaigns will be developed. Page 17 of Chapter 7

364 Human Resource Development Energy conservation in curriculum There is a need for introducing module on energy conservation (EC) in the curriculum in schools and colleges. The EC concept will be introduced by modifying existing text of related subjects in school & college curriculum. Active involvement of NCERT, State Boards, Academic institutions, Universities will be ensured for review of the existing curriculum, training and sensitization of teachers and principals. Efforts would be put in for training /equipping the teachers of vocational schools, Industrial Training Institutes on inducting energy efficiency modules in the compulsory and optional subjects. The curricula for graduation /post graduation in engineering levels needs to suitably modify. Suitable modules will be included for the management education as well as finance, science and humanities streams (for subjects such as social sciences, economics, environmental education, etc. vi) Training in Information Technology Information technology has pervaded all spares of life, adequate training according to the job requirement should be provided in the field of information technology. Use of IT should be promoted and maximum number of personnel should be made computer literate. As information technology is also developing very fast, the training should be dynamic in nature to ensure that knowledge and skill of people are in tune with latest development in the field of IT. Employees should also be made aware of the Right to Information Act. vii) Introduction of Training on attitudinal changes/ behavioral sciences. Attitude of an individual plays an extremely important role in contributing to his/her performance level. Thus, in spite of availability of the best of knowledge and skill, the ability of providing the desired services may still be found wanting in individuals if they are not imbued with appropriate attitudinal disposition. It has been observed that the training is presently concentrated mainly in the area of acquisition of knowledge and upgradation of skill and very little emphasis is given on attitudinal changes/behavioral sciences as it is high time to introduce this aspects of training in the management curriculum of induction level training as well as retraining programs. In some of the Utilities behavioral science has achieved very good results particularly with respect to the attitudinal change of the lower category of personnel. After undergoing such training, the personnel develop a sense of belongingness to the organization. In Addition To Technical Skills, Power Professionals, Need To Have Life Skills Such As: Communication Skills Time Management Team Work Technical Writing Ethics Page 18 of Chapter 7

365 Human Resource Development Training Load Training requirement for 11 th and 12 th Plans have been worked out on the basis of manpower projections with the following assumptions: i) Induction training to all freshly recruited technical persons as per statutory requirements under Indian Electricity Rules. ii) iii) For all freshly recruited non-technical staff induction training of three months for executives and one month for non-executives. Minimum one week training (Refresher/Managerial/Attitudinal) every year for all personnel. Overall training load during 11 th Plan is estimated as 4.65 lakh man-months/year against the available training infrastructure of 0.77 lakh man-months/year. Out of the total, training load for technical people is estimated as 3.64 lakh man-months/year (Appendix 7.1). The estimation for non-technical personnel is 0.73 lakh manmonths/year (Appendix 7.2). While assessing the above, Assumptions made are: 1. One week refresher training for all employees. 2. Fresh Manpower on account of re-coupment and capacity addition not considered for refresher training. 3. For Non-Technical staff induction level training duration is 3 months for Executives & 1 month for Non-Executives % of the refresher training load is taken as training load for Management training including behavioural component Overall training load during 12 TH Plan is estimated as 4.78 lakh man-months/year against the available infrastructure of 0.80 lakh man-months/year. Out of the total training load for technical people is estimated as 3.98 lakh man-months/year (Appendix 7.3). The estimation for non-technical personnel is 0.80 lakh manmonths/year (Appendix 7.4). While assessing the above, Assumptions made are: 1. One week refresher training for all employees. 2. Fresh Manpower on account of re-coupment and capacity addition not considered for refresher training. 3. For Non-Technical staff induction level training duration is 3 months for Executives & 1 month for Non-Executives % of the refresher training load is taken as training load for Management training including behavioural component Basically three types of training infrastructure/facilities are available: i) Training institutes recognized by CEA for imparting statutory induction training Page 19 of Chapter 7

366 Human Resource Development ii) Lineman Training Institutes Other Training facility (Class/board rooms for refresher/ management programs) including networking with academic/training institutions outside power sector Training Infrastructure-Requirements vis-à-vis availability It may be seen from Appendix 7.1 that during 11th Plan the availability of infrastructure is about 0.77 lakh man-months against the requirement of 3.40 lakh man-months/year i.e., a deficit of about 77%. It may be noted that inspite of such a situation of lack of availability of required infrastructure, quite often a number of training institutes remain under utilized. The Sub Group also stressed on Networking with the training/academic institutions like NPTI, IIMs, ASCI and other reputed institutions for providing training to power sector personnel and other stakeholders. 7.4 FUNDING & CAPITAL OUTLAY Establishing and sustaining a continuous training initiative needs adequate funds. Decision makers must appreciate that training is an investment and not a mere expenditure towards a ritual. The funds required for training can broadly be categorized under two heads, Capital outlay (Plan) and Recurring Expenditure (Non Plan). The fund required for creating training infrastructure is booked under the first one while expenses towards salaries, TA/DA training fee etc. comes under the second. 10 major states should set up State Level Training Institutes encompassing training infrastructure for Induction level, Linemen and for Franchisees. GoI may provide part funding of Rs 10 Crores for each state. An incentive to the sponsoring Rs 2000 per man-week of Refresher Training (towards part Training Fee Component only) may be provided by GoI to the institute providing training. Approximate outlay during the 11th Plan will be 100 crores. Central assistance of about Rs 140 Crores may be provided for setting up National Level Transmission, Distribution and a Hydro Institute. GIS Based Electrical Distribution Systems to be set-up in various regions for training. Budgetary allocation of Rs 6.00 crores is proposed. For Upgradation of various labs and Infrastructure of National Institutes, 100 crores is proposed. A 660 MW Super Critical Power Plant Simulator at a cost of Rs Crores is also proposed. Page 20 of Chapter 7

367 Human Resource Development The Total Plan period outlay is about Rs 462 Crores. This does not include the plan fund outlay proposed by other Sub-Groups The Working Group recommends Training Institutes and Centers to enter into bilateral/multilateral agreements with various funding agencies such as UNDP, USAID, GTZ, World Bank, ADB, Japanese Aid etc., through appropriate forums such as MoP, State Boards /Utilities for the development of state-of-the-art training facilities. Recurring Expenditure 5% of Salary budget should be earmarked exclusively for training by every organization. Expenditure towards training may be included while costing for power tariff like other essential cost heads like servicing of capital, fuel charges, salary, insurance etc. and this expenditure should be reflected in the annual balance sheet of the organization. 7.5 MAJOR RECOMMENDATIONS Every employee should be provided refresher training of minimum one week per year as mandated in National Training Policy. Statutory rules provide for periodical refresher training for all O&M personnel in different segments. In addition, refresher training to all power sector personnel as per their requirement should also be included. A national programme also needs to be launched for training and capacity building for upgrading and enhancing the skills of franchisee who are proposed to be deployed on a large scale for small as well as urban areas. ********** Page 21 of Chapter 7

368 Human Resource Development S. No Training Load during 11 th Area Category Appendix 7.1 Plan for Technical (Includes Infrastructure) in Thousand-Man-Months (TMM) Manpower to be trained in Thousands Average duration in Months Total for 11 th Plan Thou-Man- Months Per year Thou- Man- Months (A) On-Job compone nt 50%of (A) Infrastructure required per year (TMM) Infrastructur e available in 10 th Plan + 5% (TMM) Surplus (+) Deficit (-) Thermal (Induction) Engrs 30% Engineers Opers 15% Op/Sup/JEs Tech 55% Technicians Sub-Total Hydro(Induction) Engrs 20% Engineers Oper 35% Op/Sup/JEs Tech 45% Technicians Sub-Total Power System (a) (b) Transmission (Induction) Engrs 10% Engineers Oper 20% Op/Sup/JEs Tech 70% Technicians Sub-Total Distribution (Induction) Engrs 10% Engineers Oper 20% Op/Sup/JEs Tech 70% Technicians Sub-Total Refresher Course Refresher Course 5. Management Management Training (20%) Grand Total Page 22 of Chapter 7

369 Human Resource Development Appendix 7.2 Training Load during 11 th Plan for Non-Technical (Includes Infrastructure) in Thousand-Man-Months S. No. Area Category Manpower to be trained in Thousands Average duration in Months Total for 11 th Plan Thou-Man- Months Per year Thou- Man- Months (A) On-Job component 50%of (A) Infrastructur e required per year (TMM) Infrastructu re available in 10 th Plan + 5%(TMM) Surplus (+) Deficit (-) 1. Thermal (Induction) Exec 20% Executives Non-Exec 80% Sup/UDCs /LDCs etc Sub-Total Hydro(Induction) Exec 20% Executive Non-Exec 80% Sup/UDCs /LDCs etc Sub-Total Power System (a) Transmission (Induction) Exec 20% Executive Non-Exec 80% Sup/UDCs /LDCs etc Sub-Total (b) Distribution (Induction) Exec 20% Executive Non-Exec 80% Sup/UDCs /LDCs etc. Sub-Total Refresher Course Refresher Course 5. Management Training Management (20%) Grand Total Page 23 of Chapter 7

370 Human Resource Development S. No. 1. Appendix 7.3 Training Load (Induction) during 12 th Plan for Technical (Includes Infrastructure) in Thousand-Man-Months Area Category Manpower to be trained in Thousands Averag e duratio n in Month s Total for 12 th Plan Thou- Man- Months Per year Thou- Man- Months (A) On-Job componen t 50%of (A) Infrastructure required per year (TMM) Infrastructure available in 11 th Plan + 5% (TMM) Surplus (+) Deficit (-) Thermal (Induction) Engrs. 30% Engineers Oper 15% Op/Sup/JEs Tech 55% Technicians Sub-Total Hydro (Induction) Engrs. 20% Engineers Oper 35% Op/Sup/Jes Tech 45% Technicians Sub-Total Power System (a) Transmission (Induction) Engrs. 10% Engineers Oper 20% Op/Sup/JEs Tech 70% Technicians Sub-Total (b) Distribution (Induction) Engrs. 10% Engineers Oper 20% Op/Sup/JEs Tech 70% Technicians Sub-Total Refresher Course Refresher Course Management Management Training (20%) Grand Total Page 24 of Chapter 7

371 Human Resource Development S. No Appendix 7.4 Training Load (Induction) during 12 th Plan for Non-Technical (Includes Infrastructure) in Thousand-man-months Area Category Manpower to be trained in Thousands Thermal (Induction) Average duration in Months Total for 12 th Plan Thou- Man- Months Per year Thou- Man- Months (A) On-Job compone nt 50%of (A) Infrastructur e required per year (TMM) Infrastructure available in 11 th Plan +5% (TMM) Surplus (+) Deficit (-) Exec 20% Executives Non-Ex 80% Sup/UDCs /LDCs etc Sub-Total Hydro(Induction) Exec 20% Executives Non-Exec 80% Sup/UDCs /LDCs etc Sub-Total Power System Transmission (Induction) Exec 20% Executives Non-Exec 80% Sup/UDCs /LDCs etc Sub-Total Distribution (Induction) Exec 20% Executives Non-Exec 80% Sup/UDCs /LDCs etc. Sub-Total Refresher Course Refresher Course 5. Management Training Management (20%) Grand Total Page 25 of Chapter 7

372 Legislative and Policy Issues Chapter-8 LEGISLATIVE AND POLICY ISSUES 8.0 BACK GROUND The Electricity Act 2003 has put in place a liberal and progressive framework for the development of electricity sector in the country. Its main objectives are promoting competition, Protecting interest of consumers, Supply of electricity to all areas, Rationalization of electricity tariff and ensuring transparent policies regarding subsidies. The National Electricity Policy and the Tariff Policy have been notified under the provisions of the Act. The National Electricity Policy, inter-alia, aims at Providing access to electricity to all in next five years, Overcoming energy and peaking shortages and having adequate spinning reserves by year 2012 for fully meeting the demand, Supply of reliable and quality power of specific standards in an efficient manner and at reasonable rates. The Tariff Policy aims at ensuring financial viability of the sector and promoting transparency, consistency and predictability in regulatory approaches. It also aims at promoting competition and efficiency in operation and meeting quality of supply. The Working Group deliberated on the specific recommendations made in the Integrated Energy Policy and National Electricity Policy and recommended measures for their implementation. The Integrated Energy Policy and the National Electricity Policy endeavor to fundamentally change the Power Sector to function in an open, competitive regime under regulatory oversight. The provisions of these Policies must be implemented within the stipulated time in order to make power available at affordable cost to all by This Chapter includes the provisions of the Policies and measures recommended by the Working-Group for their implementation. In certain cases provisions of the Policies are countered by the Working-Group, in case of which the Government may take appropriate action. Comments of Prayas Energy Group are enclosed at Appendix 8.2 and IIT Kanpur are enclosed at Appendix IMPLEMENTATION OF PROVISIONS OF ACT AND POLICIES The legal provisions of the Act, National Electricity Policy, Tariff Policy and the Integrated Energy Policy provide an appropriate legislative and policy framework for the development of the country. There is a need to implement these at the earliest to achieve the stated goals. Page 1 of Chapter 8

373 Legislative and Policy Issues 8.2 STATUS OF IMPLEMENTATION AND DEVIATIONS OF INTEGRATED ENERGY POLICY The Integrated Energy Policy announced by the Government aims at overall development of the Energy Sector. It is essential that its recommendations are implemented within the stipulated time period in order to realize the benefits envisaged, Details of the recommendations of the Policy and the status of their recommendations are as furnished below: 1. Recommendation : Bifurcate agricultural pumping load from the non-pumping load in all rural feeders and use available technological measures to limit and measure the amount of energy supplied to pumps. Position Being recommended by the Working Group 2. Recommendation : To introduce automatic meter reading at distribution transformers to pinpoint theft of electricity. To introduce an incentive scheme for staff whereby they share additional revenue collected in their distribution circle. Position Tariff Policy (para 8.2.1(2)) provides that SERCs may encourage suitable local area based incentive and disincentive scheme for the staff of the utility linked to reduction in losses. Further, States are being advised to introduce suitable incentive schemes for rewarding informers who assist in control of theft. 3. Recommendation : The data about AT&C losses should be disseminated to the public to create support for corrective action. Position The National Electricity Policy (para ) provides that the data reliable index should be compiled and published by the Central Electricity Authority. Similar action should be taken in respect of feederwise AT&C losses. 4. Recommendation : For all loads above 50 kwh, intelligent metering to facilitate real time and remote recording should be adopted. Position The National Electricity Policy (para ) provides adoption of modern IT systems with due consideration to costs and benefits. 5. Recommendation : Introduce time-of-day pricing with shift to electronic meters. Page 2 of Chapter 8

374 Legislative and Policy Issues Position CEA s Metering Regulations provide that all new consumer meters would be of electronic type. The Tariff Policy (para 8.4) provides that time differentiated tariff shall be introduced on priority for large consumers (above 1 MW) within one year. 6. Recommendation : All Central assistance to States in power sector must be linked exclusively to loss reduction and improved viability. Position Being recommended by Working Group. 7. Recommendation : Management reforms particularly in the distribution sector are as important as a liberal captive and open access regime. Position Working Group has given specific recommendations in this regard. 8. Recommendation : Involve stakeholders for successful regulation. Appoint an office of Consumer Advocate at State level. Position Working Group has recommended encouraging participation of consumer organizations in the regulatory process. The Electricity Act provides for Ombudsman to look into settlement of consumer grievances. The Electricity Rules, 2005 provide for six monthly report of the ombudsman to the Regulatory Commission in this regard. 9. Recommendation : Strength of dominant public sector can be effectively leveraged to introduce competition that extracts efficiency gains in generation, transmission and distribution. Position The Working Group has also recommended that the public sector companies should be encouraged to participate in the competitive bids. 10. Recommendation : In case of tariff determination based on costs and norms, the Regulatory Commission may adopt either ROE approach or ROC approach whichever is considered better in the interest of consumers. Position Tariff Policy (para 5.3(a)) provides for this. 11. Recommendation : Distribution should be bid on the basis of distribution margin or paid for by a regulated distribution charge. Page 3 of Chapter 8

375 Legislative and Policy Issues Position Tariff Policy (para 5.3(a)) provides that the SERC may consider distribution margin as basis for allowing return in distribution. 12. Recommendation : All generation and transmission projects should be developed through competitive route with a transition window of 5 years for public sector. Position Tariff Policy (para 5.1) already provides for this. 13. Recommendation : Liberal captive and group captive regime should be realized on the ground on the basis of competitive wheeling charges. Position Tariff Policy provides for this and Forum of Regulators has been requested to expedite this. 14. Recommendation : Any subsidy given to poor households or farmers should be funded from the State Government budget. Position Section 65 of the Electricity Act already provides for this. 15. Recommendation : Existing projects and future investment which are not competitively bid must comply with CERC tariff guidelines. Position This is already provided in section 61 of the Act which makes it mandatory to follow CERC s principles and methodologies in respect of tariff for generation and transmission. 16. Recommendation : Regulators should set tariff for a number of years and differentiate them by time-of-day. Position Tariff Policy (para 5.3(h)) provides that the Multi Year Tariff is to be adopted for tariffs to be determined from April 1, The policy also provides for TOD tariffs. 17. Recommendation : Respective regulators should adopt best international practices for harnessing distributed generation with waste heat recovery, Demand Side Management and energy conservation. Position This is already provided in the National Electricity Policy and needs to be implemented. 18. Recommendation : Regulators must establish feed-in-tariffs for power from renewable energy sources. Such tariffs should provide Time of day benefits. Page 4 of Chapter 8

376 Legislative and Policy Issues Position Tariff Policy in its para 6.4 provides for competitive procurement of power from non-conventional sources of energy. The policy envisages bidding among the suppliers from same sources of non-conventional energy. To elaborate, bids are required to be called separately for energy from solar based plants, wind based plants, biomass based plants etc. The Tariff Policy also provides that the Appropriate Commission may introduce differential rates of fixed charges for peak and off-peak power for better management of load. 19. Recommendation : Separate content from carriage in both transmission and distribution with regulated caps for wheeling charges at different voltages and distribution margins for consumers. Introduce competition in building transmission capacity on the basis of wheeling tariffs and in distribution on the basis of distribution margins. Position The Act debars Central Transmission Units (CTU) from trading. Tariff Policy already provides for developing transmission projects through competitive bidding. The policy also gives option of adopting distribution margin as a method for regulating distribution. 20. Recommendation : Transmission lines critical for inter-state flows of power and for system stability should be managed by the Central body even if such lines are entirely in one State. Position CERC has full jurisdiction over inter-state transmission of electricity. Such inter-state transmission includes conveyance of electricity within a State also. 21. Recommendation : Independent and/or fully transparent load dispatch is required to create level playing field. Position RLDC is under the control of the Central Commission. Presently, RLDCs are being operated by CTU i.e. Power Grid. This function of CTU could be ring fenced adequately to ensure transparency. 22. Recommendation : An independent planning body is necessary for transmission networks. Page 5 of Chapter 8

377 Legislative and Policy Issues Position According to section 3 of the Electricity Act, 2003, CEA has to prepare the National Electricity Plan in accordance with the National Electricity Policy. The National Electricity Policy provides that CEA shall prepare short-term and perspective plan. Further the plan has to include transmission planning also. The National Electricity Policy (para 5.3.2) provides that the CTU and the STU shall discharge responsibility of network planning and development based on the National Electricity Plan in coordination with all concerned agencies as provided in the Act. This arrangement takes care of planning by an expert body CEA and necessary coordination in network expansion by the respective transmission utility. 23. Recommendation : Require the State Governments to notify rural areas under section 14 of the Act. Position The Rural Electrification Policy (para 8.2) provides that the State Governments would notify the rural area for this purpose within two months. 23 States have already issued notifications. 24. Recommendation : To facilitate distributed generation and promote renewable sources of energy, make mandatory setting up grid interconnections for feeding surplus power into the grid at the grid s avoided cost. Position Tariff Policy (para 6.4) provides for competitive procurement of power from non-conventional sources of energy. 25. Recommendation: Encourage the organized sector to adopt rural communities in their areas of operation for setting up offgrid and distributed generation facilities and involve local community. Position The Rural Electrification Policy (para 8.8) provides for a special enabling dispensation for setting up standalone system upto one MW using locally available resources. This needs to be implemented at the earliest. 26. Recommendation : Augment exploration/drilling capacity of CMPDIL and it should also be given more autonomy. Open up coal exploration for other players also. Position Working Group has given recommendations in this regard. Page 6 of Chapter 8

378 Legislative and Policy Issues 27. Recommendation : Allocate coal blocks in competitive and transparent way creating a level playing field with a condition that these blocks be brought into production by year Transfer pricing of coal from captive mines needs to be established both for assessing royalties as well as tariffs in a regulated sector such as power wherein coal cost is a pass through. Position Working Group has recommended allotment of captive coal blocks in a transparent and competitive manner.to power generation projects based on competitive bidding for lowest cost of electricity. 28. Recommendation : Rail freight rates for coal transport should be rationalized. Position Working Group recommends implementation of this measure as it is essential for lowering the cost of power 29. Recommendation : Simplify procedures for preparation of EMPs for coal mining. Create a reserve of compensatory afforestation in advance. Position Working Group recommends implementation of this measure as it is necessary to accelerate captive coal mining. 30. Recommendation : A regulator in coal sector for regulating allotment and exploitation of coal blocks, for approving coal price revisions. Position Working Group recommends implementation of this measure. 31. Recommendation : Coal linkages should be made tradable in the first instance with long term objective of replacing the current coal linkages for power plants with fuel supply and transport agreements. Position Working Group opines that there is a requirement to convert the coal linkages into formal fuel supply contracts catering to full requirement of the power plant. However, there is a need to be cautious in implementation of this recommendation for making coal linkages tradable as there is a possibility of speculative trading leading to increase in price of fuel. 32. Recommendation : Include natural gas and LNG in the category of declared goods so that only central sales tax of 4% is levied. Page 7 of Chapter 8

379 Legislative and Policy Issues Position Working Group recommends implementation of this measure. 33. Recommendation : In the present scenario price of domestic natural gas, its allocation should be independently regulated on a cost plus basis including reasonable returns. Position Working Group has also recommended this. 34. Recommendation : The Integrated Energy Policy gives two options for ensuring environmental impact. First option is to impose environmental tax and give subsidies. Second option is setting up emission and energy conservation standards on the equipments. Position The Integrated Energy Policy provides for optional strategies. Second option of setting emission and energy conservation standards on equipments is more suitable for power sector and can be implemented easily. The National Electricity Policy also provides that all generating stations should ensure full compliance with prescribed environmental norms and standards. This is considered to be a better option than imposing environmental tax. Environmental tax would raise the cost of electricity which is a basic infrastructure requirement and would adversely affect development of our economy. Instead of taxes, penalties should be imposed on those who fail to comply with the laid down standards. 35. Recommendation: Institutionalize the selection of regulators and their impact assessment under the regulatory academy. Position Setting up the suggested regulatory academy would be appropriate for capacity building in the staff of various regulatory bodies. The selection of the regulators is governed by the relevant provision of law. However, there is a genuine concern about the outcome of the selection process in case of some of the State Electricity Regulatory Commissions. Since the electricity is a concurrent subject, ways and means to strengthen and improve the selection process at State level needs to be discussed in depth with the State Governments. Assessment of impact of regulatory process is being done by NGOs and other similar organizations. 36. Recommendation : Mandate training for all regulators. Position Recommended by the Working Group. Page 8 of Chapter 8

380 Legislative and Policy Issues 37. Recommendation : Grant financial autonomy to regulatory institutions. Position The Electricity Act already provides for a fund for each Regulatory Commission. 38. Recommendation : Make regulators accountable to the Parliament and mandate annual reports. Position This is already provided in the Act. Format of the reports has been laid down in the rules. 39. Recommendation : With reference to Mega Power Policy, there should be no discrimination in available incentive based on the size or type of technology or fuel used. Position Working Group opines that this needs further examination. 40. Recommendation : The Central Government and the State Governments and FIs should develop long term (20 years plus) debt instrument. Position This would be necessary in view of the provisions of the Tariff Policy to dispense with advance against depreciation. 41. Recommendation : Special policies for encouraging renewable energy should be for a well defined period or upto a well defined limit in a way that encourages outcome and not just outlays. Position Working Group has given specific recommendation in this regard. 42. Recommendation : The environmental subsidy for renewables could be financed by a cess on non-renewables and fuels causing environmental damage. Page 9 of Chapter 8

381 Legislative and Policy Issues Position This would increase the cost of electricity across the board. The Electricity Act provides for preferential purchase from non-conventional sources to the extent specified by the Regulatory Commission taking into account local situation. The National Electricity Policy provides for preferential charges for procuring energy from non-conventional sources in view of the fact that such non-conventional technologies would take some time to compete with conventional sources in terms of cost. The Tariff Policy stipulates that these technologies would compete with conventional sources in the long term in terms of full costs. Some of the non-conventional sources like wind have almost reached the stage of selfsustainability. To promote non-conventional source further, there is a need to provide for a long term financing because initial capital cost is higher in these cases. 43. Recommendation : Supply companies/ entrepreneurs could be free to set up micro grid and recover revenues from customers. Position The Rural Electrification Policy (para 8.8) provides for a special enabling dispensation for setting up standalone system upto one MW using locally available resources. Working Group also recommends that this needs to be implemented at the earliest. 44. Recommendation : A charge of Rupee one per unit for the first 30 units per month could be levied on poor households. Position National Electricity Policy (para 5.5.2) provides for cross subsidized tariff for 30 units per month for BPL households. 45 More Effective Planning & Implementation Recommendation in Policy (Pg. 114 Cl 18) - Policy stipulates In order to avoid shortages and take timely action, annual electricity requirements should be projected and year-wise targets for generation capacity be set for seven years. Each project should be monitored along with a number of milestones.. Working-group Implementation The achievements in capacity addition during 8th & 9th plan periods have been merely 50% of the plan target. Also during 10th Plan the actual capacity addition is expected to be about 31,000 MW against the plan target of 41,110 MW. The Working-Group deliberated on the reasons for this large variation and recommended as follows:- Page 10 of Chapter 8

382 Legislative and Policy Issues The status of preparation and approvals etc. for each of scheme included in the 11TH Plan must be realistically assessed and the sponsoring entity must indicate 5 to 6 time based milestones for each scheme. Plan document should indicate scheme wise commissioning targets for 7 years (5 years of the Plan period and first two years of the next plan) and monitoring should be done for all these schemes so that substantial capacities are commissioned from the first year of the Plan onward. However, for 11th Plan, five year plan period may be considered. Since Hydro & Nuclear Projects have comparatively larger Gestation period, planning for their projects shall be for a period of 10 years. In order to facilitate timely implementation of projects, capacity building in respect of infrastructural requirements like road, railways, erection, manufacturing etc. is essentially to be ensured. Well structured plans need to be evolved to ensure this aspect. Demand adopted for Planning 46. Recommendation in Policy ( Pg 20, Table 2.5) Policy has projected the following installed capacity requirements during the subsequent Plans corresponding to 8% and 9% GDP growth: (Fig. in GW) Plan 8% GDP Growth 9% GDP Growth 11th th th th th (till ) Working- group deviation The Working-Group recommends that generation capacity addition shall be planned by adopting demand projections as per the current Report of Electric Power Survey rather than GDP growth rate. The Electric Power Surveys assess the demand based on a systematic, detailed analysis of electric utilization in various sectors of consumption and the expansion plans of various sectors. These figures are also validated by econometric model. However for Plans beyond that covered by the current EPS, growth as per Government s GDP growth plans and elasticity figures could be adopted. For 12th Plan we have worked out demand taking 7%, 8% & 9% growth with elasticity of 0.9 & 1.0 in each case. The demand as per the EPS Reports has therefore been found to be very close to the actual demand and therefore its adoption for working out the generation capacity addition would be more accurate then assuming the same GDP growth for each sector of our economy. Page 11 of Chapter 8

383 Legislative and Policy Issues 47. Use of Washed Coal Recommendation in Policy (Pg.xv Cl i) Policy stipulates that washed coal must become the norm and use of unwashed coal must become the exception. Working-group - recommendation In this connection, the Working-Group opined that the major problems faced on account of coal are related to inconsistency of indigenous coal quality and lack of appropriate quality control measures at mining end. Such measures would effectively control the menace of excessive overburden and extraneous matter in the coal as supplied to power stations. Use of washed coal would be imperative for power stations located at a farther distance from the coal source and/or in those cases where cost of coal washing gets neutralized by improvement in plant performance. Therefore, Working group recommends that use of washed coal has to be appropriately adopted based on overall cost economics taking into account the low washing yields for most of our coals. 48. Improvement in Efficiency of Generating Plants Recommendation in Policy (Pg xxi Cl vii) Policy envisages to Increase the gross efficiency in power generation from the current average of 30.5% to 34%. All new plants should adopt technologies that improve their gross efficiency from the prevailing 36%to at least 38-40%. Working-group recommendation Working-Group concluded that towards implementation of stipulation of Policy, units of 500 MW and supercritical units of higher sizes have been considered during 11th Plan onwards, which would be able to meet the criteria of designed efficiency of 38-40% depending on coal quality envisaged. 49. Captive Power Generation Recommendation in Policy (Pg xvi, Cl iv) The Policy stipulates The Committee also recommends that the liberal captive and group captive regime foreseen under Electricity Act 2003 be realized on the ground Working-group - implementation India s liberal captive regime will not only derive economic benefits from the availability of distributed generation but will also set competitive wheeling charges to supply power to group captive consumers. This will pave the way for open access to distribution networks. It will also facilitate private generation that limits its interface with the host utility to the use of the distribution network for a fee and thus can be realised even before AT&C losses are reduced. The Working-Group discussed the Page 12 of Chapter 8

384 Legislative and Policy Issues issues to be reckoned with i.e. open access, wheeling and banking and duties and made recommendations to solve these issues. 50. Imported coal based coastal plants Recommendation in Policy (Pg.xiv, Cl i) Policy mentions that.needed infrastructure must be created to facilitate thermal coal imports. This will facilitate coastal power generation capacity based on imported thermal coal.. Working-group- recommendation Some Coastal Ultra Mega Projects based on imported coal are already being conceived. 51 Standardization of Unit Size and Bulk Procurement Recommendation in Policy (Chapter X clause 5) MOP should seek global tenders for large-scale (20,000 MW or more) National Power Projects that seek to exploit objectives such as standardised (super critical 800 MW units or better) bulk orders to reduce capital costs, internationally comparable conversion/energy efficiencies, coastal locations with dedicated facilities for handling domestic coal moved by sea or imported coal, improved emission standards etc. Working-group- recommendation As regards bulk procurement, it may be stated that presently the invitation of the tenders/procurement of the projects for capacity addition are being taken up by different Power Generation companies such as NTPC, SEBs/ State generation companies, IPPs etc. For Bulk procurement to be undertaken, a Centralized Procurement Body would be required. Further, for bulk procurement to be tendered on global basis, clearances for all the projects would be required concurrently. While undertaking bulk procurement, the competition angle would also have to be borne in mind as it is felt that presently only a few players would be in a position to offer bids in case of bulk procurement. It is proposed that to benchmark the Price for different Unit Sizes, an Empowered Committee may be nominated. 52. Rate of Return Recommendation in Policy ( Chapter X, clause 16) Policy provides that where the cost plus regime cannot be avoided and payment security mechanism under TPA is available, rate of return should be linked to longterm Govt. bonds. Page 13 of Chapter 8

385 Legislative and Policy Issues Working-group- Deviation Any policy while deciding the rate of return in power sector must consider present scenario of the power sector. The need of the time is to provide attractive return for power utilities. Return is an issue of tariff determination and as per Electricity Act, 2003, tariffs are to be determined by the Regulatory Commissions. In doing so, they are to be guided by the provisions of National Electricity Policy and Tariff Policy issued by Govt. of India. Accordingly, GOI has already issued these policy documents for setting out guiding principles for the regulatory commissions. Mention of such provisions in different policy documents will only lead to confusion. Hence, the provisions of the Integrated Energy Policy may be reviewed. 53. Coal pricing Recommendation in Policy(Chapter XI clause 22) regarding coal prices Policy provides that Pit-head price of coal under FSTAs should be revised annually by coal regulator based on the formula that reflects prices obtained through e- auction, FOB price of imported coal and production cost inclusive of return based on efficiency standards. Working-group- Deviation Linking coal price to price obtained through e-auction will only push up coal price and is not advisable in view of goal of providing power to all at affordable price. Linking the coal price with the imported coal price also would not be appropriate as the prices there are quite volatile and vary in line with oil prices and as such would have adverse impact on electricity prices. If at all it has to be linked, it should be linked to the pit-head price of imported coal with respect to the pit-head price of Indian coal on heat value basis. In view of the above, it is suggested that coal price for supply under FSTA should be fixed by Regulator based on cost of production inclusive of return based on efficiency standards. Further, once the utilities develop the captive mines allocated to them, the same can be used for benchmarking the coal prices. 54. Allocation of Coal mining Blocks Recommendation in Policy Domestic coal production should be stepped up by allotting coal blocks to central and state public sector units and for captive mines to notified end users. Coal blocks held by Coal India Limited (CIL) which CIL cannot bring into production by , either directly or through joint ventures, should be made available to other eligible candidates for development and bringing into production by Working-group- Deviation Page 14 of Chapter 8

386 Legislative and Policy Issues It is suggested that the allocation of coal blocks should be in an orderly and transparent manner. There is a need to enroll more specialist agencies to conduct exploration of blocks and prepare GRs, so that production from blocks can start in a timely manner. Support of the State Govt. in providing required statutory clearances and administrative support for law and order is essential for creating conducive environment for captive mining. 8.3 NATIONAL ELECTRICITY POLICY - DEVIATIONS AND STATUS OF IMPLEMENTATION i. Availability and Security of Power POLICY(Pg.2 Cl 2.0) Policy aims at achieving the following objectives : Access to Electricity - Available for all households in next five years Availability of Power - Demand to be fully met by Energy and peaking shortages to be overcome and adequate spinning reserve to be available. Supply of Reliable and Quality Power of specified standards in an efficient manner and at reasonable rates. Per capita availability of electricity to be increased to over 1000 units by Minimum lifeline consumption of 1 unit/household/day as a merit good by year Financial Turnaround and Commercial Viability of Electricity Sector. Protection of consumers interests. Also (Pg 5, Cl 5.2.3) In addition to enhancing the overall availability of Installed Capacity to 85%, a spinning reserve of at least 5% at national level, would need to be created to ensure grid security and quality and reliability of power supply. WORKING-GROUP RECOMMENDATION The Working-Group has considered these objectives of the National Electricity Policy and the generation capacity requirements for 11TH & 12th Plans recommended by the Working-Group take into account these objectives. The reserve of 5% has also been included in the capacity requirement calculations. By maintenance and modernization of power plants, the overall availability of already installed capacity shall be improved to about 85%. The Working-Group also feels that a spinning reserve is very much on higher side, since after formation of National Grid, only tripping of the highest unit size must be the appropriate spinning reserve to be catered to. This could be corrected in future after the system becomes more commercially established. Spinning reserve of around 1000 MW will be created at the end of 11th Five Year Plan. In addition to this, there would be capacity available from non-conventional as Page 15 of Chapter 8

387 Legislative and Policy Issues well as surplus of captive power plants to meet total spinning reserve of 5% as specified in National Electricity Policy. ii. Suggested Areas/Location of Generation Capacity Addition & Transmission System POLICY (Pg 3, Cl 3.2)- Policy stipulates National Electricity Plan would be for a short-term framework of five years while giving a 15 year perspective and would include : Short term and long term demand forecast for different regions. Suggested areas/locations for capacity additions in generation and transmission keeping in view the economics of generation and transmission.. WORKING-GROUP IMPLEMENTATION CEA has prepared National Electricity Plan considering demand as per 16th EPS and the above parameters. The Working-Group has discussed and decided to include generation expansion plan as contained in NEP. NEP is expected to be finalized shortly. Other aspects like economics of generation, setting up of power plants at pit head, load centre requirement, environment considerations taking into account the allocation and capacity of the power plants have also been included in the recommendations of the Working-Group. (iii) National Electricity Plan POLICY (Pg.3, Cl 3.1) Policy mentions that Plan prepared by CEA and approved by Central Government can be used by perspective generating companies, transmission utilities and transmission/distribution licensees as reference document. WORKING-GROUP DEVIATION The Working-Group opined that development of hydro power is a crucial issue requiring a comprehensive development plan comprising of a balanced development of Run of the River projects as well as Storage Schemes. Storage schemes assume importance in view of their capability to provide peaking power. However, since development of Storage schemes also involve a number of clearances etc., generally developers find it more hassle free and attractive to develop storage sites also as Run of the River schemes. The Working group recommends that hydro projects developed, their siteing, capacity and type (whether storage or/ror) shall be in accordance with the National Electricity Plan. The projects to be developed by the developers shall generally be from amongst the projects included in NEP. Page 16 of Chapter 8

388 Legislative and Policy Issues (iv) Monitoring and Adjustment in Capacity Addition Plans POLICY (Pg.5, Cl 5.2.4) Policy states that The progress of implementation of capacity addition plans and growth of demand would need to be constantly monitored and necessary adjustments made from time to time. In creating new generation capacities, appropriate technology may be considered keeping in view the likely widening of the difference between peak demand and the base load. WORKING-GROUP IMPLEMENTATION Working-Group feels that there is need for extensive and intensified monitoring of implementation of capacity addition plans and the growth of demand at regular intervals. However, considerations like non-availability of gas have made the task of choosing appropriate technology more difficult. Super critical technologies and higher size units have been considered. Pump storage schemes in Northern region and Eastern region are being implemented and also storage type hydro projects are being planned where ever possible. (V) Hydro Generation POLICY (Pg.6, Cl 5.2.5) Policy stipulates that Maximum emphasis would be laid on the full development of the feasible hydro potential in the country. The 50,000 MW hydro Institute has already been launched and is being vigorously pursued.. WORKING-GROUP DEVIATION An analysis has been carried out to assess the projects which can materialize during the 11th Plan. The Working group opines that even with best efforts, about 15,585 MW hydro projects are possible during 11th Plan. (vi) Lignite based Plants POLICY(Pg.6, Cl ) The Policy mentions that significant Lignite resources in the country are located in Tamil Nadu, Gujarat and Rajasthan and these should be increasingly utilized for power WORKING-GROUP - IMPLEMENTATION The Working-Group agrees that lignite extraction technology needs to be improved. There are plans to add a total capacity of 1375 MW based on lignite during 11TH Plan. Page 17 of Chapter 8

389 Legislative and Policy Issues (vii)gas based Plants(Pg.6, Cl ) POLICY Policy mentions that Use of gas as a fuel for power generation would depend upon its availability at reasonable prices. Natural gas is being used in Gas Turbine/Combined Cycle Gas Turbine (GT/CCGT) stations which currently accounts for about 10% of total capacity. WORKING-GROUP - IMPLEMENTATION The Working-Group states that due to non-availability of gas/lng at a favorable price not much gas based generation capacity is expected during 11th Plan. However, the position could be reviewed as and when gas prices are favorable and the availability of gas improves. (viii)r&m Schemes POLICY(Pg.7, Cl & ) The Policy mentions that If economic operation does not appear feasible through R&M, then there may be no alternative but to closure of such plants as the last resort. In case of plants with poor O&M record and persisting operational problems, alternatives strategies including change of management may need to be considered so as to improve the efficiency to acceptable levels of these power stations. WORKING-GROUP - IMPLEMENTATION Working-Group has recommended that R&M/LE schemes should only be considered if they are economically viable. If cost analysis show that closure of the plant and installation of a new unit is more economical, this alternative shall be considered. Working-Group opines that in case the management of the Plant continuously has poor O&M record, this shall be changed by way of joint ventures with central undertakings like NTPC or State Sector undertakings like APGENCO. 8.4 MAJOR ISSUES AND RECOMMENDATIONS Major Issues deliberated and recommendations of the Working Group are as follows: Capacity Building Promoting Open Access & Trading Controlling the Cost of Electricity Making Regulatory Process more effective Improving Distribution Segment Empowering Consumers Rural Electricity Supply Planning at State Level Page 18 of Chapter 8

390 Legislative and Policy Issues Capacity Building The National Electricity Policy aims at overcoming energy and peaking shortages and having 5% spinning reserves by year The Tariff Policy stipulates that all future requirement of power is to be procured competitively by distribution licensees except the expansion projects and public sector projects for which a five year window has been envisaged after which all the generation and transmission projects would be developed through competitive route. In accordance with the provisions of section 63 of the Act, the Central Government has already issued the competitive bidding guidelines for: Procurement of power by distribution licensees and Procuring transmission services To facilitate competitive procurement of power, the Central Government has already issued standard bidding documents for development of power projects at a specific given site and based on a particular fuel (Case-II of the bidding guidelines). The competitive bidding guidelines also envisage procurement of power without specifying any specific location or fuel (Case-I procurement). The Working Group is of the view that situation is not yet ripe for procurement through Case-I route because fuel, both coal and gas, are not yet freely available in the market. Therefore, all efforts should be made to develop new capacity through developing new power projects under Case-II procurement. This route is fully feasible and successful as has been demonstrated by tariff based competitive bidding in Uttar Pradesh for Anapara-C expansion project. The Central Government has also taken up major initiative for developing Ultra Mega Power Projects through Case-II procurement. Few coastal power stations based on imported coal can be set up based on the option of competitive bids for net heat rate Experience in the past has shown that projects had got delayed considerably because of difficulties in tying-up various inputs like land, fuel, water and clearances particularly environmental and forest clearance. Since we are envisaging private sector participation at a large scale, the Working -Group recommends that Special Purpose Vehicle(SPV) route would be necessary to develop new generation capacities quickly. The SPV is responsible for arranging necessary inputs such as land, fuel and water and also tying-up initial clearances and offering the project for tariff based competitive bidding. Important areas for further improvement are environmental/ forest clearance and geological report for coal blocks. In the area of environmental clearance, the experience has been that the procedure takes a long time. Therefore, there is a need to streamline and standardize the procedure to shorten the time cycle for obtaining environmental/forest clearance with greater emphasis on compliance with laid down standards and conditions imposed while granting environmental clearance. Regarding the geological report of the coal blocks, it is being felt that the blocks being made available for power project development are not adequately explored which is leading to longer project preparation cycle and uncertainties. Presently, CMPDI is the main agency for exploration of coal reserves. The Working -Group recommends that the exploration capacity of the CMPDIL needs to be augmented and it needs to be given more autonomy so that it can discharge its responsibility in a fair and neutral manner. Number of agencies having authorization to undertake exploration of coal blocks also needs to be increased. Page 19 of Chapter 8

391 Legislative and Policy Issues The Working - Group also recommends the possibility of making available power projects sites quickly by scrapping those small sized old power generation units which are operating at significantly higher heat rates. An appropriate cut-off of gross station heat rate, say 3000 kilo calorie per unit, can be considered for identifying inefficient old power plants of more than 25 years age and these sites could be released for setting-up power plants of more efficient and large sized units depending upon the scope of expansion available and with due cost benefit analysis. Coal linkages of the old power plants should also be transferred to the new generating units. Regarding the promotion of non-conventional energy sources, the Tariff Policy provides that minimum percentage for procurement of energy from such sources by a licensee should be made applicable immediately for the tariffs to be determined by the SERCs. The Policy further states that procurement of future requirement of power from non-conventional energy sources shall be done as far as possible through competitive bidding process u/s 63 of the Act among the suppliers offering energy from same type of non-conventional sources. The Policy provides that in the long-term, these technologies would need to compete with other sources in terms of full costs. In view of these provisions in the Tariff Policy, a Sub Group recommends: In the interest of larger competition aimed at consumer benefits, the procurement from non-conventional energy sources should not be restricted to only within that State but suppliers from outside State should also be allowed to compete. Procurement from non conventional sources should invariably,unless there are compelling reasons, be done through the competitive bidding process as this would add to transparency and lower procurement costs. After assessing the stage of development of various non conventional energy technologies, a definite timeframe should be laid down after which preferential tariff for power generated from such sources would not be available. Such an arrangement is already in place in Germany. For encouraging captive generators to supply surplus power to grid, the Implementation of recommendations of Forum of Regulators for rationalising various charges such as parallel operation charge, minimum demand charge, start-up power charge etc. on captive power generators could be a made a condition which may be linked to Central assistance to the State power sector. With a view to encourage Renovation & modernization (R&M) of old power plants additional benefits after R&M are clearly identified and shared with consumers who will bear the burden of servicing additional capital expenditure. It is required to be seen that depreciation is allowed to the power producer and normal maintenance and replacement should be funded from such depreciation amount. The Working Group recommends that CERC could set up benchmarks for capital expenditure on R&M Promoting Open Access & Trading The key features of the Electricity Act 2003 for promoting competition and providing choice to the consumers are open access in transmission from outset and for phased Page 20 of Chapter 8

392 Legislative and Policy Issues introduction of open access in distribution. Most of the State Electricity Regulatory Commissions (SERCs) have notified open access regulations and many of them have also notified cross-subsidies surcharge. Open access in distribution would become a realty only if certain pre-requisites are met. These are availability of power beyond long-term PPAs, adequate transmission facilities and an appropriate transmission tariff To make available adequate power for open access consumers, there is a requirement of having an enabling policy framework for merchant power plants which could be in the size of up to 1000 MW. This size is considered appropriate from the view point of greater possibility of financial closure without long-term PPAs and also of making available transmission corridors for such merchant power plants. We could target a merchant capacity of about 10,000 to 12,000 MW by the end of 11th Five Year Plan. Working Group recommends that coal linkages should be made freely available for power project developers to come forward to set up such merchant power projects. In case captive coal blocks are considered to be given to such merchant power plants, it should be a mandatory condition that such a power project developer would not compete in competitive bidding for long-term PPA based power procurement in order to avoid unequal competition (because only few developers would have such coal blocks and others would not). For allocation of both coal linkage or coal blocks for merchant power plants, an additional condition should be that captive coal mining must begin within a period of three to four years failing which the allocation should be cancelled. For providing transmission corridors for such merchant power plants, the Working Group recommends that adequate redundancy should be built at the stage of transmission planning with the approval of Appropriate Regulatory Commission. The National Electricity Policy already provides that prior agreement with the beneficiaries would not be a pre-condition for network expansion and that CTU/STU should undertake network expansion after identifying the requirements in consultation with stakeholders and taking up the execution after due regulatory approvals. There is a need to identify the major load centres who would be drawing power from such merchant power plants and the required redundancies could be planned. The cost of providing such redundancy should be absorbed in the transmission tariff by the concerned region / zone and should be shared by all the beneficiaries. A rationale transmission tariff framework is essential for facilitating optimum network use and promoting power trade. Presently, the pricing principle applied to the transmission systems have differentiated between the inter-regional, regional and State level flows with such tariffs applied for each component of network used. This has led to pancaking of the network. Realizing this problem fully, the Tariff Policy envisages a National Transmission Tariff Framework which is sensitive to distance and direction and related to quantum of power offered. Regarding the regulation of tariff of merchant power, the Electricity Act 2003 provides regulation by SERC of cost of power purchased by the licensees under section 86 (1) (b) of the Act. The Act further provides that in case of open access is availed by the consumer; the price would be as mutually agreed by the consumer and the supplier. Page 21 of Chapter 8

393 Legislative and Policy Issues However, there is an urgent need for regulations for providing grid connectivity to the merchant power plants Controlling cost of bulk power Main efficiency gains leading to reduction in the cost of bulk power would come through procurement of power through tariff based competitive bidding. In addition to competitive procurement, cost of power could be reduced by reducing the fuel cost as major part of the cost of bulk power is fuel cost. Captive coal mining has been permitted for power sector The Working Group recommends that the coal blocks should be offered on the basis of competitive bidding as part of the integrated coal mine-cum-power project to achieve this objective. Natural gas is another fuel which could be used for power production if it is available at reasonable prices. Due to shortage of gas, the Working Group recommends that the price of domestic natural gas and its allocation should be independently regulated on a cost plus basis including reasonable return. Incidence of various taxes on power sector projects and fuel used for power generation needs to be rationalized. Therefore, Working Group recommends following: In line with crude oil and coal, natural gas and LNG may also be included in the category of declared goods so that a central sales tax of 4% is levied on them and exemption from any state sales tax is extended. Lowering of Import duty on coal to 5% needs to be continued. Exemption of import duties is available to power generation projects under the Mega Power Policy. Similar dispensation should be made available to all important transmission projects where imported components forms a large part of the project cost. It is likely that nuclear power stations would be segregated from other strategic nuclear installations in future. In that case determination of tariff from nuclear power stations needs to be done through regulatory mechanism in a transparent manner adopting two part tariff structure and efficient operating norms. It is understood that the cess being levied on water used by power stations for cooling purposes is on gross volume basis i.e. no consideration is given for the quantity of water actually consumed. There is a need to move to levy cess on the basis of consumptive use of water. This would encourage the closed cooling system which is a need of hour in view of the decreasing availability of water at power project sites Making regulatory process more effective The CERC and the SERCs are discharging a very important role in power sector reforms by bringing in close scrutiny of the data furnished by the licensees and also enhancing transparency in the whole process. It is therefore essential to attract Page 22 of Chapter 8

394 Legislative and Policy Issues regulatory personnel with required background and also to provide training to raise regulatory capacity in terms of the required expertise and skill sets. The Working Group recommends the following measures to make the regulatory approach more effective: Service conditions of the staff of the Regulatory Commissions as well as BEE i.e. providing housing accommodation, medical facilities etc need to be made attractive. State Governments should be asked to establish the Regulatory Commission Funds at the earliest. This could be one of the follow up point while releasing central assistance to the States. There is a need to put in place a mechanism for periodical training/ reorientation for the staff of the Regulatory Commission and for the newly appointed regulators. A broad estimation has been done about the requirement of funds for this pupose. The total cost per year for training 25 regulators and 50 staff is about Rs 40 lakhs. Total expected expenditure for the next five years is about Rs 2 crores 21 lakhs. Details of the above estimation are furnished in Appendix 8.1. A corpus could be made available to the Forum of Regulators for this purpose, income from which could be used for these training programmes. The FOR has been entrusted with number of responsibilities in the Tariff Policy with a view to ensure consistency in the regulatory approach. For discharging this role, the FOR would require consultancy for availing relevant expertise including international experience on various matters. The Central Government should provide funds for this purpose Improving Distribution Segment It is well known that making distribution segment efficient and financially viable is the key to the power sector reforms. This would not only improve the consumer services including the power tariffs but also be critical for mobilization of investment in generation and transmission segment. The Working Group has deliberated indepth on various possible measures for reducing distribution losses and improving quality of supply to the consumers. For reducing AT&C losses, larger investments would be required for upgradation of distribution networks and a special drive would be necessary for identifying high loss areas and controlling commercial losses in such areas. Following is recommended by the Working Group in this regard: i. High loss making feeders need to be franchised by the distribution companies. Towns having ATC losses higher than 35% need to be franchised on input energy basis immediately whereas towns having losses between 25-30% should be observed for improvement for six months and if there is no improvement then these towns should also be franchised. ii. Through appropriate metering and energy audit, feeders incurring high level of losses (may be more than 20% for urban feeders and more than 35% for rural feeders, this would depend on the stage in Page 23 of Chapter 8

395 Legislative and Policy Issues which distribution reforms are in a particular state) should be identified. Performance of the staff should then be assessed on the basis of Key Performance Indicators(KPI) which would be primarily loss reduction. AT&C loss reduction of 3% every year in next five years should be targeted. iii. iv. The Tariff Policy emphasizes on the need for putting in place local area based incentive/disincentive scheme for the staff linked to distribution losses. This should be immediately implemented by the SERCs. To realize the objective of Tariff Policy of supplying uninterruptible electricity to those consumers who are ready to pay efficient cost, the Working Group recommends that distribution tariff should move to distribution margin model which is also provided in the Tariff Policy. Such distribution margin could be based on loss reduction trajectory in a MYT framework and the actual power purchase costs should be paid by the consumers over and above the distribution margin. Consumers of a particular area should be given option to collectively choose either uninterruptible supply or otherwise and the tariff could be determined accordingly. v. The Working Group also recommends that setting up of peaking power stations should be encouraged to overcome peaking shortages as the additional power cost of supply from such a station could then be passed on to the consumers who opt for uninterruptible supply. vi. vii. Correct metering and billing is crucial to reducing distribution losses and also for ensuring that consumers pay according to their consumption. CEA has notified metering regulations which mandate that all new consumer meters would be of static type (electronic). These meters measure the consumption correctly over a long period of time. The Working Group recommends that use of electronic meters and spot billing needs to be expanded rapidly and the State should be emphasized to do so. Also, with the objective of promoting more efficient use of electricity and also to provide another payment option to consumers, use of pre-paid meters needs to be promoted. The Electricity Act gives discretion to the licensees to undertake supply for a specified area within his area of supply through a franchisee. The Working Group recommends that the Forum of Regulators should develop a model agreement for distribution of electricity by distribution licensee through a franchisee in urban areas outlining the responsibilities and duties of various parties clearly Empowering Consumers The Electricity Act has many important provisions for protecting consumer interests and for redressal of their grievances. These are: Page 24 of Chapter 8

396 Legislative and Policy Issues Setting up of Forums for redressal of consumer grievances Ombudsman to supervise and oversee the Forum Standards of performance for licensee with provision of penalty for nonfulfillment. Advisory Committees to the Regulatory Commissions. It is utmost important that consumers are involved fully in the regulatory process. National Electricity Policy emphasizes on capacity building of consumer groups and their effective representation before the Regulatory Commission. The Working Group recommends that necessary financial assistance could be provided to consumer groups having proven track record for facilitating their effective representation before the Regulatory Commission. In addition to the financial assistance, the Central Government should also arrange orientation programmes to educate these groups about various provisions of the law and rules. Such scheme(s) should be administered by the Department of Consumer Affairs Rural Electricity Supply The Central Government is already implementing the ambitious nationwide programme of RGGVY for providing access to electricity to all the households. Need is felt to take up programmes to ensure supply of quality power at reasonable cost to the rural areas. The Rural Electrification Policy notified by the Government under the Electricity Act provides for a facilitative framework for encouraging local resources based decentralized distributed generation systems. Most of the States have already notified rural areas for the purpose of section 14 of the Act. Now there is a need to promote such decentralized distributed generation system Planning at State Level Prior to reorganization of SEBs, the planning for electricity sector at State level was used to be done by the SEBs. Working Group opines that there is a need to institutionalize a framework for indicative planning at State level post restructuring of SEBs so that steps could be taken in time for necessary planning and execution of projects. This becomes all the more important as generation projects are now to be developed through competitive route for inviting power sector investment and therefore initiative is to be taken at the State Government level. Similarly, advance planning is required for augmenting the State level transmission network for catering to new generation capacity and also for enabling open access. Therefore, the Working Group recommends that State Government should set up a dedicated planning cell for developing electricity plan at the State level including specific projects which could be posed for investment to the power sector. Such a plan could be on the lines of National Electricity Plan Agriculture Sector- Subsidies and Cross subsidies Besides agriculture, domestic consumers are also provided subsidized tariff in most the States. The Electricity Act 2003 and subsequent policy statements require gradual elimination of cross subsidies. Section-61(G) of Electricity Act states that appropriate commissioning shall be guided by the following while determining tariffs: Page 25 of Chapter 8

397 Legislative and Policy Issues that the tariff progressively reflects the cost of supply of electricity and also, reduces and eliminates cross subsidies within the period to be specified by the Appropriate Commission Clause 8.3 of the National Tariff Policy (NTP) states, 1. In accordance with the National Electricity Policy, consumers below poverty line who consume below a specified level, say 30 units per month, may receive a special support through cross subsidy. Tariffs for such designated group of consumers will be at least 50% of the average cost of supply. This provision will be re-examined after five years. 2. For achieving the objective that the tariff progressively reflects the cost of electricity, the SERCs would notify roadmap within six months with a target that latest by the end of year tariffs are within + 20% of the average cost of supply. The road map would also have intermediate milestones, based on the approach of a gradual reduction in cross subsidy. Most of the SERCs are yet to specify the trajectory for reduction of cross subsidies in accordance with the provisions of NTP. Given the fact that the prevailing agricultural tariff are significantly lower than the average cost of supply tariffs towards cost of supply will lead to steep upward movement of bringing tariffs for the agricultural and residential consumer categories which is bound to be resisted by the affected groups. National Electricity Policy and tariff policy provides for creation of life line category for consumers below poverty line including those consuming less than 30 units per month. These categories will also face steep increase in tariff as the present level of subsidy is far below the average cost of supply. There will also be practical difficulties in administering the provision. In these circumstances, it may not be feasible to eliminate cross subsidies completely in the near future, though it can be gradually reduced over time. Some of the steps that can be taken to ensure that the agricultural tariffs are reflective of the costs incurred and appropriate tariff signals are given to the consumers, are: Energy audits based on scientific sampling methods, to assess electricity consumption for agriculture across regions, crops, ground water level, etc. Higher tariffs for higher capacity pumpsets Tariffs linked to acreage under cultivation Tariffs linked to cost-to-serve, rather than average cost of supply or voltage level cost of supply. Clause 8.3 of the NTP states, 3. While fixing tariff for agricultural use, the imperatives of the need of using ground water resources in a sustainable manner would also need to be kept in mind in addition to the average cost of supply. Tariff for agricultural use may be set at different levels for different parts of a state depending of the condition of the ground water table to prevent excessive depletion of ground water. Section 62 (3) of the Act provides that geographical position of any area could be one of the criteria for tariff Page 26 of Chapter 8

398 Legislative and Policy Issues differentiation. A higher level of subsidy could be considered to support poorer farmers of the region where adverse ground water table condition requires larger quantity of electricity for irrigation purposes subject to suitable restrictions to ensure maintenance of ground water levels and sustainable ground water usage. Alternative mechanism for cross-subsidies is provision of subsidy by the State Governments which intend to provide supply of power to certain categories at less than the prevailing average cost of supply. If cross-subsidy has to be reduced and no tariff increase is planned for the subsidized categories, the State Governments will have to bear the financial burden by providing subsidy to the utilities. Since the gap between average cost of supply and tariffs for agricultural consumer is large the burden is bound to be significant on the State Governments which are already providing capital subsidy in many states. The Electricity Act provides that State Governments should provide such subsidies in advance to the utilities. Section 65 of the EA 2003 states, If the State Government requires the grant of any subsidy to any consumer or class of consumers in the tariff determined by the State Commission under section 62, the State Government shall, notwithstanding any direction which may be given under section 108, pay, in advance in the manner as may be specified by the State Commission, the amount to compensate the person affected by the grant of subsidy in the manner the State Commission may direct, as a condition for the licensee or any other person concerned to implement the subsidy provided for by the State Government. Clause of the National Electricity Policy (NEP) notified in February 2005, states, The State Governments may give advance subsidy to the extent they consider appropriate in terms of section 65 of the Act in which case necessary budget provision would be required to be made in advance so that the utility does not suffer financial problems that may affect its operations. Efforts would be made to ensure that the subsidies reach the targeted beneficiaries in the most transparent and efficient way. Clause (3) of the National Tariff Policy (NTP) notified in January 2006 states, Section 65 of the Act provides.. To ensure implementation of the provision of the law, the State Commission should determine the tariff initially, without considering the subsidy commitment by the Sate Government and subsidized tariff shall be arrived at thereafter considering the subsidy by the State Government for the respective categories of consumers. Clause 8.3 of the NTP states, The State Governments can give subsidy to the extent they consider appropriate as per the provisions of section 65 of the Act. Direct subsidy is a better way to support the poorer categories of consumers than the mechanism of cross-subsidizing the tariff across the board. Subsidies should be targeted effectively and in transparent manner. As a substitute of cross-subsidies, the State Government has the option of Page 27 of Chapter 8

399 Legislative and Policy Issues raising resources through mechanism of electricity duty and giving direct subsides to only needy consumers. This is a better way of targeting subsidies effectively. Considering the stretched finances of most State Governments, the provision of this subsidy affects investments and expenditure in other areas. The huge losses incurred by utilities due to various technical and commercial reasons is aggravating the financial position of the utilities making them unviable and force them to depend on the State Government for support. To withstand this financial burden, State Governments will have to look for additional revenue sources. Direct subsidy will eliminate various issues associated with cross subsidy as the burden of subsidy shifts to general tax payers in the State. 8.5 SUMMARY OF RECOMMENDATIONS 1. Situation is not ripe for procurement through Case-I route since both coal and gas are not yet freely available in the market. All efforts should be made to develop new capacity under Case-II procurement. 2. SPV is necessary to develop new generation capacities quickly. 3. There is need to streamline and standardize the procedure to shorten time cycle for obtaining environmental/forest clearance with greater emphasis on compliance with laid down standards and conditions. 4. Exploration capacity of CMPDIL may be augmented and also it may be given more autonomy so that it can discharge its responsibility in fair and neutral manner. Number of agencies having authorization to undertake exploration of coal blocks should be increased. 5. Coal blocks to be used for captive coal mining by power projects should be explored fully at the earliest and GRs should be readily made available to power project developers on actual cost basis. 6. Appropriate cut-off of gross station heat rate, say 3000 kilo calorie per unit, can be considered for identifying inefficient old power plants of more than 25 years age and the sites could be released for setting-up plants of more efficient and large sized units depending on the scope of expansion available and with due cost benefit analysis. Coal linkages of the old power plants should be transferred to new generating units. 7. Till the long-term coal supply contracts emerge in international coal markets, the option of competitive bids for net heat rate may be explored for imported coal based stations. 8. In the interests of larger competition aimed at consumer benefits, procurement from non-conventional energy sources should not be restricted to within the State but suppliers from outside State should also be allowed to compete. Page 28 of Chapter 8

400 Legislative and Policy Issues 9. Procurement from non conventional sources should, unless there are compelling reasons, be done through competitive bidding process as this would add to transparency and lower procurement costs. 10. After assessing the stage of development of various non conventional energy technologies, definite timeframe should be laid down for doing away with preferential tariff for power generated from such sources. 11. Tariff Policy advises States to rationalize taxes and duties on captive power consumption. This may be reviewed periodically with States and made a condition for Central assistance to State power sector. 12. In competitive procurement of power, bidding by CPSUs should be ensured in initial few projects to encourage competition. 13. CERC could set up benchmarks for capital expenditure to facilitate accelerated R&M of old power plants. 14. To make available adequate power for open access consumers, there is need for enabling policy framework for merchant power plants. Size of MPPs could be up to 1000 MW which may be appropriate considering greater possibility of financial closure without long-term PPAs for comparatively smaller sized projects and also of making available transmission corridors for such MPPs. We could target MPP capacity of about 10,000 to 12,000 MW by end of 11 th Plan. Such merchant capacity would be without the basis of long term PPAs. 15. Coal linkages should be freely available for power project developers who come forward to set up such MPPs. In case captive coal blocks are given to MPPs, there should be a mandatory condition that such the project developer would not compete in competitive bidding for long-term PPA based power procurement in order to avoid unequal competition since only few developers would have such coal blocks. For allocation of linkage or coal blocks for MPPs, an additional condition should be that captive mining must begin within a period of 3 to 4 years failing which the allocation should be cancelled. 16. For providing transmission corridors for such MPPs, adequate redundancy should be built at the stage of transmission planning. Presently, also there is a redundancy of about 20-25% in the transmission planning. There is need to identify the major load centres who would draw power from such MPP. These load centres would be most likely situated in northern and western region where many States are deficit in power supply. Therefore, the required redundancies could be planned from the likely location of the MPP (which would be in eastern region) to such load centres. The cost of providing such redundancy should be absorbed in the transmission tariff by the concerned beneficiaries. This would be in the long-term interests of consumers who will gain from efficiency arising out of competition among the generators. 17. Tariff Policy envisages a National Transmission Tariff Framework sensitive to distance and direction and related to quantum of power offered. CERC is in the process of developing such a Framework which needs to be done Page 29 of Chapter 8

401 Legislative and Policy Issues expedited. This would be a necessary pre-requisite for promoting open access and power trading. 18. There is urgent need for regulations for providing grid connectivity to MPPs. The National Electricity Policy already provides that prior agreements would not be a pre-condition for network expansion and the transmission utilities should undertake network expansion after identifying the requirements in consonance with the National Electricity Plan and in consultation with the stakeholder, and taking up the execution after due regulatory approvals. 19. The reduction in cost of production of coal on account of higher efficiency in captive coal mining should be passed on to the consumers through reduced cost of bulk power. The coal blocks should be offered on the basis of competitive bidding as part of the integrated coal mine-cum-power project to achieve this objective. Any other method of allocating coal blocks for power projects is not likely to pass on the efficiencies of captive coal mining to the consumers. 20. As long as there is shortage of natural gas and the two major users of gas fertilizer and power work in a regulated cost plus environment, price of domestic gas and its allocation should be independently regulated on cost plus basis including reasonable returns. 21. Like crude oil and coal, natural gas and LNG may also be included in the category of declared goods so that central sales tax of 4% is levied on them and exemption from any state sales tax is extended. 22. Import duty on coal has been lowered to 5%. This position needs to be continued as we would be depending on imported coal for generation. 23. Exemption of import duties available to generation projects under Mega Policy should be available to all important transmission projects where imported components form large part of the project cost. 24. Nuclear power stations are likely to be segregated from other strategic nuclear installations in future. In that case, tariff determination from nuclear power stations should be done through regulatory mechanism in a transparent manner adopting two part tariff structure and efficient operating norms. 25. There is a need to levy cess on the basis of consumptive use of water. This would encourage closed cooling system which is the need of the hour considering decreasing availability of water at project sites. 26. Service conditions of staff of the Regulatory Commissions and BEE should be made attractive. Such staff should be eligible for housing accommodation, medical facilities etc. on the lines of Government employees. 27. State Governments should be asked to establish the Regulatory Commission Funds at the earliest. This could be one of the follow up points while releasing central assistance to the States. Page 30 of Chapter 8

402 Legislative and Policy Issues 28. There is a need to put in place a mechanism for periodical training/ reorientation for staff of the Commissions and for newly appointed regulators. A corpus could be made available to the Forum of Regulators (FOR) for this purpose income from which could be used for the training programmes. The training programme and the training institutions should be settled by FOR after taking into account guidelines issued by the Central Government in this regard. 29. FOR has been entrusted with number of responsibilities in the Tariff Policy with a view to ensure consistency in the regulatory approach. For discharging this role, the FOR would require consultancy for availing relevant expertise including international experience on various matters. Central Government should provide funds for this purpose. 30. FOR should also compile periodically various progressive orders of the SERCs for sharing the best practices. The compilation may also include important judgments of the Appellate Tribunal for Electricity. 31. To bring in appropriate accountability of the regulatory process, proposed regulations of the Regulatory Commissions should be examined indepth at draft stage itself. Further, there is a need for scrutinizing the regulations for ensuring consistency with the letter and spirit of the law before they are laid in the Parliament/ State Assembly. This is important since regulations, once published in the gazette, become sub-ordinate legislation. 32. FOR should also undertake periodical review of implementation of the National Electricity Policy and Tariff Policy since the law requires the Commissions to be guided by these policies. 33. High loss making feeders may be franchised by distribution companies. Towns having ATC losses higher than 35% may be franchised on input energy basis immediately. Towns having losses between 25-30% should be observed for improvement for 6 months and if there is no improvement, these towns should also be franchised. 34. Through appropriate metering and energy audit, feeders incurring high level of losses (may be more than 20% for urban feeders and more than 35% for rural feeders, this would depend on the stage in which distribution reforms are in a particular state) should be identified. Performance of the staff should be then assessed on the basis of Key Performance Indicators(KPI) which would be primarily loss reduction. ATC loss reduction of 3% every year in next five years should be targeted. The Tariff Policy emphasizes on the need of putting in place local area based incentive/disincentive scheme for the staff linked to distribution losses. This should be immediately implemented by the SERCs. 35. The robust legal framework contained in the Act for control of theft is being further strengthened. Annual conferences of power utilities should be organized at national level for highlighting success stories and achievement made in different States in controlling theft. Page 31 of Chapter 8

403 Legislative and Policy Issues 36. To enlist public support for rapid reduction of commercial losses, the list of high losses feeders should be publicized periodically. 37. To realize the objective of Tariff Policy of supplying uninterruptible electricity to those consumers who are ready to pay efficient cost, the distribution tariff should move to distribution margin model which is also provided in the Tariff Policy. Such distribution margin could be based on loss reduction trajectory in a MYT framework and the actual power purchase costs should be paid by the consumers over and above the distribution margin. Consumers of a particular area should be given option to collectively choose either uninterruptible supply or otherwise and the tariff could be determined accordingly. 38. Setting up of peaking power stations should be encouraged to overcome peaking shortages as the additional power costs of supply from such a station could be then passed on to the consumers who opt for uninterruptible supply. 39. Use of electronic meters and spot billing should be expanded rapidly and State should be emphasized upon to do so. 40. FOR should develop a model agreement for distribution of electricity by distribution licensee through a franchisee in urban areas outlining the responsibilities and duties of various parties clearly. 41. There have been some experimental efforts, with good success, for outsourcing distribution of electricity for an identified feeder by the licensee to a private entrepreneur selected competitively. This model needs to be supported fully and replicated in high loss areas. 42. Necessary financial assistance may be provided to consumer groups having proven track record for facilitating effective representation before the Regulatory Commission. In addition, Central Government should also arrange orientation programmes to educate these groups about various provisions of the law and rules. Such scheme(s) should be administered by the Department of Consumer Affairs. 43. The Rural Policy provides that standalone systems of upto one MW would have automatic approval for a. Land use change for area as per norms b. Pollution clearance if technology is proven within laid down norms and c. Safety clearance on the basis of self certification. These policy measures need to be implemented by the concerned authorities at the earliest. 44. Schemes for separation of agricultural feeders in rural areas need to be promoted. Agricultural consumers could be supplied electricity as per seasonal demand for agricultural purpose and the tariff could be fixed taking into view off-peak pricing and uninterruptible supply. Page 32 of Chapter 8

404 Legislative and Policy Issues 45. Schemes for transferring subsidies directly to consumers may be encouraged. 46. State Government should set up a dedicated planning cell for developing electricity plan at the State level including specific projects which could be posed for investment to the power sector. Such a plan could be on the lines of National Electricity Plan. 47. With the objective of promoting more efficient use of electricity and also to provide another payment option to the consumers, use of pre-paid meters needs to be promoted. 48. In order to assess the progress made in achieving higher energy efficiency, suitable mechanism should be put in place indicating the clear cut methodology for computing various parameters in this regard. ********** Page 33 of Chapter 8

405 Legislative and Policy Issues Appendix 8.1 FUND REQUIREMENT FOR TRAINING OF ELECTRICITY REGULATORS AND STAFF TRAINING FOR STAFF OF ERCS There are 25 SERCs including CERC It is proposed to give training to 2 staff per ERC Total staff to be trained in a year is 50 2 training programme in a year each batch with 25 persons Duration of Training Programme : 9 days Details of Expenditure Expenditure Item Projected Expenditure (Rs.) Professional Cost 4,31,750 Communication and local conveyance 20,000 Logistics (including accommodation and 7,97,500 meals) Sub-Total 12,49,250 Overheads 12,495 Service 1,66,199 Grand Total 15,42,374 (Approx. Rs.16 lakhs) Cost for one Training Programme (25 Rs.16 lakhs persons per batch) Cost for two Training Programme (25 Rs.32 lakhs persons per batch) TRAINING FOR REGULATORS OF ERCS 25 Regulators to be trained in a year One training programme in a year each batch with 25 Regulators Duration of training programme: 3 days Page 34 of Chapter 8

406 Legislative and Policy Issues Details of Expenditure Expenditure Item Projected Expenditure (Rs.) Professional Cost Communication and local conveyance 1000 Logistics (including accommodation and meals) Sub-Total Overheads Service Grand Total (Approx. Rs.8 lakhs) Cost for one Training Programme (25 Rs.8 lakhs persons per batch) Total cost per year for training 25 Regulators and 50 Staff : Rs.32 lakhs + Rs.8 lakhs = Rs.40 lakhs Total expected expenditure for the next five years: Year lakhs lakhs lakhs lakhs Expected Expenditure (Including 5%) Rs lakhs Total Rs.2 crores 21 lakhs Page 35 of Chapter 8

407 Legislative and Policy Issues REF: PEG/2006/296 Dated: 30 h Dec 2006 To, Shri R. V. Shahi, Chairman Working Group on Power, Ministry of Power Appendix 8.2 Subject: Comments / suggestions on the draft report of the Working Group on Power Sir, On behalf of Prayas Energy Group, I wish to thank you for the opportunity to comment on the Draft report of the Working Group. As per your suggestion I have attempted to keep it short. There were limitations in our inputs earlier arising from (1) some of the sub-groups (that we were involved in, could not have meeting to discuss the draft report, (2) only after reading all reports, one could develop an holistic picture, (3) we have limited support for such work. In light of this, I request you to allow little longer comments. Larger Comments - As elaborated in Box at the end, the estimate of MW and Rs Crore investment is on an optimistic side. This has a material impact while recommending the policies necessary to raise the required funds. Hence, these estimates should be reviewed. - There is a large increase in kind and quantity of central government subsidy schemes (RGGVY, DDG, 1 MW stand along systems etc.). A well-balanced committee should be established to transparently monitor the targets and operation of these schemes and a separate committee to find ways in which performance of REC / PFC can be further improved to meet the sector objectives. - Draft report suggests several different roles for REC. Considering the potential conflict of interest among these roles we strongly suggest institutional separation of roles. - Success SPV route adopted for Ultra-mega should be further enhanced. A mechanism should be created to develop projects for Case-2 Tariff bidding. These projects then could be offered to Discoms for competitive bidding. - Consumer funding should be done at multi-level (state and national) which is well aligned with activity & agency work. - A committee should be constituted to look into the options for meeting intermediate and peak load demand in the most economic manner. This could help remove the critical planning gap during Advance Actions for the 12 th plan. - Tariff impact of the proposed schemes should be included in the report. The remaining comments are given chapter-wise. Demand-Supply: - The capital cost of projects over the last 10 years should be plotted as a scatter diagram (Rs/MW and year), with each project shown as one point. Two separate graphs for coal and CCGT could be drawn. - It appears that the energy demand forecast does not consider generation by addition of CPP (estimated addition of 12,000 MW), NCES (~10,000 MW), or co-generation plants. Page 36 of Chapter 8

408 Legislative and Policy Issues It is possible that these would generate 85,000 MU/yr. In which case, it would be equal to a third of the incremental energy demand (on the grid) during the XIth plan. The expected increase in MU generation (due to additional CPP) should be clearly specified and cross-checked with total industrial demand (met from grid and CPP). Generation from NCES should be considered in the grid. - The 210 / 250 MW units have large variation in heat rates. The bottom 10% units with highest heat rates and the top 5 units with least heat rate should be audited to draw lessons. - CERC tariff should provide incentive for Heat rate improvement, based on report of energy audit & heat rate verification for all power plants. This report should be put up on Website by all utilities. This could be a condition for R&M assistance. Transmission: - It may be useful to represent the addition of inter-regional transmission capacities, major Transmission lines on national map. - The capital cost of Rs 140,000 Cr seems on a high side for the projected increased in grid capacity as well as the incremental energy sales. Annual fixed charges of Transmission investment (@15% of 140,000 Cr) translates to a wheeling cost of 90 Paisa/unit based on incremental sales of 290,000 MU. This is quite large. Distribution: - Role of REC: It is proposed that (1) REC be nodal agency for several programs like DDG (subsidy of Rs 20,000 Cr), RGGVY (Rs 40,000 Cr), APDRP (Rs 40,000 Cr, including pump energization). (2) REC would fund the equipment manufacturers for expansion and modernisation, (3) REC would set up venture capital fund for equipment manufacturers, (4) REC would set standards for equipment manufacturers. The role of REC has undergone a major change with RGGVY and more radical changes are proposed. We suggest that (a) In light of likely conflict of interest among the multiple roles proposed for REC such a move is not desirable. REC may have invested in some equipment manufacturer either through venture capital fund or simply given it a loan. REC would be setting equipment standards and REC would also be a major buyer of the distribution equipment (under RGGVY, DDG, etc.). The potential conflict of interest between different roles - facilitator, nodal agency for implementation, financing agency, and regulator (setting standards) may be large and these roles should NOT be integrated in one institution (b) performance of REC as nodal / implementation agency for the large subsidized schemes (e.g. RGGVY) should be reviewed to identify areas that need strengthening. A committee could be constituted for this. - REC / PFC giving reform loans: The conditions to be imposed by REC / PFC should be approved in writing by MoP. The states may accept a shorter list of these conditions as mutually approved by REC / PFC and the recipient. - Role of REC/ PRF: The Planning Commission should appoint an oversight committee to transparently evaluate possible ways in which these agencies can better meet their and power sector objectives. - RGGVY: (1) The revised cost estimation of RGGVY should be mentioned along with its basis (2) Scope of RGGVY - electricity connection to all houses by year 2012 should be reaffirmed in accordance with the government s mandate. - DDG (a) Business model of DDG is not yet fully clear. A group should be formed to monitor these projects. (b) The cost effectiveness of DDG would come from utilizing them in say co-generation mode or linked to waste heat applications a 5 MW size is high for this purpose. (c) Title of section 3.13 is Cost to Serve/ Delivered Cost. It should be Page 37 of Chapter 8

409 Legislative and Policy Issues modified to suite content. The Tariff policy does not advocate the Cost to Serve as basis for Tariff. (d) Consumers are not listed in the description of Role of Stakeholders. At least in initial experimental 100 cases there should be annual survey of consumer experience. The cost of such survey can be minimized and accuracy enhanced by giving a Response Form to all consumers as bill-insert (to be mailed to the independent survey agency). - Water-electricity nexus: The suggestion from Prayas was to form a Task force on this issue to create wider awareness of negative implications of free-power and ground water depletion. The members of task force should come from agriculture, ground water, irrigation and power sectors. DSM, Energy Efficiency and BEE: - MoP has taken a broader mandate through BEE, to improve efficiency of not just power consumption but also oil, gas and coal consumption. MoP has responsibility to fulfill this mandate. - The BEE proposed budget of 650 Cr is less than 0.1% of the overall budget of the sector. This should be given as grant in aid (linked to activity plan) - The BEE should be made accountable for its performance, while making it autonomous. A steering group of six / seven persons should be appointed for a period of 3 or 5 years, for this task. The steering group should have mandate of approving BEE schemes and taking an annual review of its performance. Members of steering group should be on contract from MoP. - There is an urgent need to encourage technical institutions / engineering colleges to carry out R&D related to energy efficiency. Improved linkage of industry need-fundingmanpower resources is necessary. - Need for improved appliance standards should be explained with an example such as one given here We are adding about 100 million CFLs in the system each year this number is doubling in less than 3 years. With such a large addition of CFLs, improvement in their quality is urgent. Raising the Power Factor of CFLs from 50% to 85% by adding passive PF correction in the electronic ballast would reduce 10,000 MVA demand in the XI th plan period. This will reduce the need for addition in Distribution Transformers capacity by nearly 10% of planned addition. R&D: - Following topics should be added to the focus areas for R&D: o Assessment of needs of the 10 crore very poor consumers (including to be consumes) o Soft technologies like DSM, improved use of IT for accountability of utilities, better forecasting models, and power plant dispatch planning. o On-line detection of faults to improve plant availability - Clear process for evaluation / effectiveness of public money spent on R&D should be initiated - The plan for spending 1% of RGGVY money reserved for evaluation, training and R&D should be developed by MoP through an open and consultative process. Key inputs - Land (forest and non-forest land) and water requirement for power plants are critical inputs for the sector. The chapter should estimate total land requirements (by projects) and the persons likely to be displaced. Page 38 of Chapter 8

410 Legislative and Policy Issues - Coal requirement: It has been worked out assuming base-load PLF (~ 85% for new power plants). This would generate about 300,000 MU, but as seen in Box 1, the energy demand forecast indicates additional energy requirement of only 290,000 MU. The coal requirement may be reasonable if it is clarified that it also includes the requirement of 12,000 MW of CPP capacity addition. Table 9.7 would need corresponding modification. Finance: - Capitalization of dividend in construction period: Rather than a piecemeal adjustment, the treatment given to equity should be comprehensively reconsidered by MoP. In some countries equity is returned (along with loan) to reduce the tariff in later years. Such aspects can be integrated in the review. - Estimation of MU, MW and Rs Cr: On the conservative side the MU and MW addition numbers can be considered on a higher side. The same when done about finance can have negative impacts (See Box 1 at the end for details). If the fund requirement is not Rs 9.67 Trillion but say Rs 6 Trillion, then required financing adjustments may be much different than what is proposed. - Banking norms: If relaxation of lending norms is to be considered, at the minimum there should be complete transparency in terms of which banks are using the relaxed norms for which corporate groups and for which specific projects. Policy: - E-Act: Ministry of Power should do a review of E Act when five years are complete. The review should be broad based to be able to remove the difficulties being faced, such as the legal precedence being created by ATE and court orders that are contrary to the intent of the Act. - Coal pricing and allocation of mines: o It is welcome idea to give mines to integrated mine-power project that intends to sell power to utilities. This will pass the benefit of mining efficiency to small consumers that are going to face a large tariff hike. o The coal pricing should be directly linked with calorific value (on delivered basis) rather than grades of coal. - Merchant Plants: The draft report recommends that merchant plants be encouraged through measures such as giving coal blocks, so as to create the liquidity necessary to make markets function. We think this is not a good idea for large-scale promotion, for the following reasons: o Experience of merchant plants in other countries shows problems. For example, the merchant plant industry in USA has been almost decimated. Initial optimism about the industry led to many projects being announced. However, as conditions in the market changed and investors began to understand the real risks in building merchant plants and trading electricity, the share prices of these companies plummeted. Many of the proposed projects were either postponed indefinitely or cancelled. o On a priority basis, the coalmines should be allocated to projects that will supply electricity to utilities under a long-term contract. If they are allocated to merchant plants, then the benefits go to the plant owner. o Utilities (hence small consumers) should not be burdened for creating redundancies in Transmission system for facilitating the merchant plants. Benefit and cost sharing under this would be unfair. Page 39 of Chapter 8

411 Legislative and Policy Issues o If inspite of this experience, the government decides to give coal blocks to merchant plant developers then it should lay down three conditions (1) if the plants does not come up or stops operation, then the coal blocks must be returned and (2) the coal block should be given to the developer through a price bid, (3) such a promotion should be limited to only a handful demonstration projects by PSUs. - SERCs: It should be clarified that fundamental duties of SERCs include monitoring the demand-supply situation and ensure that utilities meet the power demand. - Separation of Agricultural consumption: Example of Akshay Prakash in Maharashtra is a noteworthy example, where this is achieved, in addition to theft reduction at not cost to the utility. This should be included in the Box in Policy chapter. - Consumer Funding: It is much safer to have multiple mechanisms for consumer funding. It is only natural to have different mechanism for state level education, national training, and intervention and policy analysis support. [Refer to the note submitted by Prayas and Dr Navroz Dubash.] - Real time meter Reading: Remote reading of all 33/11 KV (or 66/11 KV) substations should be the first priority. This will give exact amount of load shedding and help establish 11 KV energy audits. Remote reading of DTs should not be mixed with this, as this may increase the work burden exponentially. Remote reading of all consumers above 50 KW is utility s commercial priority but remote reading at substation is a priority for public accountability of utilities. - Captive plants: The captive plants should pay wheeling charges and transmission losses by voltage level (reference saying that captive plants should pay only the technical losses in Transmission system should be removed). - Public Sector improvement: In association with some state distribution utilities the MoP should test the results of incentive-disincentive scheme for employees and managers of utility. This could be implemented as a part of APDRP scheme. Box 1: MU, MW, and Rs Cr investment linkage MU-MW linkage: Chapter 1 states the demand forecast on the basis of expected increase in sales by 290,000 MU (on the grid - Ex bus) and plans addition of 71,000 MW. The implicit net-plf of this 71,000 MW capacity would be below 50% (for 290,000 MU sales). This is unlikely. Following factors need to be looked into: - The MU generation of 10,000 MW of NCES (nearly 26,000 30% PLF) should be accounted for in grid supply in chapter 1. - Spinning reserve should be considered as capacity of the two largest units in the region. Rs. Crore investment estimate The total investment of Rs 967,000 Crore projected in the XI th plan would result in a fixed cost of Rs 175,000 Cr p.a. (fixed 18% p.a.) Dividing this by the incremental sales of 290,000 MU implies a capacity charge of Rs 6/unit. The fuel cost would be additional. This is an anomaly. And the financing need should be pegged at a lower level. Miscellaneous Issues Distribution - Lack of accountability of utilities: Take the case of Sec in the Chapter on Distribution where Maharashtra is said to have achieved 100% metering of 11 KV Page 40 of Chapter 8

412 Legislative and Policy Issues feeders. In fact MoP data shows that Maharashtra has achieved 100% metering of 11 KV feeders several years ago. But MSEDCL submitted data to MERC is contradictory. In the recent ARR submitted to MERC, MSEDCL indicates following: o 11 KV feeders with meter 80% (of 8500 feeders of MSEDCL) o 11 KV feeders with reliably working meter 68% o Only 570 meters have data download facility but the facility is not used. This raises doubts about the validity of data submitted by utility to MoP and / or to the SERC. - HVDS, GIS and consumer indexing etc.: When some states have implemented the scheme a post-factor Cost:Benefit analysis should be the basis for recommendation by Planning Commission. Simple articulation of claimed benefits is inadequate for recommending such high cost schemes for all utilities. - Experience of Reforms: Orissa is not really a success in terms of reduction in T&D loss. It is better to remove that from the list (section 3.24) - It would be useful to mention that utilities should be able to demonstrate that they are meeting Standards of Performance Regulations of the regulatory commissions. - Rs / employee: (a) It needs to be clarified that some utilities are concentrated urban utilities while some are low-density rural utilities. (b) It would be good to clarify that it excludes cost of contract labor and also franchisees. (c) The AP numbers should be given for different Discoms instead of one number for the state, (d) Year for which the data is given should be indicated. I wish to thank you once again for this opportunity and hope that you will give due consideration to the points raised. Thanking you, (Girish Sant) for Prayas Energy Group CC: Dr Sethi (Planning Commission), Addn Sec (MoP), CEA. Page 41 of Chapter 8

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