evolving perspectives in the development of indian ... · viii | indian infrastructure: evolving...

EVOLVING PERSPECTIVES IN THE DEVELOPMENT OF

INDIAN INFRASTRUCTURE

EVOLVING PERSPECTIVES IN THE

DEVELOPMENT OF INDIAN INFRASTRUCTURE

Volume 1

Infrastructure Development Finance Company Limited

ORIENT BLACKSWAN PRIVATE LIMITED

Registered office3-6-752 Himayatnagar, Hyderabad 500 029 (A.P.), India

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© Infrastructure Development Finance Company Limited 2012First published 2012

All rights reserved.No part of this book may be reproduced or transmitted in any form or by

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permission of Orient Blackswan Private Limited.

ISBN 978 81 250 4666 0

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Published byOrient Blackswan Private Limited

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The external boundary and coastline of India as depicted in themaps in this book are neither correct nor authentic.

CONTENTS

List of Tables, Figures and Boxes vii

Foreword by Rajiv B. Lall xv

Acknowledgements xvii

Introduction xix

List of Abbreviations xxiii

ENERGY

1 Power Sector Reform: Policy Decisions in Distribution 3

2 Power Sector in India: A Summary Description 13

3 Power Sector Reform in Argentina: A Summary Description 22

4 Orissa Power Sector Reform: A Brief Overview of the Process 31

5 Power Sector Financing: A Note on Conditionalities 40

6 Six Steps to Accelerated Privatisation of Electricity Distribution 52

7 Regulation of Petroleum Product Pipelines 70

8 Incentives, Ownership and Performance inPower Sector: The Case of UP 108

9 Discussion Paper on Developing Power Markets 124

10 Captive Coal Mining by Private Power Developers:Issues and the Road Ahead 143

11 Power Distribution Reforms in Andhra Pradesh 163

12 Power Distribution Reforms in Maharashtra 181

13 Power Distribution Reforms in Gujarat 202

14 Barriers to Development of Renewable Energy inIndia and Proposed Recommendations: A Discussion Paper 222

15 Power Distribution Reforms in Delhi 273

16 Power Distribution: Being Driven toInsolvency by a Governance Crisis 290

17 India Solar Policy: Elements Casting Shadow onHarnessing the Potential 334

TELECOMMUNICATIONS

18 Telecom Sector Reform: RestructuringTelecommunications as if the Future Mattered 363

19 Transitioning from Administrative Allocation ofSpectrum to a Market-based Approach 372

LIST OF TABLES, FIGURES AND BOXES

Tables

Table 3.1 Total production of electricity and the share ofdifferent types of generation 22

Table 6.1 Timeline for accelerated privatisation of distribution 68

Table 7.1 Supply/demand—petroleum products (in mmt) 74

Table 7.2 Supply/demand—natural gas (in mmscmd) 76

Table 7.3 Gas demand estimates of different government agencies 78

Table 7.4 Total gas supply potential—Tenth Plan (in mmscmd) 79

Table 7.5 Total gas supply potential post K–G Basin find (in mmscmd) 80

Table 7.6 Projections for POL consumption 2001–2008(in ‘000 metric tonnes) 97

Table 7.7 List of LNG terminals 97

Table 7.8 List of crude pipelines 98

Table 7.9 List of gas pipelines 98

Table 7.10 List of refineries 99

Table 7.11 List of oil product pipelines 99

Table 7.12 List of ports handling oil/petroleum products 100

Table 8.1 Cumulative commercial losses of consolidated UPPCL 111

Table 8.2 Performance parameters 112

Table 8.3 Performance of UPRVUNL generating stations 114

Table 8.4 Reduction of AT&C loss in North Delhi Power Ltd 117

Table 8.5 Collection efficiency (%)—governmental andnon-governmental categories 119

Table 9.1 Recommended loan conditions 132

Table 9.2 Trading margins 136

Table 10.1 Coal blocks identified for the power sector 144

Table 10.2 Criteria for allocation of coal blocks 146

Table 10.3 Pre-production approvals for allottees of coal blocks 147

Table 10.4 Comparison of mining leases in Australia, Canada and India 151

Table 10.5 Normative time limit ceilings as provided in guidelinesfor allocation of captive blocks and conditions of allotmentthrough the screening committee, Ministry of Coal 156

Table 10.6 Minimum time frame of process 159

Table 11.1 Steps taken for power sector reforms in Andhra Pradesh 168

Table 11.2 Investment in infrastructure 172

Table 11.3 AT&C losses (%) of distribution companies 174

Table 11.4 Collection efficiency (%) of distribution companies 175

Table 11.5 Subsidy received 175

Table 11.6 Profit with and without subsidy 176

Table 11.7 Peak deficit and energy deficit in AP 177

Table 11.8 Subsidy received by distribution companies 178

Table 11.9 Sales mix (%) of distribution companies 179

Table 11.10 Revenue mix (%) of distribution companies 179

Table 11.11 Expenses as (%) of total cost for distribution companies 179

Table 12.1 Progress of Single Phasing Scheme 188

Table 12.2 Power scenario in Bhiwandi—before and after franchising 192

Table 12.3 Profits of MSEDCL 196

Table 12.4 MSEDCL’s arrears 196

Table 12.5 Sales mix (as percentage of total units sold) 200

Table 12.6 Revenue mix (as percentage of total revenue) 200

Table 12.7 Expenses as percentage of total expense 201

Table 13.1 AT&C losses for distribution companies 213

Table 13.2 Distribution losses of discoms 213

Table 13.3 Collection efficiency of distribution companies 214

Table 13.4 Subsidy received by distribution companies 215

Table 13.5 Gap between ARR and ACS for distributioncompanies without subsidy 216

Table 13.6 Profits of distribution companies without subsidy 216

Table 13.7 Profits of distribution companies with subsidy 216

Table 13.8 Gujarat state peak deficit and energy deficit 217

Table 13.9 Quality of Service parameters for discoms 218

Table 13.10 Sales mix of distribution companies 219

Table 13.11 Revenue mix of distribution companies 219

viii | Indian Infrastructure: Evolving Perspectives

Table 13.12 Expenses as percentage of total cost fordistribution companies 219

Table 14.1 RE potential and target cumulative capacity addition (in MWeq) 225

Table 14.2 Mismatch between RE capacity envisaged under policy and capacityaddition targeted 229

Table 14.3 Policy instruments for promotion of RE 232

Table 14.4 Regulatory framework for promotion of RE 234

Table 14.5 Penalties for non-achievement of RPO 235

Table 14.6 Status of RPO across Maharashtra 235

Table 14.7 RET capacity added across states with tariff orders/FiTs 236

Table 14.8 Year-wise wind power capacity addition inAndhra Pradesh (in MW) 236

Table 14.9 Salient features of the schemes proposed under the solar powerpurchase policy of JNNSM 248

Table 14.10 Summary of RPOs at state level for select states 264

Table 14.11 FiTs for wind energy and assumptions for FiTs across states 266

Table 14.12 FiITs for solar power across states 267

Table 14.13 FiTs for SHP and assumptions for FiTs across states 268

Table 14.14 FiTs for biomass and bagasse and assumptions for FiTs across states 269

Table 15.1 Accepted bid loss rejection trajectory; minimumbid loss rejection trajectory 276

Table 15.2 Profits 280

Table 15.3 QoS parameters 281

Table 15.4 Peak and energy deficit 282

Table 15.5 Loan to Transco 282

Table 15.6 Expenses break-up of discoms 284

Table 15.7 Capital expenditure by discoms 287

Table 15.8 AT&C loss reduction by discoms 287

Table 15.9 Sales and revenue mix 288

Table 16.1 States exhibiting increases in losses from distribution business 292

Table 16.2 States exhibiting profits or decrease in lossesfrom distribution losses 293

List of Tables, Figures and Boxes | ix

Table 16.3 Most utilities have shown considerable reduction in AT&C lossesbetween 2005–06 and 2008–09 294

Table 16.4 Agricultural consumption continues to remain unmetered—statusin select states 296

Table 16.5 Level of agricultural consumption in select states in 2008–09 297

Table 16.6 Status of implementation of select distribution reform initiativesas of April 2010 298

Table 16.7 Cost recovery in 2008–09 301

Table 16.8 Status of tariff revision in states/union territoriesat the end of 2009 307

Table 16.9 Increase in revenue gap without subsidy for utilitiesbetween 2005–06 and 2008–09 309

Table 16.10 Consumer tariffs as percentage of Average Cost of Supply approvedby SERCs in FY 2008–09 311

Table 16.11 Funding of revenue gap of utilities in Uttar Pradesh 315

Table 16.12 Means of financing the revenue deficits of utilities (indicative) 318

Table 16.13 Outstanding bank loans and government guaranteesin select states (Rs crore) 320

Table 16.14 Interest expenses disallowed by ERCs primarily on accountof short-term loans taken by distribution utilities 323

Table 16.15 Estimated financial losses of utilities in 2012–13 325

Table 16.16 Tariff trends in UMPP bids 327

Table 17.1 Projected deployment of funds in SPSA 340

Table 17.2 List of projects selected under migration scheme of JNNSM 353

Table 17.3 List of projects selected under JNNSM for bundling scheme 354

Table 17.4 Allotment of solar capacities in Gujarat 356

Table 19.1 International experience in spectrum trading 379

Table 19.2 Example of spectrum trading with revenue share payments 384

Table 19.3 Example of revenue neutral differential pricing between SSUs 386

Table 19.4 Allocation of spectrum in other countries 388

Table 19.5 Allocation of spectrum in Indian telecom circles 389

Table 19.6 Public spectrum registry—example of contents 390

x | Indian Infrastructure: Evolving Perspectives

Figures

Figure 2.1 Institutional structure of the Indian power sector 14

Figure 3.1 Restructuring of the Argentine electricity industry(federal assets) 24

Figure 3.2 Estimate medium monomial contract price in the market 26

Figure 3.3 Argentina’s transmission system 27

Figure 3.4 Evolution of capacity and energy prices 28

Figure 3.5 Outages as a per cent of energy demand 29

Figure 7.1 Growth of GDP versus POL consumption 75

Figure 7.2 Aggregate supply/demand POL 2001–02 76

Figure 7.3 Main consumers of natural gas 77

Figure 7.4 LNG prices, US gas prices and crude oil prices 81

Figure 7.5 Comparative transportation costs for road,rail and pipeline modes 84

Figure 7.6 Influence of amortization for a 12” diameter pipeline 85

Figure 7.7 OPEC supply/price dynamics 101

Figure 10.1 PERT chart for coal mine development 149

Figure 10.2 Flowchart of mining proposal approval process 158

Figure 11.1 Cost of power supply, average tariff and gap 164

Figure 11.2 Power sector: Structure pre- and post-reforms 169

Figure 11.3 AT&C losses 173

Figure 11.4 Collection efficiency 174

Figure 11.5 Subsidy received 175

Figure 11.6 ACS, ARR (without subsidy) and gap over the years 177

Figure 12.1 Average cost and realization of power in 2000–01 182

Figure 12.2 Restructuring of MSEB 185


Figure 12.4 Collection efficiency 195

Figure 12.5 Subsidy from state 195

List of Tables, Figures and Boxes | xi

Figure 12.6 Average revenue realised (ARR), average cost of supply (ACS)

and the gap between them over the years for Maharashtra 196

Figure 12.7 Average revenue realised (ARR) without subsidy, average cost

of supply (ACS) and the gap between them over the years

for Maharashtra post-reforms 197

Figure 12.8 SAIFI 197

Figure 12.9 SAIDI 198

Figure 12.10 CAIDI 198

Figure 13.1 Average revenue realisation in Rs/kWh for

various consumer categories 203

Figure 13.2 Restructuring of GEB 205

Figure 13.3 Improvement in cash collections over the years 210


Figure 13.5 Subsidy received 214

Figure 13.6 ARR, ACS and gap between them over the years 215

Figure 14.1 Role of RE in India’s power generation capacity

as on 31 March 2009 223

Figure 14.2 Technology-wise grid-interactive RE capacity in India

as on 31 October 2009 224

Figure 14.3 Events influencing RE development and

RE capacity addition 228

Figure 14.4 Bundling mechanism for sale of solar

power under JNNSM 247

Figure 14.5 Time frame for completion of migration scheme

under solar power purchase policy of JNNSM 247

Figure 14.6 Time frame for completion of scheme for new

projects under solar power purchase policy of JNNSM 247

Figure 15.1 T&D losses and commercial losses pre-reforms 274


Figure 15.3 ARR & ACS 281

Figure 16.1 Losses without subsidy for distribution utilities

have risen sharply in 2008–09 291

xii | Indian Infrastructure: Evolving Perspectives

Figure 16.2 Cash losses before subsidy received for distribution

utilities have trebled between 2005–06 and 2008–09 291

Figure 16.3 All-India AT&C losses are below 30% 295

Figure 16.4 Gap between ARR (without subsidy) and ACS at

the all-India level has increased 300

Figure 16.5 In recent years, tariff increase has not kept pace

with increasing ACS 302

Figure 16.6 Power purchase costs have increased 303

Figure 16.7 Procurement of short term power is increasing 303

Figure 16.8 Short-term power prices have shot up 304

Figure 16.9 Peak and energy deficit in India 304

Figure 16.10 Purchase of short-term power in select states (MU) 305

Figure 16.11 Coal imports for power plants have doubled

between 2005–06 and 2008–09 306

Figure 16.12 Trends in price of imported coal 306

Figure 16.13 Increase in employee costs for distribution utilities in India 307

Figure 16.14 Subsidies booked by distribution utilities are rising

but payment by state governments is inadequate 312

Figure 16.15 Top 10 states exhibiting the maximum increase

in subsidy booked 312

Figure 16.16 States not paying full amount of subsidy to utilities 313

Figure 16.17 Distribution losses in Punjab 316

Figure 16.18 Distribution losses in Madhya Pradesh 316

Figure 16.19 Employee costs of PSEB 317

Figure 16.20 Debtors for sale/transmission of power for state-owned

generation, trading and transmission companies 323

Figure 16.21 Private sector will lead future capacity addition in India 326

Figure 19.1 Variations in use of spectrum across circles and operators 378

Figure 19.2 Example of standard spectrum unit 381

List of Tables, Figures and Boxes | xiii

Boxes

Box 1.1 Take-or-pay in Indonesia 4

Box 1.2 Power sector reform in Argentina 9

Box 3.1 Objectives of CAMMESA 25

Box 3.2 Objectives of ENRE 25

Box 4.1 Timeline of key events in power sector reforms in Orissa 38

Box 6.1 Privatisation of generation assets of SEBs 56

Box 6.2 Limitations of the ‘mixed-zone’ structure 57

Box 6.3 Disadvantages of the single-buyer model 62

Box 7.1 New Exploration Licensing Policy 71

Box 7.2 Definition of petroleum products 73

Box 7.3 Impact of OCC on oil product prices 88

Box 7.4 Contract carrier versus common carriage carrier 90

Box 7.5 Main conversions used in the petroleum industry 102

Box 8.1 Memorandum of Understanding with GOI 113

Box 8.2 Noida Power Company (NPCL)—

a successful distribution company 120

Box 8.3 KESCO privatization 121

Box 11.1 APSEB’s performance review 164

Box 12.1 MSEB’s performance review 183

Box 12.2 White paper on Maharashtra power sector reforms 184

Box 12.3 Load management 187

Box 14.1 Salient features of JNNSM 246

Box 14.2 Urjankur Nidhi Fund in Maharashtra 262

Box 14.3 Detailed provisions of National Solar Mission 271

Box 15.1 Computation and treatment of over/under

achievement of target AT&C loss levels 275

Box 17.1 Solar Power: International Experience 348

Box 19.1 The spectrum is finally attached to the licence 374

Box 19.2 Defining spectrum trading units in Australia 381

Box 19.3 Ofcom’s proposed process for transacting a spectrum trade 382

xiv | Indian Infrastructure: Evolving Perspectives

FOREWORD

Infrastructure Development Finance Company Limited (IDFC) was set up at the initiativeof the Government of India with the mandate to ‘lead’ private capital to commercially viableinfrastructure projects in India. Over the fifteen years of our existence, we have witnessedthe share of private capital grow from an insignificant proportion to the current levels ofalmost 40 per cent of the total infrastructure investment. In the Twelfth Plan, the share ofthe private sector is expected to grow even further to 50 per cent of the investment. Allthrough this period, IDFC has been actively engaged with governments, independentregulators, private developers, banks, financial investors and other stakeholders in the processof advocating and developing appropriate policy, and legal and regulatory frameworks forthis purpose. We would, therefore, celebrate our fifteenth anniversary, later this year, with agreat deal of satisfaction, now that private investment has become an important mode ofinvestment across various infrastructure sectors.

From the beginning, the role envisaged for IDFC was not limited merely to funding, but tolead private investment to this sector. In any case, there were very few private sector projects tofinance in 1997. Leading capital to projects required intense preparatory work and activeengagement with the government in policy formulation, in the preparation of legal andregulatory frameworks, and in the development of transparent procurement processes, objectiveevaluation criteria and equitable concession documents. IDFC, both through its policy advocacyand advisory services teams, provided inputs through a series of interventions. Some of theseinputs were through specific advisory services transactions, for instance, in major ports andnational highways. In power and telecom, inputs were often provided in response to theconsultative process initiated by the regulator or government but were also through notes andopinions conveyed on specific issues. We believe that IDFC’s role was very useful and oftenpivotal in shaping opinion and in leading private investment to infrastructure.

In fulfilment of its mandate to develop infrastructure, a large body of written material hasbeen prepared over the years. These include sector studies, policy recommendations forresolving some of the difficult issues, overviews of emerging trends, outlines of good practicesand issues in financing. Some of these find a place in the thematic India Infrastructure Reportthat is published every year. A few others have been published elsewhere, covered in IDFC’squarterly policy reviews, or released as occasional papers. Many have remained in privatedomain. This publication is an anthology of some of the papers prepared by IDFC over thelast fifteen years, and reflects its emerging views in the quest of nation building. It is arepresentative collection and not an exhaustive one.

Last year we set up IDFC Foundation under Section 25 of the Companies Act 1956, as awholly owned subsidiary of IDFC. IDFC’s development agenda is now being carried outthrough the IDFC Foundation. It is fitting that on the first anniversary of the Foundation,we are able to release this publication as a testament of IDFC’s contribution to infrastructuredevelopment in India.

RAJIV B. LALL

March 2012 Managing Director and CEO

ACKNOWLEDGEMENTS

It is always difficult to acknowledge all those who have contributed to a publication of thisnature, which includes papers and notes written over a fifteen-year period. All the papershave received inputs of different kinds from various sources. The inputs include views,opinions, critical feedback, discussions, encouragement and sometimes just the opportunityto share ideas. In that sense, it would be impossible to acknowledge all the contributors.

At the outset, it would only be fitting to acknowledge the Government of India and thevarious state governments that have, over the years, used IDFC as a sounding board forpolicy and regulatory advice. Within the organisation, at a strategic level, we would first ofall acknowledge the encouragement and support of Deepak Parekh, Chairman, IDFC, RakeshMohan, who briefly served as Vice-Chairman, and its first two Managing Directors,D. J. Balaji Rao and Nasser Munjee. This support has been strongly continued by Rajiv B.Lall, the present Managing Director and CEO of IDFC, under whose stewardship the IDFCFoundation was set up. Acknowledgements are also due to Anil Baijal, Chairman, IDFCFoundation; Urjit R. Patel, who headed the policy group at IDFC for the first ten years; andRitu Anand, who oversees it at present. The inputs received from the various members ofIDFC’s Policy Advisory Boards from time to time, have certainly helped to clarify perspectivesand shape policy opinions. For this, we thank each and every one of them.

Where the papers already include the names of the authors, credits have been given at theend of the respective papers. Nevertheless, the following writers, too, need to be acknowledged:Rajiv B. Lall, Urjit R. Patel, Ritu Anand, Cherian Thomas, Partha Mukhopadhyay, SrikumarTadimala, Anupam Rastogi, Nirmal Mohanty, P. V. Ravi, Saugata Bhattacharya, PiyushTiwari, Sambit Basu, Shishir Mathur, Manisha Gulati, Kaushik Deb, Sunaina Kilachand,Aditi Jagtiani, Kunal Katara, Neeraj Sansanwal, Bhagyathej Reddy, Ashish Agarwal,Pritika Hingorani and Ranesh Nair. Their valuable contributions have gone into thecompilation of these volumes, which provide both historical and current perspectives andcould be useful points of reference in all our future efforts at nation building.

Our thanks are due also to Orient BlackSwan, the publishers of this volume, who have beenconsistent in maintaining quality while accommodating the sometimes exacting demandsmade on them.

Finally, we would like to thank all our colleagues at IDFC, past and present, whose consistentfeedback and varying perspectives on the various themes have been of immense value. Whilewe have taken care to include everyone who helped us in compiling this report, any omissionsare unintentional and we hope that they would be construed as such.

INTRODUCTION

Evolving Perspectives in the Development of Indian Infrastructure (in two volumes) is acompilation of several papers written by IDFC over the last fifteen years on the themes ofinfrastructure development and financing. It is not an exhaustive summary of all of IDFC’swork in infrastructure policy and regulation during this period. Much of IDFC’s policycontribution has been through inputs provided to the many task forces, working groupsand high-level committees constituted by central and state governments from time to time,in which IDFC’s officials have been (or are being) represented. In many other instances,recommendations have been provided to governments and regulators as part of theconsultative process followed while seeking views of stakeholders in these sectors. Some ofIDFC’s development work has also been through specific outputs in the form of reports anddocuments prepared as part of advisory service transactions for governments. Another visibleoutput that is published year after year is the India Infrastructure Report—a thematic reportthat discusses issues of contemporary concern across the infrastructure space. In some ways,this anthology captures some of IDFC’s emerging views over this period, which may bereflected in its recommendations and inputs in the activities listed above.

This publication consists of two volumes. The first volume has two sections—energy andtelecommunications. The second volume deals with transport, urban and other infrastructure,and infrastructure development and financing. It comprises 45 papers on a range of topicson various aspects of policy and financing. These cover the period from May 1998 toJanuary 2012. The papers are of varying lengths, depending on the specific context in whichthey were written and the need sought to be addressed. Some of the issues debated in theearlier papers and the recommendations may still be relevant in the current context, andthese volumes would have more than a historical significance. The power sector, notsurprisingly, has the most number of papers—since it is the biggest of the infrastructuresectors—and these papers are reflective of the various emerging issues in the sector. A section-wise summary of the two volumes is set out below.

The initial papers in the power sector (written 1998–2001) set out the issues and challengesfor private investment in the sector. Drawing from international experiences in Argentinaand Indonesia, right from the outset, IDFC highlighted the need to focus on reforms and onrestructuring the sector with a view to increase efficiency and reduce losses. The suggestionsfor creating a more competitive market structure conducive to private sector participation—unbundling the monolithic electricity boards and creating independent regulatory authorities,separating network business from supply, and establishing power trading as a separate licensedactivity—were forerunners to many subsequent changes, such as the introduction of openaccess. Equally noteworthy are the suggestions for private sector investment in powerdistribution, initially through franchising dense urban areas. The relative success of thefranchisee model (in Bhiwandi and other places) in improving distribution efficiencies andcollections reflect the merits of this suggestion. The separation of urban and non-urbanareas and the development of a transparent mechanism for payment of subsidies will continueto be issues that engage us as the reform process in the sector moves ahead.

Some of the papers review the reforms and progress of the sector in the states of Orissa(February 2000), Uttar Pradesh (February 2005), Andhra Pradesh, Delhi, Maharashtra andGujarat. The review includes an assessment of the gains made so far, as well as theshortcomings and the challenges ahead for each of these states. The most recent paper onthe power distribution sector clearly highlights the severity of the losses in power distribution,the looming risk of insolvency of these utilities, and the urgent need for good governance toenable future capacity addition and to restore the overall health of the financial system.The wide gamut of subjects covered include the regulation of petroleum product pipelines,the conditionalities in power sector lending, and the challenges in implementing the captivecoal mining policy. The section also includes a discussion paper on renewable energy and aspecific paper on solar energy.

The telecom section is rather small since much of the policy input was provided by IDFC aspart of the consultative process in this sector with the government and the regulator. Theinitial paper on the sector (December 1998) set out some of the sectoral challenges, keepingin mind the new telecom policy that was to be announced. The second paper covered theprinciples for allocation of spectrum and also the issue of spectrum trading. The wisdom ofusing the market-based approach has been clearly vindicated by the subsequent events thathave overtaken the sector.

The second volume begins with a section on issues related to the transport sector. Much ofthe work done by IDFC in the transport sector was as Secretariat to the Task Force onInfrastructure and through specific advisory assignments in major ports and nationalhighways sectors, in the initial years. The paper on ports sector reforms (December 1999)argued that there is little need for immediate additional public investment in the sector, butsuggested a focus on efficiency in port services by private providers subject to competitivepressures. It also recommended a push to reform port labour, the need for strengtheninghinterland connectivity, and that of putting in place a pro-competitive and stable regulatorysystem. All these represent a continuing agenda in the sector. A subsequent paper(November 2000) highlighted the need to integrate coastal shipping with the surfacetransport network. This is a challenge that has largely been ignored for several decadesand could assume increasing importance given the enormous environmental benefits andlower transport costs that could accrue from increased coastal movement of goods.A paper on railways sets out the opportunities for public–private partnerships in the sector,and includes the experience of the Hassan–Mangalore railway project in Karnataka. Paperson the roads sector include a status note on the National Highway DevelopmentProgramme (NHDP), a review of the challenges of financing highways, and, the mostrecent one, on the challenges for NHAI in financing the NHDP.

The first paper in the urban sector covers the water sector. The paper (March 2001)highlighted the need for independent regulation, rational tariff setting and the appropriaterole of the private sector. This is followed by a paper on special economic zones (SEZs)which argued that SEZs are more in the nature of ‘band aid’ fixes and that the focus of thepolicy should move from augmenting infrastructure facilities for export production to anoverall focus on higher-quality infrastructure, growth and employment. A selection of papers

xx | Indian Infrastructure: Evolving Perspectives

from IDFC policy quarterly research notes covers the issues of land pooling, bus rapid transitsystems, green buildings, sewage water recycling for industrial use, and municipal borrowingsusing pooled finance mechanisms. The base note prepared on urban financing (for the HighPowered Expert Committee) provides a comprehensive review of the financing for urbaninfrastructure. A paper on private healthcare in India (December 2002) broadly reviewedthe key challenges of the sector at that point and identified a few business models for healthcareinvestment in future.

The last section of the second volume includes papers on various cross-cutting issues ininfrastructure development and financing. The earliest paper (May 1999) briefly reviewedthe challenges of reforming the debt market in India, some of which still remain.A detailed paper on competitive bidding (August 2000) argued that competitive biddingprovides the most efficient and cost effective method for procurement of infrastructureservices—a lesson that has become systematised practice over the last decade across sectors.Two papers deal with the issue of regulation. The January 2005 paper reviews regulationacross sectors and argues that regulation is one piece of the infrastructure puzzle and has tobe complemented with an industry structure that aligns operators’ incentives towards pursuitof value for money. The more recent paper on regulation looks further at the future ofregulation in India. Papers on financing comprise two independently written reviews:domestic financing and the role of IDFC, and infrastructure financing and the role of non-banking finance companies. Other papers include a short note on infrastructure developmentin India (prepared for the World Economic Forum), an analysis of the political economy ofinfrastructure development (which concludes that political logic would drive decisionmakersto deliver improved infrastructure with a greater reliance on private provision of theseservices), and a detailed comparison of infrastructure creation in China and in India. Thelast paper identifies some of the lessons that can be learnt from the Chinese experience, suchas using improved technology, pursuing financially sustainable solutions, and improvingefficiency and accountability in the government while pursuing solutions that are moreimplementable in our context.

All in all, it is hoped that this publication would give the readers an insight into some of theevolving policy perspectives and recommendations that have emerged in the last fifteenyears—a period when infrastructure development has received more focussed attention than

at any time since Independence.

Introduction | xxi

LIST OF ABBREVIATIONS

A$ Australian Dollar

ACA Australian Communications Authority

ACCC Australian Competition Consumer Council

ACS Average Cost of Supply

ADB Asian Development Bank

ADF Airport Development Fees

ADRD Alberta Department of Resource Development

AEC Ahmedabad Electricity Company

AEE Autorita per l'Energia Elettrica e il Gas

AERA Aviation Economic Regulatory Authority

AGCOM The Communications Regulatory Authority

AGR Adjusted Gross Revenue

AIM Alternative Investment Market

AIP Administrative Incentive Pricing

AMC Ahmedabad Municipal Corporation

AP Andhra Pradesh

APDRP Accelerated Power Development and Reform Programme

APERC Andhra Pradesh Electricity Regulatory Commission

APL Adaptable Programme Loan/Lending

APM Administrative Price Mechanism

APPSRP Andhra Pradesh Power Sector Restructuring Programme

APSEB Andhra Pradesh State Electricity Board

ARR Annual Revenue Requirement

ARR Average Revenue Realised

ASEAN Association of Southeast Asian Nations

ASP Activated Sludge Process

AT&C Aggregate Technical and Commercial

ATE Appellate Tribunal for Electricity

ATF Aviation Turbine Fuel

AUDA Ahmedabad Urban Development Authority

BBCD Bare-Boat-Charter-cum-Demise

bbl Barrels

BCC Beneficiary Capital Contribution

BCC Base Construction Cost

bcm Billion Cubic Metres

BCM Book Consolidation Module

BEE Bureau of Energy Efficiency

BEST Brihan Mumbai (Bombay) Electric Supply and Transport Undertaking

BG Broad Gauge

BIAL Bengaluru International Airport Limited

BKCC B. K. Chaturvedi Committee

BLD Billion Litres per Day

BLT Build, Lease, Transfer

BOD Biological Oxygen Demand

BOLT Build, Operate, Lease, Transfer

BOO Build, Own, Operate

BOOM Build, Own, Operate, Maintain

BOOST Build, Own, Operate, Share, Transfer

BOOT Build, Own, Operate, Transfer

BOQ Bill of Quantities

BOT Build Operate Transfer

BP British Petroleum

BPCL Bharat Petroleum Corporation Limited

BRPL Bongaigaon Refinery and Petrochemicals Limited

BRTS Bus Rapid Transit System

BS basic service

BSES Bombay Suburban Electric Supply

BSF Bond Service Fund

BSNL Bharat Sanchar Nigam Limited

BTS Bangkok Mass Transit System

BUA Built-up Area

BWSSB Bangalore Water Supply and Sanitation Board

BYPL BSES Yamuna Power Limited

xxiv | Indian Infrastructure: Evolving Perspectives

CA Constitutional Amendment

CAA Constitutional Amendment Act

CAA Civil Aviation Authority

CAA Cost under the Annuity Approach

CAGR Compound Annual Growth Rate

CAIDI Consumer Average Interruption Duration Index

CAM Common Area Maintenance

CAMMESA Compañía Administradora del Mercado Mayorista Eléctrico

CAT Consumer Analysis Tool

CBDT Central Board of Direct Taxes

CCA Cost under the Conventional Approach

CCI Competition Commission of India

CDB China Development Bank

CDMA Code Division Multiple Access

CDs Certificates of Deposits

CEA Central Electricity Authority

CEPZ Cochin Export Processing Zone

CERC Central Electricity Regulatory Commission

CESC Calcutta Electric Supply Company

CESCO Central Electricity Supply Company

CFC Consumer Facilitation Centres

CFS Centre for Sight

CGD City Gas Distribution

CGHS Central Government Health Scheme

CGWB Central Ground Water Board

CIL Coal India Limited

CLF Credit Local de France

CMIE Centre for Monitoring Indian Economy

CMS Cellular Mobile Service

CMT Comisión del Mercado de las Telecomunicaciones

CMTS Cellular Mobile Telephony Service

CMW Chennai Metro Water

List of Abbreviations | xxv

CNE Comisión Nacional de Energía

COAI Cellular Operators Association of India

CONCOR Container Corporation of India

CONEA Coalition of North East Association

CP Commercial Paper

CPCB Central Pollution Control Board

CPPs Captive Power Plants

CPSU Central Public Sector Unit

CPT Chennai Port

CPUC California Public Utilities Commission

CREF Credit Rating Enhancement Fund

CRG Crisis Resolution Group

CSE Centre for Science and Environment

CST Concentrated Solar Thermal

CSUs Central Sector Undertakings

CTC Competitive Transition Charge

DALY Disability Adjusted Life Years

DBFO Design Build Finance Operate

DELs Direct Exchange Lines

DEPB Duty Entitlement Pass Book

DERC Delhi Electricity Regulatory Commission

DESU Delhi Electric Supply Undertaking

DF Distribution Franchisee

DFID Department for International Development

DFIs Development Finance Institutions

DFRC Duty Free Replenishment Certificate

DGH Directorate General of Hydrocarbons

DIAL Delhi International Airport Limited

DIMTS Delhi Integrated Multimodal Transit System

discom/distco Distribution Company

DJB Delhi Jal Board

DM De-mineralisation

xxvi | Indian Infrastructure: Evolving Perspectives

DMRC Delhi Metro Rail Corporation

DoT Department of Telecommunications

DSCR Debt-Service Coverage Ratio

DSM Demand-Side Management

DSR Debt Service Requirement

DT/DTR Distribution Transformer

DTA Domestic Tariff Area

DVA Distribution Value Added

DVB Delhi Vidyut Board

DVP Delivery versus Payment

DWT Decentralised Wastewater Treatment

EA 03 Electricity Act 2003

EA Energy Audit

EC European Commission

ECB External Commercial Borrowings

ECBC Energy Conservation Building Code

EDENOR Empresa Distribuidora y Comercializadora Norte S.A.

EDZ Economic Development Zone

EIRP Equivalent Isotropically Radiated Power

ENARGAS Ente Nacional Regulador del Gas

ENRE Ente Nacional Regulador de la Electricidad

EoD Event of Default

EOU Export Oriented Unit

EPC Engineering, Procurement and Construction

EPZ: Export Promotion Zone

ERC Electricity Regulatory Commission

ESC Essential Services Commission

ESIS Employees State Insurance Scheme

ETDMA Extended Time Division Multiple Access

ETOSS Ente Tripartito de Obras y Servicios Sanitarios

EU European Union

EUA Electricity Utilities Act

List of Abbreviations | xxvii

EUB Energy and Utilities Board

EWS Economically Weaker Section

FAA Federal Aviation Administration

FAR Floor Area Ratio

FCA Fuel Cost Adjustment

FCC Federal Communications Commission

FDI Foreign Direct Investment

FERC Federal Energy Regulatory Commission

FIE Foreign Invested Enterprises

FIPB Foreign Investment Promotion Board

FIs Financial Institutions

FiT Feed-in Tariff

FM Frequency Modulation

FO Furnace Oil

FOB Free-on-Board

FOR Forum of Regulators

FP Future Plot

FPPPA Fuel and Power Purchase Price Adjustment

FRP Financial Restructuring Plan

FSA Fuel Supply Agreement

FSA Financial Services Authority

FSI Floor Space Index

FTCs Foreign Trade Companies

FY Fiscal Year

GACL Gujarat Ambuja Cements Limited

GAIL Gas Authority of India Limited

GARR Guaranteed Average Revenue Realisation

GBI Generation-based Incentives

GBWASP Greater Bangalore Water Supply and Sanitation Project

GDP Gross domestic product

GIC General Insurance Corporation of India

GNCL Gujarat NRE Coke Limited

xxviii | Indian Infrastructure: Evolving Perspectives

GNCTD Government of National Capital Territory of Delhi

GNIDA Greater Noida Industrial Development Authority

GOG Government of Gujarat

GOI Government of India

GOK Government of Karnataka

GOM Government of Maharashtra

GQ Golden Quadrilateral

GRIDCO Grid Corporation of Orissa

GRIHA Green Rating for Integrated Habitat Assessment

GSDP Gross State Domestic Product

G-Secs Government of India Securities

GSM Global System for Mobile Communications(formerly, Groupe Spécial Mobile)

GSPC/GSPCL Gujarat State Petroleum Corporation (Limited)

GSPL Gujarat State Petronet Limited

GTPUDA Gujarat Town Planning and Urban Development Act

GU Geographic Unit

GUVNL Gujarat Urja Vikas Nigam Limited

GWCL Ghana Water Company Limited

ha Hectare

HBEPL Hanzer Biotech Energies Private Limited

HBJ Pipeline Hazira-Bijaipur-Jagdishpur Pipeline

HCBS High Capacity Bus System

HCCL Hindustan Construction Company Limited

HERC Haryana Electricity Regulatory Commission

HFCL Himachal Futuristic Communications Limited

HIDRONOR Hidroeléctrica Norpatagónica Sociedad Anónima

HMRDCL Hassan Mangalore Rail Development Company Limited

HNIs High Net-Worth Investors

HP Himachal Pradesh

HPCL Hindustan Petroleum Corporation Limited

HR Human Resources

List of Abbreviations | xxix

HSD High Speed Diesel

HUDCO Housing and Urban Development Corporation

HVDS High Voltage Distribution System

IAAI International Airports Authority of India

IARR Implied Average Revenue Realisation

IAT Independent Assessment Team

ICICI Industrial Credit and Investment Corporation of India

ICRA (formerly) Investment Information and Credit RatingAgency of India Limited

ICTSL Indore City Transport Services Limited

IDBI Industrial Development Bank of India

iDeCK Infrastructure Development Corporation (Karnataka)

IDFC Infrastructure Development Finance Company Limited

IFCI Industrial Finance Corporation of India

IGBC Indian Green Building Council

IGIA Indira Gandhi International Airport

IGL Indraprastha Gas Limited

IIBI Industrial Investment Bank of India

IIFCL India Infrastructure Finance Company Limited

IL&FS Infrastructure Leasing and Financial Services

IOC IndianOil Corporation

IPGCL Indraprastha Power Generation Company Limited

IPPs Independent Power Producers/Projects

IR/IRC Indian Railways (Corporation)

IRA Independent Regulatory Agency

IRBI Industrial Reconstruction Bank of India

IRDA Insurance Regulatory and Development Authority

IRR Internal Rate of Return

IRRA Indian Rail Regulatory Authority

IT Information technology

ITU International Telecommunications Union

IUP Intended Use Plans

xxx | Indian Infrastructure: Evolving Perspectives

I-WIN ICICI-West Bengal Infrastructure Development Corporation Limited

JCC Japanese Cocktail Crude

JICA Japan International Cooperation Agency

JNNSM Jawaharlal Nehru National Solar Mission

JNNURM Jawaharlal Nehru National Urban Renewal Mission

JNPT Jawaharlal Nehru Port Trust

JV Joint Venture

KERC Karnataka Electricity Regulatory Commission

KESCO Kanpur Electricity Supply Company

K-G Basin Krishna-Godavari Basin

KINFRA Kerala Industrial Infrastructure Development Corporation

K-RIDE Karnataka Rail Infrastructure Development Corporation

KUIDFC Karnataka Urban Infrastructure Development andFinance Corporation

KUWASIP Karnataka Urban Water Supply Improvement Project

KUWSBD Karnataka Urban Water Supply and Drainage Board

KWSPF Karnataka Water and Sanitation Pooled Fund

LEED Leadership in Energy and Environmental Design

LIC Life Insurance Corporation of India

LNG Liquefied Natural Gas

LoI Letter of Intent

LPCD Litres per Capita per Day

LPR Land Pooling and Readjustment/Reconstitution

LPVR Least Present Value of Revenues

LSHS Low Sulphur Heavy Stock

M&A Mergers and Acquisitions

MADP Maximum Alternative Distribution Payment

MAGP Maximum Alternative Generation Payment

MASTS Mobile Assignment Technical System

MATS Monitoring and Tracking System

MBR Membrane Bio Reactor

mBtu/mmBtu Million British thermal units

List of Abbreviations | xxxi

MCA Model Concession Agreement

MCB Miniature Circuit Breaker

mcm Million Cubic Metres

MCs Municipal Corporations

MDF Municipal Development Fund

MEPZ Madras Export Processing Zone

MERC Maharashtra Electricity Regulatory Commission

MFL Madras Fertilizers Limited

MG Metre Gauge

MMC Madurai Municipal Corporation

MMDR Act Mines and Minerals (Development and Regulation) Act

MMRDA Mumbai Metropolitan Regional Development Authority

mmscmd Metric Million Standard Cubic Meters per Day

Mmt Million Metric Tonnes

Mmtpa Million Metric Tonnes per Annum

MNRE Ministry of New and Renewable Energy

MoCA Ministry of Civil Aviation

MoD Ministry of Defence

MoP Ministry of Power

MoPNG Ministry of Petroleum and Natural Gas

MoR Ministry of Railways

MoRTH Ministry of Road Transport and Highways

MoST Ministry of Surface Transport

MoU Memorandum of Understanding

MoUD Ministry of Urban Development

MP Madhya Pradesh

MPE Mumbai-Pune Expressway

MPSC Model Production Sharing Contract

MRTS Mass Rapid Transit System

MS Motor Spirit

MSB Minimum Subsidy Bidding

MSEB Maharashtra State Electricity Board

xxxii | Indian Infrastructure: Evolving Perspectives

MSEDCL Maharashtra State Electricity Distribution Company Limited

MSRDC Maharashtra State Road Development Corporation

MT Million Tons

mt Metric Tonnes

MTNL Mahanagar Telephone Nigam Limited

MYT Multi-year Tariff

NABARD National Bank for Agriculture and Rural Development

NBFCs Non-Bank Financial Companies

NBFI Non-Bank Financial Institution

NCR National Capital Region

NDPL North Delhi Power Limited

NDRC National Development and Reform Commission

NELP New Exploration Licensing Policy

NEN National Expressway Network

NEPZ Noida Export Processing Zone

NESCO Northern Electricity Supply Company

NFAP National Frequency Allocation Plan

NHAI National Highways Authority of India

NHDP National Highway Development Project

NHPC National Hydroelectric Power Corporation

NLD National Long Distance

NMMC Navi Mumbai Municipal Corporation

NMP National Mineral Policy

NMPT New Mangalore Port Trust

NPAs Non-performing Assets

NPCL Noida Power Company Limited

NPV Net Present Value

NSDL National Securities Depository Limited

NSE National Stock Exchange

NS-EW North South-East West

NTHS National Trunk Highway System

NTPC National Thermal Power Corporation

List of Abbreviations | xxxiii

NUIF National Urban Infrastructure Fund

NUTP National Urban Transport Policy

NWP National Water Policy

NWRC National Water Resources Council

NYSPSC New York State Public Service Commission

NZ$ New Zealand dollar

O&M Operation and Maintenance

OA Open Access

OCC Oil Coordination Committee

OECD Organisation for Economic Co-operation and Development

OECF Overseas Economic Cooperation Fund

OERC Orissa Electricity Regulatory Commission

OFAPs Operational and Financial Action Plans

OFCOM Office of Communications

OFGEM Office of Gas Electricity Markets

OFWAT Office of Water Services

OHPC Orissa Hydro Power Corporation

OIL Oil India Limited

OMT Operate, Maintain, Transfer

ONGC Oil and Natural Gas Corporation of India

OP Original Plot

OPEC Organization of Petroleum Exporting Countries

OPGC Orissa Power Generation Corporation

ORR Office of the Rail Regulator

OSEB Orissa State Electricity Board

OSN Obras Sanitarias de la Nación

OUR Office of Utilities Regulation

P&O Peninsular and Oriental Steam Navigation Company

PBOC People’s Bank of China

PBR Private Business Radio

PCS Personal Communications Services

PDCOR Project Development Company of Rajasthan

xxxiv | Indian Infrastructure: Evolving Perspectives

PE Private Equity

PFC Power Finance Corporation

PFDF Pooled Finance Development Fund

PFDS Pooled Finance Development Fund Scheme

PFI Private Finance Initiative

PfP Payment for Performance

PFs Provident Funds

PGCIL Power Grid Corporation of India Limited

PIDB Punjab Infrastructure Development Board

PIL Petronet India Limited

PIL Public Interest Litigation

PLF Plant Load Factor

PMCs Project Management Consultants

PMT Panna Mukta Tapti

PNGRB Petroleum and Natural Gas Regulatory Board

POL Petroleum, Oil and Lubricants

PPA Power Purchase Agreement

PPCL Pragati Power Corporation Limited

PPFCA Power Purchase Fuel Cost Adjustment

PPIAF Public-Private Infrastructure Advisory Facility

PPP Public-Private Partnership

PSA Port of Singapore Authority

PSA Power Sale Agreement

PSC Production Sharing Contract

PSC Public Sector Comparator

PSEB Punjab State Electricity Board

PSP Private Sector Participation

PSU Public Sector Undertaking

PTC Power Trading Company

PTIM Pre-tax Investment Multiple

PwC PricewaterhouseCoopers

PWLB Public Works Loan Board

List of Abbreviations | xxxv

QoS Quality of Service Parameters

QoSS Quality of Supply and Service

R&D Research and Development

RAPDRP Restructured-Accelerated Power Development andReforms Programme

RCF Rashtriya Chemicals and Fertilizers Limited

RE Renewable Energy

REBs Regional Electricity Boards

REC Renewable Energy Certificate

RERC Rajasthan Electricity Regulatory Commission

RET Renewable Energy Technology

RFP Request for Proposal

RFQ Request for Quotation

RFQ Request for Qualification

RLDCs Regional Load Dispatch Centres

RMC Rajkot Municipal Corporation

RoC Regulation by Contract

ROE Return on Equity

ROR Rate of Return

ROT Rehabilitate, Operate, Transfer

ROW Right of Way

RPOs Renewable Purchase Obligations

SAA Simultaneous Ascending Auction

SAIDI System Average Interruption Duration Index

SAIFI System Average Interruption Frequency Index

SBR Sequential Batch Reactor

SCADA Supervisory Control and Data Acquisition System

SCI Shipping Corporation of India

SCM Subsidies and Countervailing Measures

SEBI Securities and Exchange Board of India

SEBs State Electricity Boards

SEDs State Electricity Departments

xxxvi | Indian Infrastructure: Evolving Perspectives

SEEG Société d'Exploitation des Eaux de Guinée

SEEPZ Santa Cruz Electronic Export Processing Zone

SEGBA Servicios Eléctricos del Gran Buenos Aires

SERC State Electricity Regulatory Commission

SEZ Special Economic Zone

SFC State Finance Commission

SFCD State Finance Commission Devolution

SGAs Specialised Government Agencies

SGI Solicitor General of India

SHP Small Hydro Power

SKO Superior Kerosene Oil

SLAUs Special Land Acquisition Units

SOE State-owned Enterprise

SONEG Société Nationalé des Eaux de Guinée

SOUTHCO Southern Electricity Supply Company

SPD Solar Power Developer

SPFE State Pooled Finance Entity

SPV Special Purpose Vehicle/Company

SPV Solar Photovoltaic

SSI Small Scale Industry

SSUs Standard Spectrum Units

STD Subscriber Trunk Dialing

STP Sewage Treatment Plant

STU Standard Trading Unit

STW Sewage Treated Water

SWM Solid Waste Management

T&D Transmission and Distribution

TA Technical Assistance

TACID Tamil Nadu Corporation for Industrial Infrastructure Development

TAMP Tariff Authority for Major Ports

TAT Tourism Authority of Thailand

TBA To Be Announced

List of Abbreviations | xxxvii

tcf Trillion Cubic Feet

tcm Thousand Cubic Metres

TDRs Transfer of Development Rights

TDSAT Telecom Disputes Settlement and Appellate Tribunal

TD-SCDMA Time Division Synchronous Code Division Multiple Access

TEA Tirupur Exporters Association

TERI The Energy and Resources Institute

TEU Twenty-foot Equivalent Unit

TFC Thirteenth Finance Commission

TIMS Transformer Information Management System

TN Tamil Nadu

TNEB Tamil Nadu Electricity Board

TNERC Tamil Nadu Electricity Regulatory Commission

TNUDF Tamil Nadu Urban Development Fund

TNUIFSL Tamil Nadu Urban Infrastructure Financial Services Ltd

TNWSPF Tamil Nadu Water and Sanitation Pooled Fund

TOU Time of Use

TPAs Third Party Administrators

TPC Total Project Cost

TPO Town Planning Officer

TRAI Telecom Regulatory Authority of India

Transco Transmission Company

TSS Total Suspended Solids

TTRO Tertiary Treatment and Reverse Osmosis Plant

TVEs Township and Village Enterprises

UASL Unified Access Services License

UDF User Development Fee

UI Unscheduled Interchange

ULBs Urban Local Bodies

UMPPs Ultra Mega Power Projects

UMTS Universal Mobile Telecom Service

UPERC Uttar Pradesh Electricity Regulatory Commission

xxxviii | Indian Infrastructure: Evolving Perspectives

UPPCL Uttar Pradesh Power Corporation Ltd

UPRVUNL Uttar Pradesh Rajya Vidyut Utpadan Nigam Limited

UPSEB Uttar Pradesh State Electricity Board

US$ United States Dollar

USAID United States Agency for International Development

USF Universal Service Fund

USFA Universal Service Fund Administrator

VAT Value Added Tax

VfM Value for Money

VGF Viability Gap Funding

VPT Village Public Telephone

VSNL Videsh Sanchaar Nigam Limited

WB West Bengal

WBSEDCL West Bengal State Electricity Distribution Company Limited

WESCO Western Electricity Supply Company

WLL Wireless Local Loop

WPC Wireless Planning and Coordination Wing

WPI Wholesale Price Index

WS&S Water Storage and Supply

WSA Water Service Agency

WSP Waste Stabilisation Pond

WSPF Water and Sanitation Pooled Fund

WSS Water Supply and Sewerage

WTO World Trade Organization

WUA Water Users Association

WWD Water Works Department

List of Abbreviations | xxxix

1. INTRODUCTION

The investment needed in the power sector in the next five years is estimated tobe in excess of Rs 200,000 crore (US$50 billion), largely in new generating plants.Over a longer term, 75,000 MW of new generating capacity is being contemplatedin the form of mega power plants. Since each MW of generating capacity installedby an independent power producer requires an estimated commitment of aboutRs 1.5 crore per annum (6000 MWhrs, at Rs 2.5 per kWh), the payment liabilityfor this generating capacity would amount to Rs 112,500 crore (US$28 billion)per year. Considering that the total revenue of all electricity boards in the countryis only around Rs 40,000 crore per annum, the additional liabilities areunmanageable under the current regime of revenue mobilisation.

The government has provided many incentives to independent power producers(IPPs). These include a guaranteed rate of return of 16 per cent, counter guaranteesfrom the central and state governments, escrow accounts for assured payments, etc.As a result, over 250 MoUs have been signed. However, the success rate from MoUto financial closure has been low. Only a few projects have been implemented in thepast seven years. The primary hurdle in implementation is now recognised as thepoor financial health of the electricity boards, who are currently the sole purchasersof electricity from the IPPs. In turn, this is attributable to the poor state ofdistribution, characterised by low quality of service, rampant theft, high subsidiesand poor revenue recovery.

Therefore, in order to make these planned MWs a reality, a substantially increasedrevenue generation from the distribution system assumes the highest priority.Additional megawatts can only be generated if more megawatt hours are delivered

POWER SECTOR REFORM:Policy Decisions inDistributionMay 1998

1

4 | Indian Infrastructure: Evolving Perspectives

and paid for, that is, either the number of paying consumers has to increase or theconsumption of the currently paying consumers must rise. An efficient revenuegenerating system would also obviate the need for sovereign guarantees, escrowaccounts and take-or-pay contracts, and permit the development of the sector oncommercial lines. The consequences of ignoring additional revenue generation canlead eventually to major national problems, similar to that being currentlyexperienced in Indonesia (see Box 1.1).

Box 1.1: Take-or-pay in Indonesia

In a situation very similar to that of India, the paucity of investible funds led Indonesiato invite the private sector to construct power plants. With optimistic growth forecasts,the National Power Corporation, PLN, set itself ambitious targets and signed 26 “take-or-pay” power purchase agreements with private IPPs. In most contracts, the price,which was linked to the US dollar, ranged from 5.7 to 8.5 US cents per kWh. Therecent Southeast Asian currency crisis saw the Indonesian rupiah depreciate by over70 per cent and the GDP growth rate turn negative. The growth in electricity demandslumped to zero and the dollar equivalent of the tariff fell sharply. At the prevailingexchange rate, PLN’s tariff rates are less than 2.0 US cents per kWh. Its liability for thenext 15 years is estimated at US$43 billion, which it has no means to honour. PLN’s

take-or-pay contracts are now a major national problem.

2. CHARACTERISTICS OF SEBs

State Electricity Boards (SEBs) in India are beset with numerous problems. They arecharacterised by huge financial losses, high transmission and distribution lossescomprising technical and non-technical components, unsatisfactory quality andlow reliability of supply, undelivered and misdelivered bills, poor collection andunresponsiveness to consumers’ requirements.

Financial losses: The annual commercial losses of the electricity boards in thecountry have increased from Rs 1565 crore in 1985–86 to nearlyRs 10,000 crore in 1996–97 (Planning Commission 1997). The average revenuecollection per unit sold is 158 paise, against the average cost of208 paise. A desirable scenario where the electricity boards can undertake asustainable expansion programme would require surplus generation of aboutRs 10,000 crore,1 which in effect means that the current shortfall in revenue is closeto Rs 20,000 crore per year.

Transmission and distribution losses: The transmission and distribution lossesfor the country were reported to be 21.2 per cent in 1994–95. However, it is widelybelieved, and substantiated by spot surveys, that the level of losses is considerablyhigher—in the range of 40 to 50 per cent—in many electricity boards, with a large

Power Sector Reform | 5

degree of regional variations. It is alleged that lower losses are shown by falselyattributing higher energy consumption to unmetered consumers. In fact, the so-called losses are more likely to be due to uncalibrated and unsatisfactory meters,theft of energy by unauthorised connections, tampering of meters, and collusionbetween consumers and board staff to reduce the billing.

Poor quality of service: The quality of service in electricity supply can be measuredby the frequency, voltage and continuity of supply. On all these scores, the Indiandistribution system rates extremely low. Frequency variations of ±2 per cent arequite common on Indian grids, whereas internationally even a 0.2 per centvariation is considered unacceptable. Voltage variations here regularly exceed ±10per cent, whereas international norms prescribe ±5 per cent as the maximumpermissible range. Consequently, agricultural and industrial electrical equipmentand domestic electrical appliances suffer from frequent breakdowns. Continuityof service, that is, receiving uninterrupted power supply, is quite rare in India.Restoration of service after an unplanned or forced interruption is generally greatlydelayed. The consumer response to the situation is the proliferation of “gensets”,involving significant investment in a relatively inefficient mode of powergeneration using scarce liquid fuels.

3. REASONS FOR THE PRESENT STATE OF SEBsThe factors that have contributed to the present state of electricity boards can bebroadly classified under two heads—management failure and inappropriate policieson the part of state governments. The potential for corruption in this highly capital-intensive sector has only added to its woe.

Lack of management attention: The management of distribution facilities are notup to desired standards in terms of investment, manpower allocation andtechnological innovation. The share of transmission and distribution in the planoutlays has been only 26 to 28 per cent since the second five-year plan, against adesirable level of about 40 to 50 per cent. Generation projects requiring largeinvestments, higher technological content, well-defined objectives and greaterpotential for job satisfaction and rewards have traditionally attracted more resources.

Inappropriate emphasis: In distribution, the emphasis has been on extensivedevelopment rather than intensive development. Since targets focus on quantityrather than quality, the tendency has been to spread a low-cost and low-standarddistribution network to as many households, villages and agricultural pump sets aspossible, within the constraints of the budget. After construction, relatively littleattention is devoted to preventive maintenance, as most distribution staff are engagedin new constructions.


Metering, billing and collection practices: The present collection system causeslarge revenue losses. It is characterised by lack of proper customer informationand reliance on antiquated billing and accounting systems that do not providetimely information. Existing labour policies provide no incentive for staff toproduce results. Added to this is the persistent inability to take disciplinary actionagainst defaulting consumers, many of whom are state and local governmentorganisations or influential industrial and commercial consumers. This has led toestimated revenue arrears, receivable by electricity boards, of over Rs 13,000 crorein 1995–96 amounting to 37.5 per cent of the total annual revenues (PlanningCommission 1997).

Government subsidy policies: The government’s policy of supplying electricityto favoured consumers at lower costs is estimated to have resulted in a revenueloss of Rs 19,228 crore in 1996–97 (Planning Commission 1997). State governmentsare required to compensate the electricity boards for such losses. To the extentthat this is done, it has a debilitating effect on state finances. Often though, thestate government does not make the necessary budgetary transfers, resulting inpaucity of funds for operation, maintenance and capital work. Apart from therevenue loss, a worse long-term consequence of this policy is the loss of incentivefor electricity boards to meter such consumers, affecting the very basis of therevenue generation infrastructure.

Cross-subsidisation: Electricity boards try to recover a part of the above revenueloss by charging higher tariffs to other sectors, such as industrial and commercialconsumers. However, over-reliance on this mechanism results in unduly hightariffs, which affects industrial competitiveness and also drives industries to setup their own generation, through captive power plants.

4. SOLUTIONS

To reiterate, in order to add additional megawatts to the sector, it is imperativethat additional revenue be generated from the distribution system. Currently, theSEBs, who run the system, are characterised by massive financial losses, largetransmission and distribution losses and poor quality of supply. They are not in aposition to increase the resources mobilised from electricity consumers. In orderto accomplish this task, it is thus necessary to remedy the fundamental causes ofSEB failure, that is, ineffective management and inappropriate policies, as describedabove. The recommendations that follow seek to do just that.

Separate the distribution system: The distribution system must be separated fromthe generation and transmission systems, and formed into commercial companies.This separation is essential to insulate the revenue-generating portion of the power


sector from external pressure. It would also lead to more attention being paid todistribution issues, through a focused management.2

Privatise the management: The only way to incentivise the separated distributionsystem to mobilise additional resources is to ensure that it bears responsibility forits losses. The most credible manner of enforcing such a hard budget constraint isto privatise the management. This can be done in a variety of ways, such asmanagement contracts, leases, joint ventures and outright disinvestment. Themethod is not as important as the principles on which such management control istransferred. The two crucial aspects are:

• Transfer, whether by management contract or lease or any other method, mustbe for a long period (for example, 30 years), enough to make new investmentremunerative.

• The private management must have complete autonomy in all commercialdecisions, subject to oversight due to the continuing monopoly status.

Create an independent regulatory authority: Once management is transferred toprivate hands, there is a strong need for independent state-level regulatorycommissions to monitor the private managements’ decisions in matters of tariff,investments, etc. They should be empowered to approve tariffs that will permit thelicensees to earn a reasonable return on their investment, if they are operatingefficiently. In addition, the commissions will provide a useful and necessary forumto resolve disputes between the government and the new private managers.

Strategies to attract private investment: In the current environment, it may not beeasy to induce private firms to take over the management of distribution companies,due to several perceived hurdles. These include the presence of mandated customersin distribution zones; a relatively low rate of return; absence of long-term incentives;unreliable power supply from the electricity boards; difficulty in carrying out assetvaluation; and continued interference from the government and electricity boardbureaucracies, leading to difficulty in dealing with the existing staff. In order toaccelerate the process of improvement in distribution management and revenuemobilisation through private sector participation, these problems need to beaddressed quickly. One way of doing so is outlined below.

Offer urban franchise areas: The object of privatising the management of distributionis to generate efficiency gains leading to additional resource mobilisation. The franchiseareas should be chosen to maximise these efficiency gains. For this, the area must havetwo properties. It must have a customer base of sufficient size, with the capability topay, and it must have physical infrastructure in reasonable condition. It is, therefore,recommended that private investors should initially be offered dense urban areas,and other areas that satisfy the above properties, like industrial estates, for distribution.3


Since urban demand is over 50 per cent of the total demand in the country, the ultimatescope of the proposed strategy will be large. In these areas, licensees would not beburdened with social obligations, nor would there be subsidisation of any consumersin the licence area. In view of the highly successful operation of licensees in urbancentres, like Ahmedabad, Surat, Mumbai and Kolkata, it would be much easier toattract private investment in such centres. In order to provide sufficient incentive forlicensees to meet inevitable urban expansion, a process must be simultaneously put inplace for transferring contiguous urban agglomerations and other new concentrationsof consumers to private management.

Give full management autonomy: Since the thrust of this strategy is to increaseresource mobilisation by reaping efficiency gains, it is essential that managementshave complete autonomy over commercial decisions, including those relating toemployment. Without such autonomy, managements cannot be held fullyresponsible, and this would dilute the incentives for efficient operation. Since theurban areas employ only a fraction of the total labour force of the SEBs, the problemsof staff transfer need not form a bottleneck, and if required, the electricity boardshould retain the staff in the interim.

Provide a reasonable rate of return: The permissible rate of return to privateinvestors in distribution as per the Indian Electricity Act is set at RBI Bank Rate plus5 per cent, which currently works out to 14 per cent. This is lower than the 16 percent permitted to IPPs at 68.5 per cent Plant Load Factor (PLF). With an incentivebonus of 0.7 per cent for each per cent increase in PLF, IPPs can expect to earnreturns of 22 to 23 per cent. Operation and maintenance of distribution facilities inIndia involve greater effort and greater degree of risk than what is involved in settingup generating plants. This skews the investment incentives towards generation. Thereis, therefore, a need to free the private investors in distribution from the provisionsof the Electricity Act and permit the state regulatory commissions to determinetariffs to recover higher rates of return when warranted. Eventually, this could leadto a system where prices are regulated, instead of rates of return, and bulk consumerscan strike customised deals with distributors and generators.

Enable wheeling: In order for the distribution licensees to supply quality power,they need to be free from the vagaries of supply from unreliable generators. Thesimplest way would be to allow the distribution licensees access to efficient andreliable generators through wheeling, that is, by permitting the transport of powerfrom a generating station in one area to a consuming centre in another area usingthe transmission network of the grid operator (SEB/Transmission Company/PowerGrid Corporation). Permitting wheeling will also enable cost-effective captivegeneration plants to sell their surplus power to other consumers and expand theircapacities to serve consumers in contiguous areas. This will add experienced


producers to the pool of power generators.4 In the short term, however, lack oftransmission capacity may prevent this from happening. This should not be areason to hold back on the urban distribution strategy.

Power trading corporation: A power trading corporation like the MEM in Argentina(see box below), which is a virtual spot market for power, could facilitate the processof wheeling considerably. By enabling efficient generators to supply electricity tocreditworthy distributors at competitive rates, by enforcing commercial disciplineon the distribution licensees and by excluding them from the market for non-payment, it creates a powerful force to generate additional revenues, thus bringingin extra megawatts.

It is understood that there is a proposal to create Power Trading Companies(PTCs)5 for handling power wheeling. Furthermore, these are to act as long-termbuyers of power and to sell it to existing HT consumers. However, unlike theexample above, this is similar to escrowing the HT consumers for the IPPs thatsell power to the PTC. This approach does not increase the total resourcemobilisation from the distribution system, since the identified HT consumers arealready paying customers. As such, it does not generate additional revenue fromthe distribution system, which is imperative in order to add additional megawatts.

Box 1.2: Power sector reform in Argentina

In the late 1980s, the Government of Argentina (GOA) reformed its power sectorto achieve efficient pricing and sufficient investment levels. The reform processcomprised unbundling, privatisation and regulation. The reform strategy simulatedcompetition in natural monopoly segments, such as distribution and transmission,through regulation, award of concessions and the creation of a wholesale marketfor electricity.

In distribution, the federal government broke up the Buenos Aires distribution area,which accounts for almost 60 per cent of Argentina’s electricity consumption, andawarded three exclusive concessions. To facilitate competition, a spot wholesale marketfor electricity, called the MEM, was created. Large consumers as well as distributionentities are free to negotiate power contracts directly with generators or fulfil theirneeds through the MEM. A National Regulatory Entity for Electricity (ENRE) was setup to ensure fair access to transmission and distribution networks and oversee all facetsof the sector, including service quality. ENRE also sets maximum tariffs for transmissionand distribution services under a price cap system (RPI-X), with the cap reset everyfive to eight years.

Since the advent of the reform process in 1992, EDESUR, one of the major suppliersto the Buenos Aires area, has decreased its energy losses from 21 per cent to 12 per centand reduced its outages from 39 to 6 hours per year. During the same period, the spot


price of electricity on the MEM has decreased from 4.2 to 2.2 US cents per kWh, andthermal availability has increased from 48 per cent to 70 per cent. In transmission,forced outages have declined from 1000 to 300 hours.

The privatised distribution companies have also made substantial investments in the sector.For example, the consortium owning EDENOR invested US$380 million till 1995, and isexpected to invest an additional US$500 million by 2000. Private sector investment in

the entire electricity sector is projected to reach US$7 billion by the year 2001.

Revenue implications for remaining areas: The strategy being proposed can beaccused of “cherry picking” the lucrative areas for private management. Thequestion naturally arises as to how the remaining distribution will be handled bythe SEBs, in the absence of the “profitable” urban areas. At the outset, it is necessaryto realise that many urban areas—for example, Lucknow and Bhubaneshwar—are not presently profitable. In fact, the suggested strategy focuses on “dense urbanareas” because they have significant potential for efficiency gains. Their transferwill reduce losses to the boards and augment their revenues. In addition, bulksupply to urban licensees, wheeling charges and additional revenues in terms oftaxes and excise duty on the sale of electricity, as being currently practised incities like Ahmedabad and Mumbai, will also augment the SEB/governmentresources. These additional resources arising out of the expected efficiency gainswill result in more revenue, not less, which can be used to support distribution inthe remaining areas.

Decentralised distribution and generation: Over time, other approaches will haveto be explored to solve the problem of developing extensive distribution networksin far-flung areas and consumers with limited capability to pay. A model worthconsideration is the one being thought about by West Bengal, that has created theRural Energy Development Corporation, that will be responsible for the distributionof power under 11 kV to all rural areas (Gupta 1998). Decentralised distributioncoupled with decentralised generation may be an answer to this problem. Thisapproach could also use non-conventional energy sources, which areenvironmentally beneficial. Even if the generation cost is higher, this may becompensated by direct cost-savings on building long-distance transmission linkagesand lower transmission losses.

5. NEXT STEPS AND CONCLUSION

This section lays out the next steps to be taken in order to implement the identifiedstrategy for improving resource mobilisation in the distribution systems of the Indianpower sector. The first two are absolutely necessary, while the third helps tosubstantially increase efficiency.


Selection of centres: The first priority is to select twenty or so centres to start theprocess. To begin with, areas contiguous with urban zones currently under privatelicense, like Ahmedabad and Kolkata, can be offered. Urban centres in states thathave completed their unbundling exercise are the next natural target. Their sizewould vary from region to region, but indicative examples are Pune and Nagpur inMaharashtra, Vadodara and Rajkot in Gujarat, and Hyderabad and Visakhapatnamin Andhra Pradesh. Industrial estates with sufficient power consumption can alsobe included.

Mode of transfer to private management: The actual mode can be determined ona case-to-case basis (as noted on page 7: ‘Privatise the management’) using atransparent process like international competitive bidding. Transfer of assets, whennecessary, should take place on the basis of the revenue stream it can be expected togenerate. In all cases, management autonomy must be guaranteed.

Facilitating wheeling: The Indian Electricity Act will need to be amended to permitwheeling transactions, and electricity boards and the Power Grid Corporation willhave to be obligated to permit the use of their network for a charge to be determinedon a case-by-case basis by the central or state regulatory commissions. This, however,is not a precondition for successful transfer to private managements and can bedone in tandem with the above processes.

Conclusion: In the above paragraphs, we attempted a quick review of thecharacteristics of the distribution system as it exists today, and the causes thathave led to this situation. More to the point, we have outlined a strategy that isbased upon increasing the size of the financial cake produced by the distributionsystem, rather than quarrelling over who gets the larger slice. The strategy reliesupon transferring urban areas and other such dense concentrations of consumersto private management, and implementing appropriate arrangements for theremaining distribution areas. We feel this can be quickly implemented, and thatthis can revitalise the Indian power sector by enhancing distribution efficiency,thereby generating additional revenues to bring in extra megawatts, withoutsovereign guarantees and take-or-pay contracts.


REFERENCES

1. “Annual Report on the Working of State Electricity Boards and ElectricityDepartment” – by Planning Commission (November 1997).

2. “A Concept Note on Power Trading Corporation” – by T. L. Sankar (undated).

3. “Energising Power Sector: Light at the End of the Tunnel” – by R.K. Pachauri,Times of India (1 May 1998).

4. “PFC’s Initiative on Power Sector Reform” – by Power Finance Corporation(undated).

5. “Privatisation of Distribution in India: Issues, Options and Lessons from OtherCountries – by International Resource Group Ltd (8 December 1997).

6. “Report of the Committee on Private Sector Participation in PowerDistribution” – by S.J. Coelho (March 1998).

7. “Separate Power Corporation for Rural Sector in Bengal” – by Gautam Gupta,Economic Times (29 April 1998).

NOTES

1. This is based on a rough calculation. An annual increase of 8000 MW in capacity, atRs 4 crore a megawatt, requires Rs 32,000 crore of investment. A 70:30 debt equity ratiowould imply that SEBs should be able to commit around Rs 10,000 crore.

2. Studies conducted for various SEBs over the past few years have led to nearly similarreform structures. They all recommend the separation of the distribution systemfrom the generation and transmission systems, and the establishment of commissionsto set tariffs, license activities and perform other regulatory functions (Power FinanceCorporation, “PFC’s Initiative on Power Sector Reform”; Coelho 1998).

3. The current approach is to create zonal distribution companies. The franchise areasinclude a mix of paying consumers and mandated customers, who are supplied electricityat subsidised or free rates. Each zone has a mix of urban and rural areas, with far-flungdistribution networks, high cost of supply, and agricultural and irrigation loads fromwhich recovery has traditionally been weak. The currently defined franchise areas thusadd additional costs and social responsibilities that private investors are ill equipped toshoulder. Such privatisation needs transparent and guaranteed mechanisms for flow ofsubsidy from the state government to the licensee, which complicates the process anddetracts from commercial orientation.

4. Some estimates indicate that there is about 15,000 MW of captive generating capacitywhich will be “decaptivated” by the wheeling provision (Sankar, “A Concept Note onPower Trading Corporation”).

5. Based on the “Annual Report on the Working of State Electricity Boards and ElectricityDepartment” by Planning Commission (1997) and newspaper reports.

Power Sector in India | 13

1. INTRODUCTION

Since Independence, in 1947, the Indian power sector has been mainly dominatedby the public sector. As of 31 March 1997, about 95 per cent of the total installedcapacity of 85,919 MW was owned by the central (32 per cent) and state (63 percent) sector undertakings. In terms of fuel-type mix, thermal, hydro andnuclear capacities account for 72 per cent, 25 per cent and 3 per cent respectively.During the year 1996–97, the total generation in the country was about 394billion units.

Legislation: Under the Indian constitution, electricity is on the concurrent list—meaning that it comes under the purview of both the central (federal) and state(provincial) governments. The Indian Electricity (IE) Act 1910 and the ElectricitySupply (ES) Act 1948 are the key Central Acts, under the broad ambit of whichindividual states have enacted their own laws. The IE Act 1910, which was enactedwhile India was still under the British rule, defines the obligations, powers andresponsibilities of licensees in the electricity industry. Few such licensees exist today.The ES Act of 1948, passed soon after India achieved independence, set out theframework for establishing the Central Electricity Authority (CEA), the StateElectricity Boards (SEBs) and generating companies. The first SEBs were establishedin the early 1950s, soon after the legislation had been enacted. The industrial policyresolution adopted in 1956 provided that generation and transmission of electricitywould be reserved exclusively for the public sector. Accordingly, the law stated thatno person or firm shall engage in the business of supplying energy to the publicexcept with the previous sanction of the state government. Although the centralgovernment is apparently competent to give permission to generating companies

POWER SECTOR IN INDIA:A Summary DescriptionNovember 19982


to sell energy, it can only do so for the sales aimed at SEBs or State ElectricityDepartments (SEDs).

2. INSTITUTIONAL STRUCTURE

Although policy, generation and transmission activities are undertaken by both thecentral and state governments, distribution and supply of electricity to the finalconsumer and the associated tariff setting are exclusively under the purview of thestate governments. A pictorial representation of the institutional structure of theIndian power sector is provided in Figure 2.1.

Figure 2.1: Institutional structure of the Indian power sector

Central level: At the federal level, the Ministry of Power and Non-ConventionalEnergy Sources is responsible for power policy as well as the generation andtransmission capacity in the central sector undertakings (CSUs).

Policy: In policy setting, the ministry is assisted by the Central Electricity Authority(CEA), which was formed in 1948 as the industry’s regulatory body.1 In addition tocontributing to national power policy, CEA also undertakes other coordinatingactivities such as conducting appraisals of projects, granting clearances and issuingguidelines for setting tariffs.

Generation: The generating capacity in the central sector accounts for about 30 percent of the country’s total generating capacity. This capacity comes mainly from theNational Thermal Power Corporation (NTPC) and the National HydroelectricPower Corporation (NHPC). SEBs draw their share of power from these CSUs, andeach CSU is entitled to a tariff that is an aggregate of three components—fixed cost

Governmentof India

Central Electricity Authority (CEA)

StateGovernments

State Electricity Boards (SEBs)/

Departments (SEDs)

Departmentof Energy

Private sector licensees

Ministryof Power

Department of Atomic Energy

NationalDevelopment

Council

PlanningCommission

NuclearPower Corporation

National ThermalPower Corporation(NTPC) and others

Generating utilities

Power Grid Corporation of

India Ltd (PGCIL)

Transmission utilityRegional

Electricity Boards (REBs)


(capacity charge), variable cost (energy charge) and incentive. With a capacity of16,795 MW, NTPC is the largest power generating utility in the country, contributingabout 20 per cent of the total installed capacity in the country. In terms of PlantLoad Factor (PLF), NTPC achieved a PLF of 77 per cent in 1996–97 as against thenational average of 64 per cent.

Transmission: In recognition of the need for greater integration of the transmissionsystem, five regional electricity boards (REBs) were established in 1964, coveringthe northern, western, southern, eastern and north-eastern regions. These REBsco-ordinate system operations within each regional grid through regional loaddispatch centres (RLDCs). In 1989, the Power Grid Corporation of India Limited(PGCIL) was established for managing the national transmission and dispatchingsystem. As of March 1997, PGCIL was operating about 27,853 circuit kilometres(CKMs) of transmission lines, distributed over 54 substations with 23,331 MVAof transformation capacity. PGCIL’s performance in terms of overall averageavailability of its transmission lines—at above 98 per cent—is comparable tointernational standards. About 30 per cent of the country’s total installedgenerating capacity (81,500 MW) is connected to its network. Currently, PGCILis in the process of linking regional grids, through a series of high voltage directcurrent (HVDC) interconnections. On the successful completion of this process,PGCIL’s network would have the capacity to transfer 1000 to 1500 MW of powerfrom any one region to another.

State level: State governments are exclusively responsible for the supply of power tofinal consumers located in the state, along with associated tariffs. In the states, thepolicy for the power sector is looked after by the departments of energy of therespective state governments and the generation, transmission and distributionfacilities are owned and managed through the respective SEBs/SEDs. Although thelegislation provides for financial autonomy to the SEBs, most of them work underthe administrative control of the respective state governments and state ministriesand are under the technical control of CEA, REB and RLDC.

Much of the expansion of the electricity industry in India since the early 1950s hasbeen carried out by the SEBs, which account for 63 per cent of the country’sgenerating capacity. Two-thirds of this capacity comes mainly from eight states—Andhra Pradesh, Gujarat, Karnataka, Madhya Pradesh, Maharashtra, Punjab andTamil Nadu. Following their formation in 1948, SEBs established independenttransmission networks to supply power within each state. However, most of thestates have a very low HT:LT ratio and, hence, suffer high technical losses and non-technical losses (theft of electricity). Most of the states charge agricultural anddomestic consumers tariffs that are far below the cost of generating electricity andseek to make up for this by charging higher tariffs to industrial consumers.


Private sector: Although private sector utilities and local authorities provided around80 per cent of the public supply in India prior to Independence, the state subsequentlytook over most licensees when their licences expired, and after 1956, no new licenceswere granted. Five private utilities remain in existence: Bombay Suburban ElectricSupply Company, Tata Electric Companies, Ahmedabad Electricity Company, SuratElectric Company and CESC Ltd (formerly Calcutta Electric Supply Corporation).These five have a generating capacity of around 2800 MW. In addition, there existsabout 12,000 MW of captive power capacity, which largely comprise coal-basedplants (about 6000 MW) and diesel generating sets (about 4000 PW). Coal-basedplants are owned mainly by power intensive industries like aluminium, steel,fertilisers, cement and petrochemicals. Diesel-based plants are used as a standbysource of power in the event of non-availability of grid power.

3. PERFORMANCE

Over the past five years, the physical performance of both the central and statesector utilities has either improved or held steady at the previous levels. On theother hand, the financial performance of the sector has deteriorated considerably,and the sector has failed to achieve the targeted additions to its capacity. It isimportant to note that the following paragraphs on performances are based onaggregates at the national level and there could be significant performance variationsacross different states.

Physical performance: During 1992–97, the overall deficit in electricity supply(energy) increased from 8.3 per cent to 11.5 per cent, whereas peak-shortage hasshown a marginal improvement from 20.5 per cent to 18 per cent. The sale ofelectricity increased from 213 billion kWh in 1992–93 to 275 billion kWh in 1996–97, representing an annual growth rate of 6.6 per cent. Inadequate transmissioninfrastructure is regarded as one of the main reasons for the shortage of peakingpower. In the absence of adequate transmission capacity to transfer power acrossthe regions, there is limited scope for exploiting the differences in the time ofoccurrence of peak demand in various regions.

Plant Load Factor (PLF) and plant availability: The PLF of thermal power plantsincreased from 45 per cent in 1980–81 to 64.4 per cent in 1996–97. However, it issignificantly lower than the international standard of about 70–75 per cent. Thelower PLF is mainly attributed to the lower availability of coal-based power plants.The average availability of Indian power plants is about 75–80 per cent. The PLF ofpower plants owned by the centre, the SEBs and private companies show significantvariations. The central and private sector plants have consistently shown a higherPLF as compared to the plants owned and managed by the SEBs. Also, on an average,private and central sector plants have higher plant availability as compared to the


SEB-owned plants. The central sector plants supply power to more than one statein a region, which protects them from the reduction in demand from one of thestates and enables them to maintain a high output level.

Transmission and distribution losses: Of the electricity generated, about21–22 per cent is lost in the process of transmission and distribution. A significantportion of these losses is attributable to inadequate metering and theft of electricity.The difference in the amount of electricity supplied and the amount actually meteredis usually reported as T&D losses. In most of the states, the electricity supplied toagriculture is unmetered and is charged on the basis of the connected load. As theamount of electricity consumed by this sector is usually overestimated, actual T&Dlosses may be significantly higher than those reported. In addition, there is largescale theft of electricity through unauthorised connections. The main reason forhigh T&D losses in the Indian power system is the transmission and distribution ofa large amount of power at low voltages—less than 11 kV or Low Tension (LT).

Capacity addition: During the five-year plan period that ended inMarch 1997, only 16,742 MW of capacity could be added as against the target of30,858 MW.

Financial performance: The commercial losses of SEBs, without subsidy,have increased from Rs 45.6 billion (US$1.1 billion) in 1992–93 to Rs 98.0 billion(US$2.3 billion) in 1996–97, and these are projected to increase to Rs 101.65 billion(US$2.4 billion) in 1997–98. The Rate of Return on Capital, after taking into accountthe subsidy from the government, has deteriorated from (-)7.6 per cent in 1992–93to (-)11.6 per cent in 1997–98. Without subsidy, the situation would have been farworse at (-)16.4 per cent in the year 1997–98.

Subsidies and shortfall in tariffs: During 1991–97, the average unit cost increasedfrom Rs 1.17 to Rs 2.08, whereas the tariff per unit increased fromRs 0.89 to Rs 1.58. Thus, the direct shortfall in revenue remained at about24 per cent, which indicates that only three-fourths of the costs are being recoveredthrough tariffs. Such shortfall is much more significant in the case of agriculturaland domestic consumer categories. Due to political reasons, the tariffs for agriculturaland domestic consumers have been very low in most of the states, at an average rateof Rs 0.22 per kWh and Rs 0.89 per kWh respectively, in 1995–96. In order to subsidiseagricultural and domestic consumers, commercial and industrial consumers werecharged much higher tariffs, at an average rate of Rs 2.24 and Rs 2.35 per kWhrespectively, in 1995–96. According to an estimate, the effective subsidy for these sectorsis expected to increase from Rs 159.5 billion (US$3.8 billion) in 1995–96 toRs 192.3 billion (US$4.6 billion) in 1996–97 and Rs 217.9 billion (US$5.2 billion) inthe following year. Cross-subsidisation of agricultural and domestic sectors is becomingan increasingly difficult proposition because the share of agriculture in the total


consumption increased from 17.6 per cent in 1980–81 to about 30 per cent in1993–94, even as that of industry declined from 58.4 per cent to about 39.6 percent in the same period.

Revenue arrears and outstanding dues: The outstanding dues to be paid by SEBs totheir central sector suppliers of electricity, equipment, finance and energy inputsare reported to be over Rs 122.5 billion (US$2.92 billion) as on 31 March 1997. Onthe other hand, as on March 1996, SEBs were to receive from their customers anamount of Rs 116.8 billion (US$2.78 billion), which accounts for 30–33 per cent oftheir annual sales turnover.

4. REFORM EFFORTS AND PRIVATISATION

Since the economic liberalisation in 1992, both the central and state governmentshave sought to increase private sector participation in the provision of infrastructureservices, including power. Initially, the focus of the reform was on encouragingprivate participation in generation. In response, nearly 127 expressions have beenregistered, aggregating Rs 2500 billion (US$59.5 billion) investment for setting up69,000 MW. However, how many of these expressions would turn into realityremains a moot question, considering that only a handful of private projects havecome into being over the past six years and most of the other projects are strugglingto achieve financial closure. Private investors and lenders are wary of supportingpower projects that have to rely exclusively on financially weak SEBs for evacuatingtheir power. Hence, the state governments are gradually shifting the focus of theirefforts to areas such as SEB-reform and regulation, whereas the central governmenthas been focusing on the areas of regulation, transmission-privatisation, setting upof multi-state mega projects and power trading companies. Salient points of thereform and privatisation efforts undertaken by the central and state governmentsare summarised below.

Private participation in generation: The reform policy introduced in 1991 allowedthe private sector to set up companies to act as licensees, generating and distributingpower, or simply as generators. Up to 100 per cent foreign equity participation waspermitted, with a maximum debt to equity ratio of 4:1. The return on foreign equitywas protected in foreign currency, and a number of tax concessions were also made.In order to determine the tariff for the purchase of power, a notification, which laiddown the guidelines for a two-part tariff, was issued. The main features of thenotification were:

• The tariff would constitute two parts—a fixed part comprising return on equity(RoE), interest on loan capital, depreciation, operations and maintenance costs(O&M); and a variable part comprising fuel costs.


• A maximum of 16 per cent RoE was allowed to be included in the tariff (thiswas protected against fluctuations in the exchange rate).

• Fixed cost could be recovered at a PLF of 68.5 per cent (equivalent to 6000hours of operations) in the case of thermal plants, and at an availabilityfactor of 90 per cent in the case of hydroelectric plants. The normative PLFfor thermal plants was revised to 75 per cent in February 1997.

• As an incentive, a maximum of 0.7 per cent additional RoE could be given forevery 1 per cent increase in PLF or availability.

Clearances and approvals: In order to clear a thermal project, the CEA requires anapproval from the state government and the electricity board concerned, clearanceof water availability and fuel linkage approval from the petroleum and natural gasministry or from the coal ministry. Projects also require environmental clearanceand chimney height clearance from the National Airports Authority of India.

Fuel supply and transportation: Fuel supply has become a contentious issue as thesupply of coal, naphtha and natural gas is controlled by public sector units (PSUs).The PSUs are not willing to enter into agreements for assured supply, mainly due tolack of experience with such contracts, particularly with regard to the evaluation andquantification of the associated risk and premium. Further, the Indian Railways, theprincipal carrier of fuel, is unwilling to assure uninterrupted supply. The IPPs insistthat the penalty for supply interruptions should cover the loss of revenue (fixed costcomponent of tariff) attributable to the default in fuel supply; some of them suggestthat the penalty could be on the basis of additional cost incurred in procuring fuelfrom alternative sources. PSUs and the Railways, however, contend that it should berelated to the value of the fuel not supplied. In the absence of any satisfactory resolutionto this problem, financial closure is getting delayed because the lending institutions,understandably, are reluctant to bank on a risky fuel supply agreement (FSA).

SEB restructuring and reform: Some of the state governments are taking steps tointroduce comprehensive reform legislation that could, eventually, lead to (a)unbundling of generation, transmission and distribution segments;(b) setting up of independent regulatory institutions; and, in a few cases,(c) privatisation. For instance, in the state of Orissa, the government has decided tolimit its own role to policy making and regulation. Under a scheme endorsed by acouncil of ministers in 1994, the Orissa SEB is to be unbundled into new generation,transmission and distribution companies. Hydropower will remain in stateownership, as will transmission, but thermal generation has already been partiallyprivatised and distribution is expected to pass into private hands by the middle of1999. Similarly, in the case of Andhra Pradesh, the reforms envisaged includerestructuring of the Andhra Pradesh SEB into a series of subsidiaries including the


AP Power Corporation, the AP Transmission Corporation and a number of regionaldistribution companies. The transmission company would remain in publicownership while the distribution companies would be privatised gradually; fullprivatisation of the distribution companies was expected by 2000–01. Initially, thegenerating company would also remain in the public sector but operate as acommercial organisation.

Regulatory commissions: The Indian Parliament recently enacted the ElectricityRegulatory Commissions Act 1998, which provides for the setting up of independentregulatory commissions at the central and state levels. The independent regulatorycommissions are expected to ensure that the industry develops on a sustainablebasis. It is expected that the regulatory commissions, being independent of thegovernment, would be able to effect tariff rationalisation, which is normally apolitically sensitive and unpalatable decision for the governments. While the centraland a few state governments such as Orissa and Haryana have already set upregulatory commissions, a few other states are in the process of setting up the same.The Ministry of Power (MoP) is assessing the need to redefine the role of the CEAas its role overlaps with that envisaged for the Central Electricity RegulatoryCommission. Further, since power is a concurrent subject (under the jurisdictionof both the states and the centre), the respective roles of the central and state electricityregulatory commissions in the development of the power sector, especially withregard to the approval of large projects, need to be clarified.

Transmission bill: The Electricity Laws (Amendment) Bill 1998 provides for thesetting up of central and state transmission utilities for undertaking inter-stateand intra-state transmission respectively. Under license from the respectiveelectricity regulatory commissions/governments, transmission licensees canconstruct, maintain and operate transmission (inter-state or intra-state) systemsunder the direction, control and supervision of respective transmission utilities.

Multi-state mega projects and power trading company: The Ministry of Power,Government of India, has been actively pursuing the concept of setting up megapower projects in the private sector, to (a) harness the economies of scale andlocations associated with large pit-head plants; (b) take advantage of the low pricesprevailing in the international markets for power equipment; and (c) quickly makeup for the shortfall in capacity addition in the private sector at the state level.Considering that these projects would be of about 1500 to 2000 MW capacity, theoutput is expected to be shared by more than one state; so these projects are alsoreferred to as multi-state mega projects. Private investors, however, have beenreluctant to enter into multiple Power Purchase Agreements (PPAs) with severalstates and have indicated that they would prefer to deal with a single agency. Inresponse, the Ministry of Power is considering setting up an intermediary—the


Power Trading Company (PTC)—that will undertake to buy all the power fromthe mega projects. PTC, in turn, will sell that power to State Electricity Boards,using the transmission network of PGCIL and arrange to collect the paymentsfrom them. To enhance PTC’s operational flexibility in evacuating power acrossvarious states and to shore up its stature, the shares of PTC are sought to be heldby PGCIL (the national transmission utility), NTPC, SEBs and major Indianfinancial institutions.

5. CONCLUSION

Clearly, the Indian power sector is undergoing a crucial phase of transition. Reformefforts to increase generating capacity have exposed the inadequacies in theremaining segments of the sector. Both the central and state governments areactively engaged in finding viable solutions to achieve sustainable developmentin the sector. As of now, regulation, rapid capacity addition and SEB-reform,with a specific focus on improving revenues from the distribution segment, areemerging as important areas of concern.

NOTE

1. India has recently set up the Central Electricity Regulatory Commission, as anotherregulatory authority, which is discussed later.


1. INTRODUCTION

The debt crisis of the 1980s severely impacted the Argentine economy, leaving itwith a legacy of high inflation, low growth, a deteriorating infrastructure and limitedresources available with the government. Argentina’s electricity industry, like manyothers, was completely state-owned. Its generation capacity was balanced betweenthermal and hydroelectric resources, some of which were shared with neighbouringcountries like Uruguay and Paraguay. The nuclear programme, started in 1950,provided about a tenth of the energy needs (see Table 3.1). Immediate attentionneeded to be given to the efficiency and resource problems of the sector, if it was todevelop further.

Table 3.1: Total production of electricity and the share of differenttypes of generation

Year Thermal Hydro Nuclear Total (mn kWh)

1985 41% 47% 12% 43,587

1990 49% 37% 14% 48,945

1995 44% 46% 10% 65,720

Status prior to privatisation

Argentina set up its first fully state-owned utility, AYEE, in 1947 in an attemptto provide more capital to the sector. At the beginning of the 1990s, the industrywas completely state-owned. In 1991, immediately prior to privatisation,Argentina had four federal (equivalent to the central sector) utilities, 19 provincial(equivalent to the state sector) utilities and two binational bodies controlling large

POWER SECTOR REFORM IN

ARGENTINA: A SummaryDescriptionNovember 1998

3

Power Sector Reform in Argentina | 23

hydroelectric projects jointly owned by Argentina and Uruguay, and Argentinaand Paraguay respectively. The federal utilities owned a large proportion of thegeneration, including all the nuclear generation plants and transmission assetsnationwide, and the distribution assets for the capital, Buenos Aires, and itssurrounding region. The provincial utilities owned nearly all distribution assetsoutside the region around the capital. By the time of reform, the system haddeteriorated badly and was characterised by considerable operational andfinancial problems. The cost of electricity was high (around US$60 per MWh),there were large commercial losses due to theft and non-payment and periodicthreats of blackouts, aggravated in times of low rainfall by a large dependenceon power from hydroelectric stations.

2. NATURE OF ELECTRICITY REFORM IN ARGENTINA

Objective

The goal of the reform process was to have an electricity industry that was capableof ensuring the economy sufficient energy at the best price that reflected the economiccosts of maintaining and expanding the activity. It was also driven by the increasinginability of the government to service the public debt and the need to attract privateinvestment to the sector.

In January 1992, the electricity privatisation law was passed. The reform was basedon principles of open access to the wholesale capacity, energy pool for generatingfacilities and least cost centralised dispatch. A national regulatory body, Ente NacionalRegulador de la Electricidad (ENRE), and a national wholesale market for electricity,CAMMESA, were established. Transmission and dispatch were mandatorilyseparated from generation and distribution, and no generator was allowed to controlmore than 10 per cent of the system’s capacity.

Restructuring

Prior to privatisation, three federal companies,1 SEGBA, AYEE and HIDRONOR,were restructured by separating their generation, transmission and distributionactivities (see Figure 3.1). Companies to be privatised were sold through auction,using a two-envelope process. This included a qualifying technical offer and acompetitive financial offer. Usually, at least a bare majority (51 per cent) wasoffered for sale, and sometimes much more. For example, 98 per cent of a 448MW hydroelectric plant was sold to a domestic aluminum company, retaining2 per cent for the employees.2 In transmission and distribution, long-termconcessions were awarded. The first of SEGBA’s generators was sold inApril 1992, followed by two more in May and August. Two distribution companieswere sold in September, followed shortly by a high-voltage transmission


company. The success of the privatisation depended to a great extent onthe regulatory and commercial environment as determined by ENRE andCAMMESA.

Figure 3.1: Restructuring of the Argentine electricity industry (federal assets)

ENRE

The national regulator is responsible for all stages of the industry, with particularemphasis on transmission and distribution. It mediates disputes between electricitycompanies and enforces federal laws, regulations and concession terms. It alsooversees the wholesale market, establishes service standards that must be met andsets the maximum price (price-cap) for transmission and distribution services.Generation is not subject to price regulation, as it is deemed to be a competitiveactivity with free entry.

CAMMESA

An independent nonprofit operating agency, CAMMESA is directed by a boardcomposed of two representatives of the federal government, power generators,transmission companies, distribution companies and large users. It has threeprimary tasks: dispatching power, determining fixed fees to be added to energyprices to cover capacity charges and the cost of transmission, and ensuring adequatereserve capacity in the system. CAMMESA dispatches power to the national gridby sending the cheapest power first, until current demand is satisfied. The paymentto each generator is based on the highest cost producer whose power is dispatched.

SEGBA(Servicios Electricos del Gran

Buenos Aires)

6Thermalgenerationcompanies

3Distributioncompanies

AYEE(Agua y Energia Electrica)

1National high voltage (500 kV)transmissioncompany

6Regional lowervoltage (220 kV)transmissioncompanies

22Thermal generation companies

4Hydroelectric generationcompanies

5Hydroelectricgenerationcompanies

HIDRONOR(HidroelectricaNorpatagonica)


CAMMESA’s budget is limited to 0.65 per cent of the total transactions in thewholesale market. Salaries, for around 150 staff members, represent almostthree-quarters of its expenditure.

Box 3.1: Objectives of CAMMESA

• Dispatch energy optimally by minimising the total operation cost.

• Maximise the security of the system and the quality of the electricity supplied.

• Plan energy needs and forecast market prices.

• Calculate economic transactions between market agents.

• Bill, collect and make payments in the Wholesale Electricity Market.

• Supervise option market operation and carry out technical dispatch of contracts.

• Guarantee transparency and equity of Wholesale Electricity Market decisions.

Box 3.2: Objectives of ENRE

• Determine basis and criteria for assigning concessions.

• Publicise and enforce regulatory structure, contracts and public service obligations.

• Issue regulations on safety and technical procedures and monitor compliance.

• Monitor billing, control, meter use and service quality.

• Define basis for calculating tariff and ensure compliance.

• Regulate sanction proceedings, impose penalties and take relevant issues to court.

• Issue an annual report and recommend policy actions to the executive as needed.

Prices

Demand and supply determine energy prices. The supply side of the wholesale marketis composed of independent power producers, privatised generators, publicly ownedgenerators and imported electricity. The demand side of the market is made up ofprivate and public distribution companies, large users (currently more than 100 kWhannually) and foreign consumers. There are three main types of prices: contractual,seasonal and spot. Transmission and distribution prices (for supplies throughdistribution companies) are regulated.

Contractual prices differ from contract to contract. They are negotiated betweengenerators, distribution companies and large users for a minimum period of oneyear. Seasonal prices are determined by CAMMESA twice a year, based onparameters like forecasted demand, power availability, fuel prices, reservoircapacity, etc. Distribution companies purchasing power in excess of contractedamounts from the market pay the seasonal price. Spot prices vary hourly and are


paid by generators who cannot supply power they have contracted to sell, andlarge users who contracted for less power than they need. Generators who havepower in excess of their contractual obligations, distribution companies and largeusers who have contracted to buy more than they currently require can sell powerin the spot market. Obviously, price trends in the spot market affect the pricepaid for contracted power.

Figure 3.2: Estimate medium monomial contract price in the market

Generation

Argentina allows free entry into the generating market. Current and prospectivegenerators make their own judgements, take their own risks on demand growth,investment levels, fuel market trends, etc. like producers of any other commodity.As noted above, there is no surety of dispatch and the price for energy dispatcheddepends on the highest cost producer whose power is dispatched. Full costrecovery is thus not guaranteed. Generators receive two types of payments fromthe market—one for the dispatched electricity and the other for the capacityoffered to the grid. The capacity payment is sufficiently low so that generatorshave a dual incentive to reduce costs—first, to have their electricity dispatchedand second, to increase their margins from electricity sales.

Generating companies are prohibited from controlling more than 10 per centof the system’s capacity, and cannot own majority shares in transmissionfacilities. However, they are assured open and equal access to the national grid.There are currently about 40 companies in Argentina, of which about 10 arestill owned by federal and provincial authorities. These effectively act asindependent power producers, selling their power through the wholesale market.

40

38

36

34

32

30

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26

US$

/MW

h

Ap/

92–J

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4

Fb–A

p/94

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6


Transmission

In contrast to generation, transmission is closely regulated. Firms enter aftersuccessfully bidding for a fixed-duration concession for a particular area and cancharge no more than a regulated maximum price, providing an incentive to reducecosts. Currently, the concessions have been awarded for 95 years but the controllingshareholders’ package is rebid every 10 years. The charges have two components—one based on availability and the other on use. Concessionaires are required toallow third parties open access to their transmission network. They are not allowedto buy or sell electricity. The revenues of the transmission company are collected bythe wholesale market through a surcharge on energy prices.

The high-voltage (500 kV) transmission network was built by combining thetransmission assets of the federal utilities into a single entity called TRANSENER.TRANSENER also operates one of the lower voltage regional systems. It serves 14 ofArgentina’s 24 provinces, carrying most of its power. In addition, there are fiveother lower voltage (220 kV) regional systems (see Figure 3.3), of which three havebeen partially privatised.

Figure 3.3: Argentina’s transmission system

Generators are required to provide new transmission facilities. A new transmissionfacility is being commissioned by a consortium of eight privatised electricity


companies, each of whom is legally prohibited from holding a majority share. Theywill fund the construction and award the concession. The project is expected to costUS$250 million. In addition, the same consortium is also planning a capacitor project.

Distribution

Like transmission, firms may enter distribution only by bidding for a concession.They also have regulated prices and a commitment to allow open access to thirdparties. The price caps are reset every five years; in the interim, the regulated companycan avail of the benefits of cost reduction. Large users can, however, choose to besupplied directly by the generators or buy directly in the spot market, instead ofthrough the distribution company. The number of large users in the wholesale markethas risen rapidly. As distribution companies must supply to large users at the samerate they charge other customers, this helps to keep prices under control. While allfederal distribution assets have been privatised, many provincial distributioncompanies remain in the public sector.

3. EFFECT OF REFORMS

Lower prices and higher reliability

Following the reform process, electricity prices fell sharply. After a period ofturbulence, they stabilised at around half the pre-privatisation levels (see Figure 3.4).The extent of outages also reduced considerably (see Figure 3.5). In EDENOR’sdistribution areas, outages fell from over 20 hours to around 5 hours a year.Generators were fitted with power system stabilisers, which permitted minimaldisconnection of generating capacity while addressing transmission faults.

Figure 3.4: Evolution of capacity and energy prices

50

45

40

35

30

25

20

15

10

5

01992 1993

US$/MWh

1994 1995

Capacity

Energy


Figure 3.5: Outages as a per cent of energy demand

Increased efficiency

Electricity loss for non-technical reasons, such as faulty billing and theft, camedown and generation availability increased considerably. For example, the LaPlata distribution company increased its customer base by over 20 per cent.Similarly, the availability of Costanera, a generator near Buenos Aires went upfrom 30 per cent to 75 per cent.

Increased investment

Substantial investments were also made in upgrading the assets bought from thegovernment. EDENOR, for instance, made capital investments of US$380 millionover 1992 to 1995, and plans an additional US$500 million until the year 2000. Itis anticipated that the total investment in the electricity sector by 2000 will bearound US$7 billion.

4. CONCLUSION

The Argentine experience demonstrates that it is possible to effect measurablechanges in a state-owned electricity sector suffering from lack of funds andinefficient management within a reasonably short time frame. A number of theproblems that plagued Argentina, such as high distribution losses and lowgenerator availability, are similar to what India faces today. The Argentine powersystem is much smaller and has a better hydrothermal mix when compared tothe Indian power system as a whole,3 but it may prove profitable to examine the

700

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-88

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-92

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-93

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-94

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-95

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-96

GWh

16% of demand


Argentine experience to see whether it would help with the design of reformin India.

NOTES

1. The fourth, CONEA, was the nuclear energy utility, which was not privatised.

2. Prices could vary substantially. For example, a 20 MW oil and gas-fired generating plantwas bought by a paper manufacturer for US$8.5 million.

3. The Argentine system is about 16,000 MW, of which nearly half is hydroelectric capacity.This compares favourably with some of the regional grids in India, though it is only afifth the size of the national system.

Orissa Power Sector Reform | 31

In India, Orissa is the first state to have undertaken comprehensive reform of itspower sector. Initiated in 1996, the programme is still under implementation.1 Infact, the crucial step of privatising distribution occurred only in 1999. Any attemptto evaluate the programme to determine its success or otherwise would therefore bepremature at this juncture. Nevertheless, the reform experience to date hasunderscored several important lessons, which could be of value for other states thatare seeking to reform their own power sectors.

1. SALIENT FEATURES OF THE ‘ORISSA MODEL’

The salient features of the reform programme included the unbundling oftransmission, distribution, thermal power generation and hydel power generationinto separate businesses; the establishment of an independent regulatory commission;and the subsequent partial divestment of equity in the thermal power generationand distribution business units to the private sector.

As part of the first transfer scheme, effective from 1 April 1996, the State ElectricityBoard was split into three entities, viz., the Orissa Power Generation Corporation(OPGC for thermal power, the Orissa Hydro Power Corporation (OHPC), for hydelpower and the Grid Corporation of Orissa (GRIDCO) for transmission anddistribution. GRIDCO was to function as the single buyer of power within the state,for onward supply to the distribution companies. Under this transfer scheme, thestate government also revalued the transmission and distribution (T&D) assets.2

According to GRIDCO, this was done in order to:

(a) create a positive capital base for the new companies expected to raise substantialdebt for making T&D investments;

ORISSA POWER SECTOR

REFORM: A BriefOverview of the ProcessFebruary 2000

4


(b) set off some of the dues from the state government to the Orissa State ElectricityBoard (OSEB); and

(c) raise some reasonable revenues from the sale of assets.

A 49 per cent stake in OPGC was subsequently divested through an internationalcompetitive bidding process. Messrs AES Corporation bought the stake forRs 603 crore.

As part of the Second Transfer Scheme, effective from November 1998, thedistribution-related assets, liabilities, proceedings and personnel of GRIDCO weretransferred to four wholly owned subsidiary companies. These companies weresubsequently privatised through the sale of 51 per cent GRIDCO’s equity to theprivate sector. Of these four distribution companies (distcos), three were bought byBombay Suburban Electric Supply (BSES) in April 1999, whereas a joint venturebetween Jyoti Structures and M/s AES Corporation bought the fourth one inSeptember 1999.

The procurement as well as sale of power by various business units is regulated bythe Orissa Electricity Regulatory Commission (OERC). The commission, whileregulating retail tariffs, takes into account various parameters, including the cost ofpower procurement, capital base, reasonable return, acceptable level of losses,employee cost, interest and depreciation.

2. EXPERIENCE TO DATE

The reform experience in Orissa to date has been rather painful.

GRIDCO’s operating balance is turning out to be inadequate to service even presentworking expenses, leave alone servicing the past dues/liabilities which were loadedonto it at the time of disinvestment and restructuring. The cash deficit of GRIDCOis likely to increase from Rs 360.67 crore in 1998–99 to around Rs 500 crore in1999–2000. This, in part, is due to GRIDCO’s arrangements with the distributioncompanies for deferred payments—which were accepted by GRIDCO in order toconclude their sale.

On the distribution front, BSES, which bought three distribution companies,expects the combined loss figure in these companies to be about Rs 174 crore atthe end of their first year of operation. The financial distress is mainly on accountof discrepancies between the information provided in the InformationMemorandum at the time of privatisation, the basis adopted for the regulatorydecisions, and the reality.

For instance, BSES finds that its subsidiaries’ operations are not viable at the tariffsfixed by OERC, which were based on a T&D loss level of 35 per cent, because theactual losses are higher at 45 per cent to 47 per cent. While the actual losses are


about 5 to 6 per cent higher than the distribution losses indicated in theInformation Memorandum, OERC has fixed tariffs based on a lower T&D losslevel. According to OERC, this was done with a view to provide strong incentivesto reduce T&D losses.

Similarly, it is reported that GRIDCO, in its enthusiasm to show lowerdistribution losses, estimated higher billings that are not based on meter readings.These became part of ‘current assets’ transferred to the distcos at the time ofhandover. According to BSES, its companies would not be able to realise thesedoubtful receivables.

Even if the regulatory commission is willing to accommodate the demand of thedistcos to base tariffs on a more realistic estimation of losses and receivables, thescope for a drastic upward revision of tariffs is limited. Unless some of these issuesare resolved, the distcos are bound to start with an inevitable sickness.

3. IMPORTANT LESSONS FROM THE ORISSA EXPERIENCE

On the face of it, the reform programme in Orissa appears to have had all theingredients, such as unbundling and privatisation, which were present in thesuccessful reform efforts in other countries.3 A closer examination, however, revealscertain limitations, which offer important lessons from the Orissa experience.

3.1 Distribution should be privatised early on in the process

Until recently, for all practical purposes, the Orissa model was almost acontinuation of the previous SEB regime. The GRIDCO performed bothtransmission and distribution activities from April 1996 to November 1998, thattoo under state-ownership, with the attendant lack of incentives for improvingefficiency. Moreover, allowing GRIDCO to perform both transmission anddistribution complicated the process of separation further down the line, as onehad to revisit the issue of apportioning the losses arising during this period ofcombined operation to the successor entities. A complete separation oftransmission and distribution functions at the time of corporatisation would havehelped the new entities to start with a clean slate.

An analysis of the power sector reveals that losses have been heaviest in the distributionsegment, the cash-generating end of the business, underscoring the significance ofprivatising distribution as soon as possible. Any interim arrangement such as creatinga combined transmission and distribution company would not help stem the rot.

3.2 Pitfalls to avoid in the process of privatising distribution

The process of distribution privatisation itself was fraught with several pitfalls suchas regulatory uncertainty, information asymmetry and prior escrow commitments.


At the time of privatising distribution zones, the private operators bid in anenvironment where they were uncertain about the regulator’s view regarding thevaluation of the existing asset base, the likely profile of prices or performance levels.Some operators made their bids under the presumption that the regulator woulduse the sixth schedule of the Electricity (Supply) Act 1948 and accept thegovernment’s overvaluation, whereas others did not put in their bids as they foundthe regulatory risk to be unacceptable. Understandably, those who bid did not seeany apparent reason to contest the overvaluation of assets, and assumed that it wouldbe reflected in the subsequent tariff.

Similarly, the data provided in the Information Memorandum at the time ofprivatising distribution zones does not appear to conform with reality. The followingobservations of BSES indicate the extent of information asymmetry between theMemorandum and reality:

Since authentic data on assets, receivable, etc., was not available, a full-fledged MIS was developed by consultancy agencies. Now, it is quite clearthat the world of MIS and reality are significantly different. An unrealisticallybetter picture of the distribution companies was presented through theseinformation memorandum and documents. The future projections madeon the basis of MIS are not only unrealistic but also too difficult to achievewithin the time period set out. Perhaps if the consultants had done a betterjob, the exercise would have turned out to be more realistic and reliable,and the interest of privatisation process would have been better served.

—BSES Limited 4

However, bidders took into account the assumption contained in the InformationMemorandum since the government had set an implicit reserve price equal to thepar value of the share, which was arrived at based on those assumptions. Thecombination of regulatory uncertainty, over-valuation and information asymmetrylimited the number of bidders for the distribution companies.

In addition to these problems, the cash flows of the Central Zone in Orissa wereescrowed to meet power purchases from OPGC, where AES was a 49 per cent jointventure partner. Added to the other problems of the Central Zone, this pre-emptionof cash flows affected investor sentiment so adversely that no responsive bid wasreceived for the Central Zone.5 Finally, after a re-bid, the zone was sold to anotherAES joint venture in September 1999.

In terms of the original reasons for revaluation, the government has benefited bybeing able to set off its dues to the erstwhile OSEB. It also managed to sell these assetsfor the stated book value. The revaluation has not made the distribution companiesany more able to raise debt (if anything, it has made them less creditworthy).


Post-privatisation, the regulator has been left to tackle the consequences ofovervaluation of assets and the poor quality of data contained in the InformationMemorandum. Not surprisingly, BSES, the successful bidder which took over threeprivatised distribution companies, and AES have already started raising these issuesfor consideration by the regulator.

In this context, the government should appreciate that by opting to arbitrarilyovervalue assets, it will be harming the process of privatisation.6 The primary aimof privatisation should be to improve the performance of the sector so as to providequality power to consumers at economic prices, and not to increase revenues forthe government. Accordingly, the government should resist any temptation toseek rents from the process of privatisation. One way of doing this is to encouragebids based on the potential of the assets being privatised for generating futurecash-flows.

In view of the above, privatisation of distribution should be preceded by a clearstatement from the regulatory commission, detailing its regulatory approach andincluding its views regarding what constitutes an appropriate valuation of rate base,likely profile of prices and expected performance levels. The government’s reserveprice, if any, should be arrived at based on the same transparent regulatoryframework; this information should be available to all potential bidders.

Such clarity would encourage serious private operators to participate, conductdue diligence of the existing assets, and submit a realistic bid. Otherwise, bidsbased on imperfect information and assumptions, though successful, are boundto create regulatory tussles and demands for re-negotiation and additionalsupport. In addition, a clear advance indication of regulatory intent would helpin preventing overzealous governments from excessively overvaluing their assetsjust prior to privatisation, with the hope to prevail upon the regulator to‘grandfather’ such decisions.

One might argue that it is the sole responsibility of the bidders to conduct their owndue diligence rather than relying on the Information Memorandum. Nevertheless,in the interest of achieving successful and smooth privatisation, it would perhapsbe more pragmatic to create appropriate conditions for encouraging more rationalbidding in the first place.

3.3 Need for continuing financial support from the state government

As any expectation for dramatic improvement in performance immediately afterprivatisation is unrealistic, one would have expected the government to continuewith its support to the sector, which it had been providing in the form of mandatorysubsidies to GRIDCO’s predecessor, OSEB. Instead, the government promptlywithdrew its support, even though the hopes of GRIDCO to raise a structural


adjustment loan from the World Bank on soft terms, to tide over the problem ofanticipated cash shortfall, did not materialise. GRIDCO’s problems werecompounded by the fact that even at the time of privatising the distcos, it was askedto retain huge liabilities on its books in order to make the distcos financially attractive.An informal understanding of GRIDCO with the World Bank and the Departmentfor International Development (DFID), to ensure its viability by a separate scheme,is yet to materialise.

The above experience underscores the importance of a structured time-boundfinancial support mechanism, which should taper off over time, based on targetedimprovements in revenue collection. It is important to provide such support todistribution companies to ensure specific targeting and to enable benchmarkingperformance across different distcos. Otherwise, providing financial support througha combined transmission and distribution company would weaken the incentivesto improve performance at the distribution level.

3.4 Limitations of the single-buyer model

The privatised distribution companies in Orissa are not free to source power fromgenerating companies of their choice. GRIDCO, the state-owned transmissioncompany, acts as the sole procurement agency on behalf of the distributioncompanies. This option is bereft of competitive pressures and leaves little scope forachieving procurement efficiency.

The experience of power sector restructuring in countries such as Argentina, Englandand Wales squarely underlines the importance of competition. It is competition inpower generation, coupled with the choice given to major consumers to sourcefrom the supplier of their choice, which has driven the wholesale prices of electricityin these countries.7 In order to facilitate competition, the unbundling of the naturalmonopoly segments (that is, transmission and distribution) from the segments thatare amenable for competition (that is, generation) is necessary; but it is not enough.

Hence, the distribution companies should be allowed to procure power fromthe generators of their choice or set up their own generating capacity, and therole of GRIDCO should be limited to providing transmission-related servicesonly. Further, until the distcos have monopoly franchise for supply to consumersin their geographical areas, the regulator could oversee their procurement toensure efficiency.

4. CONCLUSION

While it might be a little premature to judge power sector reform in Orissa, theexperience to date, however, clearly underscores a set of do’s and don’ts for otherstates which are engaged in the reform process. In summary, these are:


Do’s:

• Separate distribution from transmission and generation and privatise it earlyon in the process of reform.

• Provide regulatory certainty prior to privatisation in order to encourage seriousbidders and to avoid regulatory problems later. In particular, the regulatorycommission should spell out its regulatory approach, including its viewsregarding the appropriate valuation of asset base, likely profiles of prices andexpected performance levels.

• The reserve price, if any, should be based on a clearly spelt out support that islikely from the government and a transparent regulatory framework; thisinformation should be available to all potential bidders.

• The government should continue its financial support to the sector over alimited time period. It is important to provide this support directly todistribution companies.

• Plan for a quick transition away from a single-buyer model, which preventsdistribution companies from procuring power from the generators of theirchoice, to an open-access model, where distribution companies and largeconsumers can source their own supply.

Don’ts:

• Do not revalue assets prior to privatisation. This is, however, intimately tied tothe regulator’s approach on tariff setting and the nature of relationship betweenasset-value and expected tariffs, i.e. whether it will use Schedule VI, whichrequires an asset base.

• Do not escrow revenues from the distribution zones prior to privatisation.

NOTES

1. A timeline of key events in the restructuring is provided in the Annexure.

2. The state government took over the transmission and distribution assets of theOrissa State Electricity Board (book value plus capitalised expenses and interestat Rs 1200 crore) and revested them with GRIDCO after upvaluing by an additionalRs 1194 crore (additional 134 per cent).

3. For example, Argentina, England and Wales.

4. Vide a letter dated 27 October 1999, addressed to Special Secretary (Power), Governmentof India.

5. Tata Electric Company, which was selected as the partner for CESCO, did not pay theequity to GRIDCO, despite numerous extensions to the deadlines.


6. Normally, the various valuation options available to the government include book(historic) value, replacement value, ‘re-valued’ value, or business value based on thepotential for generating future cash-flows.

7. Following privatisation, Argentine wholesale electricity prices fell about 60 per cent from

the pre-privatisation level of US$60 per megawatt hour in August 1992.

ANNEXURE

Box 4.1: Timeline of key events in power sector reforms in Orissa

Month and year Event

November 1993 Power reforms programme announced byChief Minister.

April 1994 Reforms formally approved by the Councilof Ministers.

April 1995 Government issued a formal statement of itspower policy.

November 1995 State assembly approved the Orissa ElectricityReforms Act 1995.

April 1996 The Orissa Electricity Reforms Act 1995 and therestructuring of the industry became effective.

April 1996 The first Transfer Scheme. Assets, liabilities,proceedings and personnel of the Orissa StateElectricity Board were transferred to Orissa HydroPower Corporation (OHPC, for hydel generation)and the Grid Corporation of Orissa (GRIDCO, fortransmission and distribution).

August 1996 The Orissa Electricity Regulatory Commission(OERC) became functional. All three memberstook oath of office.

March 1997 The Orissa Distribution and Retail Supply Licenseand the Orissa Transmission and Bulk SupplyLicense were issued to GRIDCO. These licensesbecame effective on 1 April 1997.

March 1997 OERC issued an order on retail electricity tariffsfor all types of consumers, effective from1 April 1997.


November 1998 The second Transfer Scheme. Distribution relatedassets, liabilities, proceedings and personnel ofGRIDCO were transferred to four wholly ownedcompanies of GRIDCO—CESCO, WESCO,SOUTHCO and NESCO (Central, Western,Southern and Northern Electricity SupplyCompanies, respectively).

November 1998 OERC issued its Orders on Retail ElectricityTariffs and Bulk Electricity Tariffs, effective from1 December 1998.

January 1999 BSES emerged as the top bidder for WESCO,SOUTHCO and NESCO.

April 1999 BSES took over management of WESCO,SOUTHCO and NESCO, through acquisition of a51 per cent stake.

July 1999 Permission was granted to AES Transpower, foracquiring a 51 per cent stake in CESCO.

September 1999 AES Transpower took over control of CESCO.

December 1999 OERC issued Tariff Orders for retail supply forCESCO, WESCO, NESCO and SOUTHCOrespectively and a Tariff Order for bulk supply andtransmission for GRIDCO for 1999–2000.

Box 4.1: Timeline of key events in power sector reforms in Orissa (contd...)

Month and year Event


1. BACKGROUND

Since 1991, when the power sector was opened to private investment, financialinstitutions (FIs) and banks have sanctioned assistance of Rs 39,853 crore to57 independent power projects (IPPs) with an aggregate capacity of 21,393 MWin 15 states. Typically, these projects are financed on the strength of their powerpurchase agreements (PPAs) with the State Electricity Boards (SEBs) and aresupported by a 3-tier security mechanism consisting of a letter of credit, escrowcover on SEB receivables, and state government guarantees.

However, the progress of implementation of these projects has been rather slow.As many as 37 projects with an aggregate capacity of 14,618 MW are yet to achievefinancial closure.1

One of the main reasons for this slow progress, as identified in

previous meetings of the Crisis Resolution Group (CRG), is the non-availability ofescrow cover. Most of the State Electricity Boards either have no capacity to offerescrow support to IPPs or have exhausted their escrowable capacity. At the meetingof the CRG on May 16, 2000, the Union Minister for Power suggested that the onlyalternative left is to link the security mechanism with reform, by setting up crediblemilestones. Strict adherence to reform milestones by state governments will, indue course, result in improved revenue realisation, which would improve securityfor lenders.

It was therefore decided to derive a set of conditionalities including, but not limitedto, reform milestones, which could be used by FIs and banks as a basis for investmentin the Indian power sector. This note analyses the factors affecting the cashflowand viability of investments in the sector, with a view to establishing a set of

POWER SECTOR

FINANCING: A Note onConditionalitiesJune 2000

5

Power Sector Financing | 41

conditionalities. It also draws upon prior experience with conditional lending, inorder to identify possible pitfalls in the process.

2. FACTORS AFFECTING THE VIABILITY OF THE INDIAN POWER SECTOR

This section draws upon the factors affecting the viability of the sector to delineatetwo types of conditionalities. The first is a set of prior actions (or pre-conditions)that are critical to establishing the government’s commitment to reform, while thesecond set of arrangements is required to attract private investment and participationin the sector.

2.1 Conditions precedent

A recent World Bank Policy Research Report2

concludes that conditionality isunlikely to bring about lasting reform if there is no strong domestic movement forchange. Therefore, it is necessary to ensure that the state is committed to reformbefore embarking on a conditionality-based borrowing programme. Thiscommitment of the state can be measured by its willingness to meet certainpreconditions before disbursement.

2.1.1 Independent regulation

The monopoly nature of transmission and distribution makes it possible for thebusiness to exploit monopoly power, and also makes it vulnerable to interferenceby the state in view of the essential nature of the service. An independent regulatorcould address both these issues. The establishment of a credible regulatory institutionis a critical requirement for sector reforms.

2.1.2 Unbundling

The existing vertical integration extends the natural monopoly characteristic evento those segments that are amenable for competition, such as generation.Unbundling of generation, transmission and distribution is a pre-requisite forachieving competition-induced efficiencies.

2.1.3 Funding of existing liabilities

The SEBs have a number of existing liabilities, many of which are unfunded, suchas pensions, provident fund etc. They also have dues to central sector generatingunits, Coal India Limited, Railways, and other such organisations, along withreceivables of doubtful quality, including payments from various state governmentbodies. It is necessary that these liabilities and assets be clearly provided for by thegovernment, who is the owner of the SEB. One way of achieving this could be tosegregate the proceeds from privatisation

3 in a separate fund to meet these liabilities

before it is used for general budgetary support.


2.1.4 Market structure

A competitive market structure in both generation and supply is essential in orderto confer benefits to the consumer. Avoidance of this issue merely increasesuncertainty with respect to the timing of introduction of competition, which affectsthe bidding process for both generation and distribution assets. It is necessary forthe government to spell out a time frame for the introduction and the extent ofcompetition through the creation of a bulk market for power and the institution ofopen access arrangements for the grid.

2.1.5 Distribution privatisation

Theft of power is currently the single most important cause of financial bankruptcyin the sector. Privatisation of distribution is considered to be the only crediblealternative that can provide sufficient incentive to contain it. Accordingly,distribution privatisation is essential for improving cash flows in the sector.

2.1.6 Employee-related issues

Significant over-manning in the sector appears to be one of the principal sourcesof inefficiency in the sector. Currently, resistance from the employees appears tobe related to the lack of reassurance regarding payment of pensions, providentfund and other liabilities, which need to be provided for as mentioned above. Inorder to establish a viable power sector it will be necessary to allow flexibility inrationalising manpower. In addition, divestment proceeds can be used to makeprovisions for severance payments.

2.2 Conditionality for disbursement

Apart from the conditions precedent detailed above, there is a need for anadditional set of conditionalities in order to sustain the viability of the sectorthrough appropriate allocation of risk among various stakeholders. Theremaining part of this section looks at the broad risks in the sector, proposesan allocation of those risks and then suggests conditionalities aimed at achievingthat allocation and, if possible, mitigating those risks. It focuses on distributionand generation investments.

4

2.2.1 Distribution investments

Distribution companies need to be reassured that if they manage an efficientdistribution business, i.e., reduce distribution losses and avoidable outages, they willearn a reasonable return on investment. Viability of the distribution business is criticalto ensure the growth of the sector. In broad terms, this will be affected by the following:

(a) valuation of liabilities and assets handed over at the time of privatisation

(b) level of distribution losses—actual and allowable


(c) tariff level

(d) extent of subsidy support from the government

(e) timing of introducing choice to different classes of consumers

Of these, to the extent that the liabilities and assets being handed over at the timeof privatisation are clearly defined, the distribution company can be deemed tohave control over their valuation. After all, it is free to conduct due diligence andincorporate its assessment of the impact of these assets and liabilities into its bid.Further, the distribution company can be expected to have considerable controlover the actual level of distribution losses. On the other hand, the distributioncompany is unlikely to have control over the other items, viz., tariffs and allowableloss levels, which depend on the regulator, and subsidy support and timing ofintroducing choice, which depend on the government. A degree of certainty onthese matters can be achieved through a combination of conditionalitiesand guarantees.

2.2.2 Regulatory certainty

The level of tariffs and the allowable level of distribution losses are prone touncertainty since they fall under the purview of the regulatory body, which is stillan evolving institution.

5 Such uncertainty could be reduced if the regulator spells

out its regulatory approach ex-ante, i.e., at the time of privatisation—with amedium-term five-year tariff profile, conditional on levels of performance such asdistribution losses. It is possible to build in annual regulatory reviews in such aprocess in order to ensure that significant deviations from the assumptionsunderlying the tariff and performance profiles are accounted for. In case thegovernment fails to convince the regulator to offer such certainty, an alternativeroute could be for it to offer a tailored guarantee to protect the distribution companyagainst the risk of inadequate tariff being allowed by the regulator. A suggestedstructure is given in Annexure 1.

2.2.3 Subsidy commitments

The responsibility of fulfilling subsidy commitments within a predetermined timeframe should rest squarely with the government. In view of the possibility of non-fulfilment of such commitments, given the fiscal situation of most states, thecommitment to make subsidy payments will need to be guaranteed by a credit-worthy body, such as the Government of India or the World Bank.

2.2.4 Timing of introducing retail choice

The need to announce this at the time of privatisation has already been mentionedas a condition precedent, for the reasons mentioned therein.


2.3 Generation investments

The generating plant has three primary concerns—whether it will be dispatched,whether it will be paid and how much it will be paid.

6 The first relates to the overall

demand and relative cost of the plant (assuming a merit order dispatch scheme),while the last two are intimately related to the viability of the distribution businessand the structure of the power market, such as PPAs, bulk markets, etc. This sectionfocuses on the first concern, as the remaining concerns are expected to be suitablyalleviated with improvements in the viability of the distribution business and thefreedom to enter into commercial contractual arrangements with each other.

2.3.1 Dispatch risk

The dispatch risk can be further separated into two parts, namely, risk of overalldemand realisation and risk of not being in the merit order. In the former, the riskis that the plant, which is built in anticipation of demand growth, may not bedispatched because growth in demand is lower than demand forecasts. In the latter,even if the growth in demand is as per the forecast, there may be less expensivesources of supply that would be able to meet the demand.

7 Ideally, both these risks

should remain with the private sector, if they are allowed to make decisions oncapacity and technology, etc.

However, there may be a case for sharing the risks of non-realisation of demand, ifthe buyer (in the current scenario, the SEB and its owner, the government) insistson adding capacity that is higher than what the investor considers prudent. Thisrisk may be mitigated to the extent that the power from the plant could be sold tobuyers in other regions. The residual risk, if any, could be mitigated through aguarantee from the buyer (preferably, the state government), which would becomeeffective only when the total allowed power purchase (by all distribution companies)by the regulator is less than the demand forecasted by the government. A suggestedstructure for this guarantee is attached in Annexure 2.

3. EXPERIENCE WITH CONDITIONAL LENDING

This section examines the experience with employing the conditional lendingapproach, especially from the perspective of financial institutions and banks.

3.1 Multilateral conditional lending

The concept of conditional lending is often employed by aid agencies, such as theWorld Bank, to foster reform, by making financing conditional on the adoption ofcertain policies. According to the World Bank Policy Research Report mentionedearlier, about a third of the World Bank’s adjustment loans fail to meet their reformobjectives. In many cases loans were disbursed even though policy measures were


not carried out. It also quotes a recent study that indicates that the number ofconditions or resources devoted to preparation and supervision had no significanteffect on the probability of success or failure of reform. In fact, it appears that theapproach of the donor agencies in the past to ‘buy reform’ by offering assistanceto government, that were not otherwise inclined to reform, has failed.According to the report, the primary benefit of conditionality-linked loans isthat they provide a means by which reform-minded governments can publiclycommit to policy measures and send a signal to the private sector that the reformprogramme is credible.

3.2 Conditional lending in India

In the Indian power sector, the World Bank and the Power Finance Corporation(PFC) have tried out the conditional lending approach. The efficacy of theirapproach can be gauged by the following assessment of the World Bank:

8

… Operational and Financial Action Plans (OFAPs) from 1989 through1997 (with Bank support under Ln.3436-IN from 1992) attemptedrevitalization of APSEB but could not stop its rapid decline into insolvency.

It is perhaps too early to draw any meaningful conclusions on the effectiveness ofthe World Bank’s Adaptable Programme Lending (APL) approach in the states ofHaryana and Andhra Pradesh. One of the salient features of the APL approach isthat it provides a ‘stop-loss opportunity’ for the Bank at different stages of theproject. In other words, the Bank can stop further disbursements if the governmentfails to achieve/fulfil the reform-linked milestones/conditionalities. This hashappened in Haryana.

3.2.1 Possibility of replicating the conditional-lending approach ofmultilateral agencies

Although tempting, it may be counterproductive for FIs/banks to replicate theconditionalities imposed by agencies such as the World Bank. These institutions,after all, differ significantly from the World Bank in more ways than one.

First, it is important to note that the responsibility for repayment of World Bankloans is with the primary borrower, i.e., the Government of India (GOI) and notthe state government. By contrast, the FIs/banks typically provide finance directlyto public or privately owned utilities, whose creditworthiness is not backed bythe GOI. The limited scope for sound state government guarantees is alsofast disappearing.

Second, the risk-absorption capability of the FIs/banks is more limited than that ofagencies such as the World Bank, which operate on a much larger, more diversifiedand secure portfolio.


Third, the success of the lending by FIs and banks is determined by the commercialperformance of the loan, while the success of financing in the case of developmentalprojects supported by the World Bank encompasses a much broader definition ofeconomy-wide impact, including social benefits.

Fourth, they have to be satisfied with a lesser degree of leverage in order to effecttheir conditionalities as compared to aid agencies, who provide access to grantfinance and long term low interest developmental loans, through windows such asthe International Development Association.

3.2.2 Need for more caution

It is clear, based on the experience and possibility of replication, that FIs/bankshave to be more cautious while opting for conditionality-linked loans, as comparedto multilateral agencies. This is especially so given the time-inconsistent natureof conditionalities, whereby the government can cease adhering to them, afterhaving committed to them. The FIs would then be faced with accepting losses ondisbursements already made to a project, or renegotiating with the stategovernment from a weak position. Viewed from this perspective, the FIs/banksshould insist on irreversible reform steps before committing their investments.Hence, a careful assessment of the states based on their commitment and capabilityto undertake reform should precede any attempt to structure a conditional lendingprogramme. This is the basis for requiring prior action, based on the conditionsprecedent mentioned above. Concomitantly, the conditional lending programmeshould have the approval and commitment of the state legislature.

4. SUGGESTED CONDITIONALITY FOR POWER SECTOR FINANCING

Conditional lending appears to be providing a window of opportunity for FIs/banksto facilitate private sector participation in the Indian power sector. However, inview of the low degree of leverage available to them and their low tolerance for riskof failure, they should be extremely cautious in choosing the states to which theywould like to offer the conditional lending option. A suggested structure forconditional lending is given below.

Conditions for lending to distribution companies

Prior action

1. Formation of SERC

2. Unbundling of SEB

3. 100 per cent metering at 11 kV

4. Assumption of existing liabilities of the SEB by the state

5. Clearance or assumption (by the state government) of overdues of the SEB


6. Creation of a fund to segregate divestment proceeds

7. Announcement of the time frame for introducing choice to consumers

8. Announcement of a medium-term tariff and loss profile by the regulator orexecution of an average revenue realisation guarantee by the state, backed bythe GOI or the World Bank

9. Privatisation of distribution

Conditionality

1. Creation of a fund to meet payment of subsidies or execution of Guaranteefor payment of subsidies, backed by the GOI or the World Bank

2. Privatisation of generation

Additional conditions for lending to IPPs

1. Allowing IPPs to determine their plant capacity or execution of overalldemand realisation guarantee by the state,9 backed by the GOI or theWorld Bank

2. Allowing use of transmission lines for wheeling of surplus power

3. Announcement of the time frame for establishing a bulk market

Further conditions for lending to state-owned generating plants

1. Improvement in plant availability

ANNEXURE 1

Average revenue realisation guarantee (limited to debt)

Objective : To mitigate the risk of inadequate tariff being allowed bythe regulator.

Trigger : In the event that the average tariff allowed by the regulator is lowerthan a pre-specified level.

Condition : The distribution company should meet pre-specified distributionloss levels.

Explanation : This guarantee is triggered only if the cash flows of the distributioncompany are not sufficient to make debt service payments tolenders. In such an event, the following calculations and paymentswould be made:

Method : a) Pre-specify a certain consumer ratio among various tariffcategories and an overall level of Guaranteed Average RevenueRealisation (GARR), in rupees per unit.


b) Multiply the tariff allowed by the regulator with the pre-specified consumer ratio and calculate the Implied AverageRevenue Realisation (IARR), based on the power demandapproved by the regulator.

c) Deduct the IARR from the GARR to arrive at the ARR shortfall.

d) If the ARR shortfall is positive, multiply the powerdemand approved by the regulator with the ARR shortfalland call this the ‘Maximum Alternative DistributionPayment’ (MADP).

e) Make payments to each distribution company based on theamount needed to cover the minimum debt service or MADP,whichever is lower.

Example:

Years 1 2 3 4 5

1. Approved demand (MU) 32400 34800 37800 41400 45000

2. GARR (Rs per unit) 4.20 4.41 4.63 4.86 5.10

3. IARR (Rs per unit) 4.30 4.30 4.60 4.80 5.00

4. Target distribution loss (%) 35 30 30 25 20

5. Actual distribution loss (%) 36 32 28 24 20

6. ARR shortfall (Rs per unit) — 0.11 0.03 0.06 0.10

7. MADP (Rs crore) — — 113.4 248.4 450

8. Debt service (Rs crore) — 50 — 100 500

9. Guarantee payment (Rs crore) — — — 100 450

Note: In year 2, the distribution loss target is not achieved and hence there is no guarantee

payment. In year 3, there is no debt service and hence there is no guarantee payment.

In year 4, payment is made to the extent of debt service. In year 5, the debt service is

higher than the MADP, but payment is limited to the extent of MADP.10

ANNEXURE 2

Overall demand realisation guarantee (limited to debt)

Objective : To mitigate the risk of non-realisation of overall demandprojections.

Trigger : In the event that the overall power procurement allowed by theregulator is lower than the forecasted power demand.


Explanation : This guarantee is triggered only if the cash flows of the IPP arenot sufficient to make debt service payments to lenders. Insuch an event, the following calculations and paymentswould be made:

Method : a) Compare the pre-announced forecast of power demand withthe actual power procurement allowed by the regulator.Determine the extent of shortfall.

b) Allocate the shortfall on a merit order basis to the various plantsthat are available for dispatch and with which guarantees havebeen signed.

c) Multiply the allocated shortfall to each plant by the tariff ofthe highest cost plant in the list of procurements approved bythe regulatory commission. Call this amount the ‘MaximumAlternative Generation Payment’ (MAGP)

d) Make payments to each plant based on the minimum amountneeded to cover debt service or the ‘Maximum AlternativeGeneration Payment’, whichever is lower.

Example : There is an existing capacity of 5000 MW that supplies power atRs 1.50 per unit. Additional capacity is expected to be addedthrough Plant A (1000 MW starting from 2nd year supplying atRs 2.50 per unit), Plant B (1500 MW starting from 4th year atRs 2.00 per unit) and Plant C (1500 MW starting from 5th year atRs 2.20 per unit). While Plants A and B have PPAs backed by overalldemand realisation guarantees with the state government, PlantC is a merchant plant without similar guarantee cover.

Years 1 2 3 4 5

1. Total installed capacity 5000 6000 6000 7500 9000

2. Demand projected bygovernment (MW) 5500 6050 6655 7320 8000

3. Demand allowed bythe regulator (MW) 5400 5800 6300 6900 7500

4. Gap between projected andallowable demand (MW) 100 250 355 420 500

Merit order dispatch

5. Existing (5000 MW@ Rs 1.50 per unit) 5000 5000 5000 5000 5000


6. Plant B (1500 MW@ Rs 2.00 per unit) — — — 1500 1500

7. Plant C (1500 MW@ Rs 2.20 per unit) — — — — 1000

8. Plant A (1000 MW@ Rs 2.50 per unit) — 800 1000 400 0

9. Undispatched capacityof Plant A (MW) — 200 — 600 1000

10. Allocation of shortfall toPlant A (MW) (lower of 4 and9, subject to merit order) — 200 — 420 500

11. Allocation in million units(@ 6 MUs/MW) — 1200 — 2520 3000

12. Tariff of the costliest plantdispatched (Rs/unit) 1.50 2.50 2.50 2.50 2.20

13. MAGP (Rs crore) — 300 — 630 660

14. Debt service (Rs crore) — — — 300 750

Guarantee payment (Rs crore)(lower of 13 and 14) — — — 300 660

Note: In year 2, there is no debt service and hence no guarantee payment. In year 3, Plant A

is fully dispatched. In years 4 and 5, payments are limited to the gap between projected and

allowable demand and also to the burden of debt servicing. In year 5, although 500 MW of

Plant C also remains undispatched, it will not get any compensation, as it does not have

guarantee agreements like Plants A and B.

NOTES

1. To date, 10 projects (aggregate capacity of 3,359 MW) have been fully commissioned,1 project (420 MW) has been partly commissioned, and 9 projects (3,402 MW) areunder various stages of implementation.

2. ‘Assessing Aid: What Works, What Doesn’t and Why’ published by the OxfordUniversity Press (1998). A fuller discussion of the distinction between conditionalmultilateral lending and lending by FIs is given in Section 3.

3. Going by the dire financial condition of the sector, it would be a matter of surprise ifthe government could raise positive revenues from the process of privatisation ofdistribution. If it indeed does, it could be only on account of either expectation of a

Years 1 2 3 4 5


genuine turnaround, or sheer bravado on the part of the bidders or in anticipationof favourable re-negotiation with the government/regulator. The bulk of proceedsfrom privatisation should therefore be expected to come from privatisation of thegeneration segment.

4. The need for additional investment in transmission cannot be denied. However, in theinitial phase of reform it is expected to remain with the state and the investmentrequirements would become clearer as the distribution and generation businesses evolve.

5. Similarly, the regulator may impact the valuation of liabilities and assets handed overat the time of privatisation depending upon the extent to which they are accommodatedin tariff setting, either as pass-throughs or in the ratebase.

6. The equity investor is assumed to bear construction and technology risks, as is thecurrent practice. Fuel supply risk is being ignored at this point, since the focus is on thestate government, and because it is primarily a commercial risk to be borne by theequity investor, in the case of fuels such as imported coal.

7. This may come from new plants, renovated older plants or supply from other regionsmade possible by a more integrated grid.

8. The World Bank’s Project Appraisal Document on a proposed loan to India for theAndhra Pradesh Power Sector Restructuring Project, 25 January 1999.

9. This requires the state government to determine the ‘supportable capacity’ in order tostructure the guarantee (see Annexure 2).

10. There may be a case here to capture the MADP due in earlier years into a notionalreserve account in order to meet such contingencies. This would be a stronger guaranteethan the one proposed in the note.


1. INTRODUCTION

The power sector in India is facing a breakdown. Revenue arrears of StateElectricity Boards (SEBs) grow by the hour, as consequently do their dues tocentral sector units like National Thermal Power Corporation Limited (NTPC)and Coal India Limited. Even in states like Karnataka, which are relatively wellmanaged fiscally, the burden of power sector subsidies has grown to over a thirdof their fiscal deficit. Faced with this situation of a bankrupt SEB and a fiscallyparlous state government, private independent power producers (IPPs) darenot invest and even if central sector units like NTPC make investments they areequally unlikely to be paid for the power they produce. Soon, power will becomea binding constraint on our ability to maintain high growth rates. The need forreform in the power sector is therefore unarguable, especially in the distributionsegment where the losses have been the heaviest. The estimated T&D losses, asis being demonstrated by the orders of State Electricity Regulatory Commissions(SERCs), in various states is closer to 40 per cent! This is true across the country,in states as varied as Andhra Pradesh, Gujarat, Haryana, Maharashtra, Orissaand Uttar Pradesh.

Remedying this situation calls for the provision of adequate incentives and thetransfer of risk along with reward that is, today, unfortunately not possible underpublic ownership in India. In order to leverage the accountability that is now possibleas a result of the greater regulatory transparency, it is necessary to privatise thepower sector, especially the customer end, i.e., distribution. This process ofprivatisation provides an opportunity to allocate the various risks in the power sectoroptimally, to the entity that can best control them.

SIX STEPS TO ACCELERATED

PRIVATISATION OF

ELECTRICITY DISTRIBUTION

January 2001

6

Accelerated Privatisation of Electricity Distribution | 53

Privatised distribution is not an alien concept in India. Today, private distributionlicensees continue to operate in the cities of Mumbai, Calcutta, Ahmedabad andSurat. Some of these licensees also own generating assets. For instance, BombaySuburban Electric Supply (BSES) sources about 50 per cent of its electricityrequirements from its own plants. Similarly, the Ahmedabad Electricity Company(AEC) and the Calcutta Electric Supply Company (CESC) own generating capacityof 550 MW and 945 MW respectively. The fact that the tariffs of BSES, whichcaters to 19.8 lakh consumers in an area of 384 sq km, are competitive, and thatits distribution losses are now only about 10 per cent, aptly underscores the superiorperformance of distribution under private ownership. Their successful track recordhighlights the possibility that privatisation of bundled distribution-cum-generation companies can be a viable and relatively quick option for privatisingthe power sector in India.

1.1 Need to accelerate the pace of privatisation

Unfortunately, despite the need for privatisation of distribution in the reformingstates and the impressive track record of private licensees, it is not taking place atthe desired pace, for various reasons. On the one hand, reforming states areexpending enormous time and effort in configuring distribution zones forprivatisation, in the name of asset-valuation and in achieving the elusive ‘right’balance between the subsidised and subsidising categories of consumers. Forinstance, in Orissa, the first state to have undertaken comprehensive restructuringof its power sector, although reforms were initiated in 1996 (in fact discussionsstarted as early as 1992!), the crucial step of privatising distribution occurred onlyin 1999. Even in other reforming states such as Haryana, Andhra Pradesh andUttar Pradesh, the privatisation of distribution is slated to take place only three tofour years after the initiation of the restructuring process. On the other hand, asevidenced in Orissa and in the privatisation of Kanpur city in Uttar Pradesh, privateinvestors are wary of participating in distribution privatisation, as they perceiveseveral risks ranging from regulatory uncertainty to unreliable commitments onthe part of the state governments.

1.2 A one-year timeline

The adverse consequences of the delay in distribution privatisation are alreadyvisible in the continuing accumulation of losses in the SEBs and in the growingreluctance of investors to set up new generation capacity. Given the alarmingpace of decay in the distribution systems and their management, quick privatisationof distribution is a sine qua non for the success of the reform process. Against thisbackdrop, this paper delineates a set of six inter-related steps for the successfuland quick privatisation of distribution. It is our contention that it is possible to


privatise distribution within a year, through a diligent execution of the stepsoutlined below. An indicative timeline for this accelerated process is providedin Table 6.1.

2. SIX STEPS TO PRIVATISATION OF DISTRIBUTION

Distribution privatisation is a difficult task in the best of times. It will be even moredifficult in the current situation, given the low average tariffs and the decrepitdistribution network. The private sector, when it enters the distribution business, isalso required to make large investments. It makes these investments in the expectationof earning a fair return on these investments over the future. The private sector willnot bring in investment unless there is a secure foundation for these expectations.This does not imply that the private sector needs to be protected from all risks. Itdoes however imply that they should be provided with an environment that allowsthem to evaluate the various risks and price them accordingly.

Like in any other financial transaction, in distribution privatisation too, successdepends on the efficient allocation of risks. In the context of privatisation, thedistribution business is fraught with several risks arising out of the following factors:

• Existing commitments by SEBs, such as escrows and long-term power purchaseagreements (PPAs) with IPPs

• Unfunded liabilities from the past such as dues to suppliers of power and fueland employee pension commitments

• Regulation of tariffs, expected performance levels and allowable returns

• Government support to meet subsidy commitments and

• Market structure (input prices, competition and choice to consumers)

In order to be effective, a distribution privatisation strategy should satisfactorilyaddress these concerns. This is the purpose of this paper.

2.1 Step 1: Notify a policy eschewing escrows and long-term PPAs

2.1.1 Effect of escrows and long-term PPAs

An escrow facility involves dedicating a stream of revenue from specified customersor regions into an escrow account maintained by an agent bank in order to meet thepower purchase payment obligations of an IPP. This security mechanism was resortedto because the SEBs were perceived as poor credit risks. The primary claim on therevenue stream was therefore transferred from the distribution system to the IPP.In a situation where most of the privatised distribution regions would in any casebe expected to have cash losses in the initial years, an additional pre-emption ofcash flows would make it very difficult to run the distribution business. This negativeeffect of an escrow on the already low cash flow stream that would be received by


the prospective buyer makes it difficult to privatise a region that has been escrowed,as was seen recently with the Central Zone in Orissa.

The escrow facility is also associated with very long-term power purchase agreements,extending up to thirty years, which were needed since the SEB was the sole buyer ofpower. In the context of transferring such contracts to a privatised distributionsystem, one solution that has been advanced is to retain a single bulk buyer, such asthe transmission company. Here the experience of GRIDCO in Orissa indicatesthat such a measure may fail because the GRIDCO is unlikely to be a good creditrisk, and the government would have to again step in to support the contract.1

Clearly, it is inappropriate to burden prospective private owners of distributionzones with fresh contracts, especially where they are not a party to the decision.More importantly, under the emerging market structures, such long-term contractshave a deleterious effect on competition as they prevent distribution companiesfrom accessing the most competitive supplier of energy.

2.1.2 Breaking the vicious circle

As long as the distribution business does not generate sufficient revenue andthere remains a single buyer of power, there will continue to be a demand forescrows and long-term PPAs. This will continue until distribution is privatisedand IPPs are allowed to enter into direct contracts with distribution companiesand large consumers. At the same time, escrows and long-term PPAs adverselyaffect the attractiveness of the distribution zones and thereby obstruct the processof privatisation.

The government should break this vicious circle and clearly opt for improvingsecurity through privatisation of the distribution business and eschew escrows andlong-term PPAs by making a public notification of such policy. Newly privatiseddistribution companies should not be burdened with the erstwhile escrowarrangements and PPAs. Instead, they should have the freedom to enter into theirown voluntary contracts, and develop other routes to reduce energy purchase costs.

2.2 Step 2: Financial restructuring

2.2.1 Retain unfunded liabilities to realise better value

The SEBs have a number of existing liabilities, many of which are unfunded, such aspensions. In addition, they have dues to central sector generating units, Coal IndiaLimited, Railways and other such organisations, along with receivables of doubtfulquality, including payments from various state government bodies. In order to realisethe best value for the business, these liabilities need to be retained by the currentowner, i.e., the state government, under whose ownership they have beenaccumulated. Apart from the moral obligation not to transfer one’s sins onto others,


it also makes financial sense. In cases where the amount is undisputed, any transferwould result in an equivalent direct deduction from the bid amount. In cases wherethe liability is uncertain, such as future contractual commitments and pensions, theprivate sector would have a higher degree of risk aversion, given that they cannotcontrol these risks. Transferring these liabilities to them will only result in a lowerbid, which would be reduced by an amount greater than what the governmentbelieves to be the extent of the liability. Hence, as part of the Financial RestructuringPlan (FRP) prior to privatisation, these liabilities and assets should be clearly vestedwith the government, who is the owner of the SEB, and should not be passed on tothe newly formed private companies. By retaining them, the government wouldimprove the bid valuation, and can use a portion of the privatisation proceeds tomeet the liabilities as described below.

Box 6.1: Privatisation of generation assets of SEBs

Privatisation of generating stations is necessary to ensure that the generation capacityof the SEBs, which is around three fourths of the installed capacity in the country, isutilised to the maximum possible extent. The current lack of appropriate incentivesfor good management in the public sector affects their investment and operatingefficiency. As of date, the PLF (Plant Load Factor) for SEB plants is well below what ispossible, even after accounting for the age of these plants. Improving their utilisationwill enable an increase in the power supply that would mitigate the effects of the sloweraddition to new capacity.

Generating stations often do not receive regular payments for the energy they supply.Their continued government ownership weakens the commercial environment in thepower sector. There is no reason to continue to divert state resources to a commerciallyviable activity. As the distribution sector is privatised and begins to generate enoughresources to permit financially sound arrangements for power purchase, these plantswill gain in value. The value of these generating stations could be realised by selling theexisting plants and the resources used to reduce the subsidy burden and finance theunfunded liabilities in the sector. Without their sale, it is unlikely that it will be possible

to fully finance these liabilities.

2.2.2 Plough-back proceeds of privatisation

In order to provide a secure financial source to meet the deferred payments toworkers and creditors mentioned above, government should plough back all theproceeds realised by privatising the power sector, including those related to the saleof generation assets (see Box 6.1 above). In this manner, the government will beable to defray part of the liabilities assumed by it, on account of past dues, contractualobligations, pensions, etc. To meet the shortfall, if any, the government should usethe low-interest long-term support from multilateral institutions. Indeed the


appropriate use of such multilateral funds should be for such purposes rather thanto finance investment in physical assets, which can be undertaken by the privatebuyer through the local financial markets.

2.3 Step 3: Separate urban and rural zones for effective privatisation

As of now, almost all the reforming states are seeking to privatise distributionzones as a mix of subsidising and subsidised categories of consumers. This leadsto long delays as enormous time and effort is spent in configuring distributionzones for privatisation, in achieving the elusive balance between the subsidisedand subsidising categories of consumers. It also increases uncertainty, given thelack of information about the distribution system in the non-urban areas. Aprivate entrepreneur looking to buy the zones is concerned that his payingcustomers will turn to captive plants, driven away by high tariffs needed to raiserevenue to meet the ‘social obligation’ of supplying non-paying consumers. Inaddition, this ‘mixed-zone’ structure is fraught with several limitations (see Box 6.2).By contrast, separation of urban and industrial zones from rural zones can notonly result in a faster pace of privatisation; it also addresses the main reason forprivatisation of distribution, which is to reduce the extent of theft andinefficiency, as explained below.

Box 6.2: Limitations of the ‘mixed-zone’ structure

A distribution company with ‘mixed’ zones will have two revenue streams, one fromconsumers, who pay their own user charges and the other from the government inthe form of subsidy support, which would be determined by the regulator. Thepresence of a subsidy-stream provides an avenue for the company to camouflagetheft and inefficiency, by over-reporting consumption under subsidised categories,which are often not metered in full and sometimes not at all, as seems to be thecurrent practice in SEBs. Faced with the arduous task of improving the efficiency ofcollection from a large number of consumers, even the private distribution companymay find it a more attractive proposition to try and convince the regulator that largersubsidy flows are called for, instead of expending effort to eliminate theft. Thus, themanagement of a ‘mixed’ zone company, whether public or private, would havelittle or no incentive to meter agricultural consumption, since it would take awaythe ability to camouflage the theft of power. Even if the regulator is aware of thisproblem, it can only address it through a burdensome exercise of verifying actualconsumption through a programme of compulsory metering, which will take asubstantial amount of time. Further, if the ‘mixed’ zone distribution companysucceeds in its strategy of over-reporting subsidised consumption, the subsidy burdenon the government will increase to that extent. A strategy of privatisation through

segregated zones will curb this problem.


Accelerated loss reduction: Apart from Delhi, even in other places, where therehas been a certain degree of substation metering, such as Karnataka and AndhraPradesh, it is evident that the extent of commercial losses in the urban andindustrial areas is very high. Consequently, it can be inferred that pilferage andtheft is concentrated in these areas. The privatisation of distribution in these areasalong with regulatory stability2 through a medium-term tariff regime, as discussedin the next section, will provide strong incentives to distribution companies tofind thieves and make them pay, since the reduction in theft, with stable tariffs,directly enhances profits.

Faster pace of privatisation: If urban and industrial areas are offered for sale, theprocess of privatisation can proceed faster, as the need to discover the elusivebalance between the subsidised and subsidising categories of consumers will nolonger exist. This must however be done in conjunction with a stable regulatoryregime and with realistic expectations, as outlined in our previous analysis of thedelay in the privatisation of the Kanpur Electricity Supply Company (KESCO).3

The Request for Qualification (RFQ) can be issued as soon as the zoning iscompleted, as shown in Table 6.1.

Improved revenue realisation and better bidders: The third strong reason to separateurban from rural zones is to improve the sale value for the government. As long asone of the revenue streams is from the government, a private bidder will expect thatthese payments to be delayed and will accordingly discount their availability, andreduce the value of its bid. By removing the uncertainty associated with subsidysupport, the government can realise better value for urban and industrial zones atthe time of privatisation. It will also attract companies whose expertise is distributingelectricity and not those whose primary competence may be in persuading thegovernment and the regulators to release subsidies.

2.3.1 Effect of segregation on the rural zones and subsidy bill

It is now widely recognised that urban theft is often misreported as agriculturalconsumption, which inflates the amount claimed under agricultural subsidy.Separation of urban zones from the rural areas removes the incentives to camouflagetheft and inefficiency under subsidised consumption since the distribution companyserving the urban and industrial zones would not have any access to subsidy flows.It allows identification of the actual amount of subsidised consumption and permitsa more accurate estimation of theft. The increased detection of theft, as a result ofseparating urban and industrial zones, would reduce the extent of such fraudulentsubsidy claims. Combined with the better estimate of true non-urban consumption,this is likely to reduce the subsidy bill, and thus make it more likely that the statewould be able to finance the subsidy.


The privatisation of urban and industrial areas does not at all imply that rural zoneswould be worse-off. Stand-alone urban zones will separate those now consideredunable to pay, such as the rural poor, from those considered able to pay. In case thegovernment wants to continue subsidies, it can do so through direct budgetaryallocations. If the budget still comes up short, government can impose an across theboard ‘surcharge’ on electricity consumption of the urban and industrial zones anduse the resultant revenues for subsidy payments. The transparency of such a chargewill soon generate the countervailing political pressure necessary to ensure thatthose judged unable to pay are truly incapable of paying.

2.4 Step 4: Ensure stable regulation for risk mitigation

Traditionally, around the world, regulation in the electricity sector meant an intrusivecost-based regulation of vertically integrated utilities. In India, this is reflected inSchedule VI, which tries to assure a specific rate of return to the utility, which alsoinvolves a detailed and frequent examination of its costs. This regulatory regime isundergoing transformation, as it is now possible to subject more of the sector tocompetition. In a number of countries today, generation tariffs are completelyderegulated, as also the tariffs for large consumers. Tariff regulation remains inplace for the use of transmission and distribution wires, as well as for tariffs chargedto smaller consumers.

In India too, most of the central elements that affect the viability of the distributionbusiness fall under the purview of regulatory commissions. These regulated elementsinclude input prices, tariffs, allowable returns, and expected level of performance interms of technical and commercial losses. Thus, under the current arrangements,allocation of risk to distribution companies is determined, to a large extent, by theregulatory philosophy and tariff orders of the SERCs. The release of a regulatoryphilosophy document, being only a statement of intent, only partially meets theobjectives of providing information about risk allocation. The realisation of thestated intent is found in the tariff order. For this reason, prospective bidders fordistribution zones often request that the process be deferred until the issue of atariff order by the SERC. However, the Request for Proposals (RFP) can be issuedand the process of due diligence can begin as soon as the tariff submissions aremade for each separate zones.

2.4.1 Effect of recent tariff orders and risk allocation by the SERCs

Almost all SERCs have realised that tariff increases alone are not the answer tosolving the problem of SEB viability. Indeed, most SERCs have determined that itwould be unfair to shift the burden caused by high T&D losses and low collection tobilling ratios, i.e., a lack of efficiency on the part of the utility, completely onto theconsumer by raising tariffs. SERCs have also realised that it is counterproductive to


charge higher tariffs that take the price of grid power well above the cost of generatingcaptive power. Consequently, they have limited the extent of cross-subsidy fromindustrial and commercial consumers to other consumers, who are charged belowthe cost of supply. The owners of the SEB, i.e., the state governments, are nowrequired, albeit partially, to come up with the requisite funds from the state budgetto compensate the SEB, if they wish to charge tariffs below cost of supply. Thisdirect impact on the budget, in contrast to earlier practice, has made manygovernments realise the financial unsustainability of insisting on tariffs that recoveronly a small fraction of the supply cost.

This approach has however resulted in a difficult position for prospective privateowners, who are now expected to bear the financial burden caused by the high T&Dlosses, low collection to billing ratios and limited extent of cross-subsidy, until suchtime as they can bring them down. While this admittedly provides a very strongincentive to the private company to reduce losses, coupled with the regulatoryuncertainty caused by annual tariff orders, it also results in a degree of uncertaintythat may be severe enough to drive investors away from the sector.

It is thus necessary to devise a regulatory regime to balance the need to provideincentives to improve efficiency with the need to reduce the discouraging effect ofregulatory uncertainty. This assumes additional importance in the current situation,when the process of transition from public to private ownership is about to takeplace and where sizable investments are necessary for systemic improvements. Ineffect, the regulator has twin roles, viz., an oversight role as well as an investmentpromotion role. It should therefore ensure a stable and sensible regime that willprovide an environment conducive to such investments, without compromisingthe interests of consumers.

2.4.2 The need for medium-term tariff orders

This balance is possible by instilling confidence in prospective investors, by givingthem a degree of stability with respect to risk allocation. A good way to achieve thisis to announce a medium-term, for example, five-year, tariff profile based on anassociated loss profile, which provides tariff stability in the years immediatelyfollowing privatisation, along with incentives to improve efficiency. For this, thegovernment should ensure that a submission for medium-term tariff determinationis made to the SERC, separately for each zone.

The basis of determining this tariff profile would be the SERC’s judgement aboutthe ‘base case’ for improvement. In arriving at this judgement, regulatorydeterminations on three variables are critical, viz.,

1. The distribution losses that will be incurred.

2. The demand growth that will take place.

3. The investment that will be required.


While the first two of the above parameters would determine the amount of powerpurchase costs that the utility will be allowed to recover through the tariff, thethird parameter would provide the utility with information about the regulator’sview as to the extent of investment that will be needed. In order to develop acredible ‘base case’, the regulator should ensure that these parameters are peggedat realistic levels.

As regards the quantum of distribution losses, the regulator should rely mainly onthe implied T&D loss, which is the difference between the amount of energy inputinto the distribution zone and the amount of revenue collected (deposited in thebank) from the distribution zone. In the existing system, these are the only hard,credible data points, as these are easily verifiable. The regulator and governmentshould avoid spending time and effort in arriving at detailed but unverifiableestimates of a variety of losses, which, in any event, are not likely to be believed bypotential bidders. Similarly, considering the decrepit distribution system and theother difficulties emanating from the change of ownership, loss reduction targetsshould be fixed at reasonable levels—say, none for the first year, followed by increasedreductions from the second and third years. Finally, improving performance needsmassive investments for system upgradation. These should be estimated and includedin permissible investment.

The power purchase and investment costs together constitute a large proportion ofthe controllable costs of the distribution company. Hence, an order specifying thesecosts provides the investor with a clear signal as to the expectations of the regulatorregarding the kind of performance that is expected in order to earn a reasonablereturn. Based on such a profile over the next five years, a bidder for the distributionbusiness, after due diligence, can arrive at his own judgement with regard to thereasonableness of the tariff profile. If it feels that it can do better than expected bythe regulator, it will bid aggressively, in expectation of higher profits. On the otherhand, if the regulator’s perspective is perceived as being too stringent, it will bidlower, since he would not expect to make large returns.

Here, it is important to note that in case the initial regulatory order is too favourableto the private bidder, a portion of this will be recaptured in the higher price paid bythe winning bidder, and thereby prevent excessive profits. Second, and moreimportant, the returns to the investor are conditional on good performance. Theinvestor makes more money only if he does better than expected, in terms of reducinglosses, undertaking investments efficiently and increasing demand, e.g., by attractinghigh-tension users back to the grid. It is critical to acknowledge and reward suchperformance by assuring the investor that he would be able to retain suchperformance-linked driven profits. These returns are the very basis of theaccountability that privatisation of distribution seeks to induct.


Tariffs based on distribution value-added (DVA) charge: In case the regulator isreluctant to provide a medium-term profile of tariffs for want of adequateinformation, it could separate the costs associated with distribution services—thatis, distribution value-added (DVA)—which is essentially a charge for using thedistribution wires, and announce a medium-term profile only for that component.Under this arrangement, the remaining costs related to power purchase andtransmission could be allowed as a pass-through, after appropriate regulatoryscrutiny. Such a system would be compatible with an eventual structure of the sector,where a competitive power market determines power purchase costs. In the interim,this system would insulate private distribution companies from the vagaries of thebulk power market.4

2.5 Step 5: Market structure: avoid the single-buyer model

The value of the various businesses in the power sector depends on the future cashflows that they generate. The extent and sustainability of these cash flows woulddepend critically on the market structure that is adopted. Given the internationaltrends and the pointers in the proposed Electricity Bill 2000, India too will eventuallywitness the emergence of bulk power markets, merit-order dispatch, choice toconsumers and open access to the transmission and distribution wires. Each of theseis essential for the success of privatisation, as they form the very basis for competition.

The single-buyer model is often sold as a transitional arrangement, ‘justified’ inorder to maintain uniform prices across the state and form one agency responsiblefor honouring the existing PPAs entered into by the state. However, apart from itsmany disadvantages (see Box 6.3 below), its adoption instead increases the likelihoodthat, under pressure from vested interests, the next step toward liberalised electricitymarkets will be indefinitely delayed.5 This approach restricts distribution companiesand large consumers from buying from the generators of their choice. Suchrestrictions reduce the scope for efficiency gains in the short term and vitiates theprocess of developing a healthy power sector in the long run.

Box 6.3: Disadvantages of the single-buyer model

The single-buyer model has major disadvantages, particularly in situations with highdegree of corruption and low payment discipline. First, and most importantly, thesingle-buyer model weakens the incentives for distributors to collect payments fromcustomers. The state-owned single buyer is often reluctant to take politically unpopularaction against a delinquent distributor, and its aggregation of cash proceeds fromdistributors allows it to spread the shortfall caused by a poorly performing distributoramong all generators. When distributors see that paying and non-paying distributorsare treated alike, their motivation for cutting off non-paying customers weakens across


the board, vitiating the very reason for privatisation. Second, decisions about addinggeneration capacity are not made by distribution companies, who would have tobear the financial consequences of their actions. Instead government officials and‘experts’, who do not have a direct commercial stake, have to make these decisions,and often find it difficult to resist powerful interest groups pushing for state-guaranteed capacity expansion. Third, PPAs create a contingent liability for thegovernment, which is expected to step in if the state-owned transmission companyis unable to honour its obligation to the generator. Loading the state-ownedtransmission company with all the agreements when it is hardly equipped to takeon the risk arising from failure of the PPAs often leads to its financial ruin, as inthe case of GRIDCO in Orissa. To the extent that these PPAs are a net cost, it isbetter that they be addressed directly rather than be hidden under the wraps of thestate-owned transmission company. Fourth, the single-buyer model respondspoorly when electricity demand falls short of projections (such as the recentexperience with Dabhol). Ideally, electricity prices should fall, stimulating demand.6

Under the single-buyer model, however, wholesale electricity prices rise becausetake-or-pay quotas (or fixed capacity charges) must be spread over a shrinkingvolume of electricity purchases. When these high prices cannot be passed on tofinal consumers, taxpayers must bear the losses. Fifth, the single-buyer modelhampers the development of electricity trading across state borders, by leaving itto the single buyer, a state-owned company without a strong profit motive, toenter into such arrangements.

Based on The Single-Buyer Model: A Dangerous Path Toward Competitive Electricity Markets by

Laszlo Lovei, Public Policy for the Private Sector Note No. 225, the World Bank, December 2000

2.5.1 Effect on distribution privatisation

The choice of market structure has an impact on the cashflows of the distributionbusiness. For example, a distribution business that enjoys a local monopoly, i.e., whoseconsumers cannot buy their power from other suppliers, would have a differentvaluation as compared to a business whose consumers have the option of purchasingfrom alternative sources. Similarly, a distribution company that can source its powerrequirement from a competitive bulk power market would have a different valuationas compared to one that has to buy from a single high cost supplier. Hence, thegovernment should spell out the timing of introduction of the bulk power market aswell as the choice to consumers at the time of privatisation. This will enable investorsto factor in risks arising out of these developments into their bids.

An illustrative schedule for introducing choice to consumers could be as shownbelow. Since permitting such transactions would require appropriate improvementsin the areas such as billing software, interconnection and metering, the responsibilityfor such expenditure needs to be clearly and appropriately allocated between thedistribution company and the transmission company.


Illustrative time frame for introducing choice to consumers

1 year 3 years 4 years 5 years 7 years

Above 10 MW Above 5 MW Above 3 MW Above 1 MW All

2.5.2 Own-generation and vesting contracts

As noted before, the proposed Electricity Bill 2000 envisages open access to the networkand the development of a bulk power market in the medium term. In a power market,there is usually a single market price for power, which may vary over the day—fromhour to hour or at even finer intervals. In such a situation, the transmission companyis responsible only for the transmission of power and not for bulk purchase of powerfor onward supply to distribution companies. Different distribution companies thusface the same price for power purchased from the market.7

However, in an environment of power shortage, either through the lack of sufficientcapacity or due to transmission constraints, distribution companies are apprehensiveabout being held to ransom by generation companies and need assurance of powersupply. The bargaining power of the generator is higher in the short term when thedistribution company needs energy to meet its obligations and has little recourse toalternatives. In order to mitigate this uncertainty, distribution companies shouldbe allowed to set up their own generation capacity or be sold bundled together withan existing generation facility.

Alternatively, distribution companies may, at the time of privatisation, be ‘vested’with a contract that allows them to source power from a designated generationfacility, at a pre-specified price, and for a relatively short period such as five years.Such a vesting contract enables the distribution company to have contractual accessto the energy produced by the designated generator in the immediate aftermath ofprivatisation. It also enables easier sale of the generating station by assuring that ithas a ready off-take in the initial years.

2.5.3 Caveat on market structure choices

While making market structure choices, care needs to be taken to ensure that thetiming of these choices is realistic. Excessively zealous targets would only harm theprocess of privatisation. Understandably, private investors would be extremelyreluctant to make the massive investments required in system improvement today,if their consumer base dents too soon and if they are not sure about the terms ofopen access. Similarly, one should avoid a mindless pursuit of the ‘unbundling’doctrine, especially with regard to the existing, well-functioning private licensees,as we might end up wrongly ‘fixing’ what is not broken in the first place. In order toprevent such errors, the proposed Electricity Bill 2000 should permit the existingprivate licensees to maintain their status quo.


2.6 Step 6: Actual sale of the distribution business

At the conclusion of Steps 1 to 5, the following should be in place:

• The SEB has been unbundled into different generation units, a transmissioncompany and different distribution zones, where urban and industrial zoneshave been separated from non-urban zones.

• All commitments arising out of the previous PPAs, including escrowarrangements, are vested with the government and are isolated from the processof distribution privatisation.

• All unfunded liabilities such as dues to power and fuel suppliers and employeepension commitments are retained with the government and arrangementsare put in place to plough-back the proceeds from privatisation to meet thesecommitments.

• A medium-term tariff order from the regulator, specifying a tariff schedule forthe next five years, based, inter alia, on a benchmark profile of reduction inT&D losses.

• The government, in consultation with the regulator, has instituted a mechanismto meet subsidy commitments through explicit budgetary allocations and, ifnecessary, through imposition of a transparent ‘surcharge’.

• A time frame for open access to the transmission and distribution companywires has been announced.

2.6.1 Multiple-round ascending auction for urban and industrial zones

At this stage the zones are ready for bidding. As noted above, the process of saleand due diligence can and should begin earlier. It is however important that thebidding for the zones be conducted appropriately. While it is not the intent ofthis paper to go into details, it should be noted that a single-round sealed bidauction is not necessarily the best option for bidding, since it does not generatesufficient information. An alternative method is the multi-round ascendingauction. In this system, the bidders submit a sealed bid, which is then opened forall bidders. All bidders then have the option of revising their bid upward in thesecond round and resubmitting their bid. This method has recently been proposedby the Telecom Regulatory Authority of India (TRAI) for auctions to allocate thefourth cellular license.

This method makes sense, especially in the current situation with paucity ofinformation, because with each round of bidding new information will be revealed.While each bidder has its own estimates about the kind of investment that will berequired and loss reduction that would be possible, all bidders are also trying toestimate the growth in the market size. The bids of the other bidders give each


bidder some information about their estimates of the growth in the market size,which in turn affects its own estimates in this regard. However, it is important tonote that this may not be true in all situations.8

2.6.2 Minimum subsidy bidding for non-urban zones

As regards non-urban zones, private sector efficiency in delivery can be exploitedby bidding out subsidised zones for supply by private companies and cooperatives,with stringent but realistic improvements in performance parameters as regardsquality of supply, as long as they demand lesser subsidy than what it currently coststhe SEB. This will lead to a further reduction in the subsidy bill. More importantly,isolating these zones would help government in adopting a radically differentapproach to non-urban supply, which has its own special needs.9 Such interventions,for example, could range from allowing distribution through alternative ownershipstructures such as co-operatives to promoting appropriate, decentralised generationoptions such as photovoltaics and micro-turbines.

3. CONCLUSION

In order to be successful, as well as politically feasible, it is essential that consumersbenefit from the process of power sector reform. Concomitantly, the private sectormust be able to earn adequate returns, commensurate with the risks of thedistribution business. Most importantly, this process must take place quickly. Thispaper seeks to provide a set of six specific steps for accelerating this process, whilebalancing these two objectives.

The first step is to notify a policy eschewing new escrows and long-term PPAs. Theyonly add to the troubles of the SEB and make it even more difficult to undertakedistribution privatisation, which is a fundamental reform. The second is to retainthe existing liabilities with the current owner, i.e., the state government. These includeexisting financial and contractual commitments, e.g., past dues to the suppliers ofpower and fuel and existing long-term PPAs and, most importantly, deferredpayments to workers, such as pensions. The proceeds realised by privatising thepower sector, including the sale of generation assets, should be ploughed-back tomeet these retained liabilities. The third step is to separate the distribution segmentof the SEB into distinct urban and non-urban distribution businesses to obtain fullbenefit of private participation and quickly isolate and curb the rampant theft andpilferage in urban areas that is currently camouflaged as subsidised consumption.As opposed to the current practice of hidden cross-subsidy between consumers,government should make explicit budgetary provisions to meet subsidycommitments and, in case of shortfall, it may impose a transparent ‘surcharge’ onurban and industrial zones. The fourth step is to ensure that the regulatory regime


provides sufficient incentive to private entrepreneurs by allowing it to retain profitsearned as a result of improvements in efficiency and bearing of risk. This is bestdone through a medium-term, rather than an annual, tariff determination process.The fifth step is to avoid the single-buyer model and spell out the market structurein terms of the timing of introducing markets for bulk power and choice toconsumers. In order to contain the possible market power of generation companiesowing to supply shortages in the short run, private distribution companies shouldbe allowed to set up their own generation capacity or sold bundled together with anexisting generation facility. Alternatively, they may be ‘vested’ with supply from adesignated generation facility, at a specified price for a short period of five years.Finally, the urban and industrial distribution zones should be sold through a processof multiple-round ascending bid auctions. The non-urban or subsidised zones shouldalso be privatised on the basis of a minimum subsidy bid, through a process designedto attract co-operatives, in addition to large and small private entrepreneurs. Thisentire process can be accomplished within a year, as shown in Table 6.1.

As these steps are intrinsically inter-related, employing them selectively will notyield the intended results. However, taken together, they have the potential totransform our ailing power sector in a short span of two years. Further delay willonly prolong the agony and lead to a slowdown in our overall economic growth.Either we act now or face more blackouts. Frankly, the choice couldn’t be starker!


Tab

le 6

.1: T

imel

ine

for

acce

lera

ted

priv

atis

atio

n o

f di

stri

buti

on

Step

s an

d s

ub-

acti

viti

es1

23

45

67

89

1011

12

1.P

olic

y pr

epar

atio

n (

1 m

onth

)

2.Fi

nan

cial

res

tru

ctu

rin

g (6

mon

ths)

3.D

istr

ibu

tion

zon

ing

(3rd

mon

th) *

◆

4.St

able

reg

ula

tory

reg

ime

4a.

Pre

pari

ng

the

tari

ff s

ubm

issi

on (

4 m

onth

s)

4b.

Med

ium

ter

m t

arif

f su

bmis

sion

(7t

h m

onth

) *◆

4c.

Tar

iff

exam

inat

ion

by

SER

C (

3 m

onth

s)

4d.

Med

ium

ter

m t

arif

f or

der

(10t

h m

onth

) *◆

5.M

arke

t str

uct

ure

: dec

isio

n o

n o

pen

acc

ess

(6th

mon

th)

◆

6.Sa

le o

f dis

trib

uti

on b

usi

nes

s

6a.

EO

I (1

st m

onth

) *◆

6b.

Issu

e of

RFQ

(3r

d m

onth

) *◆

6c.

Subm

issi

on o

f RFQ

(5t

h m

onth

) *◆

6d.

Eva

luat

ion

of

RFQ

(2

mon

ths)

6e.

Issu

e of

RFP

(7t

h m

onth

) *◆

6f.

Du

e di

ligen

ce b

y bi

dder

s (4

mon

ths)

6g.

Fin

al b

id p

repa

rati

on (

1 m

onth

) *

6h.

Au

ctio

ns

(1 m

onth

)

Not

e: E

OI

is E

xpre

ssio

n o

f In

tere

st; R

FQ is

Req

ues

t fo

r Q

ual

ific

atio

n; R

FP is

Req

ues

t fo

r P

ropo

sals

; SE

RC

is S

tate

Ele

ctri

city

Reg

ula

tory

Com

mis

sion

.

*T

he s

ale

proc

ess

proc

eeds

in lo

ck s

tep

wit

h th

e pr

evio

us

step

s in

the

sequ

ence

. The

EO

I ca

n b

e is

sued

as

soon

as

the

polic

y to

pri

vati

se is

ann

oun

ced.

The

RFQ

can

be

issu

ed w

hen

the

zon

ing

is d

ecid

ed a

nd

the

RFP

issu

ed w

hen

the

tari

ff a

pplic

atio

n is

su

bmit

ted.

The

fin

al b

idpr

epar

atio

n c

an b

egin

as

soon

as

the

med

ium

-ter

m t

arif

f ord

er is

issu

ed.


NOTES

1. The disadvantages of the single-buyer model are further elaborated upon later in thepaper, in Section 2.5.

2. Under a medium-term tariff order, part of this recovery of stolen power by the privatedistribution companies and the associated increase in revenue would already have beenaccounted for by the SERC while deciding consumer tariffs and the benchmark T&Dloss reduction profile. Additional reduction in T&D losses, over and above thisbenchmark, would thus result in higher profits for the distribution company, which isprecisely the incentive for the distribution companies to control theft.

3. See Privatisation of Kanpur Electricity Supply Company (KESCO)—A Case Study, preparedby Infrastructure Development Finance Company Ltd, December 2000.

4. Given the perception of supply shortages, one can reasonably assume that a bulk powermarket would witness several price spikes in the initial phase of its operation.

5. Prima facie, while it is possible to de-license generation and institute a merit orderdispatch regime almost immediately, it may not be possible to implement open accessprovisions as quickly, as it requires a reasonably reliable transmission and distributionnetwork and a transparent energy accounting system for its implementation.

6. Revenue losses would be borne by private financiers, who are best equipped to managemarket risks.

7. This is not strictly true, since there may be other products that are traded, such as reservepower. In addition, it may differ at different points of the grid, in case there is a nodalsystem for transmission pricing, which attaches different prices for transmission serviceswhen off-take is from different points of the grid.

8. For example, this method does not make sense for a situation where the bid does notdepend on others’ information, e.g., when a construction contract is awarded. In thiscase, each bidder knows the design and physical inputs required, and forms its ownestimate about the cost. Knowing the bids of other bidders provides no new informationthat can lead to a revision of the bid.

9. Even in the mecca of capitalism, the USA, literally hundreds of cooperatives and smallcompanies are responsible for most of the rural electric supply.


1. INTRODUCTION

The New Exploration Licensing Policy (NELP) introduced in 1997 has givenrise to an increase in proven reserves of domestic gas. The exploration of crudeoil too may turn out to be fruitful. The oil and gas blocks auctioned underNELP I and NELP II have struck gas in significant quantity in the Krishna–Godaveri Basin (K–G Basin) and some private companies have found gas onshorein Rajasthan and Gujarat. Further auctioning of exploration blocks is on theanvil (Box 7.1: New Exploration Licensing Policy). The Directorate General ofHydrocarbons—the regulator of the upstream hydrocarbon sector—has statedon record that there is ample geological evidence that India’s hydrocarbonreserves can increase by two to three times.1 A whole host of technicalinnovations—including 3D seismic imaging, horizontal drilling, deepwaterplatforms, multi-phase pumps, and tertiary recovery techniques—have enabledoil companies to increase exploration success, reduce development costs, boostrecoveries, cut downtime, and improve access to new exploration areas.

A pipeline is a safe, convenient, reliable and environment-friendly mode oftransport for bulk liquids. Several developments in the last fifty years, such asthe use of ‘pigs’ to clean the interior of pipelines, the use of ‘batching’ to transportdifferent petroleum products through the same pipeline, the use of cathodicprotection to reduce corrosion of pipelines, and the use of computers andcommunication technologies to monitor and control pipeline operations, haveseen pipelines emerge as the preferred mode of transport for large volumes ofpetroleum products. It is generally argued that in the relevant economic markets,in which product pipelines seek to meet transportation demand, there is no

REGULATION OF

PETROLEUM PRODUCT

PIPELINES

February 2003

7

Regulation of Petroleum Product Pipelines | 71

effective competition; hence, regulatory restrictions upon the structure andconduct of firms are required to reap benefits for society.

New refineries built after the deregulation of the sector are currently able to meetthe oil product demand of the country. The basis of industry structure of crude/oilproduct pipelines has been primarily to decongest surface transport and tocomplement rail transport. The access control and tariff applicable to pipelinetransportation of oil products is a result of centrally planned development of refinerycapacity, marketing and transportation of oil and oil products.

Box 7.1: New Exploration Licensing Policy

The widening gap between domestic production and consumption of hydrocarbonproducts has put a serious strain on the Indian economy. Keeping in view the risingimport bill of Petroleum Oil and Lubricants (POL), GOI has taken several initiatives toincrease the pace of exploration and secure increasing participation of the private sectorin exploration and production of oil and gas. India has around 3.14 million sq km

of

sedimentary area in 26 basins. Only one-third of this area has been explored so far. Theratio of reserves to production of oil is 17.8 while that of natural gas is 24.5 [BP (2002)].Efforts have been made by the national oil companies and by the Directorate General ofHydrocarbons (DGH) to open up unexplored areas by providing detailed seismic data.

The government liberalised the terms of offer for exploration blocks by unveiling theNELP in 1997. Apart from better terms offered to bidders, an outstanding feature ofthe new policy is that it offers a level playing field to national oil companies and privatesector participants. The new terms offered by the government include the following:

• The possibility of seismic option in the first phase of the exploration period

• No minimum expenditure commitment during the exploration period

• No signature, production, or discovery bonus

• No mandatory state participation

• No carried interest by national oil companies

• Income tax holiday for seven years from start of commercial production

• No customs duty on imports required for petroleum operations

• Biddable cost recovery limit up to 100 per cent

• Option to amortize exploration and drilling expenditures over a period of10 years from first commercial production

• Sharing of profit petroleum, based on pre-tax investment multiple achieved bythe contractor and biddable

• Freedom to contractor to market oil and gas in domestic market

Since 1997, three rounds of NELP have been made, and 22, 23 and 23 blocks have beenallocated under NELP I, II and III respectively. In March–April 2003, another 23 blocks


are likely to be offered under NELP IV. Investments of around US$340 million(Rs 16.25 billion) were made during the first phase of exploration in NELP I blocks tillSeptember 2002. This exceeded the envisaged expenditure of US$250 million(Rs 12 billion). In the second and third phase, the expenditure estimated is aboutUS$913 million (Rs 43.8 billion).

2

Allocation of exploration blocks under NELP I, II and III

Company/consortium NELP I

Reliance Industries & Niko Resources 12

ONGC 5

IOC & ONGC 2

ONGC & GAIL 1

OIL 1

Cairn Energy 1

Total 22

Company/consortium NELP II

ONGC 6

ONGC & consortium 10

Reliance Industries & Hardy Oil 4

Niko Resources 1

OIL 1

GSPC–GAIL–Joshi Tech. 1

Total 23

Company/consortium NELP III

ONGC & consortium 13

Reliance Industries & Hardy Oil 9

GSPC consortium 1

Total 23

Sources: CMIE and media reports

Unlike oil products, pipeline is the only mode of transportation for large quantities ofnatural gas. The Hazira–Bijaipur–Jagdishpur (HBJ) pipeline—the only natural gastransmission pipeline in the country—is owned and operated by Gas Authority ofIndia Limited (GAIL). The gap between the supply and demand of gas, estimated tobe 55 metric million standard cubic metres per day (mmscmd) in ‘HydrocarbonVision 2025’, and the exhaustion of existing gas resources, situated in the western oil


fields, led the government to provide fiscal incentives to import liquefied natural gas(LNG). This in turn guided the development of LNG terminals in the country tosupply regassified LNG through the HBJ pipeline. Natural gas from Bangladesh gasfields, using a trans-national pipeline, will become a reality soon.3 With substantialgas findings in the K–G Basin and a number of LNG facilities being established in thecountry, many issues related to gas pipelines are coming to the forefront. Unlikeindustry nomenclature to use natural gas distinctly and have separate regulation forit, GOI has chosen to define petroleum products to include natural gas and all productsderived from it (Box 7.2: Definition of petroleum products).

Box 7.2: Definition of petroleum products

The definition of petroleum includes natural gas and refinery gas in the PetroleumAct, 1934 (35 of 1934). The same definition is adopted in the Petroleum and MineralsPipelines (Acquisition of Right of User Inland) Act, 1962. The Petroleum RegulatoryBoard Bill 2002 also includes natural gas in the definition of petroleum and theexpression ‘petroleum product’ means any product manufactured from petroleum.Generally, natural gas is recovered from gas lakes along with other hydrocarbons, waterand sand. Natural gas is extracted from this and refined to remove impurities likewater, other gases and sand. In its pure state, natural gas is a complex hydrocarbonvapour. This vapour can be separated or ‘fractionated’ into several components thatmay be utilised as fuels or as raw materials for other products. In India too, C1, C2, C3,C4 and C5 fractions are known by their common names—methane, ethane, propane,butane and other fractions respectively—and used as fuel, feedstock for urea plantsand fuel for power plants, production of petrochemicals, LPG and industrial fuels andsolvent respectively. To all intents and purposes, legal definition of petroleum productspipeline is inclusive of natural gas pipeline.

The purpose of this paper is to critically evaluate the demand and supply scenarioof oil products and gas emerging in the wake of the deregulation of the sector and tosuggest appropriate regulation of the pipeline industry for the benefit of consumers.Our methodology is to focus on the economic characteristics of the pipeline industryand their implications for the design of efficient regulatory policy. Demand forpipeline capacity being a derived demand from the demand and supply of oilproducts and gas, regulatory framework should be convergent with the regulatoryframework of oil and gas.

2. DEMAND AND SUPPLY OF PETROLEUM PRODUCTS

‘Hydrocarbon Vision 2025’ [GOI (2000)] has played a decisive role in thedevelopment of the hydrocarbon sector in the last few years. Its aim was to have afree market and promote healthy competition among players and to improvecustomer services.


2.1 Demand for oil products

Almost all analysis starts with the demand estimates (up to 2025) of theHydrocarbons Group. The report suggested a large gap in the demand and supplyof oil products and assumed an income elasticity of one.4 Table 7.1 gives the supply/demand estimates given in ‘Hydrocarbon Vision 2025’. Almost all official documentsand expert analyses since 2000 refer to these demand estimates.

Table 7.1: Supply/demand—petroleum products (in mmt)

Year Demand (without Demand (with Estimated Estimatedmeeting gas meeting gas refining crude

deficit) deficit) capacity requirement

1999–2000 91 103 69 69*

2001–2002 111 138 129 122*

2006–2007 148 179** 167 173

2011–2012 195 195*** 184 190

2024–2025 368 368 358 364

* Estimates given in the report. Actual crude oil consumption was 86 and 107 mmt respectively.

** Assuming 15 mmtpa of LNG import by 2007 (15 mmtpa = 57 mmscd)

*** Assuming adequate availability of gas through imports and domestic sources

Source: Report of the Group on ‘India Hydrocarbon Vision 2025’ (2000)

The report asserted that the gap will have to be met through imports and an increasein domestic production from the existing oil and gas fields. The report did notassume that the success of the NELP would increase supply of crude oil and gas inthe country. India has installed refining capacity of 115 million metric tonnes perannum (mmtpa) and another 10–15 mmtpa is likely to come on stream byDecember 2004. Detailed estimates of oil products consumption suggest that Indiawill be able to meet all its oil product consumption needs from domestic refineries(Table 7.6: Projections from POL consumption). In FY 2001–02, India consumed100.4 million metric tonnes (mmt) of oil products and had a surplus of 3.8 mmtoil products which were exported. In FY 2003, domestic consumption of oilproducts is estimated to be 103 mmt with a surplus of 5 mmt. The refining capacityis expected to increase to 162 mmtpa by 2008. The demand, on the other hand, isestimated to grow to 128 mmtpa over this period. Refining margin in India isUS$2–3/bbl compared to under a dollar margin elsewhere. Hence, refineries inIndia would prefer to satiate domestic demand before exporting5 [ICRA (2003)].

Historically there has been a strong correlation between Gross Domestic Product(GDP) growth rate and POL consumption due to the large share of the industrial andagricultural sectors. The slowdown in the industrial and agricultural sectors and the


phenomenal growth of the services sector, especially IT-related services, have changedthe composition of the GDP pie. For the past two years, GDP has been growing at5–6 per cent and POL consumption is growing at less than 2.6 per cent per annum.

Figure 7.1: Growth of GDP versus POL consumption

Sources: CMIE and MoPNG (various issues) *Quick estimates

Figure 7.1 suggests that the demand elasticity of POL consumption has declinedrapidly, and in the first half of the fiscal year 2002–03, the demand ofPOL consumption is likely to grow at less than 2.5 per cent compared to a GDPgrowth of 4.4 per cent. The demand estimates for oil products and for gas providedby ‘Hydrocarbons Vision’ are far more optimistic than what the economy canabsorb. Many LNG suppliers, who rushed to construct LNG terminals andregassification facilities, have shelved their plans in the absence of demand frompaying customers, such as independent power producers who abandoned theirprojects (see Table 7.7: List of LNG terminals).

2.2 Regional demand and supply of oil products

The total demand of POL products is not an appropriate indicator of the pipelinecapacity required for different products and of the competitive pressure facedby the pipeline industry. The demand for petroleum products is largest in thenorth and in the west due to the extent of industrialisation and the higherconcentration of vehicles on the road. As against the above demand pattern, themaximum supply of products comes from refineries situated in the western andsouthern regions.

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Figure 7.2: Aggregate supply/demand POL 2001–02Source: India Infoline estimates

Figure 7.2 shows that the northern region is in a state of deficit, the southern andeastern regions are barely in surplus, and the western region alone has substantialsurpluses.6 The mismatch of regional demand and supply requires modes oftransport to bridge the demand and supply gap. The regional disparity is likely tocontinue until refineries in the northern region are able to expand their capacityand a new refinery in the northern region gets constructed.7 The implication for oilproduct pipelines is that pipeline capacity may not be fully utilised at all times andthat demand for oil product pipeline capacity may shrink even though demand forpetroleum product increases in the region.

2.3 Demand for natural gas

The natural gas market in India is supply constrained and the latent unmet demandfor gas has attracted unprecedented attention from the LNG industry after it wasprovided fiscal incentive in Budget 2002. Natural gas in India is an intermediateindustrial product, mainly used by power generating plants and fertilizer plants.

Table 7.2: Supply/demand—natural gas (in mmscmd)

Year Demand

1999–2000 110*

2001–2002 151*

2006–2007 231

2011–2012 313

2024–2025 391

*Estimates given in the report. Actual consumption was 73.6 and 76.8 mmscmd respectively.

Source: ‘Report of the Group on India Hydrocarbon Vision 2025’ [GOI (2000)]

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‘Hydrocarbon Vision 2025’ suggested a surge in the demand for natural gas on theassumption that the power sector would be a large consumer of gas and that thefertiliser industry would substitute natural gas as raw feedstock in place of naphthaafter the deregulation of gas prices in January 2003 (Table 7.2). It asserted that thegap will have to be met from imports, an increase in domestic production, and byswitching to liquid fuels. As against the estimated demand, the present domestic gassupply and consumption is 76.8 mmscmd.

Figure 7.3: Main consumers of natural gasSource: CMIE

The two biggest consumers of natural gas are power plants and fertiliser plants.Approximately two-thirds of the natural gas produced in the country is consumed,in equal proportion, by the power sector and by the fertiliser sector, and theremaining one-third is used by domestic consumers, other industries, the transportsector and by the gas pipeline industry itself. The proportion of other users has beenrising steadily through the nineties (Figure 7.3). It is expected that gas use wouldspread wider into the residential, commercial, small industrial, and transport sectors[GOI (2002a)]. The spatial analysis of gas-based fertilizers and power plants suggeststhat there is a shortage of natural gas in western India, while the demand for gas onthe eastern side is minimal, as there they use coal of which there are large provenreserves in the region. The demand for gas may not pick up if investment in thepower and fertiliser sectors does not materialise due to delay in sectoral reforms. Inthe ‘Report of the Sub-group on Natural Gas Availability’, the MoPNG hasre-emphasised that the power sector and fertiliser demand would drive the gas demandin the country in the foreseeable future. Given such uncertainties of gas demand,

1990–91

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the official estimates of gas demand vary from 135 mmscmd to 231 mmscmd—a large variation for any investor to take the financial risk of investment in gaspipelines (Table 7.3).

Table 7.3: Gas demand estimates of different government agencies

Terminal year ofplan 2006–07

Gas linkage committee allocations +potential demand by existing market 180 mmscmd

Hydrocarbon Vision 2025 231 mmscmd

ADB’s Gas Master Plan 185 mmscmd

Initial assessment by user ministries + other sectors 135 mmscmd

Source: GOI (2002)

Many prospective investors in the power and fertiliser sectors have postponedtheir investment in these sectors because major policy issues concerning theirviability are yet to be sorted out.8 In addition to policy risk, gas demand is sensitiveto the delivered price and the price regime for competing alternatives. In the caseof fertilizers, there could be a ‘make’ versus ‘buy’ option available, and there arestrong opinions for and against the ‘buy’ option. The overall economics of thedomestic production of fertilizers, fertilizer pricing, and other such factors, wouldtherefore need to be addressed in the context of the deregulation of oil and gasprices [GOI (2002)]. In ‘Hydrocarbon Vision 2025’, large gas requirements havebeen projected for the fertilizer sector to augment agricultural production to ensurefood security. In ADB’s study on the ‘Gas Master Plan’, it was observed that itwould be relatively cheaper to buy fertilizer and/or manufacture it abroad andimport to India, rather than manufacture it domestically, based on the highprices of imported gas [GOI (2002a)]. The demand of gas from the fertilizerindustry after the dismantling of subsidies on urea may get stunted if the importof urea is allowed freely. The demand from other industries depends on thelong-term price of gas at the factory gate and not at the land-fall price. Manyindustries can substitute fuel oil and electricity with gas as heating media, onlywhen it is economical.9

The aforesaid discussion shows that natural gas is mainly an industrial productand the future demand of natural gas depends crucially on gas price and on theremoval of subsidies in the fertilizer and power sectors. Gas pipeline capacity,being a derived demand from the gas demand, need not show a secular increasein demand as suggested by various government agencies and face unquantifiabledemand and market risk.


2.4 Supply of natural gas

At present, Oil and Natural Gas Corporation of India (ONGC) and Oil India Limited(OIL) are the main producers of natural gas in India, accounting for almost 98 per centof the gas produced in the country. GAIL is a dominant player in the transportationand distribution sector, accounting for over 95 per cent of the gas sold in the country.

Gas production in the country stood at 27.9 billion cubic metres (bcm) in 2000–01. Thethree main producing basins in the country—the western offshore region, the Cambaybasin in Gujarat, and the Upper Assam region—are in the mature phase of exploration.As per the projections of the Sub-group on Utilisation of Natural Gas constituted underHydrocarbon Vision 2025, domestic gas availability is expected to decline to about16 bcm by 2011–12. Reserves at ONGC’s Gandhar fields are also declining. ONGC hasinformed large consumers that it may not be able to meet their entire requirements.Concerned by the growing gap between demand and supply of gas, the governmentwaived the countervailing duty on LNG in Budget 2002 in order to encourage the buildingof LNG terminal facilities. Several public sector units and private companies haveproposed to construct LNG terminals. An estimated 37.5 million metric tonnes perannum (mmtpa) of LNG terminal capacity has been planned (Table 7.7: List of LNGterminals). The first LNG Terminal at Dahej, owned by Petronet LNG, a PSU under theadministrative control of the MoPNG, is expected to become operational in the year2004. A couple of more LNG terminals may become operational in the year 2005.

In view of the proximity to enormous gas reserves in Iran, Qatar, Bangladesh andBurma, the option of pipeline gas is economically superior to that of LNG imports.10

However, transnational gas pipelines hinge critically on the geo-political situationand hence, the import of gas using pipelines is still a few years away. Keeping theseconstraints in mind, the MoPNG estimated the potential gas supply by 2006–07 tobe approximately 140 mmscmd. Their estimates of gas supply potential between2002–03 to 2006–07 is given in Table 7.4.

Table 7.4: Total gas supply potential—Tenth Plan (in mmscmd)

Source 2002–03 2003–04 2004–05 2005–06 2006–07

Domestic (firm) 71.99 75.73 81.53 78.89 79.80

Domestic (firm + possible) 71.99 77.13 89.67 87.47 85.76

LNG imports – – 20.00 40.00 50.00

Gas imports – transnationalgas pipeline – – – – 10.00

Total (domestic firm + imports) 71.99 75.73 101.53 118.89 139.80

Total (domestic firm +possible + imports) 71.99 77.13 109.67 127.47 145.76

Source: GOI (2002a)


But, the possibility of gas supply from domestic sources has changed considerablyafter the gas findings in the Krishna–Godavari Basin. The in-place volume of naturalgas in D-6 Block of the Krishna–Godavari Basin has been estimated to be in excessof 7 trillion cubic feet (tcf). The recoverable reserves have been estimated to be over5 tcf. Once production begins in two years’ time, 40–50 mmscmd of natural gas willbe added to the current domestic output; in 10 years, production is expected to goup to 100 mmscmd.11 An estimated production of 100 mmscmd in two years’ timeand 150 mmscmd in ten years’ time can only be absorbed if thermal power plantssubstitute natural gas in place of coal as the primary fuel. On the basis of publicannouncements of the exploration companies and DGH’s confirmation, we estimatethe potential gas supply by the year 2006–07 to be as high as 179 mmscmd(Table 7.5). These estimates have not taken into account the gas findings in the Bassein(Vasai) gas field, the K–G Basin, and in Rajasthan by ONGC and Cairn Energy becausethese gas reserves have not yet been certified by a competent authority.

Table 7.5: Total gas supply potential post K–G Basin find (in mmscmd)

Source 2002–03 2003–04 2004–05 2005–06 2006–07

Domestic (firm) 72 75 81 78 79

Domestic (firm + possible) 72 77 129 129 129

LNG imports – – 20 20 50

Total (domestic firm +

possible + imports) 72 77 149 149 179

Another development which is going to have a long-term impact on the supply ofoil and gas is the development of proven reserves of Sakhalin oil and gas fields.These reserves were found in 1970 and are being developed now. Oil majors such asBP and Royal Dutch/Shell group are developing these oil and gas fields.12 Sakhalinoil and gas are going to be important sources of energy for Japan, South Korea andChina. An LNG facility at Sakhalin, having a capacity of 9.6 mtpa, will be the nearestLNG plant to the Japanese, Korean and Chinese market. ONGC Videsh Limitedholds a 20 per cent stake in the Sakhalin-1 project. Production of oil and gas fromthese fields is expected to start in 2005 and in 2008 respectively.

2.4.1Gas prices

The business of gas has three important elements—production of gas, consumptionof gas and pipelines connecting gas fields to consumers. These elements are bondedby ‘delivered’ price of gas to consumers. The price of gas paid by consumers, inturn, has three components—price of calorific value of gas, cost of carrying gasfrom gas fields to consumers including production cost, and statutory levies and


local taxes. It is because of the inflexibility of pipelines as a means of transportationthat investment in pipelines is a sunk cost and pipelines are laid only when produceris assured of gas off-take over a long period of time. The necessity of upfront largeamount of money sunk in gas pipelines to enable gas to reach to consumers has ledto long-term contracts of 25–30 years’ duration between gas producers andconsumers. On the other hand, presence of gas producers in the entire value chain,i.e. exploration and development of gas fields, LNG plants, LNG ships and LNGdegassifcation facilities at consumers’s end has led to reduction in contract periodand development of spot market in LNG.

So far, industry practice has been to link LNG prices to crude oil prices. Japan beingthe largest consumer of LNG, reference price for LNG has been determined withrespect to Japanese Cocktail Crude (JCC) index as Japan used regassified LNG togenerate electric power. The dynamics of crude oil prices is based on revenuemaximisation of OPEC countries and a veiled attempt to dampen development ofalternative energy source such as natural gas (Appendix B). It should be noted thatthe LNG price in Japan has been substantially higher than the US gas prices becauseshipping and insurance cost from Middle East to Japan is included in this price. Inthe US—a significant producer and consumer of gas—the prices of natural gas havenot mimicked the crude oil prices. The natural gas prices have been market-determined and are less volatile compared to crude oil prices (Figure 7.4). The coststructure of natural gas production and of its transportation being different fromthose of crude oil prices, many countries are choosing market-determined rates fornatural gas.13 Hence, in India also, the linking of gas prices with crude oil prices orfuel oil prices is not in the interest of consumers.

Figure 7.4: LNG prices, US gas prices and crude oil pricesSource: BP (2002)

1.0

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2.4.1.1 Gas price scenario in India

The price of natural gas produced by ONGC and OIL are fixed by thegovernment. In 1997, the government linked the landfall price of gas to a basketof international fuel oil prices with the ceiling of Rs 2850/1000 m3. The GasPricing Committee had recommended that natural gas prices be increasedgradually so that they are at par with the import prices of LNG by 2002.The MoPNG was to review recommendations of the Gas Pricing Committee inApril 2000 but it postponed the decision on the revision of natural gas prices.The government was supposed to raise gas prices to 55 per cent, 65 per cent and75 per cent of the basket price in FY98, FY99 and FY00 respectively but did notimplement it. However, with the rise in global prices the landfall prices of gashit the ceiling in October 1999.14 The consumer price along the HBJ pipelinewas fixed at Rs 4000/1000 m3, which included a flat transportation charge ofRs 1150/1000 m3.15 Currently, the city gate price of gas is fixed and the factorygate price includes royalty, taxes and other statutory levies.

2.4.1.2 Gas price post K-G Basin gas discovery

It has been reported that Reliance will price its K–G Basin gas at US$3/mBtu on a‘delivered’ basis. The price of $3/mBtu offered by Reliance is substantially lowerthan the price of naphtha and fuel oil (a sizeable proportion of existing fertilisersand power capacity is based on these) at about US$7–7.5/mBtu and US$5.5–6.5/mBtu respectively. This means that all users, irrespective of their location, willget gas at this price. The corresponding price currently charged by GAIL for supplyof domestic gas from ONGC and other producers in the private/joint sectors isUS$1.9/mBtu to plants at landfall point/receiving on-shore gas, and US$2.5/mBtuto plants along the HBJ pipeline. The local taxes are different in different states andquite substantial in some states. For example, while Madhya Pradesh and Rajasthancharge 4 per cent sales tax on natural gas or LNG, Maharashtra charges 15.2 per cent,Andhra Pradesh wants 16 per cent and Gujarat charges 20 per cent. For importedLNG, Petronet-LNG has indicated that its price (benchmarked to the JapaneseCocktail Crude Index) at the Dahej terminal will be US$4/mBtu.16 At the user point,the price will be higher. The industries located in the ‘hinterland’ may end up payingan amount in excess of US$5/mBtu. Apart from Qatar, Australia, Russia and otherMiddle East countries are ready to supply LNG to India at a competitive price.Piped gas from Bangladesh could, perhaps, match the RIL price. Iran and Burmaare also competing to provide piped gas to India using transnational gas pipelines.

The issue of gas pipelines has been intrinsically linked to ‘delivered’ gas prices.The cornerstone of the success of the NELP is that the companies investing inexploration and development of oil and gas fields are allowed to sell oil and gas at


market price. The regassified LNG also can be sold at market price but the price ofthe gas produced by ONGC and OIL is still controlled. The MoPNG is in favourof deregulating the gas prices but the main user industries—power and fertilizer—have raised serious concerns. It is reported that the MoPNG would have liked toderegulate gas prices and it has proposed to raise the ceiling on gas prices to75 per cent of fuel oil prices by 1 January 2003 (Rs 4300 per mcm) and to 100 per centby 1 April 2003 (Rs 5800 per mcm) before deregulating completely in October 2003.This was not acceptable to user industry ministries and the government constituteda Group of Ministers Committee to recommend gas price.17

The implication of all these developments is that gas prices linked to fuel oil pricesare not in the long-term interest of Indian consumers. The government shouldabandon its existing approach of linking the price of gas to the imported price offuel oil. The pricing of gas should stand on its own, especially when global trade ingas is poised to take a quantum jump. Gas prices locked at US$3/mBtu would leadto supply of electricity at a competitive rate of Rs 2.30 to Rs 2.70 per unit and wouldensure a competitive position on the merit order of most State Electricity Boards.18

Even the fertiliser industry stands to gain substantially when gas prices are allowedto be market-determined [ICRA (2003)].

An important element in this development is that the producers of gas are ready tokeep the city gate price of gas same all over the country. This is at variance fromgovernment thinking of doing away with the flat transportation charge for gasand introducing a new distance-based charge for gas supplied through longdistance pipelines.

From the above unfolding scenario, two issues are important for the gas pipelineindustry. First, there will be a number of suppliers of gas in the country. Second,there will be a keen competition among suppliers to supply gas at competitive ratesand they would like to lock in ‘delivered’ gas price to ensure that investment in thedevelopment of gas fields and the sunk cost in laying of pipelines yield an averagerate of return over its life commensurate with the risks assessed at the timeof investment.

3. ECONOMICS OF PIPELINES

3.1 Crude pipelines

Crude oil is the most important input for any refinery. Crude pipelines are largelyowned and operated by the refinery/oil field owner. The pipeline capacity is in linewith the refinery capacity and, therefore, it is an integral part of the refinery. Thesepipelines are generally not regulated.


3.2 Product pipelines

The traditional methods for inland bulk transportation of petroleum productsinvolve the use of road tankers, rail tank wagons and pipelines. For transportingrelatively small volumes up to 300 km, road tankers are the most cost-effectivemethod, even though their unit cost (ton/kilometre) is the highest among all theabove-mentioned methods. Beyond 300 km, if volumes are good enough for fulldedicated trains, rail tank wagons could be the best solution, provided there is anexisting railway system and it is efficiently managed. When the railway is competentlyoperated, the ton/kilometre cost of using a rail tank wagon is roughly one-half theton/kilometre cost of using a road tanker. Transportation of oil products via pipelinesrequire relatively large initial investments, and generally are attractive only for largevolumes travelling long distances. However, once the initial investment costs areamortized, pipeline transportation offers the cheapest ton/kilometre costs in thelong term because the basic operating cost for the pipeline, without amortizationcosts, is less than one-half the rail operating cost [World Bank (2001)].

Figure 7.5 compares typical petroleum transportation costs for various levels ofthroughput for road, rail, and pipeline modes. As the graph shows, the specifictransportation cost via pipeline decreases with increasing transport volume, whereasproduct transport by road or railway is not dependent on the transport volume.Figure 7.5 also shows that the pipeline option becomes competitive once transportvolumes rise above 700,000 tonnes per year and that with a transport volume ofthree million tons per annum the specific transportation cost of using a pipeline isabout one-fourth the transport cost of using a road tanker.

Figure 7.5: Comparative transportation costs for road, rail and pipeline modesNote: These are economic costs and no margin for profit has been added

Source: World Bank (2001)

Pipeline

Transport volume (1000 tonnes/year)

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ific

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For the pipeline, the amortization of initial capital expenditure has a major influencein determining tariff. Once the debt repayment and capital cost depreciation iscompleted, transportation of oil products by pipeline can provide a competitiveedge. Figure 7.6 shows the specific transportation cost (before and afteramortization of capital cost) for a pipeline (12” diameter). The comparisondemonstrates that even if the cost of preventive maintenance increases, the specifictransportation cost decreases by about 50 per cent as compared to the cost duringthe amortization period.

Figure 7.6: Influence of amortization for a 12” diameter pipelineSource: World Bank (2001)

Clearly transportation of large volumes of oil products favours pipelines whichare fixed point-to-point link; and over a short distance, road tankers, which areflexible link, are economical. In the transportation of products, road tankersare an integral part of the distribution network for any oil company to reachdemand centres.

3.3 Gas pipelines

Gas is usually transported using pipelines. For transportation of gas, transmissionlines are required to transport pressurised gas over long distances and supply lineshaving low pressure are required to supply gas to end consumers.19 Investment isrequired in development of gas pipeline facilities, comprising of high pressure,medium pressure and low pressure system and associated gas compressors,telecommunication system, etc.

Though the economic profile of a gas pipeline is similar to that of an oil pipeline,there are some major disparities between oil and gas pipelines which alter the

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00 k

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break-even point of gas pipelines. First, the unit investment in gas pipelines isthree times that of oil pipelines (without terminal facilities). Second, the lifespan of gas pipelines is at least three times that of oil pipelines. Third, for oilproduct pipelines to work efficiently, a large sum of investments is required interminal facilities including storage tanks whereas gas pipelines are designed totake care of short-term storage requirements. Fourth, gas pipelines consumegas to run gas pumps to push gas down the pipeline and this internalconsumption is accounted as shrinkage. This internal consumption of gas isdirectly proportional to the distance over which gas is to be transported20

[Gardel (1981)].

The sunk cost and longevity of a gas pipeline suggest that the gas pipeline industryis one in which contestability analysis cannot be applied and these sunk costsgenerally deter the entry of a new pipeline. This implies that small gas finds cannotbe commercially exploited and the life of gas pipelines may be longer than the lifeof gas lakes.

4. MAIN ISSUES FOR PETROLEUM PRODUCT PIPELINES IN INDIA

4.1 Oil product pipelines

In India, prima facie pipelines would appear to have a fragmented network ofvarious types, thereby suggesting little planning, if any. However, when onesuperimposes railways and road network on the pipeline network with the volumeof crude/products to be pushed through the transport network, the picturebecomes clearer and the product pipeline network emerges as an integral part oftransport logistics and in congruence with the economics of product pipelines.The basis of the industry structure of crude/product pipelines has been primarilyto decongest surface transport and to complement rail transport. The access controland tariff applicable to pipeline transportation of oil/products is a result of centrallyplanned development of refinery capacity, marketing and transportation of oiland oil products. The current utilisation of oil pipelines is between 50 per cent–60 per cent of the available capacity.21 The main issues in product pipelines areownership, access and transmission charges.

4.1.1 Ownership and access

Under the Administrative Price Mechanism (APM), marketing of petroleumproducts was undertaken only by public sector oil companies and directed by theMoPNG. The existing pipelines owned by different marketing companies used tohave a ‘hospitality arrangement’ to carry products of other refineries. That is, if


refineries had a marketing arrangement with the pipeline operating company,they had access to the pipeline. Post APM, product pipelines are being usedstrategically to deny access to other refiners by the operating company and hencethe issue of access has become important.22 Some pipelines which were productpipelines have been converted into crude pipelines, thus leaving investments inpipelines connected to it, but owned by other operators, stranded.23 Productpipelines generally carry multiple products and, therefore, tap-off points need tohave substantial investment in storage and quality control facilities.

4.1.2Transportation charges

Less economical pipelines (owing to lower volume traffic or demand) were cross-subsidised by pipelines enjoying better economies. Once the asset was created, itwas serviced by the oil pool account administered by the government. Under APM,pipelines complemented the railway network to reach oil products to main demandcentres. Being captive users and the transportation charges being paid from theoil pool account, marketing companies were immune to transportation chargespaid to railways. The POL used to attract the highest rail tariff rate under theAPM.24 But sensing tough competition from the oil pipeline, the railways hasalready begun slashing freight tariff. In some sectors, the railways has reducedrates by 20 per cent or so.25 Post APM, the scenario has changed with transportcharges being paid by the marketing companies26 (see Box 7.3).

The laying of product pipelines needs upfront investment; hence tariff chargesshould be in two parts—capacity charge and user charge. The capacity charge isto cover the fixed cost of laying the pipeline and the user charge is a variablecharge in proportion to the volume of material carried through the pipeline.This second part of the tariff is to cover the operational cost of the pipeline andancillary services.

An oil product pipeline also has business risk. Capacity augmentation of anexisting refinery in a particular region or the construction of a new refinerychanges the demand and supply scenario of oil products in the region. Minorsuppliers of oil products do not want to give a long-term take-or-paycommitment to the pipeline company because the contingent liability of suchproviders increases. A refinery having a dedicated pipeline to evacuate products,however, has the comfort of pre-empting product demand in the region as wellas being able to meet the growing demand of oil products by augmenting thecapacity of the pipeline.


Box 7.3: Impact of OCC on oil product prices

The Oil Coordination Committee (OCC) was a de facto regulator for the oil industry.

The OCC was established in 1975 to implement the elaborate oil pool account

mechanism recommended by the Oil Prices Committee. As the nodal agency for the

sector, key functions of the OCC included administration of pool accounts,

coordination of the transportation of crude oil imports for PSU refineries, inland

distribution of petroleum products, deciding on allocation of crude oil, product pattern

of refineries based on imports, exports and national/regional demands, logistics of

transportation, and other allied matters. Thus, the OCC under the administrative

control of the MoPNG, performed the functions of a planner, coordinator, advisor,

and regulator in the downstream sector.27 The OCC performed its assigned role using

the Administrative Price Mechanism, which ensured

* orderly growth of the oil industry;

* continuous availability of petroleum products to consumers at fairly stable prices;

* continuous availability of crude oil to refiners; and

* achievement of socio-economic objectives of the government.

At the heart of the APM was the oil pool account. This is the account, where the subsidies

and contributions were netted off each other. Under the APM, refined products were

purchased from refineries and transferred to marketing companies. The refineries were

paid at international parity price of the products. The OCC decided the amount

marketed by each marketing company and allowed 12 per cent post tax return on

funds deployed by marketing companies. The oil pool deficit increased substantially

year after year.

The APM had many unintended consequences. Oil product pricing was divorced

from underlying crude prices. The prices of politically-sensitive products did not

reflect the economic costs of the products. Subsidies and cross-subsidies resulted

in a wide distortion of consumer prices and led to wastage of energy. The APM

provided little incentive for improving productivity or efficiency as returns were

guaranteed on the capital employed. Competition was stifled with marketing

companies acting as mere distribution companies. The industry is just trying to

get out of this mindset.

The administrative control of the ministry on utilisation/misutilisation of various

assets can be seen from the following anecdote: The MoPNG would like to ship crude

oil from Revva field offshore Andhra Pradesh to the Bongaigaon Refinery and

Petrochemicals Ltd (using the Haldia–Barauni–Bongaigaon crude pipeline) and bring

the refined products back to the northern region (using Bongaigaon–Barauni product

pipeline). Such a move is being opposed by AP as the crude is used by HPCL’s

Vizag refinery.28


4.2 Natural gas pipelines

In India, natural gas pipelines mainly serve industrial consumers. The transportationof natural gas through pipelines involves significant economies of scale and verylittle inter-modal competition. The nature of natural monopoly of gas transportcalls for a set of regulations not required for oil products pipeline. However, theissues related to gas pipelines are the same as those related to oil product pipelines,namely, ownership, access and transmission charges. The issue of state–centrejurisdiction will get settled when the Supreme Court pronounces judgement on therights of state to pass legislation related to gas.

4.2.1Ownership and access

At present, the HBJ pipeline is the only transmission gas pipeline in the country andall the gas from ONGC’s western gas fields is marketed by GAIL. But, as a numberof LNG terminals come up along the western coast, the issue of access to HBJ pipelinewill become important. Unlike oil product pipelines the tap-off point in a gas pipelinecan be easily provided as natural gas is a homogeneous product and priced on thebasis of energy content.

4.2.2 Transportation charges

Gas uses gas to transport gas and, hence, operational cost of a gas pipeline is a functionof volume of gas and distance over which the gas is to be transported.29 But, in India,gas is sold to users as bundled product where gas is priced according to calorific contentof gas and flat transportation charges. The MoPNG has fixed the transportation chargesas Rs 1150 per thousand cubic metres (tcm) along the HBJ pipeline, with effect from1 October 1997.30 While the transportation charge will remain static until the Groupof Ministers decides on decontrolling gas prices in the country, GAIL will getcompensation for cost escalation directly from the gas pool account.31

In a supply constrained scenario, transportation charges were fixed by the MoPNGto ensure that GAIL does not exploit its monopoly power and at the same timeearns ‘adequate’ return on its investment. In a few years’ time, when there will bemultiple suppliers of gas, a gas transport operator could be exposed to uncontrollablerisk if producers and importers do not supply adequate quantity. On the other hand,if flat transport charges are unremunerative, it would not be keen to increase thepipeline capacity. Long term contracts between producer and consumers mitigatethe supply risk but expose a pipeline company to credit risk.

4.2.3 State–centre jurisdiction

Gujarat is a key state for the gas industry. Besides exploration and production fromthe western onshore and offshore gas fields, Gujarat is the gateway for gas imports


in the country. The state also houses a significant number of large downstreamconsumers. Consequently, the state government passed the Gujarat Gas Act tofacilitate the development of transmission and distribution (T&D) infrastructurein the state. The Act has come in for criticism from the centre and GAIL, and it hasbeen referred to the Supreme Court for its opinion. Maharashtra, Andhra Pradesh,Punjab, Tripura and Assam are also keen to expand gas distribution pipeline networkin their states but they have not shown any inclination to establish a state levelauthority to regulate gas T&D infrastructure.

Potential centre–state areas of conflict relate to access and transportation charges ofinter-state transmission lines.32 National PSUs, such as GAIL, have argued that onecompany regulated by two regulatory authorities may give rise to operationaldifficulty if access code and transportation charges are divergent. For example, agas pipeline built on contract carriage principle cannot function on open carrierprinciple (see Box 7.4: Contract carrier versus common carriage carrier).

Box 7.4: Contract carrier versus common carriage carrier

Contract carriers are only obligated to provide service for those who have contractedfor their services. Under contract carriage, individual transmitters need to provideadditional facilities only where users are willing to sign firm contracts for their use. Inthe case of existing facilities, transmitters are required to provide transmission servicesup to the extent of any spare capacity. This means that system development generallytakes place in response to demand from users, and this in turn facilitates the financingof new developments. The users pay for capacity on pipelines and receive in return adefined set of rights enshrined in a contract. These rights set out in these contractscannot, in general, be undermined by later developments outside the control of thecontracting parties.

The main advantage to construct a pipeline on contract carrier principle is that thepipeline company is paid for capacity and demand risk is shifted to users. Capacity isbuilt in line with the committed demand and this eliminates financial risk attached tobuilding overcapacity. Regulatory risk is also limited as contracts define transportioncharges. The disadvantage under this system is that the producer has captive consumers,thus, reducing the choice which consumers may get in future.

Common carriers are obliged to render service to all comers on a non-discriminatorybasis and have the responsibility to reasonably anticipate future demand for theirservices. If the regulator feels that the transmitter is underestimating future needs, hemay require that the transmitter put up pipelines with adequate capacity. Thetransmitter would, of course, have the right to recover all costs and earn a reasonablerate of return on all authorised assets. Mandatory open access means that the regulatorshould have the power to ensure that any spare capacity in a pipeline be offered on a


non-discretionary basis to anyone who wishes to make use of that capacity. Theregulator should also have the power to provide interconnection between existing andother pipelines.

The key features of common carriage are that while transmission is provided on an ‘asrequired’ basis, users are not committed to long-term use-of-system contracts. Thismeans that the transmitter must construct additional capacity to cope with allanticipated demands for its services. The transmitter, therefore, has significant demandforecasting and investment obligations.

The main advantage is to producers and consumers as they do not have to pay orcommit for the pipeline capacity. A consumer has a choice to use an alternative supplierof the product. In the absence of committed consumers, producers are reluctant tosign take-or-pay contract which increases financing risk. Under the open carrier system,a regulator determines transportation tariff and he needs detailed capacity utilisationand financing cost to determine the tariff. Additionally, the regulator can force the

pipeline owner to increase the pipeline capacity if he feels that the capacity is inadequate.

5. POLICY AND REGULATORY DEVELOPMENTS

Instead of having separate regulatory authorities for natural gas and the downstreampetroleum sector, the MoPNG, on recommendations from user ministries, hasdecided to have a single authority in the country for the natural gas and downstreampetroleum sector.33

A bill to constitute a downstream petroleum regulatory board was introduced inthe Parliament on 8 May 2002, and has been referred to the Parliamentary StandingCommittee on Petroleum and Chemicals [GOI (2002b)]. The Bill would be tabledin Parliament as soon as the Standing Committee approves it. In the interim period,the union government will continue to act as the regulator.34

5.1 The Petroleum Regulatory Board Bill, 2002

The proposed bill is to provide for the establishment of a Petroleum RegulatoryBoard to regulate the refining, processing, storage, transportation, distribution,marketing and sale of petroleum and petroleum products excluding the productionof crude oil and natural gas. The purpose of the bill is to promote competitivemarkets.

The salient features of the bill related to petroleum product pipelines areas follows:

• The bill will authorise the central government to constitute a single authorityfor the downstream petroleum sector for the entire country.

• The regulator will have authority over new, as well as existing, pipelines.


• The regulator would regulate gas and oil product pipelines which have beenlaid on common carrier principle. Captive pipelines and crude oil pipelineswould not come under its purview. New pipeline owners/operators would haveright of first use.

• In practice, pipelines will be laid on ‘modified’ contract carriage principleand existing owners and operators of pipelines would keep the right of firstuse. Only that capacity which is not being used would come under commoncarrier principle. Even expansion of capacity will carry the right of first use(see Box 7.4: Contract carrier versus common carriage carrier).

• The regulatory body would have powers to declare a pipeline as commoncarrier, and to authorise laying, building, operating or expanding a pipeline ascommon carrier, or for establishing a liquefied natural gas terminal, or formarketing notified petroleum and petroleum products.

• Before declaring a pipeline common carrier, the owner would be given a properhearing and fix the term and conditions subject to which the pipeline is to bedeclared as a common carrier. The entity laying, building, operating orexpanding a pipeline shall have the right of first use.

• The authority would permit pipeline-on-pipeline competition and inviteopen offers.

• The regulator would have powers to regulate any distribution or marketingcompany.

5.2 Guidelines for laying petroleum product pipelines

The Ministry of Petroleum and Natural Gas has notified a new policy for layingpetroleum product pipelines in the country through the Gazette of IndiaExtraordinary dated 20 November 2002 [GOI (2002c)].

The salient features of the Guidelines are as follows:

• There would be three categories of petroleum product pipelines, namely,(i) pipelines originating from refineries upto a distance of around 300 km;(ii) captive pipelines, originating either from a refinery or from an oilcompany’s terminal, of any length; and (iii) pipelines exceeding 300 km inlength and pipelines originating from ports. Category (i) and (ii) pipelineswould be for the exclusive use of the proposer company and owned by thecompany. Any legal entity can propose and own a category (iii) pipeline.Three-fourths of the designed capacity of a category (iii) pipeline would bereserved for the owner and ‘take or pay’ contracts and only one-fourth ofthe designed capacity would be made available for use by anyone at agovernment-approved tariff.


• Through this notification, the government has taken away the monopoly ofPetronet India Limited for laying product pipelines in the country.

• ‘Contract carriage principle’ has effectively replaced the ‘Common carrierprinciple’ for pipelines.35

• The authority to grant right of use inland, i.e. to give license to lay a pipeline,will remain with the ministry.

• The Guidelines have a sunset clause. The regulatory functions of productpipelines will be passed on to the regulatory board constituted under thePetroleum Regulatory Board Bill 2002.

Through the bill and the guidelines, the government has tried to address the issuesof investment efficiency and operating efficiency, and tried to make the pipelinesbankable. The government has recognised that pipeline developments are long-term investments, reliant on market growth for their viability. As a consequence,returns are likely to be poor during the initial years of a project. For a project toproceed and to attract investment in the sector, the estimated average rate of returnof the project over its life must be commensurate with the risks as assessed at thetime of the investment. The government recognised the nature of these risks andtheir consequences and, thus, came out with the bill and further liberalised thesector through the guidelines.

Among the classes of risk that face the developer of a pipeline project in India,credit risk, market risk and regulatory risk predominate. All these risks have asignificant effect on the investor’s assessment of project viability.

The current level of credit risk is high and it needs to be mitigated and theguidelines have given a free hand to developers to manage captive pipelines aswell as pipelines upto 300 km in length. The investor expects to accept marketrisk along with construction, technological and general economic risks. Marketrisk is about whether sufficient load will materialise to make the project viable.For a greenfields project, there are two sources of load—first, penetration ofthe existing available market, i.e. the conversion of existing consumers to alternatefuels; and second, generation of new demand from new consuming businessesto the region.

The bill and the guidelines have been able to take care of the market risk and creditrisk; but the bill, which has introduced regulatory risk emanating from the regulator’spower to declare a pipeline as a common carrier, should be addressed by thegovernment and the regulatory authority.


6 . THE WAY FORWARD FOR PIPELINE REGULATION

A regulatory environment must be created to encourage pipeline infrastructuredevelopment and make an allowance for efficient market growth. The PetroleumRegulatory Board Bill 2002 is clear that there will be a single regulatory authority toregulate downstream oil and natural gas sector. As and when the bill becomes an Act,the government should establish a regulatory authority for the downstream petroleumsector under the Act which has power to regulate petroleum product pipelines.The ‘Guidelines to Lay Petroleum Product Pipelines’ has further liberalised the pipelinesector and the sunset clause in the guidelines ensures that the authority to regulatepipelines is automatically transferred to the regulator established under the Act.

The following major tasks in the pipeline industry should be addressed bythe regulator:

• Introduce distance-based transportation charges for natural gas. This wouldensure that small onshore gas fields are viable and have access to the gaspipeline network.

• The regulator must distinguish transmission gas pipelines from distributionand supply gas pipelines. Although, at present there is only one supplier of gasin metropolitan cities, the scenario could change rapidly if new suppliers ofgas enter the distribution business. The distribution and supply pipelines shouldbe licensed on open access principle right from the beginning to ensure thatretail household consumers and the transportation sector is able to choose thesupplier of gas at a later date. The gas supply companies must be asked tomaintain separate accounts to show the cost of energy and cost of supplyand distribution.

• The regulator should encourage a secondary market in the product pipelinecapacity as the market matures.36

In pipeline regulation, there are two issues which need to be addressed to mitigateregulatory risk. First, the possibility of mandated access adds to the regulatory riskfor investors and the pipeline owner. If the terms and conditions of any mandatedaccess are perceived as likely to be unduly favourable to the access seeker, theattractiveness of investment will be reduced. Regulatory risk can be reducedsignificantly if the regulatory rate of return were indicated for the life of the projectat its inception on the basis of the risks as assessed at that time.

Second, to give right of use still remains with the central government and from thisauthority the government derives the power to license a petroleum pipeline [GOI(1962)]. This power should be vested in the regulator so that the regulator has enoughteeth to ensure that interconnection and the power to declare a pipeline a ‘commoncarrier’ can be enforced.


7. CONCLUSION

The petroleum product market is enjoying the fruits of economic deregulation setin motion in 1991. Private sector investment in oil refineries has resulted in asubstantial increase in refining capacity in the last two years and the country isrunning a surplus of refined oil products. Post the dismantling of APM, thetransportation of oil products, which was overlooked earlier, has acquiredimportance. The failure of Petronet India Limited (PIL) to achieve financial closurehas led the government to change its regulatory practice of petroleum productpipelines. The ‘Guidelines to Lay Petroleum Product Pipelines’ has taken away PIL’smonopoly over laying new product pipelines and new pipelines can be constructedby anyone using a ‘modified’ contract carriage principle rather than being compelledto adopt the common carrier principle. The modification in the contract carrierprinciple is that one-fourth of the designed pipeline capacity should be made availableon open carrier principle.

The natural gas market in India is in transition as it attempts to move from a fullycentralised, government-controlled business to one that relies increasingly uponreduced government controls and a more market-responsive pricing climate toencourage foreign and private investment in upstream exploration and developmentof oil and gas. Natural gas pipeline projects are built on trust because nearly all ofthe cost is incurred at the beginning and the revenues come only over the nextcouple of decades, usually from long-term contracts signed with gas users. Pipelineconstruction and development of gas fields is undertaken only after these contractsare signed. The Petroleum Regulatory Board Bill 2002 and the ‘Guidelines to LayPetroleum Product Pipelines’ have addressed some of these issues.

The scenario which may become a reality in a couple of years’ time is the supply ofgas from multiple sources using different processes having different cost structures.In such circumstances, gas pipelines have been allowed to use contract carriageprinciple as well as to lay captive pipelines. The driving force to use pipelines will bethe sunk cost and long-term contracts with the users.37 Captive gas transmissionpipelines would not be regulated. The distribution and supply gas pipelines arebeing laid by individual gas companies and should be licensed on open-carrierprinciple right from the beginning to allow choice at a later date to retail consumersand to the transport industry. Only a few metropolitan cities have started to havepiped gas for domestic use and it faces competition from bottled LPG gas which isa ‘notified’ product and would continue to be subsidised for some more time. ThePetroleum Regulatory Board Bill provides adequate power to regulate access andthe price of gas, and to regulate distribution companies and ‘notified’ products.The gas distribution and supply pipeline regulation is going to remain in animated


suspension until the issue of centre–state jurisdiction over gas is decided by theSupreme Court.

We have critically examined the Petroleum Regulatory Board Bill 2002 and the‘Guidelines for Laying the Petroleum Product Pipelines’ which have addressed theissue of investment and operational efficiency and also made pipelines investmentbankable. The government should get the bill through Parliament and constitute apetroleum regulatory authority. The new guidelines point towards a great deal ofreliance on market forces to discover product prices and transportation tariffs.Oil product pipelines already face strong competitive pressures from other modesof transportation—such as trucking and railways.

In order to create a regulatory environment which encourages pipeline infrastructuredevelopment, the authority should provide an indicative rate of return for the lifeof the project at the time of granting right of use to mitigate regulatory risk.The authority to acquire land under the Petroleum and Minerals Pipelines(Acquisition of Right of User Inland) Act, 1962, should also vest in the regulatoryauthority in order to unify all regulatory and licensing powers in one authority.


APPENDIX ATable 7.6: Projections for POL consumption 2001–2008 (in ‘000 metric tonnes)

2001 2002 2003 2004 2005 2006 2007 2008

LPG 7021 7583 8189 8844 9552 10316 11141 12033

MS 6625 7138 7692 8288 8930 9622 10368 11171

SKO 11295 11323 11606 11896 12194 12499 12811 13131

HSD 38203 37439 38188 39906 41901 43997 46196 48506

ATF 2234 2301 2370 2441 2514 2590 2668 2748

FO/LSHS 12645 12930 13220 13518 13822 14133 14451 14776

Lubes 1027 1053 1079 1106 1134 1162 1191 1221

Bitumen 2677 2784 2895 3011 3132 3257 3387 3523

Others 6266 6391 6519 6650 6783 6918 7057 7198

Total 102000 102956 105780 109689 113997 118536 123319 128363

Overall growth rate % 0.9 2.7 3.7 3.9 4.0 4.0 4.1

Source: India Infoline Estimates

Table 7.7: List of LNG terminalsLocation Capacity (mmtpa) Promoter

Dahej (Gujarat) 5.0 Petronet LNG (January 2004)

Ennore (Tamil Nadu) – Petronet LNG

Mangalore (Karnataka) – Petronet LNG

Kochi (Kerala) 2.5 Petronet LNG

Vizag (Andhra Pradesh) 2.0 Total/HPCL

Trombay (Maharashtra) 2.5 Total/Tata Electric (shelved)

Pipavav (Gujarat) 2.5 BG/Gujarat Pipavav Port (shelved)

Dabhol (Maharashtra) 5.0 Enron (suspended)

Ennore (Tamil Nadu) 2.5 TIDCO/Unocal (shelved)

Kakinada (AP) 2.5 CMS Energy/Unocal/GVK Industries

Kakinada (AP) 2.5 IOC/Petronas/BP

Hazira (Gujarat) TBA Mobil/Gujarat Maritime Board

Hazira (Gujarat) 5.0 Reliance/Elf Aquitaine

Hazira (Gujarat) 2.5 Shell/Essar (proposed)

Total 37.5

Source: Petroleum Economist (December 1997), media reports


Table 7.8: List of crude pipelines

Pipeline Length (km) Capacity (mmtpa) Owner

Nahorkatiya–Barauni 1156 5.5 OIL

Salaya–Mathura 1881 21.0 IOCL

Ankleshwar–Koyali 95 2.0 ONGC

Kalol–Navagam–Koyali 127 2.0 ONGC

Bombay High–Uran (offshore) 203 15.0 ONGC

Haldia–Barauni 506 4.2 IOCL

Total 3968 49.7

Source: IOC Presentation, Seminar on Pipelines (2000)

Table 7.9: List of gas pipelines

Name Length (km) Owned by

Trunk Lines

Hazira–Bijaipur–Jagdishpur 2300 GAIL

Goa–Sangli–Hyderabad– ~1300 Gas TransportationVijayawada–Kakinada; Spurs to (proposed) and Infrastructure Co.Mumbai and Chiplun (Phase I) Ltd (Reliance)

Vijayawada–Chennai–Bangalore – GTIC (Reliance)–Kayamkulam (Phase II)

Mumbai–Delhi–Kolkata– ~6400 GAILChennai (proposed)

Dahej–Hazira–Uran ~600 GAIL(proposed)

Distribution lines

Paguthan–Vadodra 68 Gujarat State Petronet Ltd

Vadodra–Ahmedabad 85 Gujarat State Petronet Ltd(proposed)


Table 7.10: List of refineries

Owner Capacity as of December 2001 (mmt)

IOC, Guwahati 1.00

IOC, Barauni 4.20

IOC, Koyali 12.50

IOC, Haldia 3.75

IOC, Mathura 7.50

IOC, Digboi 0.65

CPCL, Manali 6.50

CPCL, Nasimanam 0.50

BRPL, Assam 2.35

IOC, Panipat 6.00

IOC, Gujarat 3.00

BPCL, Mumbai 6.90

KRL, Kochi 7.50

NRL, Assam 3.00

HPCL, Mumbai 5.50

HPCL, Vizag 7.50

MRPL, Bangalore 9.60

RPL, Jamnagar 27.00

Total 114.95

Table 7.11: List of oil product pipelines


Guwahati–Siliguri 435 0.82 IOCL

Koyali–Ahmedabad 116 1.10 IOCL

Barauni–Kanpur 669 1.80 IOCL

Haldia–Barauni 525 1.25 IOCL

Haldia–Mourigram–Rajbandh 277 1.35 IOCL

Mathura–Jalandhar 526 3.70 IOCL

Kandla–Bhatinda* 1443 7.50 IOCL

Digboi–Tinsukhia 75 0.73 IOCL

Bombay–Pune 161 3.67 HPCL


Mumbai–Manmad 252 4.33 BPCL

Vizag–Vijayawada 356 4.10 HPCL

Vadinar–Kandla 113 11.50 PIL

Jalandhar–Udhampur 233 – IOCL

Koyali–Sidhpur – – IOCL

Mangalore–Hassan–Bangalore 332 4.20 HPCL/PIL

Chennai–Trichy–Madurai 505 1.40 IOCL/PIL

CIPL (Jamnagar–Rajkot– 1760 – RPL/IOCL/Koyali–Ratlam) PIL(shelved)

Paradeep–Rourkela – 5.00 IOCL/PIL

Jamnagar–Bhopal (Phase I) ~2500 – GTIC(Reliance)

Bhopal–Raipur–Cuttack– (proposed) –Kolkata (Phase II)

Chennai–Bangalore – – RIL (proposed)

Total 4935 41.94

* Being converted into a crude pipeline

Source: IOC Presentation, Seminar on Pipelines (2000), media reports

Table 7.12: List of ports handling oil/petroleum products

Category Ports

Crude oil Salaya (Gujarat), Jamnagar (Gujarat), Mumbai, Mangalore,Kochi, Chennai, Vizag, Haldia

Petroleum products Kandla (Gujarat), Okha (Gujarat), Mumbai, Goa, Mangalore,Kochi, Tuticorin, Chennai, Vizag, Paradeep, Haldia, Port Blair

Table 7.11: List of oil product pipelines (contd...)



APPENDIX BCrude oil price web and natural gas prices

Apart from price spikes during brief political and economic crises, oil prices, sincethe early 1970s, have tended to move closely in line with OPEC producer capacityutilisation. Significant price increases have generally occurred when OPECproduction exceeds 90 per cent of capacity utilisation (roughly 28 to 30 millionbarrels per day). When utilisation is high, prices stay higher. When utilisation falls,producers have been unable to sustain high prices.

OPEC is crumbling now and OPEC producers have realised that substantially higherprices are not in the producers’ long-term interests. Major Middle East producershave tried to follow a strategy of maintaining moderate prices and high marketshare that will maximize their returns over time. This strategy has allowednon-OPEC economies to grow and prosper, whereas excessive energy prices haveled to reduced economic activity and lower oil consumption. It also discourages anumber of activities that run counter to OPEC interests: oil conservation and thesubstitution of alternative energy sources; synthetic fuel research and LNGdevelopments; tertiary recovery with tax and fiscal incentives; and exploitation ofnon-conventional hydrocarbons (heavy oil, oil shale, deepwater oil, and sources inArctic or near Arctic regions). A price of US$25 per barrel (in 1994 prices) isconsidered to be optimal and US$20 per barrel discourages oil conservation andsubstitution of alternative energy resources. [Conn and White (1994)]. Equivalentgas prices are in the range of US$3–4 per mBtu.

Figure 7.7: OPEC supply/price dynamics

Source: Oil Industry Outlook, BP Statistical Review 2002

0

10

20

30

40

50

60

15 20 25 30 35Crude oil production (Mbbl per day)

Pri

ce (

US$

per

bbl

in 1

994

pric

es)

1970 71 7273, 98

747576

7778

79

8081

82

838485

86

87

8889

90

9192 93

94, 95

96

9799

200001 02


APPENDIX CBox 7.5: Main conversions used in the petroleum industry

Crude oil

1 tonne = 7.33 barrels= 1.165 cubic metres (kilolitres)

1 barrel = 0.136 tonnes= 0.159 cubic metres (kilolitres)

1 cubic metre = 0.858 tonnes= 6.289 barrels

1 million tonne = 1.111 billion cubic metres natural gas= 39.2 billion cubic feet natural gas= 0.805 million tonnes LNG= 40.4 trillion British thermal units= 0.805 million tonnes LNG

Natural gas

1 billion cubic metre = 35.3 billion cubic feet natural gas= 0.90 million tonnes crude oil= 0.73 million tonnes LNG= 36 trillion British thermal units= 6.29 million barrels of oil equivalent

LNG

1 million tonne = 1.38 billion cubic metres natural gas= 48.7 billion cubic feet natural gas= 1.23 million tonnes crude oil= 52 trillion British thermal units= 8.68 million barrels of oil equivalent

Source: BP Statistical Review of World Energy 2002

NOTES

1. India, which imports 70 per cent of its energy requirement, is projected to have the capabilityof producing up to 3 per cent of the world’s oil and gas output, with a sedimentary basinregion of around 5.37 per cent, in the coming few years. In the year 2001, India produced36.1 million tonnes of crude oil (1per cent of world output) and 26.4 billion cubic metresof natural gas (1.1 per cent of world output). Compared to this, India’s proven reserveswere reported to be 0.62 billion tonnes oil and oil equivalent gas (O+OEG) [BP (2002)].The Directorate General of Hydrocarbons (DGH) has informed the Petroleum Ministrythat India’s prognostic hydrocarbon resources are about 28 billion tonnes of O+OEG.After the recent discoveries in the Krishna–Godavari deepwater area, the resources couldgo up by another 4 billion tonnes (Business Standard, 25 February 2003).


2. This information was given by the Union Minister for Petroleum and Natural Gas,

Shri Ram Naik, to the Parliamentary Consultative Committee (Infraline,

24 February 2003).

3. US energy giant Unocal has offered to sell piped natural gas from Bangladesh to markets

in northern India at US$3.5–4.5 per million British thermal units (mBtu). The landed

cost of Bangladesh gas in Delhi would be between US$3.5 and US$4.5 per mBtu,

compared to the subsidised current natural gas price of US$2.5–2.7 per mBtu (Business

Standard, 10 December 2002). Bangladesh is looking for export of around 500 million

cubic feet of gas per day. A proposal approved by Bangladeshi Prime Minister, Begum

Khaleda Zia, in February 2003 is expected to be presented in the Parliament soon for

ratification. The ruling four-party coalition government has a comfortable number of

seats in the houses to get the proposal through (Infraline, 18 February 2003).

4. The report did refer to change in industry structure in India and suggested that the

income elasticity may reduce to 0.7 by the year 2025 [GOI (2000)].

5. ‘Industry Experts Look at Downstream Future in Hydrocarbon Processing’ (January

2003) published by Gulf Publishing Company.

6. This should not surprise anyone because as a crude oil importing country it is

advantageous to have refineries in the coastal region. Incidentally, three out of four

major metropolitan cities have major ports which are served by oil tankers.

7. The IOC refinery at Panipat is going to expand its capacity from 6 mtpa to 12 mtpa by

2004. HPCL’s Bhatinda refinery and BPCL’s Bina refinery will take 6–7 years to come

on stream. Reliance is likely to expand capacity of its Jamnagar refinery from 27 mt to

37 mt in two years time. BPCL’s Mumbai refinery expansion from 8 mtpa to 12 mtpa is

expected to be completed in FY05.

8. The new domestic gas finds or more such discoveries in the future would not in any

significant way diminish the prospect of import of piped gas or LNG. Demand for gas

will grow in the country from 110 million standard cubic metres per day (mmscmd) in

2001–02 to 145 mmscmd in 2006–07, 225 mmscmd in 2011–12 and to 325 mmscmd in

2019–20, according to GAIL estimates. These estimates are modest compared to the

estimates given in Table 7.3.

9. India will continue to remain a net deficit country in natural gas production despite

the discovery of world-class gas reserves off the east coast according to the Minister of

State for Petroleum and Natural Gas, Santosh Kumar (written reply to the Lok Sabha,

12 December 2002).

10. Sale of condensate, a by-product of gas extraction, has reduced the breakeven point

of Qatargas landed in Japan to US$13.6/bbl. After adding around US$3/bbl

for regassification cost, the cost of gas could be approximately US$17/bbl or


<US$3 per mBtu in Japan (editorial in Pipeline and Gas International, May 1999).

It should be lower in India if imported from Qatargas and can compete with

imported pipe gas.

11. The reserves are estimated to be 9 tcf by DGH (Times of India, 25 February 2003 and

Hindustan Times, 20 November 2002).

12. Wall Street Journal (10 February 2003 and 2 December 2003), Far Eastern Economic

Review (30 January 2003).

13. At present, gas prices are as low as US$0.4/mBtu in North Africa to US$3.15/mBtu in

the US. In Western Europe prices are US$3/mBtu, and in Russia, Venezuela and the

Middle East prices are US$0.5–0.6/mBtu.

14. The concessional price for gas-based industries in the Northeast also rose to

Rs 1700/1000 m3.

15. Gas prices pertain to a calorific value of 10000 kcal/1000 m3 and the gas transported

by GAIL has a calorific value of 9000 kcal/1000 m3, thus consumers in effect pay

10 per cent less.

16. This will reduce marginally by US$0.10/mBtu after the reduction in import duty from

20 per cent to 5 per cent announced in Budget 2003–04.

17. Business Line, 30 January 2003.

18. Infraline, 30 January 2003 and GoM (2001).

19. Gas for Delhi and Mumbai transport need are catered to in batch mode using a bundle

of high pressure cylinders. The transport sector is allocated <3% of total gas allocation

in India.

20. In 1999–2000, shrinkage in internal consumption accounted for 7% of the total gas

consumed in India [GOI (2002a)].

21. The Financial Express, 3 October 2002.

22. The government rejected Reliance’s plea for being allowed to use public sector oil

companies’ infrastructure to sell jet fuel (Aviation Turbine Fuel) saying it does not fall

under the common carrier principle (Economic Times, 12 November 2002).

23. IOC is converting Kandla–Bhatinda pipeline to carry crude oil. It will transport only

crude oil through the Kandla–Panipat section of the Kandla–Bhatinda pipeline from

July 2004. At present, it carries both crude and petro-products from IOC’s Koyali and

Reliance’s Jamnagar refineries. Petronet has informed the MoPNG that IOC’s plan would

make its Rs 383-crore Vadinar–Kandla product pipeline unviable. Petronet’s project

was conceived on the assumption that the Kandla–Bhatinda pipeline would be available

for transporting products of Reliance and Essar refineries.


24. For petrol and HSD, ‘class’ for wagon load has been reduced from 300 to 250, and for

crude and gas it has been reduced from 270 to 250 in the Railway Budget 2003–04.

Reducing the class leads to lesser freight rates. Carrying petroleum products on the

Railways will now be 10.7 per cent cheaper (Business Standard, 27 February 2003).

25. The Economic Times (23 October 2002).

26. The government would continue to provide freight subsidy in far-flung areas in the

north and east regions, but the quantum of sales in these region is very less.

Bongaigaon Refinery and Petrochemicals Ltd, having an installed capacity of

7 mtpa, is working below capacity as crude availability from Assam oil fields is pegged

at 5 mtpa.

27. The Directorate General of Hydrocarbons (DGH) was established under the

administrative control of the MoPNG in 1993 to manage Indian petroleum and gas

resources. The DGH acts as a regulator for reservoir management of oil and gas fields;

monitors public service centres on behalf of the Government of India; and acts as a

project facilitator, assisting companies to get clearances/approvals from various

ministries. One may simply call him an upstream hydrocarbon sector regulator.

28. The Business Standard (25 December 2002).

29. In 1999–2000, gas losses due to shrinkage were 7 per cent [GOI (2002a)].

30. GAIL’s charges along non-HBJ pipelines are significantly lower (Rs 165/tcm).

These pipelines, which were primarily transferred from ONGC in the fiscal year 1993,

operate on cost plus margin basis.

31. Under the existing pricing mechanism, Rs 350 accrued to the gas pool for every ‘000 m3

of gas sold. This money is collected by GAIL and is shown as a liability on its balance

sheet. At the end of the fiscal year 1997, the gas pool account was Rs 11.3 billion in

surplus. The gas pool money is supposed to subsidise gas consumption in the states of

the Northeast. However, low consumption in these areas results in relatively small outflow

from the gas pool.

32. The Gas Authority of India (GAIL) has finally started work on the Rs 26 billion,

600 km Dahej–Vijaipur gas pipeline. It hopes to complete work on the pipeline by

April 2004. For months, the Gujarat State Petroleum Corporation Limited (GSPCL)

had tried to block GAIL’s plan to lay this 600 km pipeline from Dahej to Vijaipur to

carry regassified LNG from the Dahej terminal to customers on the HBJ. GSPCL had

argued that GAIL had no right to build pipelines in the state (The Economic Times,

February 23, 2003). Even after the passing of almost two years, Gujarat State Petronet

is still waiting for the bidders to finalise their bids to pick minority stake in a gas grid

promoted by its subsidiary Gujarat State Petronet Limited (GSPL). Gujarat State

Petroleum Corporation (GSPC) is offering 49% equity of GSPL for sale with a cap of


11 per cent on each equity holder. GSPC wants to retain management control.

The reports say that pending clarity on the constitutional validity of the Gujarat Gas

Act, none of the interested parties–Shell, British Gas, GAIL, Indian Oil, Bharat

Petroleum and KRIBHCO—are ready to commit anything. Also, the Supreme Court

is yet to pronounce judgment on the rights of the state to pass legislation related to gas

(Infraline, 18 February 2003).

33. The rationale for having the Gujarat Gas Act according to the state government has

been that the item ‘gas and gas works’ figures in the State List of the Constitution.

The item ‘gas and gas works’ pertains to synthetic and industrial gas and does not relate

to natural gas. The central government is of the opinion that natural gas is part of mineral

oils, which is under the Central List. The issue of centre–state jurisdiction would be

settled after the Supreme Court has given its opinion on this issue to the government.

34. Business Line, 22 January 2003.

35. Gas Transportation and Infrastructure Co. Ltd—a subsidiary of Reliance India Ltd—

has been given permission to acquire land under the Petroleum and Minerals Pipelines

(Acquisition of Right of User Inland) Act, 1962, to lay a gas pipeline for Goa–Hyderabad–

Kakinada and an oil product pipeline for Jamnagar–Bhopal (Government of India,

Ministry of Petroleum and Natural Gas, Lok Sabha, starred question no. 2763, answered

on 5.12.2002). Reliance intends to extend the Jamnagar–Bhopal oil product pipeline to

Kolkata passing through Raipur and Cuttak. The pipelines are expected to be ready by

the end of 2004 to supply gas from the K–G Basin to users in Andhra Pradesh,

Maharashtra and Goa and to evacuate oil products from the Jamnagar refinery to

users in Gujarat and Madhya Pradesh. The guidelines have enabled Reliance India

Ltd to lay five pipelines for moving products from its 27 million tonne refinery to

various parts of the country. These pipelines will connect Jamnagar to Delhi, Goa to

Hyderabad through Sholapur, Delhi to Patiala, and one connecting Chennai to

Bangalore (source: industry reports).

36. Oil product pipelines owned by PIL and other oil companies will benefit from the

secondary market as it has happened in the US [IDFC (2002)]. The HBJ pipeline

capacity is 65 mmscmd whereas it transports roughly 21 mmscmd. The pipeline can

function on open carrier principle for quite some time. Sunk cost of this pipeline is so

large that even at flat tariff rate, it will be beneficial for GAIL. The HBJ is a gift of a

powerful politician to his constituency at the cost of the nation. Should consumers

continue to suffer for profligation of politicians or move ahead is a question which

the regulator has to tackle.

37. The HBJ pipeline capacity of 64 mmscmd compared to usage of ~21 mmscmd would

restrain development of secondary market for sometime.


REFERENCES

1. BP (2002): ‘BP Statistical Review of World Energy’, British Petroleum,London.

2. Conn Charles and White David (1994): ‘The Revolution in Upstream Oiland Gas’, The McKinsey Quarterly Number 3.

3. ICRA (2003): ‘The Indian Oil and Gas Sector’, ICRA Limited, New Delhi.

4. IDFC (2002): ‘International Best Practices in Pipeline Regulation’ (Mimeo).

5. Gardel Andre (1981): Energy—Economy and Prospective, A Handbook forEngineers and Economists, Pergamon Press, Oxford.

6. GOI (1962): The Petroleum and Minerals Pipelines (Acquisition of Right ofUser Inland) Act, 1962, GOI, New Delhi.

7. GOI (2000): ‘Report of the Group on India Hydrocarbons Vision – 2025’,GOI, New Delhi.

8. GOI (2002a): ‘Report of the Sub-Group on Natural Gas Availability’, TenthFive Year Plan 2002–02, Ministry of Petroleum and Natural Gas, Governmentof India, New Delhi.

9. GOI (2002b): The Petroleum Regulatory Board Bill 2002, Bill No. 38 of 2002,Government of India, New Delhi.

10. GOI (2002c): ‘Guidelines for Laying Petroleum Product Pipelines’, Ministryof Petroleum and Natural Gas, Government of India, New Delhi.

11. GOM (2001): ‘Report of the Energy Review Committee (Part 1)’, Governmentof Maharashtra, Mumbai.

12. World Bank (2001): First World Bank Workshop on the Petroleum ProductsSector in Sub-Saharan Africa, World Bank, Washington.


INCENTIVES, OWNERSHIP

AND PERFORMANCE IN

POWER SECTOR:The Case of UPFebruary 2005

81. INTRODUCTION

Like in the case of all other states in India, the power sector in Uttar Pradesh (UP)has been traditionally characterized by lack of competition, high transmission anddistribution losses, irrational tariff structure and inadequate government support.These problems manifested themselves in huge cash losses for Uttar Pradesh StateElectricity Board (UPSEB) year after year. By March 1999, the accumulated lossesof UPSEB were Rs 10,300 crore or 6 per cent of SGDP and payables to powersuppliers were about Rs 3400 crore (almost 20 months of power purchases).The poor financial performance of UPSEB, which performed as a single buyer,deterred private investment, while public investment was slow due to the resourcecrunch of the state. The inadequate and often distorted investment in turn led topoor performance. The sector was thus caught in a downward spiral of poorperformance, low revenue and sluggish investment.

It is against the background of bankruptcy of UPSEB, a near halt in investment andunsustainable fiscal pressures, that the power sector reforms were introduced, withthe government issuing a power sector policy statement in January 1999. Realizingthat UPSEB was operating as an extension of the state government and that theorganizational, institutional, financial and ownership arrangements were notconducive to the realization of reform goals, the state government decided to distancethe power industry from state administration and provide the power sector withthe autonomy required to operate on commercial principles. The UP ElectricityReforms Act was notified in July 1999 to support the reform process.

A number of significant initiatives entailing changes in organizational, institutionaland financial structures have been taken in the last six years (see below).

Power Sector: The Case of UP | 109

Two significant areas that have remained untouched, however, are the ownershiparrangement and market structure. The power industry in UP is still predominantlygovernment-owned in all its segments. So far, there has been no generation capacity(other than captive power) created by the private sector in the state. Except for asmall part of the state, i.e. Greater Noida (connected load of about 35 MW) whichis operated by a private distribution company, power distribution and transmissionin the state are carried out by utilities owned by the state government.1

It may also be noted that the reform measures taken so far have virtually donenothing to change the market structure which could introduce competition intothe sector. There has been no scope for competition for the distribution marketas the recently formed distribution companies continue to be owned by thegovernment. Further, the two state generating companies have signed long-termPPAs with UPPCL, whereby, generation tariff is determined on cost-plus basisand there is no scope for competition among generating companies.

In the absence of competition, there has been a tendency on the part of theregulator and policy makers to resort to incentives to improve sector performance.The objective of this note is to assess how the power sector has responded to thevarious incentives in the last few years and examine whether governmentownership has been the dominant factor influencing the nature and extent ofthis response.

2. FACILITATING MEASURES

2.1 Multi-year tariff (MYT)

An independent regulatory commission, Uttar Pradesh Electricity RegulatoryCommission (UPERC), was established in September 1999, with a mandate to adopta tariff structure that would meet the objectives of efficiency and equity. The UPERChas issued five tariff orders so far in pursuit of its mandate. To enhance thepredictability of the basis for tariff setting and ensure that consumers gain fromreforms, the UPERC has adopted a multi-year tariff framework since 2002, whichhas been working as the prime incentive system for the utilities. Under theframework, annual performance targets for the utility have been fixed for five yearsin terms of T&D losses and collection efficiency, assuming 2000–01 as the baseyear.2 If the utility fails to achieve the targets and hence incurs a loss, the regulatorwould not treat the loss as a regulatory asset, implying that the consumers will notbe required to bear the burden (in the next year or any time in future) resultingfrom the failure of the utility to achieve targets. On the other hand, if the utilityexceeds the targets, it would retain the resultant profits.


2.2 Initiatives to improve performance

To facilitate improved performance of the sector, three important initiatives havebeen taken.

Unbundling

With the ultimate aim of introducing competition in generation and distribution,the government unbundled UPSEB into three functionally separate, autonomousand separately accountable corporations: a thermal generation company(UPRVUNL), a hydro company (UPJVNL) and a company responsible formanaging the transmission and distribution system (UPPCL). The assets,liabilities and staff of the UPSEB were transferred to these three corporationsunder a statutory transfer scheme. These companies continue to be state-owned.In a second round of unbundling, the state was divided into four geographicallycontiguous zones (barring Noida and Kanpur) and a separate distributioncompany was created in each. These four companies were carved out fromUPPCL through the notification of a transfer scheme in August 2003.3 Thediscoms are managed by boards and have organic links with the UPPCL. Tostrengthen governance in the discoms, the selection of the MDs has been donethrough open advertisement.

Financial restructuring

In January 2000, a clean up of the balance sheet of the UPSEB was carried out asa prelude to the transfer of business to successor utilities to enable the sector toinherit a relatively healthy opening balance sheet, which would facilitate a quickrestoration of the sector’s creditworthiness (World Bank, 2000). Therestructuring was done by write-off and provisioning of doubtful and obsoleteassets, recognition of liabilities that were either understated or not reflected inthe balance sheet, and settlement of cross dues between the governmentand UPSEB.

Tariff rationalization

Tariff proposals are now subject to public scrutiny and the utilities have to defendtheir requests for tariff revision in open hearings. To reduce cross subsidy, thetariff increase for the subsidizing segments (industrial, commercial, railwaytraction, etc.) has been kept at lower levels than those for the subsidized sectors.Further, to the extent the tariffs suggested by the state government deviates fromthat fixed by the regulator, the state government has been required to fill therevenue gap through subsidies.


3. IMPACT ON PERFORMANCE

3.1 Immediate results

Let us first discuss the facilitating measures. Unbundling and corporatization hasfacilitated the emergence of a clearer picture and helped identify the sources ofinefficiency, which would not have been possible under the vertically integratedentity. Thus, the true cost of generation and distribution (of different discoms, whichhave recently been created) is now revealed. It is now possible to find out, for example,the T&D loss at each discom.

Financial restructuring has provided a pragmatic solution to dealing with theproblem of past liabilities, which could have potentially become a hindrance toreforms. As a result of restructuring, the balance sheet size of the utility fell fromRs 33,800 crore to Rs 14,500 crore; the debt equity ratio fell from 23:1 to 3:1; netreceivables for sale of power declined from 440 days to 61 days because of provisionmade for doubtful receivables; and payables on power came down from 615 days to52 days (World Bank, 2000). The restructuring has clearly improved the financialviability of the sector.

Tariff rationalization process is underway. Cross-subsidies are getting reduced. Forexample, the cross-subsidization by railway traction has fallen from 47 per cent in2000–01 to 30 per cent in 2002–03; similarly, the cross-subsidy received by domesticconsumers fell from 41 per cent to 25 per cent over the same period. Further, tariffsin successive years are reflecting increasing levels of efficiency on the part of theutility. Finally, the subsidy as determined by the UPERC is being paid by thegovernment on a regular basis. Clearly, as a result of the on-going rationalization,tariffs are sending less distorted signals for production, maintenance and use.

3.2 Impact on performance

While the immediate results of the facilitating measures have been in the rightdirection, they have not been translated into better performance—financial ortechnical—of the utilities. The UPPCL, like its predecessor (the UPSEB), continuesto be in financial trouble. Total accumulated loss of consolidated UPPCL had risento Rs 5072 crore in March 2003, up from Rs 3753 crore in March 2002 and furtherto RS 7400 crore (estimated) by January 2005 (see Table 8.1).

Table 8.1: Cumulative commercial losses of consolidated UPPCL (Rs crore)

Jan 2000 Mar 2000 Mar 2001 Mar 2002 Mar 2003 Mar 2004 Jan 2005

0 142 2353 3753 5072 6156 (estd.) 7400 (estd.)

Source: PWC


In the past few years, the UPPCL has not been collecting enough revenue to evenpay for its power purchases. A large part of the commercial losses of the UPPCL canbe attributed to the repeated failure of UPPCL to reach target levels of T&D lossesand collection efficiency—which are the basis for tariff setting and which UPPCLhas committed itself to. The T&D loss has fallen from 41.5 per cent in 1998–99 to33 per cent in 2003–04 and collection efficiency has risen from 78 per cent in2000–01 to 85 per cent in 2003–04 (Table 8.2).

Even this slow and modest improvement claimed by UPPCL is suspect. TheUPERC, for example, has raised doubts about the UPPCL’s claim relating toloss levels in 2003–04.

The performance can be evaluated only when actual consumption datafor the whole year is available to the Commission. Further, the sharp fallin revenues as compared to the approved levels in the tariff order … doesraise serious doubts about the maintainability of the stand of the licenseesthat the loss position has considerably improved, as compared to theprevious year. Till the time that there is credible estimation of unmeteredconsumption and the billing data on slab-mix can be relied upon, thestand of the licensees has little value. (UPERC Tariff Order 2004–05)

In terms of physical performance parameters, while there has been moderateimprovement in PLF and oil consumption since 2000–01, the increase in generationhas been insignificant (Table 8.2).

Table 8.2: Performance parameters

2000–01 2001–02 2002–03 2003–04

Actual Target Actual Target Actual Target Estd.

T&D loss (%) 39.0 33.4 41.0 31.3 36.0 30.4 32.8

Collectionefficiency (%) 78.3 85.0 81.0 88.0 79.0 91.0 84.0

AT&C loss (%) – 45.9 52.7 41.4 49.2 36.7 43.6

Generation(billion units) 19.6 – 20.5 – 20.9 – 20.7

PLF (%) 57.2 – 59.8 – 61.2 – 60.2

Oil consumption

(KL/MU) 2.7 – 2.3 – 2.2 – 2.1

Note: AT&C: Aggregate Technical & Commercial

Generation, PLF and oil consumption relate to thermal plants.

Source: UPPCL, UPRVUNL and UPERC’s tariff orders (2001–02, 2002–03 and 2003–04)

Further, UPPCL has not made satisfactory progress in most of the directions issuedby the Commission, which ranged from introduction of MCBs to database


management (UPPCL Tariff Order 2003–04). It has also failed to honour thecommitments it made to the Government of India as per the MOUsigned in February 2000 (See Box 8.1). For example, although the MOU requiredthe UPPCL to introduce online billing in 20 selected towns by March 2001, onlyone locality of the city of Lucknow is reported to have made some progressby that date.

Box 8.1: Memorandum of Understanding with GOI

The Government of India has signed a Memorandum of Understanding with the UP

government to facilitate further reforms in a time-bound manner. The memorandum

signed on 24 February 2000, inter alia states:

Energy audit will be undertaken at all levels in order to reduce system losses.

This would be done in a time-bound manner with the following milestones:

1. Installation of metering at all 11 kV feeders by September 2000.

2. 100 per cent metering of all consumers by December 2000.

3. Online billing in 20 selected towns through computerization by 31 March 2001.

The Government of India would provide financial assistance/loans to the tune of around

Rs 7000 crore for renovation and modernization of thermal generation stations, repair

and maintenance of hydro-electric stations, repairing critical transmission and

sub-transmission lines, etc.

Source: http://powermin.nic.in/

4. OTHER INCENTIVES AND UTILITIES’ RESPONSE

4.1 Generation

The Commission allows return on equity at the rate of 14 per cent for UPRVUNLplants if stations operate at higher than UPERC benchmark PLFs and 80 per cent,whichever is higher, and at the rate of 8 per cent when they are operating at orhigher than UPERC benchmark PLF, but lower than 80 per cent. In the financialyear 2003–04, four out of seven generating stations of UPRVUNL did not qualifyfor any return on equity (Table 8.3).

Similarly, the Regulatory Commission has considered it appropriate to provideincentives (to be assessed on the basis of prescribed norms) to the generatingstations for better performance. Incentives are determined on the basis of actualperformance as compared to the benchmark PLFs. In 2003–04, only one generatingstation (Anpara B) qualified for incentives (Table 8.3).


Table 8.3: Performance of UPRVUNL generating stations

Name of the Actual Projected Benchmark Return on Incentive

station PLF 2003–04 PLF 2004–05 PLFs equity

(%) (%) (%) (Rs crore) (Rs crore)

Harduaganj 22.3 24.4 25.0 0.0 0.0

Panki 50.1 49.0 49.0 3.2 0.0

Paricha 33.9 53.0 53.0 4.2 0.0

Obra A 20.2 30.0 50.0 0.0 0.0

Obra B 62.2 57.7 65.0 0.0 0.0

Anpara A 78.9 77.7 80.0 0.0 0.0

Anpara B 86.7 80.8 80.0 177.6 4.1

Note: For estimating revenue requirement on account of return on equity and incentives for2004–05, projected PLF for 2004–05 (based on actual PLF in 2003–04) was compared withbenchmark PLF.

Source: UPERC Tariff Order 2004–05

4.2 APDRP

The GOI’s Accelerated Power Development and Reform Programme (APDRP) aimsat using the fiscal leverage of the GOI to encourage reforms at the distribution level.Funding under the APDRP has two components: the incentive component and theinvestment component (for upgradation and modernization of sub-transmissionand distribution networks). The incentive component rewards the utilities for actualcash loss reduction by way of grants (50 paisa for every 1 rupee reduction), whilethe investment component makes resources available for investment geared towardscash loss reduction. As part of the investment component, the GOI provides anassistance of 50 per cent of the project cost, of which 25 per cent is a grant and25 per cent a loan.4

Under the incentive component, UP has not benefited in any single year becauseof its inability to reduce its cash losses. As regards investment component, in2001–02, upgradation projects at a cost of Rs 124 crore were sanctioned withthe target date of completion being March 2004. Of this, Rs 30 crore has beenreleased by the GOI, but no expenditure appears to have been incurred so far.Similarly, in 2002–03, upgradation projects worth Rs 306 crore were sanctionedand the GOI has already released money against the above sanction. But thestate-owned discoms have been unduly “tardy about utilizing the funds” (UPERCTariff Order 2004–05).


4.3 Captive power

In UP, the industrial sector is one of the largest consumers of electrical energy. Anumber of industries are, however, relying on their own generation (captive andcogeneration) rather than on grid supply, primarily because of:

• Non-availability of adequate grid supply

• Poor quality and lack of reliability of grid supply

• High tariff as a result of heavy cross-subsidization.

Realizing their inability to meet the demands of the industry, state governments(including UP) have traditionally been taking policy initiatives to promote captivepower, but not to the extent that it would paralyze their respective utility. UP, forexample, has been following a transparent, but restrictive captive power policy.

The threat of loss of revenue due to existing or new industries opting out of thegrid for self-generation is generally expected to create competitive pressures,especially when the sector is corporatized. In that sense, the captive policy issupposed to create incentives for the utilities to improve their performance. Butthis has not been borne out by experience. UPPCL has made little attempt toimprove availability, quality and reliability of grid supply to retain its (existingand potential) high-paying customers. Instead, it has responded on certainoccasions by urging the regulatory authorities (unsuccessfully) not to permit thecreation of captive capacity. As a result, captive capacity continued to grow froman estimated 1240 MW in 1998 (Captive Report 1998, Power Line Research) to1907 MW in 2003 (Central Electricity Authority), while addition to capacity bystate generating companies (and earlier by UPSEB) during the period wasnegligible.5 This has been the case despite the fact that the industrial tariff overthe past few years has been relatively stagnant!

4.4 One-time settlement of UPSEB dues

Following the formulation of a well-designed scheme by an expert group set up bythe GOI, recommending a one-time settlement of outstanding dues (as on 1 October2001), a tripartite agreement (between each state government, GOI and RBI)incorporating the scheme is in operation.6 The key feature of the scheme is that itbrings into focus the payment of current dues in future by linking it to the settlementof outstanding dues through an incentive mechanism. If states adhere to somespecified conditions, which include making timely payments of current dues infuture and achieving certain performance milestones, 60 per cent of the surchargecurrently outstanding will be waived and some cash incentives will also be given tothem.7 If, however, they default, they would be penalized through graded reductionin the supply of power from central power stations and through suspension ofAPDRP grants.8


UP is one of the many states that have signed this agreement. Consequently, powerpurchase payables of erstwhile UPSEB to central generating stations have beensecuritized. As the state government is servicing this liability, the burden on thesector has been considerably reduced. But, how has the UPPCL responded to theincentive system underlying the agreement? The nature of the response can be gaugedfrom the UPPCL’s submission to the UPERC in 2003 that it purchased less powerduring 2002–03 than its own projection, so as to meet the payment conditions inthe tripartite agreement. The UPPCL did this by cutting down power supply ratherthan executing measures to improve T&D losses and collection efficiency.Furthermore, while the UPPCL’s payables to central PSUs have remained undercontrol, its payables to state generating stations have tended to go up.

5. ASSESSMENT

Reform initiatives taken in recent years have been in the right direction. Whilefinancial restructuring and one-time settlement of UPSEB dues have substantiallyreduced the burden of past liabilities of the utilities, making the utilities moreamenable to future reforms, initiatives such as unbundling and public scrutiny oftariff proposals have resulted in greater transparency. Tariff setting has beensubstantially insulated from political interference and some degree of tariffrationalization has been achieved.

There is no doubt that these measures have together created a facilitatingframework. A number of incentives are currently in operation to complement theframework. Some of them are designed to improve overall performance, whileothers are in specific areas. The incentives are largely well-designed and a strongand positive response by the utilities would have certainly helped increase sectorefficiency. But the utilities’ response has been weak and often perverse. Even thougha number of years have passed since these measures were taken, the sector efficiencyhas remained abysmally low as evidenced by grossly inadequate investment, highT&D losses, low collection efficiency and consumer dissatisfaction. Why has thisbeen the case?

5.1 Contrast with Delhi

The answer is illustrated most strikingly by contrasting UP’s response to the MYTapproach to that of Delhi. It has been noted that although UP had adopted MYT in2002, privatization of distribution is yet to occur. It was made clear to UPPCL fromthe beginning that underperformance (vis-à-vis targets) would lead to commercialloss in any given year (because tariff for a particular year is set by the regulator bytaking into account pre-determined performance targets) and would also make thechallenge for the next year even tougher. Yet, the UPPCL not only underperformedpersistently in the face of progressively stiffer targets (see Table 8.1), but also failed


to comply with even the routine directives given by the UPERC. The UPPCL’sexplanation for its repeated poor performance has been “an attempt to blameextraneous factors for its … low level of efforts” (UPERC Tariff Order 2003–04).Delhi, on the other hand, decided to privatize its distribution zones at about thesame time that it adopted the MYT approach. The experience of the past two yearsshows that the privatized distribution zones met the targets and in some cases,exceeded them (see Table 8.4).

Table 8.4: Reduction of AT&C loss in North Delhi Power Ltd (% points)

July 02–March 03 2003–04 2004–05

Committed reduction 0.5 2.3 4.5

Effective reduction 2.6 6.2 6.1*

*Up to August 2004

Source: North Delhi Power Ltd

The contrast weakens the argument made by some that it is too early for UP toexpect any substantial improvement in operations, and that the investment inrecent years in the primary and secondary systems (including metering of feeders,implementation of energy audits, etc.) would show results only in the comingyears. More importantly, the contrast provides evidence that MYT system canhardly work as an incentive scheme in a setting such as UPPCL, which lackscommercial orientation.

5.2 Contrast with NTPC

As regards efficiency in generation, a contrast of UPRVUNL stations with thoseof NTPC, which have similar kinds of incentive systems, can be illustrative. ThePLF of NTPC power stations have historically been much higher than those of UPstate generating stations. In 2003–04, for example, the overall PLF of NTPC was84.4 per cent as compared to 60.2 per cent for UPRVUNL. One major factorexplaining the difference in performance is resource (revenue and capital)availability. Resource abundance helped NTPC—whose revenues are nowprotected by the tripartite agreement—to respond positively to the tariff system,which linked profitability to physical performance. A large part of the rising profitswere ploughed back into investment, encouraging lenders to lend more and atfine rates. In contrast, UPSEB and later UPRVUNL lacked resources, primarilydue to absence of reforms at the distribution end. It is well known how this hasled to a vicious circle of deteriorating performance.

It may be pointed out that a frontier production function model study carried outby the UPERC shows that on an average, the power stations of UPRVUNL can


increase their existing output levels by 37 per cent without additional resources,simply by proper utilization of technology and adoption of best practices. But thestudy perhaps presupposes a well-trained and motivated work force and managementand a corporate culture (such as that of NTPC), which UPRVUNL does not have. Itis, of course, debatable whether it is possible to have good training, sound humanresource management and a corporate culture in the face of acute and persistentshortage of resources.

5.3 Is open access the answer?

Can the problem be taken care of by open access per se? It is expected that as openaccess is phased in as envisaged in the Electricity Act 2003, competitive pressureswould be created. If, however, the generation and distribution assets remainpredominantly with the government, the government would have a vested interestnot only in delaying the phase-in of open access, but also in rendering it ineffectiveto the extent possible. Even if open access succeeds in facilitating the creation ofprivate generating capacity, which in turn attracts away high paying consumersfrom government-owned distribution companies, it is doubtful that the latter wouldbe motivated to improve performance to remain competitive, as evidenced fromthe utilities’ experience relating to captive power. In fact, the open access regimewould entail lesser losses (and therefore weaker pressure) for the utilities than self-generation, as the former requires cross-subsidies to be paid by consumers to theaffected distribution company, while the latter does not.

6. SHORTCOMINGS OF THE CURRENT DISPENSATION

Shortcomings of the current dispensation that impede adequate response of utilitiesto reform stimuli can be mainly attributed to government ownership, as can beseen from the discussion given below.

6.1 Political patronage

There are major shortcomings in the accountability framework in government-owned utilities, even though they are managed by a board. Corporatization doesnot help in altering the orientation of accountability from internal hierarchy topower consumers or regulators. Year after year the regulator has been reprimandingthe utility for its poor performance, but to no avail. At the root of the problem is thepolitical patronage of payment indiscipline, which has been possible mainly becauseof government ownership. Given the political patronage, there is hardly any incentivefor the management to bring dishonest staff to book or to cut off connections tonon-paying consumers. Besides, the maximum punishment given to governmentemployees is usually not deterring enough. Under such circumstances, tariffrationalization can hardly serve any useful purpose: neither can it create incentives


for consumers to use electricity more efficiently nor can it boost revenues foroperators to expand access or improve services.

6.2 Government interference

The government has continued to interfere in the day-to-day operations of the newlyformed corporations, whose managements hold the same bureaucratic attitudes andpromote the same organizational cultures as before. Their relationship vis-à-vis thestate government has also remained unchanged. For example, the government ofUP, in an effort to stall tariff increase, had given a direction to the UPPCL to filetheir tariff application to the SERC for 2000–01 with reduced T&D loss target,without giving any strategy for achieving the target. The utility, being a government-owned company, had to oblige.9 Although the immediate result was that the tariffhike was moderated, ultimately, the T&D losses remained at the previous year leveland the UPPCL incurred large commercial losses. Not surprisingly, with governmentinterference eroding the autonomy of the utility, it has been difficult to establishaccountability for the utility’s performance.

6.3 Dual role for government

The government’s role as a consumer of power compromises its position as anoperator. The government is itself one of the biggest defaulters. The collectionefficiency of the government category has been fluctuating over the years: forexample, it fell from 87 per cent in 1999–2000 to 42 per cent in 2000–01. True, thegovernment is a relatively small consumer of power accounting for 11–12 per centof the total bill and therefore cannot possibly drag down the overall collectionefficiency substantially. The important point is that the government, which isconstrained by its fiscal situation, cannot provide moral leadership in paymentdiscipline because of the poor example it sets for other consumers.

Table 8.5: Collection efficiency (%)—governmental andnon-governmental categories

Billing 1997–98 1998–99 1999–2000 2000–01 2001–02

Government 74 52 87 42 52

Non-government 87 86 84 83 82

Overall collectionefficiency 86 82 84 78 78

Source: UPPCL/PWC

6.4 Erosion of hard budget constraint

The government ownership has led to an absence of hard budget constraints. It hasbeen noted that UPPCL’s payables to the state government’s generating stations has


been rising (from 112 days’ power purchases in 2003–04 to 169 days’ by September2004), while those to the central PSUs have remained under control (30 days). Similarly,in the repayment of loans, UPPCL has given the lowest priority to the government ofUP amongst all its lenders. Yet, the government continues to be its dominant lender.

7. WAY FORWARD

The government had formally recognized that privatization of the distributionbusiness was critical to the viability of the sector in its Power Sector Reform PolicyStatement in January 1999. In fact, the privatization of Greater Noida was done asearly as 1992 and the results were encouraging (see Box 8.2). There was a subsequentattempt to privatize distribution in Kanpur. While the first attempt by the stategovernment to privatize KESCO (Kanpur Electricity Supply Company Ltd) wasunsuccessful, the subsequent decisions to invite private bids have been postponedseveral times (see Box 8.3).

Recognizing that privatization is the answer is not enough; the task has to beimplemented quickly. While privatization is getting delayed, commercial losses ofthe UPPCL have been mounting and the benefits of the balance sheet clean-up in2000 are getting wiped out (Table 8.1). Since at the time of privatization, theselosses would have to be dealt with, delays in privatization will increase the financialburden on the government.

Box 8.2: Noida Power Company (NPCL)—a successful distribution company

Background

NPCL is the first private distribution company in India, which took over a networkfrom a state undertaking. It was jointly promoted by New Okhla Industrial DevelopmentAuthority (Noida) and Greater Noida Industrial Development Authority (GNIDA) in1992 to take over distribution of the new industrial township. Currently, NPCL has anequity base of Rs 9.2 crore, of which 73 per cent is held by the RPG group and thebalance by GNIDA.

Performance

The company inherited a dilapidated distribution network, inadequate to meet therising load growth. Through extensive operational revamping and high consumer focus,the company has been able to achieve a turnaround. Between 1994–95 and 2002–03,its asset base has grown from Rs 14 crore to Rs 60 crore and sales revenues fromRs 19 crore to Rs 70 crore. Its T&D loss level has been consistently about 8 per cent,one of the lowest in the country. NPCL also has one of the lowest distribution manpowercost (at Rs 0.05 per unit sold). In 2000–01, the company made a net profit ofRs 2 crore, up from Rs 0.5 crore in 1996–97.


Minimizing revenue loss

To minimize revenue loss, the company follows a thorough energy auditing process,which entails aggregation of the quantum of energy consumed in downstreamdistribution on a periodic basis for reconciliation with input energy. The 11 kV feedersare provided with electronic meters at substations, which enable accurate assessmentof energy sent out to the system. To develop the rural distribution network, NPCL hasdeveloped the concept of “cluster supply” in villages, whereby multiple small-sizedtransformers are introduced for providing supply to localized groups of consumers.By extending the high tension network to almost the doorstep of consumers, NPCLhas reduced energy pilferage opportunities. The company’s consumer focus is reflectedin the fact that connections are activated within 6 days of application for domesticconsumers and 15 days for industrial consumers.

Source: NPCL Annual Report (various issues), UPERC Order, 2003–04, Prayas Occasional

Report No.2 (2003)

Box 8.3: KESCO privatization

The government of UP indicated its intention to privatize power distribution in Kanpurcity in the first quarter of 1999. Although more than five years have since passed,distribution in Kanpur is yet to be privatized.

In April 1999, the government had pre-qualified four bidders for the privatizationprocedure—BSES Limited (BSES), Calcutta Electricity Supply Company Limited(CESC), Larsen & Toubro Limited and AES Combine (L&T–AES) and Tata ElectricCompanies (TEC). The bidders sought and obtained a postponement of the final datefor submission of bids until after the issue of the first tariff order—which came in July2000—since bidders (rightly) expected future viability of KESCO to be contingent onregulatory decisions on a number of issues such as the bulk tariff payable by KESCO toUPPCL, the consumer tariffs chargeable by KESCO and the allowable level of T&Dlosses. Bidding took place in July 2000. However, since only one company submittedits bid, the bid was not opened. Since then, although the bidding deadline has beenpostponed a number of times, bidders have not responded.

Source: Tadimalla, Sri Kumar, “Privatization of Kesco—A Case Study”, 2000

To extract best results from privatization, distribution zones need to be appropriatelydesigned. Two methods are generally considered: mixed zones and concentratedzones. The latter is a superior method, for the following reason. The option ofclaiming subsidy encourages distribution companies in mixed zones—regardlessof whether they are government-owned or owned by private players—to camouflagetheft and inefficiency rather than to improve distribution efficiency, by over-reporting consumption of subsidized categories, and thereby raising the subsidyburden on the government.10 (Concocting false consumption data is particularly


easy in states that have a large number of agricultural consumers, such as UP.) Suchoptions do not exist for concentrated zone distribution companies, who, bydefinition, would have no access to subsidy flows. In fact, these zones can be madeto cross-subsidize rural zones through a transparent electricity surcharge. Mixedzone privatization would thus weaken the motivation for the distribution companiesto respond strongly to the incentive systems.

UP had started the right way by attempting to privatize KESCO. Potential privateinvestors showed little interest because of the lopsided risk allocation that wasattempted and the absence of regulatory certainty, and not due to the fact that KESCOwas a relatively small, concentrated zone. It would not be appropriate to abandonthis strategy in favor of mixed zone model for distribution, as UP appears to havebeen doing. Unless UP rectifies this flaw at this stage, it would lose substantial benefitsof privatization.

8. CONCLUSION

As stated earlier, there are two areas that have remained untouched by the recentreform process: ownership arrangement and market structure. While the ElectricityAct, 2003 entails provisions to radically alter market structure, it allows a numberof options for ownership and does not mandate any changes in the existingownership structure. So, UP as well as a number of other major states, which arein the same stage of reform as UP (such as Rajasthan, Karnataka, Haryana andAndhra Pradesh) are well within their rights to continue with governmentownership of distribution business.

The case of UP, however, shows that it is futile to attempt to achieve higherproductivity through multi-year tariff regime and other incentive schemes if thedistribution business continues to be owned by the government. Furthermore, itwould be naïve to believe that with the onset of open access, the sector efficiencywill increase even if distribution is not privatized. The UP experience shows thatcontinued government ownership would lead the newly formed utilities to deeperand deeper financial trouble, while the sector would continue to ail. There is even adanger that reforms may be discredited. To make utilities more responsive toincentives and to take advantage of the upcoming open access regime, states need toprivatize distribution at the earliest and do it the right way.

NOTES

1. The right to distribute power in Greater Noida was sold in 1993 to Noida PowerCompany Ltd.

2 . The process of tariff setting on the basis of performance targets set each year by theregulator increases the uncertainty of investor/utility about their respective future revenue


streams. This is borne out by the KESCO privatization exercise. The practice also increasesthe burden on the financial and human resources of the utilities. Finally, such a processfails to offer correct incentives for a long-term view of investment, maintenance anduse. A multi-year incentive-based approach to regulation can rectify these shortcomings.

3. They are Varanasi, Agra, Lucknow and Meerut distribution companies. In addition tothese four, UP has two more discoms operating at Kanpur and Noida respectively.

4. The balance 50 per cent is to be arranged by the utilities either through internal resourcegeneration or as counterpart funding from financial institutions such as the RuralElectrification Corporation and Power Finance Corporation.

5. The UP Government Energy Policy 2003 states that the captive power capacity in UP ishigher than the industrial load contracted with the grid.

6. For details, see Report of the Expert Group on Settlement of SEB Dues, March 2001.

7. The balance arrears would be securitized through tax-free bond issued by respectivestate governments.

8. If defaults exceed 90 days from the date of billing, the Ministry of Finance should recoverthese dues through adjustments against releases due to them from the centre.

9. The SERC, on its part, had even felt that the target spelt out in the tariff application wasinadequate and called for even higher loss reduction target.

10. To scrutinize the validity of the claims for subsidy by distribution companies, theregulator will have to verify the actual consumption by subsidized categories, which is avery cumbersome exercise.


1. INTRODUCTION

In the electricity sector, the totally steel-jacketed arrangement of long-term contractswhich defined the rules of the game for several years has not allowed a competitivemarket structure to develop. Even though power trading has been recognized as adistinct licensed activity under the Electricity Act, 2003, the volume of trade hasbeen so insignificant and far from a critical mass that it has not created any visibleimpact. Though the National Electricity Policy, 2005, provides for 15 per cent ofthe total capacity to be developed as merchant capacity which could play a meaningfulrole in market development, even this alternative has not taken off in a credibleway. Therefore, definite action needs to be taken to ensure that (a) merchantcapacities develop at least to a level of about 15 per cent of the total capacity,(b) trading is encouraged to occupy a much larger space, thereby giving options todistribution licensees for competitive procurement, and (c) availability of openaccess, firstly to the transmission system and subsequently to the distributionnetwork, does not emerge as a constraint on facilitating these processes.

2. MERCHANT POWER PLANTS

The Electricity Act envisages the bulk of the development of power plants throughlong-term power purchase agreements (PPAs) with tariff determination as prescribedunder Sections 62 and 63 of the Act. Consistent with the provisions of the Act, theGuidelines for Determination of Tariff by Bidding Process for Procurement of Powerby Distribution Licensee stipulates PPAs for periods exceeding one year. Section62 of the Act also permits sale or purchase of electricity between a generatingcompany and a licensee or between two licensees for a period not exceeding oneyear. Section 66 of the Act explicitly provides for development of the power

DISCUSSION PAPER ON

DEVELOPING POWER

MARKETS

September 2008

9

Developing Power Markets | 125

markets. With a view to developing the electricity market, it would be essentialthat while there are power projects which are developed on the basis of long-termPPAs, lasting over project life cycles under which capacities developed are fullytied up with the procuring agencies, there are also capacities developed to cater toneeds which are short-term in nature. The competitive advantage of the electricitymarket would accrue to consumers only when a reasonablequantum of merchant power generation from a number of producers is alsoavailable for purchase on the basis of competitive tariff through trading orequivalent arrangements.

Some of the key benefits of setting up merchant power plant capacities, interalia, include:

a. Merchant power plants provide virtual capacities for regions/areas in need ofshort-term power due to temporary demand–supply mismatches.

b. The entire risk for offtake of power is carried by the merchant power plant,thereby obviating the need for procurers to enter into firm power purchaseagreements for their requirements. Procurers could enter into firm PPAs fortheir base load requirements and meet the peaking, short-term requirementsfrom merchant power plants.

c. Power plants operating on a merchant basis, necessarily need to ensure thatthe power produced is cost-effective/reliable, failing which these capacities willnot be dispatched in preference to other available power supplies.

d. These power plants can also help meet peak load demand in the system.

Development of merchant power capacities to the extent of about 15 per cent of theinstalled base would go a long way in terms of development of trading, introductionof competition, and development of the electricity markets. Project-specific merchantcapacity should be determined on the basis of the location of the project, type ofproject fuel, etc. However, there are certain issues hampering the development ofpower projects in general, which are discussed below:

a. In the recent past, a number of promoters have announced power generationcapacities in the range of 1000 MW or above. The majority of these capacitiesare based on coal or hydel and are expected to be developed in the easternpart of the country for coal (Jharkhand, Chhattisgarh or Orissa) and in thestates of Arunachal Pradesh, Himachal Pradesh, Uttaranchal or Sikkim forhydro power projects. Currently, many of the proposed generation capacitiesare in the development stage and as such are yet to tie up any offtake ofpower. Typically, most of these projects would tie up offtake for 60 per centto 70 per cent of the capacity with the balance capacity to be committed on amerchant basis. The tie-up of 60 per cent to 70 per cent of the capacity on


long-term PPA basis will be essential to service the debt for the project. In thecase of hydro projects, government policy recently notified 40 per cent of thecapacity on merchant basis.

At the time when promoters approach financiers for tying up equity/debtfunding, the generation capacities have not tied up long-term offtakers of power.The tie-up of capacity on long-term basis with the offtakers, in some cases,may take considerable time, which may delay the financing/equity tie-up. TheGuidelines for Determination of Tariff by Bidding Process for Procurement ofPower by Distribution Licensee makes it mandatory for the state discoms tocompetitively procure the power for their requirements more than one year.The procurement process of the discoms is carried out under Case I bids (wherethe location, technology or fuel is not specified by the procurer) or Case 2 bids(for hydro power projects, load centre projects or other location-specificprojects with specific fuel allocation, such as captive mines available, whichthe procurer intends to set up under the tariff-based bidding process). Thetime taken for finalization of the bids is in line with those stipulated by theMinistry of Power (MoP)—(240 days for single-stage bid to 425 days for two-stage bid (RFQ and RFP)). Additionally, the bids called by various states donot occur within a specific time period and can occur any time during theyear. These factors add to the uncertainties of the outcome associated with thebidding process, wherein the promoter may not be successful in some or allthe bids, which themselves are a time-consuming process and therefore mayextend the planned financial tie-up date. The financiers/investors would needto evaluate the credit risk associated with the offtakers, and hence it becomesimperative that the intended capacity tie-ups (60 per cent to 70 per cent) occurprior to financial closure. If it is possible for the power plant developer toindicate tied-up capacity and the states in the respective regions, then thiswould enable the CEA and the CTU to prepare a plan for additionaltransmission capacity needs of these developers.

b. The delays in tying up of firm capacities may have implications in terms ofevacuation arrangements for the project. The inter-regional transmissioninfrastructure may not be adequate to ensure evacuation of power primarilyfrom the Eastern/North-Eastern to the North/West and Southern regions,assuming that a significant part of the capacities planned in these regionsmaterialize. The existing transmission capacities are tied to generation capacitieswhich evacuate power from specific power plants to different regions. Thetransmission capacities that are expected to be developed within the next fewyears (Eleventh Plan) will evacuate the power from identified projects(78,000 MW planned to be developed in the Twelfth Plan period) to specific


regions with marginal redundant capacities. The process of planning anddeveloping evacuation infrastructure, by the Central Transmission Utility(CTU), requires the identification of the project location and the offtaker. Thisprocess of planning and development of the transmission infrastructure maytake about 30 to 36 months from the time the offtaker is identified for a specificproject. In a situation wherein the developer is unable to tie up the offtaker ofthe capacity within a suitable timeframe, it will lead to delays in the developmentand commissioning of evacuation infrastructure. Such delays in establishingevacuation infrastructure will lead to part or the complete power generationcapacity being commissioned prior to the transmission infrastructure beingoperational and create a stranded asset for a limited period of time. If developers,at the time of commencing the development activities, indicate tied-up capacityand the states in the respective regions, it would enable the CEA and the CTUto plan for additional transmission capacity needs of these developers.

In the case of coal-based plants that are coming up in Orissa, Chhattisgarhand Jharkhand, which will become the hub for the new capacities of the IPPdevelopers, a two-track policy approach may be required. First, there is needto have a dedicated line up to the identified pooling point, and its cost shouldbe shared by the developers. Second, from the common pooling point a separatecommon corridor should be planned, and its cost should be shared by all thestates in the region. This approach may be further discussed with the IPPs,CEA and the states concerned in the region.

c. In the recent past, the Ministry of Coal, Government of India, has allotted coalmines to private developers of power projects. The developers are expected touse the coal from the mines to operate their power plants. The process ofdeveloping the mine ranges from conducting geological investigations,submission of mining plans, obtaining statutory approvals to land acquisitionand obtaining mining lease. This process of development of the mines is time-consuming, and can take about four years before the extraction of coal fromthe mine can commence. The power project is, however, expected to commencegeneration prior to the extraction of the coal from the allotted mine consideringthe timelines involved in the development of the power project and the coalmine development. In such a situation, the developer is expected to have somealternative tie-up for fuel till such time as the captive mine is operational.

d. Land acquisition is one of the most critical activities that can delay projectdevelopment substantially and have major implications on the project costs.Currently, land for the private power projects is being acquired by the stategovernments, and the procedures identified under the Land Acquisition Act1894 are followed. These procedures are enshrined in various sections, starting


from Section 4(1) which relates to public notice by the state governmentinforming the general public of the land identified for acquisition in the publicinterest, followed by Section 5(1) and Section 6(1) notifications which dealwith identification of the land records, and fixing and approval of thecompensation. There are further notifications which need to be made andfinally culminate in obtaining a notification from the state government underSection 17(1), wherein the possession of the land is actually handed over tothe developer. The entire process of land acquisition by the state governmentcan take up to two years, assuming the processes are not marred bycontroversies/litigation as has been observed in some of the projects beingimplemented in Orissa. The delays in acquisition of land in turn impact onthe receipt of various statutory clearances/licences (mining lease), etc. thatfurther delay the projects.

Recommendations

The importance of merchant power projects for the development of the power sectorin India cannot be disputed. It should be ensured that capacity additions in merchantgeneration take place at a rapid pace. If the stakeholders ensure that visibility withreference to the variables under their control is enhanced, as have been identifiedherein below, thereby reducing the associated risks, the process of funding of theprojects by both the equity investors and the funding institutions would be smoothened.

A. Developers:

a. Land acquisition: Acquisition of land is a time-consuming process. It issuggested that the developers acquire at least 40 per cent of the land with afirm schedule to acquire the balance land if the developer is acquiring theland on its own or deposit about 80 per cent of the cost of the land (with thestate government) if the same is acquired by the local authority for the powerproject before approaching the funding agency (equity investor/lendinginstitution). The above will provide visibility as regards the land acquisitiontimelines and eliminate the land-related variables in the risk perception ofthe funding agency.

b. Environment: Prior to approaching funding agencies for financing (equityand debt), the developer should ensure that the following activities havebeen completed:

i. Terms of reference of the environment study are approved; and

ii. Public hearing process is either completed or is scheduled.

The above will obviate to a certain extent the risks associated with the visibilityon the key statutory clearances.


c. Firming up power offtake: The funding agencies (equity and debt) place agreat deal of importance on the credit risk associated with the offtaker ofpower. For the projects supplying power to financially stressed discoms, theequity investors are willing to participate in the project at relatively higherrate of returns and the financial institutions providing debt do so with additionalcovenants and at higher rates of interest. For mega power projects (greaterthan 1000 MW capacity), the developer should make firm arrangementsthrough medium-long-term power purchase agreements for 60 per cent to70 per cent of the capacity at the time of approaching the funding agencies fortying up equity and debt. The balance could be left open, and tied upprogressively over the next few months with discoms which are not financiallystressed. In the case of small to medium projects (less than 1000 MW), thepercentage of power offtake to be tied up at the time of the developerapproaching the funding agencies could be lower at 40 per cent to 50 per cent,with the balance being tied up later. The above provides visibility to the fundingagencies as regards the credit risks associated with the project during itsoperations phase. For Case I bidding, however, no PPA could be even discussedunless the bidder quotes a price and wins the bid. The bidder cannot quote aprice unless he has an idea of cost of funds. Therefore, the requirement ofofftake should be made a pre-disbursement condition and not pre-commitmentcondition. This approach will facilitate capacities through Case I bidding.

d. EPC/major equipment contract(s): The ability of the developer to ensuresuccessful implementation of the project to a greater extent rests on the selectionof the contractor. The developer of the merchant project, by selecting the keyequipment supplier or the EPC contractor (or at least placing the letter ofintent), will help in the assessment of the construction risks on the basis of thereputation of the contractor. Hence it is suggested that the developer shouldhave signed the agreement with the proposed equipment supplier(s) or theEPC or package contractor prior to any loan disbursement. Issuance of theletter of award of the main plant should be a precondition to loan finalisation.

e. Coal availability: The list of activities to be carried out post-allocation of thecoal block ranges from conducting geological investigations, submission ofmining plans and obtaining statutory approvals to land acquisition andobtaining mining lease. These processes can take up to four years to concludeprior to commencement of mining operations. In the event of part of the powerplant capacity achieving commercial operations prior to commencement ofmining activities, the fuel source needs to be firmed up. Developers shouldhave a clear-cut plan on the timelines within which they will obtain all necessaryapprovals or have a back-up in terms of a coal linkage. In addition, the


developers of merchant capacities should have provided a bank guarantee ofthe requisite amount to the Ministry of Coal prior to approaching fundingagencies for tying up equity and debt.

B. Regulators and Central Government/ministries

a. Coal linkages: In some of the coal blocks which have been allocated, thetimelines involved in land acquisition and obtaining all clearances leading tomining are very long. This would lead to part or total capacity achievingcommercial operation prior to the commencement of mining activities. It isrecommended that in such cases the ministry of coal should provide taperinglinkages to projects where there has been serious project development workand where delays in commencement of mining operations and extraction ofcoal from the allotted mine(s) are anticipated.

b. Open access: As of now open access in transmission is available either for a periodof up to 3 months or greater than 25 years. This poses a problem to developers asthey need open access for short/medium terms and for varying capacities to sellpower from their proposed project. It is recommended that open access be madeavailable for varying terms: short term, up to 3 months; intermediate term,3 months–5 years; medium term, 5 years–15 years; and long term, over 15 years,to merchant power plant developers to enable them to dispatch their power forvarying terms and capacities to offtakers for the untied capacities.

c. Exemption from cross-subsidy in the case of financial event of default: Currently,the power procurement for the state discoms is handled by the aggregator(s) atthe state level who invite(s) bids for power on behalf of all or some of the discoms.The financial position of all the discoms, for whom the state aggregator mayprocure power may not be similar. This will result in some of the financiallyweak discoms incurring a financial default. Though the model PPAs stipulatethird party sale, in reality, the sale of capacity defaulted on by the discom isgenerally made to another discom despite the existence of financially sound HTconsumers in the distribution area of the defaulting discom. This is due to theprevalence of cross-subsidy surcharge. It is recommended that if a state-ownedprocurer defaults on the payment for power procured from any power plant,the power plant should be allowed to sell power to third parties within the state(like HT consumers), and the discom provides the wheeling services for thepower of the project at wheeling charges as decided by the regulator. The levy ofcross-subsidy surcharge in such cases should be waived and in other cases bedecided in a rational manner, as the state procurer has already defaulted onobligations to the seller, and the surcharge should reflect the cost of efficient/uninterrupted supply. It should, however, be noted that in order to encourage


Open Access, surcharge should not be in excess of the surcharge as per the formulalaid down in para 8.5.1 of the National Tariff Policy.

d. Mega power status for tied capacities: The mega power policy of the MoP,Government of India, exempts the equipment for power projects above acapacity threshold (1000 MW for coal-based and 500 MW for hydel) fromcustoms duties and excise duties, provided such projects supply power to morethan one state and the beneficiary states have constituted their regulatorycommissions with full powers to fix tariffs as envisaged in the Central Act. Theprocuring state would also have to privatize distribution in the cities having apopulation of more than one million. In the case of a project where at least1000 MW of capacity is proposed to be sold through long-term power purchaseagreements to utilities in more than one state, the benefits of the mega powerproject should be automatically accorded to such projects. This will have aclear implication for the project cost, since the taxes and duties constitute asubstantial element of the cost, and consequently on the means of finance. Forthe merchant power projects, tying up funding on the basis of a mega powerproject’s benefits, in the absence of visibility on the applicability of the benefitsto the project, runs the risk of an increase in the project cost if the mega powerproject’s benefits are not available.

C. Governments

a. State governments should continue to assist the developer in land acquisitionand allocation of water to the merchant power plants.

b. The state governments over the past few years have had the benefit ofexperiencing the patterns of power demand, and supply and growth in thepower demand. Various states together should be in a position to project theirdemand for the next few years and arrive at an assessment of supply. On thebasis of this, the states can call for competitive bids for supply of power at thesame time to mitigate the risks associated with visibility on the power capacitytie-ups by the developer (as highlighted above).

c. MoP or the CEA could coordinate this, particularly with respect to the timingof the bids.

d. An in-principle support for transmission of power based on requisition fromthe developer, CEA or PGCIL, could provide this comfort.

D. Financing agencies

Non-finalization of loan agreements also emerges as a constraint in many cases.Financing agencies can encourage development of merchant plant/capacitiesfor which it may be necessary to adopt the following approach for some of thecritical issues:


1. Land

2. MoEF/

Forest

clearance

3. Power

offtake

4. EPC/Major

equipment

contracts

Table 9.1: Recommended loan conditions

Issues Conditions for final loan agreements Conditions for loandisbursement

Land should have been identified and

Section 6(1) notification should have been

issued for the entire land and the

developer should have deposited 80% of

the cost of the land with the

government authorities.

The terms of reference for the

environment studies should have been

approved and the public hearing process

should have been completed.

Initiated a process of bidding for offtake

of power through the competitive process

The developer should have issued the

letter of award for the entire scope of the

project (EPC basis) or major critical

equipment for the power project.

(However, for commencing the discussions

with the lenders, the promoter should have

at least initiated the tendering process for

major equipment/EPC contract and should

have achieved significant progress).

The developer should

have the possession of the

entire land for the project.

MoEF clearance and

Forest clearance should

have been obtained.

In addition, the developer

should have obtained

consent from the state

pollution control board.

Finalised off-take of power

for at least 60% to 70% of

the capacity for major

projects and 50% to 60%

of the capacity for smaller

projects (up to 500 MW).

The EPC or the major

equipment contracts, as

the case may be, should

have been finalized

incorporating the inputs

from the lenders'

engineer and all the

conditions precedent for

effectiveness of the EPC/

major equipment

contracts should have

been fulfilled.


Table 9.1: Recommended loan conditions (contd...)

Issues Conditions for final loan agreements Conditions for loandisbursement

5. Fuel tie-ups

6. Power

evacuation

The developer should have obtained Letter

of Assurance from the Ministry of Coal

and deposited the bank guarantees with

the ministry towards linked supplies.

For captive mines, in addition to obtaining

a fuel linkage for the period between the

time the plant achieves commercial

operation and the time the captive mine

commences operations, the developer

should have initiated the process of GR

preparation, mining plan preparation etc.

In addition, the heads of agreement should

have been entered into with the fuel

supplier before the financing documents

were finalized.

Currently, a single coal block is allotted to

a number of allottees. It becomes essential

that the company approaching the lenders

for financing its power project has at least

formed the company for the coal mining

and should have entered into a share-

holders agreement with the other allottees

of the coal block.

The developer should have initiated

discussions with the CTU for evacuation

of power from the project site to the

prospective states in line with 3 above.

Fuel supply agreement

should have been signed

with the state mining

agencies for projects

where fuel linkages are

available (and for projects

with captive mines

wherein fuel linkages shall

be required for the period

commencing from the

project COD till the

commencement of

mining operations).

For captive mines, the GR,

mining plan should have

been prepared and

approved by the

relevant agency.

The evacuation

arrangements/agreements

for evacuation of power

from the project to the

respective procuring states

should have been firmed

up with the CTU.

The above will reduce to a large extent the risks associated with financing anddevelopment of merchant power plants and ensure that the capacities announcedby the various developers materialize.


3. POWER TRADING

Prior to enactment of the Electricity Act 2003, there was no concept of tradingof power. The power sector was a natural monopoly with state-owned entities,viz. State Electricity Boards (SEBs) which were vertically integrated(i.e. generation, transmission and distribution housed in one entity) andaccorded the right to carry out their businesses in a geographically definedterritory with pre-approved tariffs. Each SEB had an allocated share in a central/jointly-owned power station. The entire power sector operated on a fixed returnbasis and interplay of market forces remained non-existent. Utilities wouldback down their generating stations in case of low demand and resort to load-shedding in case of excess demand. Thus the concept of power sector operations(generation, transmission and distribution) as a commercial activity whichcould utilize the surpluses of other regions and use the fixed assets for betterreturns did not exist.

With a view to developing the electricity market, power trading was introducedas a concept in 2001 to tap the power from surplus regions of the country tothe deficit regions. This resulted in better utilization of existing capacities byway of creating virtual capacities and also added to the cause of substantialimprovement in plant load factors of the existing generation units. The initialgrowth of the short-term power trading market was appreciable. The share ofshort-term traded power increased to about 2.5 per cent, while the balancegrid power continued under long-term power purchase agreements. Theparticipants in the power sector for the first time started to look at power as asource of revenue. In the present situation, many states like Chhattisgarh,Jharkhand, Orissa, Himachal Pradesh, J&K and Uttaranchal have devisedpolicies and planned large capacity additions to become power hubs. This willlead to rapid capacity addition, including merchant power plant capacities.

Characteristics/Advantages of power trading

After due consideration over a long period of time, power trading is now recognizedas a distinct activity, hence it may be worthwhile outlining the characteristics/meritsof electricity as a trading activity:

a. Electricity trading facilitates sale of power from a surplus region to a deficitregion, mitigating shortage. In effect, electricity trading enables better utilizationof existing generation assets, without requiring huge investments to be madein setting up generation assets.

b. Electricity traders act like market makers. They provide a single-pointspecialized service and enable buyers and sellers to transact their business. Inthe absence of traders, both buyers and sellers shall have to incur significant


expenditure for training manpower, locating sellers/buyers and establishingthe trading infrastructure.

c. Unlike an intermediary who does not acquire interest and incur liability, theelectricity trader purchases electricity and assumes all the risks of thetransaction, especially the payment risk by way of adequate payment securitymechanism. An electricity trader acts as a specialist who accepts liability andresponsibility for the transaction to be completed, unlike a person who gets acommission for bringing seller and buyer together.

d. By assuming counter-party credit risk, electricity traders provide comfort tothe seller of electricity by facilitating sale and purchase of power at apredetermined price, thereby insulating the purchaser and the seller from thefinancial risk of transacting through the Unscheduled Interchange (UI) market,where the frequency and rate realised are variable. Such predetermined sale ofpower also aids better grid discipline and leads to better grid parameters.

e. With the development of the electricity markets, the number of activeparticipants in the trading segment would increase. This would create, thoughin a limited way, an environment of competition in which the procurerdistribution companies do have the option to choose from various tradingagencies which, in turn, leads to reduced burden on ultimate consumers. Goingahead, there is a potential for credible trading agencies to act as catalysts/facilitators of new generation capacity, wherein the trader could facilitatetie-up of the bulk of the capacity on a long-term basis with a utility and take aprincipal risk for the balance untied amount.

f. Even the limited volume of trading activity has been able to establish thevalue/price of power and has brought in a commercial sense among, if notall, a large number, of state utilities.

Regulatory orders on power trading

The increased demand for power as well as inadequate new generation capacitybeing set up has led to a rise, over the past two to three years, in the short-term priceof the power being traded, causing concern to purchasing utilities as well as to theregulatory bodies. To address the situation, the CERC/Appellate Tribunal for Electricity(ATE) have passed three orders, and highlights of which are presented below:

a. The trading margin, which can be charged by trading licensees for inter-statetrading of power was capped at 4 paise/kWh on power traded on a short-termbasis (not exceeding a year), including all charges, except charges for scheduledenergy, open access and transmission losses.

b. The price at which a generating company can trade power should not exceedthe base price plus 4 per cent thereof.


c. Trader-to-trader transactions are not permitted.

The above matters are sub judice, and final decisions on the same are still awaited.

Current trading scenario

a. The capping of trading margin has not led to price stability. The transactionprices quoted below indicate that there has been no price stabilization postfixation of trading margin by CERC.

Table 9.2: Trading margins

Year 2005-06 2006-07

Weighted average purchase price 3.14 4.47

Weighted average sale price 3.23 4.51

Trading margin 0.09 0.04

b. The present short-term bilateral market prices have reached levels of Rs 7 toRs 8/kWh, which is less than the present maximum Unscheduled Interchange(UI) price. The present maximum UI price is in the range of Rs10/kWh, withmany of the state utilities continuing to overdraw from the grid, causingsubstantial variation in the grid frequency. The short-term prices (UI price/bilateral contract prices) are sending out price signals of a massive deficit powersituation in the country.

c. Pursuant to the above trading restrictions, the growth rate in short-term tradingvolumes has declined, and the market appears to have stagnated. Few playersin the trading industry have remained active, and many are reworking theirbusiness plans to ensure that viability/profitability levels are maintained. Marketmaking/trading as an activity is not making an impact or contributing to theextent envisaged.

d. The role of a trader, in accordance with the Act, is also to promote electricitymarkets and develop new and innovative products, which may inherentlycarry higher risks. Capping of trading margin will reduce the risktakingappetite of traders and discourage them from assuming a principal rolein trade and push them to a broking role, wherein they would haveback-to-back arrangements tied up.

e. Traders bring a substantial level of comfort to both buyers and sellers ofelectricity by way of providing the counter-party credit risk in even long-termpower purchase and sale agreements. The trader effectively assumes a principalposition and takes high payment risks toward open access charges payable toCentral Transmission Utility, full fixed charges during plant life (35/25/15 years)


even in the event of failure of power off-take, and prompt payment to theseller even if it receives delayed or no payment from the buyers. Such comfortby the trader to the project developer helps finance new and upcoming projects.In absence of such a counter-party guarantee and such trading restrictionsover a prolonged period, investment in new and upcoming projects may getadversely affected, which will become a barrier to the overall development ofthe electricity market in the country.

Recommendations

a. Trader-to-trader transactions:

Pursuant to the Electricity Act 2003, the power sector has been unbundled andreorganized. The monolithic SEBs in many states have been split up into distinctgeneration, transmission and distribution companies. In many of the states, astate-owned trading company has been incorporated which is involved in bulkpurchase/sale of power. The state-owned trading entity procures power inbulk for onward sale to the distribution companies (discoms) in the states.In the present situation, wherein the financial position of the discoms isweak, it has become necessary to aggregate/facilitate power procurementat a nodal level, i.e. bulk purchaser/state-owned trading entity, at a commonprice from generators/inter-state traders and avoid duplication of expertiseand effort. Also, in most of the states, financial health varies significantlyacross discoms, which results in higher power purchase cost for a financiallyweaker discom as compared to a discom having a better credit rating.Imposition of restrictions on trader-to-trader transactions may also affectthe progress of reform of state utilities. Even though by virtue of anintervention by the Hon’ble Supreme Court, technically, restrictions ontrader-to-trader transactions for purchase/sale of power do not exist, inview of an earlier order of the CERC, many of the states have been avoidingtrader-to-trader transactions.

The trader-to-trader transaction should be freely allowed, so long as it isunidirectional, and the discoms/state-owned bulk procurers of power shouldbe permitted to buy power from either generators or traders; however, thepurchase consideration should be governed solely by the cost competitivenessof the procured power. Restricting state-owned traders to procuring poweronly from generators will constrain the development of the electricity marketsin the future and minimize options available to the purchaser of power.

The Act does not disallow trader-to-trader transactions; rather, it is silent onthis issue. Furthermore, if the trader is not broking a deal as an intermediary,but assuming the role of a principal, then he bears the risks associated with the


trade and hence enjoys the returns thereof. Traders cannot force utilities tobuy power at high rates as the economics of demand and supply dictate thesale and purchase of electricity.

To prevent any price escalations arising due to the operation of a trading cartel,trader-to-trader transactions could be allowed, provided the trade conductedis unidirectional in nature.

b. Generator-to-trader transactions:

The restriction on the generator-to-trader transactions at a price not exceeding4 per cent over the cost of generation may prove to be counterproductive interms of developing the electricity market. In a situation of extreme powershortage, when part of the proposed/planned capacity is merchant in nature(i.e. where power sale is not tied through long-term PPAs), with associatedrisks to be borne by developers, any exercise to cap the price through regulatoryintervention could only hamper the process of addition of such capacitiescoming into the grid. Since the cost of generation is not determined forcompetitively bid out projects and merchant power plants, the restriction of4 per cent over base price on the sale of power by generators to traders shouldnot be applied to such plants. With the introduction of the power exchange,the sale/purchase of power will be market-driven, and price restrictions onsale of power may be difficult to implement. It needs to be recognized that oneof the reasons for trading volume not increasing substantially is insufficientpower available outside long-term PPAs. Such power can be available onlywhen the regulator facilitates merchant capacity and duly recognizes the riskswhich developers may have to take while developing such projects. Further,this may not send the right investment signals to the states which have alreadyplanned for power hubs or are willing to set up such hubs in the near future.Though technically this restriction does not exist currently by virtue of theintervention of the Hon’ble Supreme Court, in view of an earlier judgmentof the Appellate Tribunal of Electricity, there has been uncertainty on thefinal outcome of the case.

It may be reiterated that the objective of power trading outside the long-termpower purchase agreements (PPAs) is to permit the development of electricitymarkets and enable competitive forces to determine price. The NationalElectricity Policy (NEP) recognises that, to promote market development, apart of new generating capacities, say 15 per cent, may be sold outside long-term PPAs, i.e. effectively on market-based commercial principles. In thecoming years, a significant portion of the installed capacity of new generatingstations could participate in competitive power markets. Regulators may need


to be more proactive towards promotion of the power market and takeadditional steps to bring in captive, renewables, etc. into the fold. This willincrease the depth of the power markets, provide alternatives for both generatorsand licensees/consumers and, in the long run, lead to reduction in tariff.

c. Cap on trading margin:

In the initial years, the trading companies commenced operations asintermediaries, without assuming any principal risk and as such theoperating/financial risk for traders was significantly lower. Past experienceindicates that trading licensees could be encouraged to undertake a certainamount of risk, and they will be prepared to do so. Of the over two dozenlicensees (those authorized by CERC), there are some who have not onlyimbibed operational capabilities in trading but are also financially sound.These trading companies may not necessarily assume an intermediaryposition but may, for part of the trading volume, assume a principal positionwherein they would not always have back-to-back arrangements with thedistribution companies for any commitment which they make with thegenerators. In such a situation, the traders would bear significantly higherrisks and as such would expect commensurate returns. Therefore, anyrestriction on the trading margin needs to be removed. Any cap on themargin admissible to trading licensees may only prove counter-productivewith regard to the process of trading and its becoming an instrument/catalyst for capacity development. In the most simplistic model of a traderonly functioning as an intermediary, such a stipulation could perhaps bejustified, but unless we think of different alternatives and structureappropriate risk–reward models which could permit various types of traderswith their meaningful contribution, we may end up defeating the objectiveof trading being a distinct licensed activity and the resultant outcomesexpected from such institutions.

In short, the removal of the restriction on the trader-to-trader transaction,and the lifting of the cap on the trader’s margin will lead to the development oftrading markets that will ensure market price–based competition amongst thetraders. In addition, the traders will be encouraged to introduce new productsin the electricity markets and differentiate their offerings to the end-consumer,resulting in benefits to the latter.

4. OPEN ACCESS IN TRANSMISSION

In the Electricity Act, “open access” has been defined as “the non-discriminatoryprovision for the use of transmission lines or distribution system or associated


facilities with such lines or system by any licensee or consumer or a personengaged in generation in accordance with the regulations specified by theAppropriate Commission”. It may be seen that the option has been providedto consumers, to intermediaries like trading licensees or distributionlicensees or even to generating companies. Each one of them is entitled tothe use of transmission systems or distribution infrastructure in a non-discriminatory manner.

Advantages of open access

a Enables power to be sold from surplus regions to deficit regions, therebyenabling overall economic growth in both regions.

b Encourages merchant power capacities to come up, and thereby leads tocompetition in the power markets and development of power markets.

c Provides freedom to procurers to choose their suppliers, promotingcompetition in the sector and reduction in the cost of procurement.

d Provides flexibility to generators to sell their power to procurers oftheir choice.

The present dispensation on provision of open access on transmission is sostructured that it is almost impossible to develop capacities to larger volumesoutside long-term contracts. Open-access requests are entertained for periods(a) up to 3 months and (b) 25 years or more. No trader can be in a position tomake any long-term arrangement beyond three months unless he takes the riskof beyond 25 years (a highly unrealistic proposition). Unless transactions ofvarious types, short-term, medium-term, long-term, and for interveningdurations are permitted, it will be difficult for any meaningful marketdevelopment outside PPA to materialize. A number of project developers, keento take investment risks, are facing difficulties at the time of achieving financialclosure due to restrictive conditionalities in providing open access to the grid.Unlike other commodities, electricity does need to have a dedicated transmissionsystem. Project developers can take risks in terms of likely consumers and marketprices. However, to expect the developers to accept the risk of evacuationinfrastructure/open-access availability is an unrealistic proposition in a situationof power shortages.

RECOMMENDATIONS

1. Open access period

The present arrangement of short term up to 3 months and long term of25 years needs to be modified if we have to take into account the practical


requirements of industry and consumers. Open access should be availablefor the following periods:

• Short term: up to 3 months

• Intermediate term: 3 months to 5 years

• Medium term: 5 years to 15 years

• Long term: over 15 years

The above will ensure contracts (trading and transmission) for interveningdurations (3 months to less than 25 years) and increase competitionamongst the various players in the trading/generating sphere to the benefitof the end user.

2. Transmission hubs

A large number of merchant power plants are coming up in the states of Orissa,Chhattisgarh, Jharkhand, Sikkim and Arunachal Pradesh. The CentralElectricity Authority (CEA) and the Power Grid Corporation of India Limited(PGCIL) should take up the lead in developing transmission hubs in thesestates as the development of large merchant capacities calls for largetransmission capacity additions. Such transmission capacities should be madeavailable to the merchant generation capacities on a non-discriminatory basis.Project developers could at most be expected to connect to the transmissionhubs (maximum 100 to 150 km). The CEA and the PGCIL will be in the bestposition to determine the direction of flow of power from the transmissionhubs to the load centres, and they shall keep creating the transmission network.

The contention that aiming at eliminating congestion with large investmentsmay not be optimal needs to be challenged. This approach may be applicableto a system which is stabilized and augmentation requirement is minimal. Inthe Indian context, when the growth of the power sector is expected to be8 per cent to 10 per cent a year, the stakeholders involved need not beconcerned about excess build-up on transmission. Any excess would getabsorbed within the network in a couple of years, particularly when thedemand for power is growing at 8 per cent to 10 per cent per year. In theunlikely event that the PGCIL, for some reason, is constrained to bring inrequisite funds due to the absence of beneficiary state utilities, i.e. offtakenot being tied up, then it is recommended that the funds be sought fromthe Plan Allocation on a need basis.

3. Open access charges

Pancaking of transmission charges, i.e. adding up of transmission charges ofintermediate regions in case of transfer of power from one region to another,


leads to increase in cost of power. The same renders the generated power fromefficient generators located in other regions/states expensive. It is recommendedthat a postage stamp pricing mechanism be adopted to both simplify the tariffmechanism and encourage open access.

4. Timely open access permission by state load dispatch centres (SLDCs)

There are instances where it is seen that when captive power plants approachthe SLDCs for open-access permission, the SLDCs take considerable time inarriving at a decision, leading to uncertainties for the developer. Many statesare yet to fix the transmission charges and wheeling charges. This works as adisincentive to merchant power plants and restricts competition anddevelopment of the power market.

5. Cross-subsidy charges

Cross-subsidy surcharge may need to be reworked in a manner that encouragesand facilitates open access rather than constrains this initiative. Some stateregulatory commissions have notified cross-subsidy charges which are so highthat open access would practically not be possible.

Captive Coal Mining by Private Developers | 143

The rapid growth in the Indian economy has led to a robust growth in the demandfor power, which has been constantly outpacing supply. With a view to reducing thedemand–supply gap, large additions to generation capacity have been planned.Notwithstanding efforts to have a diversified portfolio of fuel options in powergeneration, the share of coal-based generation has increased over the years, and withlarge capacity additions envisaged over the next decade, coal will continue to remainthe primary source of fuel for power generation. Besides substantial coal-based capacityadditions, the increase in demand for coal has been accentuated by improved utilizationof plants, diminishing quality of coal and inadequate availability of gas.

With rapid growth in demand for coal, coal supply is proving to be a major causefor concern. The Government of India (GOI) is targeting coal-based generationcapacity addition of about 53,000 MW by 2012 (end of the Eleventh Plan period);coal-based installed capacity would then be more than 125 GW by 2012.1 In thisscenario, there is an apprehension that coal companies may not be able to cater tothe enhanced coal requirement due to resource and other constraints. To augmentthe coal supply, the Ministry of Coal (MoC), GOI, decided to allocate captive minesto bulk users of coal, in the public and private sectors, and consequently manycaptive coal blocks have been allocated to power developers.2

In May 2007, at the Parliamentary Consultative Committee meeting of the MoC,3

it was announced that, to meet the coal demand, about 81 coal blocks withgeological reserves of about 20 billion tonnes had been identified for allocation tocompanies, both government and private, for permissible end uses. Of these,41 coal blocks, with geological reserves of about 15.7 billion tonnes, were earmarkedfor the power sector. Currently, the allocation of coal mining blocks to companies,other than Coal India Ltd (CIL), is done either under the government company

CAPTIVE COAL MINING BY

PRIVATE POWER

DEVELOPERS:Issues and the Road AheadOctober 2009

10


dispensation route4 or through the captive dispensation route. These blocks forthe power sector have been further categorized in three separate lists on thebasis of method of allocation, namely government company dispensation route,screening committee5 route and tariff-based bidding as per the Ministry of Power(MoP) guidelines. The details of these blocks identified for the power sector areas follows:

Table 10.1: Coal blocks identified for the power sector

Method of allocation No. of blocks Total reserves(billion tonnes)

Government dispensation route 10 6.1

Tariff-based bidding as per Ministryof Power guidelines 16 6.0

Screening committee route 15 3.6

Total 41 15.7

According to the MoC, till 31 December 2007, 170 captive coal blocks had beenallocated, of which 15 blocks allotted to three PSUs and nine private companieshad already started producing coal. Of the 170 captive coal blocks allotted (withreserves of 39.3 billion tonnes), 76 coal blocks with reserves of about 23.6 billiontonnes had been allotted to the power sector (24 coal blocks were allottedin 2007).6

It may be noted that production of coal through open cast mining may notneed a lengthy lead time unlike in the case of underground mining, whichinvolves a lengthy gestation period, particularly when the stripping ratio is high.Given the foregoing, one may be misled into believing that coal production canstart within a short period from the allotted coal blocks. This is not the case, asthe allocated mines could also involve underground mining.

Discussions with private sector and public sector coal mine allottees haverevealed that the lead time is at least four to six years on account of initialplanning, conducting geological studies to authenticate quantum and structureof reserves, obtaining several statutory approvals from a multitude of authoritiesand agencies, formulating mining plans and getting approvals, land acquisition,relief and rehabilitation issues, and infrastructure development.

This note attempts to examine the problems faced by allottees of the captive coalblocks and suggests recommendations which could shorten the actual lead timeinvolved in commercial production of coal from these coal blocks.


GUIDELINES FOLLOWED FOR IDENTIFICATION OF COAL BLOCKS FOR

CAPTIVE ALLOCATION

The guidelines adopted for demarcating the blocks are such that the developers wouldface a number of problems in quickly bringing the allotted blocks to the productionstage. The MoC relies on Coal India Ltd (CIL) and Singareni Collieries Company Ltd(SCCL), for identifying the captive coal blocks. The guidelines adopted by CIL andSCCL for identifying and allotting coal blocks for captive mining are as follows7 :

• The blocks offered to the private sector should be at reasonable distance fromexisting mines and projects of CIL in order to avoid operational problems.

• Preferably, blocks in greenfield areas with little or no development of basicinfrastructure, like road or rail links, may be allotted to the public/private sectorfor captive mining. The areas where CIL has already invested in creating suchinfrastructure for opening new mines should not be handed over to the privatesector, except on reimbursement of costs.

• Blocks already identified for development by CIL, where adequate funding ison hand or in sight should not be offered to the private sector.

• The public/private sector should be asked to bear the full cost of explorationin the blocks offered.

• For identifying blocks, the requirement of coal for about 30 years would beconsidered.

• Others, which include mine plan approval under the provisions of the Minesand Mineral (Development and Regulation) Act 1957, approval of theDirectorate General of Mine Safety, and inspection by the Coal Controller forappropriate enforcement of conservation measures under the provisions ofthe Coal Mines (Conservation and Development) Act 1974.

Given the fact that the blocks are identified at a distance from the existing infrastructureof the CIL and also that coal blocks are located in remote areas devoid of all basicinfrastructure, like roads, rail links and electricity it is difficult for the coal block allotteesto quickly bring the coal blocks to production stage. The development of infrastructureon a piecemeal basis, i.e. individually on a block-by-block basis, may cause a drain onthe resources of the developer, would not bring in economies of scale, and could beonerous as well. Further, the blocks identified are only regionally explored with inadequateinformation, which adds to the risk and causes a delay in the development of the blocks.

Thus, to facilitate speedy development of coal blocks, it is recommended that thefollowing be considered in identifying and allocating the blocks:

• If there are coal blocks in the vicinity of the CIL/SCCL—blocks which are notincluded in the expansion plans of CIL/SCCL—then these blocks should also


be included in the list of captive blocks for allocation and not excluded simplybecause of their proximity to CIL/SCCL blocks.

• In identifying captive coal blocks at a ‘reasonable’ distance from existing minesand projects of CIL/SCCL, it should be ensured that the distance should notput the captive coal block developer at a disadvantage in terms of availableinfrastructure and other facilities.

• Without disturbing the present procedure of coal block allotment, the futureallotment should be on the basis of better investigation, for which CMPDILand other agencies should be mobilized.

Further, in the context of inadequacies in infrastructure associated with the captiveblocks identified for allocation, it is recommended that the central/state governmentagencies facilitate development and creation of infrastructure in the mining areas,particularly in providing right of way, railway clearances, water, electricity, etc. TheGovernment could also consider pre-identification of non-coal bearing corridorsto be used for rehabilitation colonies and townships.

The captive block developers should coordinate with other coal block developers inproximity to jointly fund the development of infrastructure based on a master planprepared by an independent agency.

ALLOCATION OF COAL BLOCKS

Allocation of coal blocks should not only look into the promoter background andthe end-use but should also give importance to the technical and financial capabilityof the applicants for timely development of the blocks. The process of allocation ofthe blocks could also take into consideration the extent of the preparedness of thedevelopers and the projects. Further, the auctioning approach may be adopted forallocation of coal blocks. However, it may be noted that auctioning of the block tothe highest bidder may not be economically viable, since it would get translatedinto a pass-through in the cost of the end-use product and thereby adversely affectthe ultimate consumer.

The following approaches, depending on the level of information available for thecoal blocks, may be adopted in taking the auctioning route for allocation of blocks:

Table 10.2: Criteria for allocation of coal blocks

Status of block Possible criteria for allocation

Fully explored Lowest cost of power generated

Partly explored Maximum estimated production

Totally unexplored Production-sharing formula

Auctioning on the basis of the maximum proposed production or a production-sharing formula may be workable till sufficient data on the depth, seam thickness,


and quantity and quality of the coal is available for the blocks put up for auction.However, once sufficient data is available for the blocks put up for auction, thecriteria for grant of block could be linked to the lowest cost of power generatedfrom the captive coal block.

APPROVALS AND CLEARANCES

In the present legislative and regulatory framework, the allottee of a captive coalblock has to obtain a multitude of clearances and approvals as stipulated under theprovisions of the Coal Mines (Nationalisation) Act, the Colliery Control Rule 2004,the Coal Mines (Conservation and Development) Act 1974 and rules thereunder,the Mines and Minerals (Development and Regulation) Act 1957 (MMDR), theMineral Concession Rules 1960 (MCR), the Environment Protection Act with itsrules and procedures, and the Forest Conservation Act with its rules and procedures.

In the federal structure of India, the state government is the owner of the mineralslocated within the boundaries of the state. Thus, though the central government allocatesthe coal blocks for captive mining, the state government grants the reconnaissance permit(RP), prospecting licence (PL) and mining lease (ML) under the provisions of the MMDRAct and Mineral Concession Rules. However, the state government can grant themining lease only with the prior approval of the central government as provided underSection 5(1) of the MMDR Act. The central government approves the applicationonly after the coal block allottee obtains the mining plan approval and clearancesfrom several authorities at the central, state and district levels.

Although broadly three clearances are required—grant of RP or ML, environmentalclearance and forest clearance, depending on whether the allotted block is exploredor unexplored, in forest or non-forest areas, etc.—clearances may be required frommultiple authorities. Table 10.3 below indicates the authorities and agencies at thecentral and state levels from whom the approvals have to be sought by coal blockallottees before actual production can begin:

Table 10.3: Pre-production approvals for allottees of coal blocks

Approvals/Clearances Authority/Agency involved

Mining Lease

Approval or purchase of CMPDIL (purchase could also be fromgeological report SCCL, MECL)

Directorate General of Civil Aviation andMinistry of Defence (for unexplored blocks ifaerial reconnaissance is conceived)

Mine plan CMPDILCoal Controller


Mine safety Directorate General of Mine Safety

Mining technology & Coal Controller (under the provisions ofconservation measures; Colliery Control Rules and the Coal Minescoal categorisation (Conservation & Development) Act)

Mining Lease State Government (Mining Department),Ministry of Coal (GOI) – Reviewed at variouslevels within the departments at the state &central government levels

Environment

EIA/EMP studies State Pollution Control Board;State Environmental ImpactAssessment Authority;State Water Resource and WaterSupply Department;District Administration (for various aspectsof site clearance);Coal Controller;Department of Environment (MoEF).

Forest

Forest clearance & valuing Committee to advise GOI (MoEF);compensatory afforestation Office of Chief Conservation of Forests,

(Regional Office of MoEF);State Forest Department & District Authority;Department of Environment &Forests (MoEF);State Revenue Department;Hon’ble Supreme Court

Land Acquisition Ministry of Coal (under provisions of CBA);State Department of Revenue

Infrastructure (electricity, Appropriate departments of the statewater, railways, roads, etc.) government & ministries of

central government

It may be noted that of all the clearances, the MoEF clearance is the most time-consuming, since many departments and issues are involved in gettingenvironmental clearances and also the vast majority of the coal blocks aresituated on forest land. Even geological investigations (which require

Table 10.3: Pre-production approvals for allottees of coal blocks (contd...)

Approvals/Clearances Authority/agency involved


Lett

er o

f all

otm

ent o

f coa

l blo

ck (

zero

dat

e)

0 3 6 9 12 15 18 21 24 27 30 32 36 39 42 44 48

InfrastCoal mining

Coal pStart of prod.Start of oining op.

Source: Infraline

GR purchase

Land acquisitionmining lease grant

Submission & approval of mining plan

EIA/EMP studies & approval

Forest clearance

drilling for exploration) in these areas require MoEF approval. This is alengthy process.

The Guidelines for Allocation of Captive Blocks & Conditions of Allotmentthrough the Screening Committee, MoC, provide for the normative time limitceilings (Appendix, Table 10.5) to ensure that coal production from the allocatedcaptive blocks commences within 36 months (42 months in case the area is inforest land) of the date of issuance of letter of allocation in the case of open cast(OC) mines and within 48 months (54 months in case the area falls under forestland) from the date of the said letter in respect of underground (UG) mines.Figure 10.1 (drawing upon the ceiling time limit provided in the guidelines) is anindicative depiction of the schedule of commencement of mining operations fromthe time the coal block is allocated.

Figure 10.1: PERT chart for coal mine development

The MoC guidelines mentioned above are to ensure timely development andoperation of the allocated captive blocks. In order that timelines are adhered to, theallottee has to provide a bank guarantee, and the encashment of the bank guaranteeis dependent on achievement of the milestones consistent with the normative timelimit ceilings.

Time limits are specified in the Mineral Concession Rules and other legislation formaximum time permissible for grant of approval to an application. This is based onthe time to be taken from the receipt of the completed application. Since basicinformation required for processing the application is available at the district level,particularly for forest clearance, unless and until all such information is available,the application is considered incomplete. The time taken at various levels of scrutinydelays the process. Thus, in view of the large number of approvals required, it isunlikely that the timeline specified by the MoC for development of the coal block


would be adhered to by the coal block allottees. The existing provisions of the actsdo not provide for deemed approval status to applications if the timelines are notadhered to, and thus there is no urgency in disposing of the applications withinthe specified time.

From the above, the following limitations are thus evident in the process of grant ofclearances and approvals, which would cause significant delay in production fromthe allotted captive blocks:

• Several parallel clearance and approval processes are to be pursued at the centraland state government levels, and the allottee has to follow up the applicationswith various authorities.

• Environment and Forest clearance is extremely time-consuming, andsignificant delays arise in the public consultation process, valuation ofcompensatory afforestation, identification of non-forest land forcompensatory afforestation, enumeration of trees and completion of cost–benefit analysis by the forest departments.

• The entire process of seeking approvals lacks clarity, and often delays in oneprocess cause delays in the others. Besides, conditions of the mining lease arenot standardized and could be significantly influenced by individual judgmentof the granting authorities.

A comparative study on grant of mining leases in Australia, Canada and India,included in the Report of the Expert Group, constituted by the Ministry of Steel forformulating Guidelines for Preferential Grant of Mining Leases (2005), suggeststhat the time taken for grant of mining lease in Australia is about one to two years(12 + months) and in Canada about two to three years (12 to 36 months) as comparedto seven to eight years in India (though the Mineral Concession Rule8 provides thatthe state government shall dispose of the application for grant of mining lease within12 months of the date of receipt of application). The observations of the study arelisted in Table 10.4.

Based on the above observations and discussions, the following suggestions may beconsidered to speed up the approval process and grant of mining lease:

• A single-window approach through nodal agency set up at the state level underthe department of mines with representation from all the departmentsconcerned in various ministries. The nodal agency can predetermine theconditions for each category of land based on environmental sensitivity andthe nature of the proposed activity (prospecting, mining, etc.). The nodal agencymay complete the requirements of identification of land for compensatoryafforestation, enumeration of trees, cost–benefit analysis, etc. before invitingapplication for ML.


State is fully empowered togrant mining lease

Single-window process,involving four agencies:

• Department of Minerals& Energy

• Department ofEnvironment

• National Native TitleTribunal

• Land AcquisitionAuthority in LocalGovernment

Minister of Minerals andEnergy is the finalapproving authority, andtakes decisions inconsultation with otherMinistries. Close interactionbetween Department ofMinerals and Energy andagencies responsible forprotection of environment.

Mining Lease: Time takenfor grant of mining lease isone to two years. Timetaken for activities involvedare fixed and largelyadhered to, except in caseswhere public consultationprocess and stakeholderparticipation is involved.

Applicants submitapplication for grant of

Table 10.4: Comparison of mining leases in Australia, Canada and India

Australia Canada India

State is fully empowered togrant mining permit (MP)

Single-window process,involving three governmentagencies:• Department of Natural

Resources• Department of

Environment• Department of Labour

Mining Lease: The timetaken for grant of MP is twoto three years. Fixed timeframes are complied with.

The project can be rejectedif there are strong chancesof adverse socio-economicand environmental impacts.

State to grant mining leasewith the approval of theCentral Government

Approvals are requiredfrom a multitude ofauthorities at the central,state and district levels, withthe different authoritieshaving little or nocoordination amongstthem. Broadly threedifferent clearancesrequiring submission ofseparate applications:1)Approval of grant of ML2) Forest clearance3) Environmental

clearance

Central Government grantsforest and environmentalclearances on therecommendations of thestate government.

Mining Lease: Althoughtime frames for clearancesand approvals arespecified as less than a yearin the various rules, theactual time taken is usuallyseven to eight years forgrant of ML.

Identification of non-forestland for compensatoryafforestation is a lengthy


Table 10.4: Comparison of mining leases in Australia, Canada and India (contd...)

Australia Canada India

lease to the Mining

Registrar in the Department

of Minerals & Energy.

Mining areas are

categorized as per

environmental sensitivity.

Conditions and procedures

for each category are

predetermined and

identified in each case.

Grant of mining leases in

very sensitive areas requires

approval from both Houses

of Parliament.

Applicant is required to

submit a bond to take care

of environmental and

rehabilitation

considerations.

Financial and technical

strengths of the applicant

are taken into

consideration before grant

of mining lease.

Minimum term of mining

lease is granted for 21 years.

The project is first assessed

from an environment angle,

before processing for

mining permit (MP). Once

the project gets

environmental clearance,

the proponent makes an

application for MP.

Department of Natural

Resources requires a bond

or security to ensure that

reclamation work is

carried out.

Information not available

The minimum term of

mining permit is 20 years.

process, and sometimes

takes more than a decade.

Requirement of

enumeration of trees; cost-

benefit analysis carried out

by the State Forest

Department is time-

consuming (10 to 12 months)

—

Limited emphasis being

given to the technical and

financial strength of the

applicant.

Mining lease is granted for

20 to 30 years.


Since a single-window approach may require change in legal procedure,alternatively a Public–Private Partnership model can be adopted in the formof a shell company formed for each of the captive blocks allocated, as has beendone in the case of UMPPs in the power sector, wherein shell companies(formed by the public sector) are bid out to the private sector only afterobtaining clearances and completion of the land acquisition process.

• As an immediate remedial measure, MoEF should map and segregate the entirecoal-bearing areas into ‘Go’ and ‘No-Go’ areas for each type of lease(reconnaisance, prospecting, and mining) on the basis of forest cover, andenvironmental and ecological sensitivity. The GOI/MoC, by not allotting theblocks under the ‘No-Go’ areas, would prevent wastage of resources and alsospeed up the approval process for grant of lease. Thus, for areas defined as‘Go’, it may be prudent to allow minimal or no forest and environmentalclearances for investigative or prospecting purposes, with the conditionalitythat cutting of trees without prior permission is not allowed. Thus, althoughthe need for detailed environmental impact studies, assessment ofcompensatory afforestation and enumeration of trees and cost–benefitanalysis for forest clearance is required for mining approval, the same levelof detail may not be required for limited drilling involved in prospecting orinvestigative purposes.

• Forest clearance is a contentious issue, and the problem has been furthercompounded by the development which requires, in each case of forestclearance, concurrence by the forest advisory committee or the empoweredcommittee, which has to then send a report to the Hon’ble Supreme Courtbefore sanction is accorded. This procedure needs to be reviewed, and theempowered advisory group or the empowered committee and the MoEFcould be delegated authority to accord approval in certain defined categoriesof forest areas.

• MoEF clearances for projects which have a greater probability of commencingoperations before the Eleventh Plan should be given priority.

• Approval for the prospecting licence by the state government should be issuedas the foremost requirement within a minimum time. The developer couldthen develop the coal block in two or three phases, i.e. identify comparativelyeasier areas within these blocks (keeping in view government/private land,forest/non-forest land, etc.) and get on with the required investigations,mining plan, approach, etc. for the first phase so that production could startearly, and also repeat the cycle of activities in the subsequent phases. Thisapproach will require due consideration and consent by the Ministry of Coalas well as the MoEF.


LAND ACQUISITION

Unlike in the case of other industries, siting of a coal mine does not leave room forchoice in the land to be acquired. Land has to be acquired where coal exists,irrespective of population base or existence/density of forest land. The presentprocedure regarding land acquisition is lengthy and is prone to litigation. In a greatnumber of cases, a large part of the land belongs to the government, and in suchcases the government should take measures to transfer the land to the developers ina shorter time frame.

Rehabilitation of project-affected people

As regards rehabilitation of project-affected people (PAP), there are many prevalentresettlement and rehabilitation (R&R) policies. The central government has aNational R&R Policy 2007, which provides for the state governments to have theirown policies. The R&R policies for the benefit of the PAPs are more stringent onthe project developers. Also, providing employment to all PAPs may not always bepossible as new technology-driven mining methods are less labour intensive.

It is recommended that the MoC coordinate with the state governments to alignthe state R&R policies with the national R&R policy. Further, the stategovernments should help developers negotiate the compensation package withthe PAPs.

For general development and improvement in the coalfield areas, the stategovernment could consider creating an Area Development Fund by applying a levyon each tonne of coal produced. This fund could be utilized for social welfare ofPAPs, including their health and education, improvement of infrastructure, roads,water supply, etc.

Geological investigations and mining plan—Alternative agencies

In most coal blocks allocated to companies, detailed geological investigations havenot been done. At present, exploration for coal in India is carried out by theGeological Survey of India (GSI), Mineral Exploration Corporation Ltd (MECL),Singareni Collieries Company Ltd (SCCL), and directorates of mines and geologyof some states. These agencies have limited capacity for drilling of areas (for collatingdata) and, currently, are already fully stretched. Out of 22,400 km2 of the coal-bearingsedimentary formations identified by the GSI, only about 10,200 km2, or only45 per cent of the total area, has been systematically explored through regional andpromotional drilling.

Apart from geological investigations, in the present legislative framework, the miningplan is approved by the MoC (with technical inputs from CMPDIL). This furtherdelays the whole process.


Thus, new agencies with the competence to perform geological investigationsneed to be set up and accredited by the GOI. These agencies should beindependent and unaffiliated to Coal India Limited or other public sector coalcompanies. These agencies or an independent expert group should also beempowered to review and approve the mining plan, which would be an input tothe MoC.

Tapering coal linkage/marketing of surplus coal

The time frame for development of the coal block is likely to be much longer thanfor a power plant in view of the various problems faced by the developers.Therefore, there is a risk that the power plant would be commissioned prior tothe commercial operations date of the coal mine. In order to mitigate this risk ofdelay in the commercial operations of the coal mine, the MoC has decided toprovide coal linkage on a tapering basis to the power producers who have beenallotted coal blocks for captive use. The tapering linkage is being considered bythe MoC to facilitate the working of end-use plants in case development of coalblocks allocated to such consumers does not synchronize with the operation ofend-use plants. In this regard, the MoC, in December 2007, came out with aguideline relating to issuance of LoA/allocation of coal on a ‘tapering basis’ tovarious consumers. However, the application for such tapering linkage wouldonly be considered if the applicant has an approved mining plan for the coalblock allocated.

This is tricky, and most of the captive block owners are unlikely to qualify for taperinglinkage even if their end-use plant is in an advanced stage of development. TheMinistry of Coal should consider reviewing this condition for grant of taperinglinkage to facilitate rapid capacity addition in power (considering the huge deficitsituation in power and sustenance of economic growth), and should considergranting tapering linkage based on the technical and financial capability of thedeveloper and preparedness of the end-use project. Instead of keeping approvedmining lease as the criterion for considering the application of tapering linkage, theMoC should provide for the condition that the mining lease be approved before thepower plant commences operations.

Joint allotment of coal blocks

In some cases, a coal block has been allotted to a number of companies and theallottees have been required to submit bank guarantees to safeguard commercialobligations and ensure timely development of the allotted coal blocks. If somepartner companies of the proposed joint venture do not furnish the bank guarantee,then the development of the mine and its associated power plant is held up.


It is recommended that if in the consortium of companies granted a coal block, oneor some of the partners are not serious, but the remaining partners are serious, thenthe progress of the development of the block by the consortium should not bejeopardised. Thus, companies in the consortium who furnish the bank guaranteeshould be allowed to proceed with development of the coal block, and the partnerswho fail to provide the bank guarantee should be replaced with other companiesfrom among the applicants whose applications are pending with the ministry.However, pending the replacement of partners, the development of the coal blockshould proceed as usual. In this regard, the company allocated the coal block, havingthe requisite financial strength, could also be given the freedom to choose partnersfrom among the applicants whose applications are pending with the ministry.

Infrastructure status for coal industry

The coal industry needs to be given infrastructure status so as to attract more playersinto this industry and to incentivise domestic production of mining equipment.The infrastructure status could be for both coal mining and coal washeries.Infrastructure status for the coal sector would bring it on a par with other sectorssuch as roads, railways and oil, and the laying of oil and gas pipelines.

In the past, this proposal was rejected as the bulk of coal mining was under the publicsector. Coal mining, however, is expected to undergo a major change in the comingyears, with production from captive blocks mainly by private sector companies. Themain beneficiaries would be power companies as concessions would make coalproduction economical and ultimately help in keeping power tariffs low. Coal companieswould be also able to import capital equipment and spares at concessional rates.

APPENDICES

APPENDIX 1Table 10.5: Normative time limit ceilings as provided in guidelines for

allocation of captive blocks and conditions of allotment through the screeningcommittee, Ministry of Coal

Sr. Event Time limitno. in months from ‘0’ date

1 Allocation 0

2 Purchase of GR 1.5

3 Bank guarantee 3

4 Mining lease application 3

5 Mining plan submission 6


Table 10.5: Normative time limit ceilings (contd...)

Sr. Event Time limitno. in months from ‘0’ date

6 Mining plan approval 8

7 Previous approval application 11

8 Previous approval 11

9 Forest clearance application 12

10 Forest clearance 18

11 Environment clearance application 12

12 Environment clearance 18

13 Mining lease grant 24

14 Land acquisition begins 9, 19

15 Land acquisition 30, 36

16 Opening permission application 34, 40 for OC

17 Opening permission grant 35, 41 for OC

18 Production 36, 42 for OC

48, 54 for UG


APPENDIX 2 (A)

Figure 10.2: Flowchart of mining proposal approval process

Source: Mining Approvals in South Australia, Regulatory Guideline No.1 of the Division ofMinerals and Energy Resources, Government of South Australia, June 2007

Note: PIRSA - Department of Primary Industries and Resources; TRC - Tenement ReviewCommittee - PIRSA independent peer review committee for lease application assessments; DAC -Development Assessment Commission; EIC - Extractive Industries Committee - a subcommitteeof DAC; EPA - Environment Protection Authority; MARP - Mining and Rehabilitation Program;SEB - Significant environmental benefit (offset for native vegetation clearance)

ApplicantResponsibilities

PIRSAResponsibilities

Initial stakeholder consultation

Assess risks with key stakeholders (including PIRSA)

Prepare draft proposal

Assessment report drafted including lease conditions

MINING MAYCOMMENCE

MARP/SEB plan assessed andapproved

EPA Licencegranted

Formally apply forEPA Licence (if required)

Matter is referred to Cabinet orproposalmodified

Applicantrevises

proposal

Waivers obtained(if required)

Assessment report endorsed by PIRSA TRC?

Lease grant intention endorsed by Director of Mines.Is referral to DAC or Minister for RiverMurray or Minister for Environment and

Conservation required?

Minister for Environment and Conservation recommends grant?

EIC of DAC recommends

grant?

Minister for River Murrayrecommends grant?

Is Native titleagreementrequired?

MARP prepared

Minister or delegate grants Lease.

Lease offered to applicant

Native title Agreement registered with PIRSA

Native title agreement negotiated

Are Lease conditions accepted by applicant?

Bond paid.

Comments provided by other agencies

Is consultation with other agencies required?

Applicant appeals to Minister

Has proposal changed materially

Is response adequate?

Applicant prepares response

Responses to consultation collated and referred to applicant for response

Proposal publicly advertised and circulated to other government agencies

Formally lodge proposal with PIRSA

Is proposal suitable for public circulation? Return toapplicant

No

No

No

NoNo

No

No

No

No

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes YesYes

Yes Yes

No

No

Other agencyResponsibilities


APPENDIX 2 (B)Table 10.6: Minimum time frame of process

Step Activity Duration Comment

1 Applicant engages and Duration dependent on applicant’sundertakes consultation with resources, complexity of project, andrelevant stakeholders and stakeholder sensitivity.acquires relevant studies.

2 Applicant organises risk Duration dependent on applicant’sworkshop with key stakeholders, resources, complexity of project, andincluding PIRSA and other stakeholder sensitivity.relevant government agencies.

3 Applicant prepares proposal, Duration dependent on applicant’staking into account these resources, complexity of project, andguidelines and identified stakeholder sensitivity.stakeholder concerns.

4 Applicant submits draft 1 day Nominal timeframeproposal

5 PIRSA reviews draft 2 weeksproposal

6 If acceptable - Step 7. Otherwise back to Steps 1 to 3

7 Applicant formally submits Duration dependent on applicant’slease application and proposal resources and efforts so far

8 PIRSA commences statutoryprocessing of mining leaseapplication. This includes Statutory 14-day time frame topreparation of advertisement for 2 weeks notify landowner and council.relevant newspapers and formal Approximately 2 weeks to preparenotification to landowner and for formal consultation.council that an application hasbeen received.

9 Formal public consultation 2 to 8 The statutory time frame is at leastperiod. (Written submissions weeks 14 days. Dependent on complexityreceived from agencies and or more of project and PIRSA assessment ofpublic). consultation undertaken by applicant,

the time frame may be extended atrequest of individual stakeholders.

10 Applicant formally asked to Depends on extent of stakeholderrespond to issues raised during concern.consultation. PIRSA may


Table 10.6: Minimum time frame of process (contd...)


summarise issues raised in public 2 weeksconsultation and recommend or moreactions to be taken by applicantto address issues raised.

11 Applicant produces response Duration at applicant’s discretion.document. Document will be made public.

12 If acceptable, Step 13. Otherwise (major issues are raised, or major material changesto the project are proposed) back to Step 10, or Steps 1-3.

13 PIRSA assesses all documentation This is a major task for PIRSA. This

(including proposal, time frame cannot be reduced

submissions and response) 4 weeks without compromising quality of

and produces formal Assessment assessment. Assessment report is

Report, including detailed made public.

lease conditions.

14 Consideration of Assessment PIRSA will manage as far as possible

Report and Draft Lease 2 weeks to keep to a minimum.

Conditions by Tenement Review

Committee and Director of Mines.

15 Consideration of lease Not under PIRSA’s control. Subject

conditions by Minister for to EIC/DAC meeting arrangements,

Planning (Schedule 20 area of and Minister for Environment and

Development Act); Minister for Conservation or River Murray

Environment and Conservation time frames. If the recommendation

(regional reserve or jointly of PIRSA is rejected by DAC or

proclaimed park under National Minister for Environment and

Parks and Wildlife Act); and/or Conservation or Minister for River

Minister for the River Murray Murray, the matter may be resolved

(River Murray Protected Area). in Cabinet.

16 Applicant negotiates native

title access and/or aboriginal Duration at applicant’s discretion

heritage access and registers with

PIRSA (if subject to native title).

17 Formal offer of mining lease 1 week

with detailed conditions.

18 Applicant accepts offer of 21 days is a statutory time frame to

mining lease terms and 3 weeks which a response must be made by

conditions. the applicant. The time frame may be


extended at the discretion of PIRSA.If applicant does not accept terms andconditions offered, the applicant mayappeal directly to the Minister.

19 Formal grant of mining lease. 1 week

20 Company formally applies for Duration at applicant’s discretionEPA licence and works approval(if required).

21 Company finalises MARP Duration at applicant’s discretionand SEB plan.

22 Consultation on MARP with Not under PIRSA’s control. Subject toother government agencies, if other agency timeframes.required by lease conditions orfor other reasons.

23 PIRSA assesses draft MARP 2 weeksand sets bond.

24 PIRSA formally approves MARP 1 weekand SEB plan (if required).

25 EPA works approval/ Not under PIRSA control.licence issued.

26 Leaseholder pays bond to PIRSALeaseholder obtains waivers and Duration at leaseholder’s discretion.provides copy to PIRSA(if applicable).

27 Leaseholder may commencemining

TOTAL minimum timeframe approximately 6 months from formal submission of anacceptable mining lease proposal, dependent on complexity of project, quality ofstakeholder engagement undertaken by applicant, PIRSA and other government agencyworkloads. If any part of this process covers the Christmas – New Year period, a furthermonth can be added to the approximate time frame.

Source: Mining Approvals in South Australia, Regulatory Guideline No.1 of the Division of

Minerals and Energy Resources, Government of South Australia, June 2007

Table 10.6: Minimum time frame of process (contd...)



NOTES

1. Power Scenario at a Glance for All India, CEA, GOI, July 2008; White Paper on Strategyfor 11th Plan, CEA & CII, August 2007.

2. Under the provisions of the 1993 amendment to Coal Mines (Nationalisation) Act 1973.

3. 81 coal blocks identified for allocation under captive END-USE, Press Release, PIB, GOI,18th May 2007.

4. Under the government dispensation route, the block is allocated to a governmentcompany and this company has the right to be used for a specific end-use such as power,steel and cement.

5. A screening committee has been set up in the MoC for screening the proposals receivedfor captive mining of coal and lignite. The screening committee comprises membersrepresenting the Ministry of Coal, the Ministry of Power, the Ministry of Railways, theMinistry of Steel, state governments concerned, CIL, CMPDIL, and the Department ofIndustrial Policy & Promotion (Ministry of Industry).

6. Coal Directory of India 2006–07, Part-I: Coal Statistics, Ministry of Coal, GOI

7. Coal Directory of India 2006–07, Part-I: Coal Statistics, Ministry of Coal, GOI

8. Mineral Concession (Amendment) Rules 2002.

9. The mining proposal approval process and minimum timeframes of process as providedin the Regulatory Guideline No.1 of the Division of Minerals and Energy Resources,Government of South Australia, June 2007, are presented in Appendix 2. The regulationslaid down by the Department of Industry & Resources, Government of Western Australia,are similar.

Distribution Reforms in Andhra Pradesh | 163

INTRODUCTION

The Andhra Pradesh State Electricity Board (APSEB) was formed on 1 April 1959.Until its unbundling in February 1999, APSEB was responsible for electricitygeneration, transmission, distribution and supply. It functioned under the overallguidance of the state government, interacting with the central power agencies forplanning and coordination.

The APSEB enjoyed a good reputation amongst the other utilities in India. Theplant load factor (PLF) of APSEB-owned generation stations was 83.2 per cent in2000, much higher than the national average of 67 per cent. The VijayawadaThermal Power Station (VTPS) received the productivity award in 2000 (PLF of86.9 per cent) and the Rayalaseema Thermal Power Plant (RTPP) won the incentiveaward. Other aspects of good performance include rapid erection of power stations,and low employee/consumer ratio.1 The APSEB was the third-largest SEB in termsof units of power sold, next only to Maharashtra and Gujarat.2

REFORMS IMPERATIVE IN THE STATE

Though APSEB’s performance on the generation side was far better compared toother state electricity boards, its performance on distribution and financial aspectswas poor.1 By the late nineties, the state was facing both energy and peak shortagesand the quality of power supply had deteriorated; the power utility’s financiallosses had grown to Rs 39 billion and new investments were not financeable.The power subsidies had increased to 1.6 per cent of the Gross State DomesticProduct (GSDP), while on the other hand the combined public expenditure onhealth and education had declined from 4.7 per cent of GSDP in FY1987 to

POWER DISTRIBUTION

REFORMS IN ANDHRA

PRADESH

October 2009

11


3.6 per cent of GSDP in FY1998.3 The gap between average cost of supply (ACS)and average revenue realized (ARR) grew from 4.2 paise/kWh in 1990–91 to138.8 paise/kWh in 1999–2000.2

Power sector reforms became imminent as in their absence the need for subsidiesfrom the government’s budget would have continued to grow and crowd out socialsector investments.

Figure 11.1: Cost of power supply, average tariff and gap

Source: Annual Report (2001–02) on the Working of State Electricity Boards & ElectricityDepartments, Planning Commission (Power & Energy Division), Government of India,May 2002

Box 11.1: APSEB’s performance review

• Power deficit: The power shortage faced by the state kept on increasing despitesignificant growth witnessed in generation in Andhra Pradesh. The total deficitincreased from 6.7 per cent in 1991–92 to 8.5 per cent in 2001–02. During the sameperiod, peak power deficit saw an increase from 15.8 per cent to 19.9 per cent.2

• Transmission and distribution losses (T&D losses): Inadequate infrastructure, lowinvestments in new infrastructure and improper O&M of the network led to anincrease in T&D losses reported by APSEB. T&D losses as a percentage of availabilityincreased from 19.2 per cent in 1992–93 to 35.2 per cent in 1999–2000.2

• Gap in cost and revenue realized: The gap between cost of power supply and theaverage tariff realized from the customers denotes the margin for a powerdistribution business. This gap grew from 4.2 paise/kWh in 1990–91 to138.8 paise/kWh in 1999–2000.2

350

300

250

200

150

100

50

0

Pai

se/k

Wh

1990–91 1991–92 1992–93 1993–94 1994–95 1995–96 1996–97 1998–991997–98 1999–2000

4.2 5.9 5.8 10.4

36.059.0 57.8

73.1

122.3

138.8

Cost of power supply Average tariff Gap


• Increasing losses and subsidy: Increasing T&D losses combined with the large gapin cost of supply and revenue realized led to deterioration in the financial healthof APSEB. Commercial losses without subsidy increased from Rs 4 crore in1992–93 to Rs 3117 crore in 1999–2000. Subsidy received from State Governmentincreased during the same period from zero to Rs 3064 crore.2

T&D losses as % of availability

Source: Annual Report (2001–02) on the Working of State Electricity Boards &Electricity Departments, Planning Commission (Power & Energy Division)Government of India May 2002

Commercial loss (without subsidy)

Source: Annual Report (2001–02) on the Working of SEBs & Electricity Dept.,

Planning Commission (Power & Energy Division), Government of India May 2002

The deteriorating situation on the power front in Andhra Pradesh had a number ofcauses. Some of the main reasons are:

• Change in hydro-thermal energy mix: In Andhra Pradesh, historically, installedcapacity of hydel power used to be greater than that of thermal power.

40

35

30

25

20

15

10

5

0

1992–93 1993–94 1994–95 1995–96 1996–97 1998–991997–98 1999–2000

3500

3000

2500

2000

1500

1000

500

01992–93 1993–94 1994–95 1995–96 1996–97 1998–991997–98 1999–2000

4 23

9811255

939

2679

1376

3117


In 1960–61, hydel power accounted for 58.2 per cent and thermal power for41.8 per cent of the installed capacity. Over time, this mix has changed infavour of thermal power. In 1990–91 the proportion of installed capacityconstituted 50.1 per cent hydel power and 48 per cent thermal power, whichfurther changed to 36.5 per cent for hydel power and 42.9 per cent for thermalpower by 1997–98. The remaining power capacity in 1997–98 was in gasprojects.1 As the proportion of cheaper hydel power declined over time andthe proportion of costly thermal power increased, so did the average unit costof power. With the rising average cost of power supply, the gap in ACS andARR widened, leading to deterioration in the financial health of APSEB.

• Change in load mix: There was a huge disparity between agricultural andindustrial tariffs over the years, putting pressure on the industrial sector andleading to stagnation in industrial consumption. Slowly, industry movedtowards cheaper captive generation. Sale of power to industry declined from35 per cent in 1993–94 to 24 per cent in 1999–2000, while sale to agricultureremained unchanged at around 40 per cent during the same period. Theaverage tariff charged from industry and agriculture during 1999–2000 was394.9 paise/kWh and 15.35 paise/kWh respectively2.

REFORMS UNDERTAKEN

In the background of the deteriorating situation on the power front and the newinitiatives by the Government of India to attract private investment, the stategovernment contemplated restructuring the power sector. Reforms were broughtabout in multiple steps.

Hiten Bhaya Committee

The Government of Andhra Pradesh constituted a high-level committee under thechairmanship of Hiten Bhaya, a former chairman of the Central Electricity Authority,to suggest reforms in the power sector. This committee was constituted inJanuary 1995, and it submitted its report in June. The important proposals made bythe Hiten Bhaya committee were:

• A tariff structure which covers production costs

• Restructuring APSEB on a functional basis to promote efficiency and functionalspecialization by unbundling APSEB. Constituting separate companies for eachfunction (namely generation, transmission and distribution) and putting themin the hands of different companies

• Keeping the companies thus formed as subsidiaries of APSEB

–


• Running the companies on commercial lines

• Retaining the board as a holding company in charge of long-term sectorplanning, supervision and co ordination of the subsidiaries

• Government to retain role of monitoring reform implementation and advisingon policy

• Setting up a regulatory commission to fix tariff structure and keep licensingpowers with the state government

• The committee did not recommend outright privatization of public utilitiesand cautioned that substituting private monopoly for public monopolywould only make the situation worse. The committee felt that theprivatization initiative should start initially with management contracts inthe distribution business.

The World Bank and the AP power sector restructuring programme

After Chandrababu Naidu became chief minister in September 1995, the Governmentof Andhra Pradesh (GoAP) approached the World Bank for a structural adjustmentloan to tide over the fiscal crisis that it was facing. In response, the World Bank broughtout a comprehensive report, AP—Agenda for Economic Reforms, in January 1997,outlining its approach to reforms, including the power sector.

The bank suggested comprehensive reforms in the power sector going beyond therecommendations of the Hiten Bhaya Committee. Some important components ofthe reforms proposed by the World Bank were:

• Defining a structure for the sector consistent with privatization of distributionand private sector development in generation

• Corporatizing power utilities and ensuring that they operate withoutgovernmental interference

• Creating an independent and transparent regulatory system for the sectorwith a broad range of responsibilities, including granting of licences andenforcing them

• Enacting comprehensive reform legislation to establish the new regulatoryframework and implement restructuring measures

• Increasing the tariff rate for agriculture to at least 50 paise/kWh in thenear term and continuing to adjust tariffs to cover costs and reducecross-subsidies.


Table 11.1: Steps taken for power sector reforms in Andhra Pradesh

1995 June Hiten Bhaya Committee Report

1996 September World Bank’s Agenda for Economic Reforms in Andhra Pradesh

1997 March AP State Government’s Policy Statement on Power Sector Reforms

1998 April Passing of AP Electricity Reforms Bill in the State Legislative Assembly

1999 January World Bank’s PAD on AP Power Sector Reforms Programme (APPSRP)

1999 February AP Electricity Reforms Act 1998 comes into force

1999 February APSEB unbundled into APGENCO and APTRANSCO

1999 April AP Electricity Regulatory Commission starts functioning

2000 March APTRANSCO further unbundled into APTRANSCO and four discoms

2002 April Financial autonomy to discoms

2002 August Employee division (option process) among APGENCO, APTRANSCOand discoms on permanent basis

2003 June Enactment of Electricity Act, 2003

2003 August Suspension of the World Bank loan after the first stage itself citing highinterest rate and unacceptable conditions

2004 May Change in government and the announcement of free power to theagricultural sector.

The bank's approach was driven by the idea of changing the ownership frompublic to private in a span of eight to ten years. The AP Power SectorRestructuring Programme (APPSRP) was to be implemented over a ten-yearperiod, starting February 1999. The Adaptable Programme Loan (APL) schemewas planned in five stages, APL-1 to APL-5. The total loan amount wasUS$4460 million, with the World Bank contributing 22 per cent of the amount.The other international lending agencies included Department for InternationalDevelopment (DFID) and Overseas Economic Cooperation Fund (OECF). TheIndian agencies included the GoAP, the Power Finance Corporation and theRural Electrification Corporation. This loan had several preconditions whichwere to be satisfied so that the utility became eligible for the next stage of theloan. These conditions included privatization of distribution and generation,average annual tariff hikes, implementing cost-based tariff and reducinggovernment subsidy to zero.

Reforms undertaken by the AP Government

Within six months of the World Bank recommendations, on 14 June 1997, theGoAP released a power sector policy statement indicating proposed policy and


structural changes in the power sector. In order to give concrete shape to this policy,the GoAP enacted the Electricity Reforms Act of 1998. The Reform Bill wasintroduced in the Legislative Assembly on 27 April 1998 and was passed onApril 28. It was notified on 29 October 1998 and came into effect in February 1999.

Figure 11.2: Power sector: Structure pre- and post-reforms

The APSEB was unbundled into APGENCO and APTRANSCO in February 1999.The Electricity Reforms Act provided for the constitution of the Andhra PradeshElectricity Regulatory Commission (APERC). In April 2000, APTRANSCO wasfurther unbundled into a transmission company and four distribution companies(discoms) managing distribution in the four zones of the State—Central, Eastern,Northern and Southern. The state government signed an MOU with the Ministryof Power, Government of India, on reform and restructuring which had the roadmap for reform, plans for tariff rationalization, metering and maintaining griddiscipline. As part of the distribution sector reforms, in April 2001 the four discomswere issued independent licences for distribution.

Andhra Pradesh took to power sector reforms much earlier than most other statesin the country. However, the pace of reforms slowed down by year 2004. Signs ofthe slowdown were visible in suspension of the World Bank loan after Stage I itself,and no attempt was made to privatize distribution. The reasons identified for thisslowdown were opposition to the reform agenda, failure of the World Bank-ledreform process in Orissa and the national-level rethinking on World Bank-ledreforms. In May 2004, the Congress came to power in AP, replacing ChandrababuNaidu’s TDP. It announced free power to agriculture and promised to review thereforms, including power purchase agreements (PPAs) with private generators.

APSEB(Andhra Pradesh State Electricity Board)

Structure prior to reforms

Structure post-reforms

APGENCOGeneration Company

APTRANSCOTransmission Company

APCPDCL(AP Central Power

Distribution Company Ltd)

APEPDCL(AP Eastern Power


APNPDCL(AP Northern Power


APSPDCL(AP Southern Power



Initiatives taken during the reform process

Power distribution sector reforms in Andhra Pradesh were concentrated on reducinglosses and improving commercial viability through improved infrastructure, betterauditing, and use of information technology. The initiatives taken during the reformprocess were:

• Theft control: The GoAP enacted an anti-theft legislation in July 2000, layingdown stringent penalties for theft of electricity, including mandatoryimprisonment of offenders. The legislation enabled constitution of specialtribunals and courts for speedy trial and recognized collusion of the utilitystaff as a punishable offence. The enforcement efforts made by both governmentand distribution companies have shown positive results in controlling theft.According to a report by the World Bank, about 5 million out of 12 millionmetered services have been inspected. About 150,000 cases of theft wereregistered during FY2000–03 compared to 9200 cases during FY1998–2000.Also, 4100 consumers and about 50 employees were arrested.3

The success of the theft-control initiatives was built on proactive measurestaken, including:

• Communicating to the stakeholders the objective, intent and the enforcementof the new act

• A regularization drive was launched to provide a one-time opportunity to theunauthorized consumers to register legally. About 2 million3 residentialconsumers were regularized.

• Implementing institutional, management and administrative changes in thepower distribution companies to ensure effective enforcement of the act

• Legal support system geared up to provide implementation support

• The vigilance department has been strengthened with appointment of theInspector General of Police as the joint managing director in the company.

• The organizational structure was modified to strengthen coordination betweenvarious departments like operations/technical department, commercialdepartments and vigilance department.

• Special police stations were set up to deal with electricity theft cases.

Initially, statewide inspections and revenue collection drives were launched targetinglarge industrial and commercial consumers, and were gradually extended to therural areas. This was supported by a comprehensive programme of consumermetering and energy audit. Discoms have developed specialized IT-based tools for


institutionalization of theft control and monitoring measures. These efforts at theftcontrol led to improvements in billing and collection by the utilities.

• Energy audit and metering: To measure power transacted at various levels anddetermine reliable extent of transmission and distribution losses in the system,a new metering drive was launched. High-quality meters were installed on theinterface points between the power sector companies. The 11-kV feeders weremetered and data loggers were installed to monitor the supply of electricity toagricultural consumers. For realistic estimation of agriculture consumption,about 30,000 distribution transformers (out of 190,000 DTRs) supplying powerto predominantly agriculture consumers were metered3.

A programme to improve the consumer metering system was also started bydistribution companies. For high-value customers, the existing meters werereplaced with high-accuracy electronic meters.

• Consumer Analysis Tool (CAT): CAT is a customer database used to analyzecustomer information in order to identify trends in metering, billing, andcollections. A key feature of CAT is to risk-profile customers to enable themanagement to design strategies for efficiency improvements targeted atspecific customer groups. The customers are grouped into different categoriesbased on their payment history—a matrix of proportion of bill paid and numberof defaults in a twelve-month payment track record.

CAT addresses the needs of a number of departments, including operations,vigilance, and regulatory affairs departments. It acts as an effective monitoringtool and helps exercise control. The results are reflected in improved billingand collection efficiency.

• Monitoring and Tracking System (MATS): MATS has been designed as a toolto assist in monitoring and tracking various cases of irregularities, like theft,malpractice and back-billing. The objectives of the system are to:

• Streamline the regularization system by reducing the effort and timerequired to inspect and follow up on irregularities

• Enable process automation to reduce high documentation requirementsand loss of records

• Enable a performance-based monitoring system to track and take actionon irregularities. MATS is based on a workflow process where eachcompleted document is automatically sent to the appropriate reviewingofficer based on the defined process. Training is given to all officers onthe usage of the system to enable them to fulfil their role.


• The system also enables performance review of the employees by trackingthe period of time each case is kept pending at each level.

• The system is highly role-based with each officer being able to track aswell as take action only on cases that lie within his/her jurisdiction.

• Investment in infrastructure: The distribution infrastructure was modernizedto bring down technical losses and improve the performance of the system.Under the first power sector restructuring loan under the adaptable loanprogramme of the World Bank (APL1), funds were provided for financinghigh-priority investments in the T&D system. Till 2006, a total ofRs 6652 crore was spent on improving the distribution system.8 These fundswere utilized for installing new meters, replacing or repairing old meters,installing new transformers and upgrading distribution lines. The yearlycapital expenditure of various discoms is shown in Table 11.2:

Table 11.2: Investment in infrastructure (Rs crore)

2001 2002 2003 2004 2005 2006 Total

APCPDCL 404 397 445 426 456 483 2611

APEPDCL 186 199 151 198 222 167 1124

APNPDCL 327 207 195 194 287 329 1537

APSPDCL 261 171 195 194 283 277 1381

TOTAL 1178 974 985 1012 1249 1255 6652

Source: Power Sector Reforms in Andhra Pradesh: Their Impact and Policy Gaps: B. SarangaPani, N. Sreekumar and M. Thimma Reddy

• Transformer Information Management System (TIMS): TIMS enables effectivetracking of the distribution transformers as well as the associated structuresthroughout their life cycle and analyzes the information to:

• Improve asset tracking, utilization and maintenance

• Improve customer service through deployment of transformers andexception handling (in case of failures)

• Enable greater visibility leading to improved decision making.

Discoms benefit financially by reducing inventory carrying costs.Operationally, they help reduce transformer downtime and evaluatevendor performance, and enable these through various reports whichindicate data like:

• Availability of stocks of DTRs in stores

• Locations with maximum transformer failures


• Identification of transformers and structures which show frequent failure

• Time required to repair transformers at each repairing location

• Book Consolidation Module (BCM): BCM is a tool aimed at reducing thetime taken and the manual intervention involved in the consolidation ofaccounts from the circle level. The tool generates balance sheets and profit/loss for the discoms after consolidation of all accounting units. In addition toconsolidation, the tool also provides for various variance reports:

• Budgeted versus actual comparisons: These reports compare monthlyvariance between budgeted and actual income or expenses from variousaccount codes.

• Comparative statements: These reports compare income/expense forcurrent month with the previous month or the previous year to calculateappropriate variances.

Outcome of reforms and initiatives

The reform process in Andhra Pradesh was started under the guidance of the WorldBank. However, the loan was suspended after the first tranche, and the regime alsochanged in AP. The new regime changed the course of the reform process, and thiswas reflected in a number of parameters used to assess the distribution sector.Some of these are discussed below:

• Aggregate technical and commercial losses (AT&C): AT&C losses in AP havedecreased from 27 per cent in 2002–03 to 16 per cent in 2007–08. Such a decreaseis attributable to the focus of reforms on reducing losses through better auditingand investment in infrastructure. However, AT&C losses have not declinedmuch since 2005–06.

Figure 11.3: AT&C losses (%)Source: Report on the Performance of the State Power Utilities for the Years 2002–03to 2004–05 and 2005–06 to 2007–08, Power Finance Corporation Limited

30

25

20

15

10

5

0

2002–03 2007–082003–04 2004–05 2005–06 2006–07

27.0

16.216.5

21.2

16.717.9


The performance of the discoms is shown in Table 11.3. While eastern andnorthern region discoms have reported low losses significantly, AT&C lossesreported by central and southern region discoms are still high. Also, post-2004–05, loss reduction has not been significant.

Table 11.3: AT&C losses (%) of distribution companies

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

APCPDCL 30.19 18.99 23.95 18.99 18.32 19.23

APEPDCL 17.61 16.57 14.27 12.19 12.09 7.46

APNPDCL 27.09 9.79 21.91 11.82 23.28 11.92

APSPDCL 27.45 17.06 20.55 19.23 17.47 20.02

Source: Report on the Performance of the State Power Utilities for the Years 2002–03

to 2004–05 and 2005–06 to 2007–08, Power Finance Corporation Limited

• Collection efficiency: The collection efficiency in Andhra Pradesh has beenabove 90 per cent post-reforms. High collection efficiency has been possibledue to the energy auditing and metering drive and implementation of toolslike MATS and CAT.

Collection efficiency of individual discoms is shown in Table 11.4.While collection efficiency of all discoms has been high, there has been a lot ofvariation in collection efficiency reported by APNPDCL.

Figure 11.4: Collection efficiency (%)



120

100

80

60

40

20

0

2002-03 2007-082003-04 2004-05 2005-06 2006-07

92.4102.9

96.5 97.2 98.1100.2


Table 11.4: Collection efficiency (%) of distribution companies

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

APCPDCL 90.52 102.39 94.81 99.04 98.51 97.46

APEPDCL 96.95 96.63 99.54 99.18 99.22 99.88

APNPDCL 92.57 113.10 96.65 104.27 89.41 96.90

APSPDCL 92.11 102.83 97.03 100.58 98.53 99.23



• Subsidy by state: Subsidy provided by the state government to the powerdistribution sector has come down significantly from the pre-reforms period.In 1999–2000, subsidy by the state was over Rs 3000 crore while the subsidyreceived in 2004–5 was Rs 1303 crore. However, post-2004–05, subsidy hasstarted increasing. Subsidy reported for the year 2007–08 was Rs 2408 crore.

Figure 11.5: Subsidy received (Rs crore)



Subsidy received by individual discoms is given below:

Table 11.5: Subsidy received (Rs crore)

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

APCPDCL 506 579 464 261 499 1108

APEPDCL 212 227 194 31 8 0

APNPDCL 353 307 311 639 839 733

APSPDCL 438 402 334 552 496 567



3000

2500

2000

1500

1000

500

02002–03 2007–082003–04 2004–05 2005–06 2006–07

1509 15151303 1483

1842

2408


• Financial viability of AP discoms:

1. Profitability: Discoms in AP have been registering losses without subsidy.While these losses were around Rs 1200 crore in 2004–05, they startedincreasing in later years. Aggregate losses registered without subsidy forthe year 2007–08 were Rs 2526 crore. With the help of subsidy, discomshave been able to cover the losses made. However, in 2007–08, aggregatelosses with subsidy were Rs 118 crore.

Table 11.6: Profit with and without subsidy

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

With subsidy 16 -135 26 308 145 -118

Without subsidy -1232 -1579 -1194 -1241 -1697 -2526



2. Gap in cost and revenue realized: Post-reforms, the gap in ACS andARR has decreased significantly for AP post-reforms. The gap reportedfor the year 1999–2000 was 138 paise/kWh as compared to48 paise/kWh in 2007–08. However, this gap has started increasing in thelast few years.

CONCLUSION

Andhra Pradesh is among the states that initiated reforms in the power sector. Thefirst steps were taken way back in 1995 with the formation of the Hiten BhayaCommittee. Actual unbundling took place in the year 2000. It has been over eightyears since the power sector has been unbundled in AP. Over this period, AP hasseen a change of regime which has also brought a change in the way reforms havebeen pursued in the state. At the time of unbundling of the APSEB, the reformswere driven by World Bank guidelines, and minimization of cross-subsidizationand privatization of discoms were considered eventual outcome of reforms.However, the World Bank's failure in Orissa led to AP withdrawing from theprogramme and to change in the course of reforms.

All the discoms are still under government ownership. Also, the new governmentannounced free power for agriculture. At the time of introduction of free powerto agriculture, the four discoms together were receiving nearly Rs 400 crore1 asrevenue from agricultural connections. It was claimed that the same amount wouldbe saved by renegotiating the PPAs with the IPPs in the state. However,


3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.02002–03 2007–082003–04 2004–05 2005–06 2006–07

ACS ARR Gap

0.37 0.380.29 0.30

0.35 0.48

increasing subsidy and the gap between ACS and ARR after introductionof free power shows that it had a negative impact on the financial health ofthe sector.

Figure 11.6: ACS, ARR (without subsidy) and gap over the years

Source: Report on the performance of the State Power Utilities for the Years 2002–03 to

2004–05 and 2005–06 to 2007–08, Power Finance Corporation Limited

The impact of distribution reforms had been positive and can be seen in decreasedlosses, improved collection efficiencies, and smaller gap between ARR andACS compared to what existed in the state prior to reforms. Also, the deficitposition of the state has improved over the years. Peak deficit for the state declinedfrom 19 per cent in 2002–03 to 7.6 per cent in 2008–09. Overall energy deficitdeclined considerably till 2003–04 but rose again and stood at 6.8 per centin 2008–09.7

Table 11.7: Peak deficit (%) and energy deficit (%) in AP

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08 2008–09Peak deficit 19.2 10.5 2.3 5.1 15.4 8.8 7.6

Energy deficit 6.8 2.9 0.7 1.3 4.4 4.1 6.8

Source: Power Sector at a Glance, April 2009, Central Electricity Authority

Performance, both in financial and operational terms, has varied across thediscoms. While APEPDCL has been able to considerably reduce its AT&C lossesand subsidy received, APCPDCL and APSPDCL have not been able to maintain asimilar performance.


Table 11.8: Subsidy received by distribution companies

APCPDCL APEPDCL APNPDCL APSPDCL

2002–03 506 212 353 438

2003–04 579 227 327 402

2004–05 464 194 377 334

2005–06 261 31 639 552

2006–07 499 8 839 612

2007–08 1108 0 733 567

Source: Report on the performance of the State Power Utilities for the Years 2002–03 to

2004–05 and 2005–06 to 2007–08, Power Finance Corporation Limited

The good performance of APEPDCL can be attributed to the customer mix, giventhe high proportion of industrial mix it inherited from APSEB (see Annexure 1).However, APNPDCL has performed even better despite having a high proportionof agricultural customers.

In the long run, there is a question mark over the commercial viability of variousdiscoms without subsidy, especially in view of the rise in subsidy requirements inthe last three financial years of this study. Also Quality of Supply (QoS) targets needto be set and measured in order to usher in a power distribution sector which isboth commercially viable and consumer friendly.

ANNEXURE 1

Sales mix, revenue mix and cost components

• Sales mix: This was inherited by discoms from APSEB depending on theirregion. While APEPDCL inherited a favourable mix due to very low agriculturalcomponent, APNPDCL sells approximately 50 per cent of its power to theagricultural sector. Over the years, the sales mix for various discoms hasremained the same.

• Revenue mix: The revenue mix of various discoms given below shows thatmaximum contribution to revenue is made by the industrial sector, irrespectiveof the proportion of sales accounted for by them. Also, it can be seen that theagriculture sector contributes very little to the revenue of discoms. Contributionto revenue by the commercial sector is also higher than the proportion of salesaccounted by them. This revenue mix clearly shows the cross-subsidizationbeing done by the industrial and commercial sectors.


Tab

le 1

1.9:

Sal

es m

ix (

%)

of d

istr

ibu

tion

com

pan

ies

2005

–06

2006

–07

2007

–08

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

Dom

estic

18.8

26.0

19.4

27.0

17.8

26.2

18.5

25.7

18.7

28.4

17.4

27.5

Com

mer

cial

9.2

5.0

3.3

5.8

10.0

5.2

3.2

5.6

6.2

5.4

3.3

6.1

Agric

ultu

ral

36.1

19.0

48.7

34.8

37.1

18.1

50.7

35.8

30.0

16.1

49.2

30.1

Indu

stria

l32

.741

.716

.024

.032

.742

.015

.325

.042

.037

.315

.028

.3O

ther

s3.

38.

512

.78.

42.

48.

512

.37.

93.

113

.015

.18.

0So

urce

: Rep

ort

on t

he P

erfo

rman

ce o

f the

Sta

te P

ower

Uti

litie

s fo

r th

e Y

ears

200

5–06

to

2007

–08,

Pow

er F

inan

ce C

orpo

rati

on L

imit

ed

Tab

le 1

1.10

: Rev

enu

e m

ix (

%)

of d

istr

ibu

tion

com

pan

ies

2005

–06

2006

–07

2007

–08

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

Dom

estic

19.4

19.6

23.6

24.4

19.9

20.7

26.9

24.1

19.2

19.9

26.7

26.8

Com

mer

cial

21.3

10.1

10.6

12.8

23.4

10.6

11.8

13.7

23.5

10.4

11.2

15.1

Agric

ultu

ral

3.6

0.8

2.0

0.8

1.4

0.8

1.8

0.5

1.3

0.7

1.6

0.5

Indu

stria

l52

.546

.938

.738

.752

.749

.138

.642

.151

.346

.034

.946

.9O

ther

s3.

322

.525

.123

.32.

718

.820

.919

.64.

723

.125

.610

.7So

urce

: Rep

ort

on t

he P

erfo

rman

ce o

f the

Sta

te P

ower

Uti

litie

s fo

r th

e Y

ears

200

5–06

to

2007

–08,

Pow

er F

inan

ce C

orpo

rati

on L

imit

ed

Tab

le 1

1.11

: Exp

ense

s as

% o

f tot

al c

ost f

or d

istr

ibu

tion

com

pan

ies

2005

–06

2006

–07

2007

–08

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

APCP

DCL

APEP

DCL

APN

PDCL

APSP

DCL

Pow

er p

urch

ase

83.8

%81

.7%

80.6

%77

.5%

86.8

%84

.1%

80.6

%79

.8%

78.4

%83

.7%

80.7

%79

.3%

Empl

oyee

cos

t4.

6%5.

7%6.

2%5.

2%5.

4%7.

2%8.

0%5.

4%5.

3%7.

8%6.

2%7.

1%O

&M

cos

t1.

2%0.

6%1.

5%1.

2%1.

4%0.

5%1.

3%1.

0%1.

4%0.

5%1.

3%1.

2%In

tere

st co

st4.

9%4.

1%4.

5%4.

5%3.

9%4.

5%2.

7%4.

6%1.

7%4.

4%2.

9%4.

7%D

epre

ciat

ion

3.4%

5.8%

4.9%

5.3%

3.5%

6.0%

4.8%

5.7%

3.2%

4.2%

4.5%

4.7%

Adm

in &

Gen

eral

expe

nses

1.3%

1.6%

1.5%

1.6%

1.2%

1.6%

1.4%

1.5%

0.8%

1.5%

1.0%

1.1%

Oth

er e

xpen

ses

0.8%

0.7%

0.7%

4.6%

-2.3

%-3

.9%

1.2%

2.0%

9.3%

-2.1

%3.

4%1.

9%So

urce

: Rep

ort

on t

he P

erfo

rman

ce o

f the

Sta

te P

ower

Uti

litie

s fo

r th

e Y

ears

200

5–06

to

2007

–08,

Pow

er F

inan

ce C

orpo

rati

on L

imit

ed


• Cost components: The cost components as percentage of cost have remainedthe same over the years. Interest cost for APCPDCL and APNPDCL hasdeclined. APEPDCL has seen a continuous increase in employee costs.

REFERENCES

1. Saranga Pani, B., N. Sreekumar and M. Thimma Reddy. Power Sector Reformsin the State of Andhra Pradesh in India.

2. Government of India. 2002. Annual Report (2001–02) on the Working of StateElectricity Boards & Electricity Departments. Planning Commission (Power &Energy Division).

3. Government of Andhra Pradesh. 2004. World Bank implementation completionreport on a loan in the amount of US$210 million to the Government of India forAndhra Pradesh power sector restructuring project.

4. Power Finance Corporation Limited. Report on the Performance of the StatePower Utilities for the Years 2002–03 to 2004–05.

5. Power Finance Corporation Limited. Report on the Performance of the StatePower Utilities for the Years 2005–06 to 2007–08.

6. Chatterjee, Rachel. 2003. Presentation. National Conference on Reforms inInfrastructure Sectors: Impact Assessment and Governance.

7. Central Electricity Authority. 2009. Power Sector at a Glance.

8. Saranga Pani, B., N. Sreekumar and M. Thimma Reddy. 2007. Power SectorReforms in Andhra Pradesh: Their Impact and Policy Gaps.

Distribution Reforms in Maharashtra | 181

INTRODUCTION

Traditionally, the power sector in Maharashtra, excluding Mumbai, has been servedby Maharashtra State Electricity Board (MSEB) which was set up in 1960 to generate,transmit and distribute power to all consumers in Maharashtra excluding Mumbai.Mumbai is served by three power utilities—Tata Power Company Ltd, BombaySuburban Electric Supply (BSES) Ltd and Bombay Electric Supply & TransportUndertaking (BEST). MSEB was the largest SEB in the country in terms of units ofpower sold till 2005–06.5 Its generation capacity grew from 760 MW in 1960–61 to9771 MW in 2001–02. MSEB's customer base of 107,833 in 1960–61 grew to 14,009,089in 2001–02. MSEB's thermal power stations were also efficient as they achieved highpower availability of 86 per cent and plant load factor of 74 per cent in 2001–02 (theaverage PLF [thermal] for various utilities was 69.9 per cent in 2001–02).2 By 2001–02MSEB had a large Transmission & Distribution (T&D) network of 6.67 lakh ckt km.1

IMPERATIVE FOR REFORMS IN THE STATE

Over time, the predominance of social objectives led to a lack of commercialorientation in the operations of MSEB. Further, tariffs for domestic, power loomsand agricultural segments were lower than the average cost of supply of power, andwere subsidized by industrial and commercial consumers. For the year 2000–01average cost of supply for MSEB was Rs 3.65 kWh whereas average realization wasRs 2.93/kWh. As shown in Figure 12.1

1 revenue realized from agricultural

connections was far lower than the cost of supply.

The distorted tariff structure led to more and more high-paying industrial consumerssetting up their own captive generating stations. This led to decline in consumption

POWER DISTRIBUTION

REFORMS IN

MAHARASHTRA

October 2009

12


of power from the MSEB grid by high-paying industrial consumers, whileconsumption by subsidized consumer categories grew over the years. Share ofelectricity sold to agricultural customers grew from 25 per cent in 1993–94 to34 per cent in 1998–99 in Maharashtra. During the same period, share of industryfell from 35 per cent to 32 per cent.

2

Figure 12.1: Average cost and realization of power in 2000–01

Further, the low tariff for subsidized consumers led not only to deterioration infinancial performance, but also to wasteful consumption from these consumers.The impact of the lack of commercial focus was reflected in both the quality ofsupply and the performance of MSEB as shown in Box 12.1.

The above factors contributed to MSEB's decline in financial health. MSEB madecommercial profits without subsidy till 1994–95. Commercial profits (withoutsubsidy) as reported in 1994–95 were Rs 276 crore. These profits declined over timeand MSEB reported a commercial loss (without subsidy) of Rs 1479 crore in theyear 1999–2000.

2 However, MSEB shows commercial profits during the year if the

subsidy of Rs 2084 crore provided by the state government is taken into account.The commercial profits stood at Rs 605 crore.

With deterioration in its financial health, MSEDCL found it difficult to invest inmaintenance and upgradation of infrastructure. This led to further deteriorationin the quality of supply and increase in technical losses. Caught in this downwardspiral, MSEB was finding it hard to escape from declining performance. Due tofinancial deterioration and ever increasing need for subsidies, need for reformsbecame eminent.

5.0

4.5

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0Commercial Industrial

Average cost of supply

Average realization

Rs 3.65/kWh

Rs 2.92/kWh

Residential Agriculture

4.62

4.20

2.25

0.86

Rs/

kWh


Box 12.1: MSEB’s performance review

• Power deficit: The state faced a shortage in meeting overall as well as peak loadrequirements. Energy deficit grew from 4.5 per cent to 8.8 per cent between1991–92 and 2001–02. The peak deficit during the same period grew from8.7 per cent to 12.5 per cent.2

• Transmission and distribution losses (T&D losses): Ageing infrastructure,inadequate O&M of the network and low investments in new infrastructure andincreased power theft led to an increase in T&D losses from 17.7 per cent in1995–96 to 30.5 per cent in 1999–2000.2

• Gap in cost and revenue realized: The difference between the cost of power supplyand the average tariff realized from the customers denotes the margin for a powerdistribution business. This difference grew from 16.3 paise/kWh in 1995–96

2 to

48.8 paise/kWh in 1999–2000.2

• Increasing subsidy: The increasing difference between the cost of supply andrevenue realization per unit led to increase in subsidy requirements. From1994–95 to 1999–2000 the subsidy provided by the state government to MSEDCL

increased from nil to Rs 2084 crore.2

REFORMS UNDERTAKEN

Given the deteriorating financial health of MSEB and its impact on the state, theGovernment of Maharashtra (GOM) decided to review the power situation in thestate and undertake reforms. The GOM constituted the State Electricity RestructuringCommittee and the Energy Review Committee (ERC) to review the power situationin the state and suggest broad future course of reforms for the power sector in thestate. The GOM came up with a white paper in August 2002, indicating reforms tobe undertaken and the timelines for the same. The summary of various suggestionsmade in this white paper are discussed in Box 12.2. This white paper specificallymentioned that employees and unions of MSEB were opposed to unbundling and/or privatization and stated that full operational autonomy must be given to MSEBand internal reforms should be carried out first.

In less than a year of this initiative taken by the GOM, Electricity Act 2003 waspassed. As per the Act, states were required to unbundle SEBs and, at the minimum,the transmission activity was to be separated from SEBs. Consequently, the GOMunbundled the MSEB in June 2005 into one holding and three subsidiary companies.The new entities formed were:

• MSEB Holding Company

• Maharashtra State Generation Company

• Maharashtra State Transmission Company

• Maharashtra State Electricity Distribution Company


MSEB Holding Company was expected to function as a think tank and take necessarydecisions relating to investment in the three companies.

Maharashtra State Electricity Distribution Company Limited (MSEDCL) came intoexistence on 6 June 2005 as a result of this unbundling. MSEDCL is also known asMahavitaran or Mahadiscom. MSEDCL inherited a number of problems from itspredecessor, MSEB, which showed in its results for the year 2005–06:

• Low collection efficiency: Collection efficiency reported by MSEB for the year2005–06, when unbundling was done, was less than 90 per cent.5

Box 12.2: White paper on Maharashtra power sector reforms1

Participants: Prior to the preparation, the Government of Maharashtra (GOM) invitedsuggestions from various stakeholders comprising industry, employees, consumers andthe Maharashtra Electricity Regulatory Commission (MERC).

Reform requirements identified: The reform process was expected to bring about changesunder three broad categories:

• Internal reforms: These reforms were expected to focus on developing human

resources, implementing loss-reduction measures and anti-theft measures. Toimprove the quality of service, demand side management and consumer grievanceredressal system were to be set up.

• Independent regulatory mechanism: GOM did setup MERC under the provisions

of the Electricity Regulatory Commissions Act, 1998. GOM made a commitmentto ensure smooth and independent functioning of MERC. Tariff rationalizationwas also considered as an important measure to ensure the recovery of the cost ofpower supply.

• Structural changes: It was identified that a vertically integrated MSEB catering to

the diverse needs of a customer base has inherent limitations. GOM proposed thatMSEB be restructured in order to promote and encourage efficiency, autonomyand accountability in decision making and functional specialization.

Milestones: GOM identified the following milestones:

• Legislative milestones: To make anti-theft legislation effective from October 2002

and pass the Maharashtra Electricity Reforms Bill in December 2002

• Efficiency improvement milestones:

• To develop Consumer Charter of Rights in six months

• To reduce technical losses by 1 per cent and commercial losses by 3 per cent

per year in urban areas. In rural areas, technical losses to be reduced by0.5 per cent and commercial losses by 2 per cent per year

• To increase overall collection efficiency to 94 per cent in two years

• To ensure metering of all agricultural consumers by December 2004


• Inadequate distribution infrastructure: MSEDCL also inherited an inadequateinfrastructure which had a negative impact on technical losses as well asreliability of supply. The LT to HT ratio of distribution lines at that time washigh at about 2:1 which led to high technical losses.

• Aggregate Technical and Commercial Losses (AT&C): AT&C losses for theyear 2005–06 stood at 36.74 per cent for MSEDCL.

• Power deficit: By the year 2005–06 the peak deficit reached 23.1 per cent.3

• Gap in cost and revenue realized: For the year 2005–06 average cost of supply(ACS) and average revenue realized (ARR) stood at Rs 2.49/ kWh and Rs 2.43/kWh respectively.

• Consumer-related problems: When MSEDCL came into existence, a numberof problems existed on the consumer front:

• No separate consumer care centres

• No call centre for complaints

• No system to give feedback to consumers

• Delay in supply restoration against complaints

• No system for tracking status of consumer complaints

Due to high level of consumer dissatisfaction caused by low quality of supply andhigh losses, MSEDCL decided to undertake a number of initiatives.

Figure 12.2: Restructuring of MSEB

MSEB(Maharashtra State Electricity Board)

MSPGCL(Maharashtra State

Power Generation Co. Ltd)

MSETCL(Maharashtra State

ElectricityTransmission Co. Ltd)

MSEDCL(Maharashtra State

ElectricityDistribution Co. Ltd)

MSEB Holding Co.


INITIATIVES TAKEN POST-REFORMS

MSEDCL decided to undertake a number of initiatives to bring about concertedchanges in the distribution business and power scenario in the state. These initiativeswere combined under what is called as a "ten-point programme". The programmeis as follows:

1. Preventive maintenance

2. Distribution network planning

3. Consumer grievances redressal systems

4. Distribution system loss reduction

5. Improvement in collection efficiency

6. Circles to act as profit centres

7. Efficient use of technology

8. Improved services to ag. consumers

9. Improving working conditions of employees

10. Demand side management

It can be seen from the ten-point programme that the initiatives taken by MSEDCLfocused on three broad areas:

• Initiatives to improve Quality of Supply (QoS)

• Initiatives to minimize AT&C losses

• Customer-centric initiatives

Initiatives to improve Quality of Supply (QoS)

Quality of Supply (QoS) is determined by keeping in view a number of factors likereliability of supply, load shedding, etc. To improve QoS, MSEDCL decided to startinitiatives that can ensure better management of existing infrastructure by optimizingallocation of infrastructure and better load management on demand side. Initiativesintroduced to achieve better QoS by MSEDCL are:

• Gaothan Feeder Separation Scheme: Under this scheme, MSEDCL isseparating the rural feeders that service homes from those that feed agriculturalpumpsets. Expected to be completed in two phases, this scheme sought toensure better power supply to homes in rural areas.

Guaranteed 8 hours of electricity to agricultural water pumps would help inshifting the agricultural load to non-peak hours, thereby enabling better loadmanagement on the part of MSEDCL. Gaothan Feeder Separation Scheme hasbeen planned for more than 15000 villages. This scheme will be implemented


with an estimated total cost of Rs 2389 crore for both the phases.18

This schemeis expected to provide multiple benefits to MSEDCL and is also expected tobring relief to consumers by providing reliable power supply through loadmanagement. Some of the benefits this scheme is expected to provide are:

1. Uninterrupted power supply to homes in villages and suburban areas

2. As agricultural connections are low-tariff connections, separating them willlead to better power accounting.

3. Flattening of load curve: A typical load curve in MSEDCL shows peakdemand for the day at around 22:00 in the evening. At that time of the day,demand-supply gap is the largest for MSEDCL. Schemes like Gaothan FeederScheme can help MSEDCL to achieve the flattening of this load curve in ajudicial way, thereby reducing the cost on power purchase and reducingthe penalty for unscheduled interchanges.

Phase-I of Gaothan Feeder Separation Scheme has covered 5185 villages tillApril 2009. 1318 feeders have been commissioned and a load management ofthe order of 1592 MW has been achieved under this phase.18

• Akshay Prakash Yojana: Akshay Prakash Yojana (APY) is a demand sidemanagement measure, whereby MSEDCL has attempted to restrict rural feederloads to 20 per cent of actual value by reducing pilferage, removing inefficientdevices and using better load management. The programme rests on thecollective responsibility of the inhabitants of the village and is carried outvoluntarily for ensuring better quality of supply.

3000

2500

2000

1500

1000

500

0

-500

00–0

101

–02

02–0

303

–04

04–0

505

–06

06–0

707

–08

08–0

909

–10

10–1

111

–12

12–1

313

–14

14–1

515

–16

16–1

717

–18

18–1

919

–20

20–2

121

–22

22–2

323

–24

Load gap on a typical day in MSEDCL (6 July 2009)

Time during the day

20552573

MW

Box 12.3: Load management

The graph above shows the gap between power supply and demand for MSEDCL on a typicalday. Power requirements are high at certain times of the day, due to which peak daily deficitis high. As shown in the graph, the peak deficit is of the order of 2573 MW at 10:00 pm,whereas there is no deficit at 3:00 am.7 Schemes like Gaothan and Akshay Prakash Yojanaallow MSEDCL to shift the agricultural load from high deficit time to non-deficit periods,thereby reducing daily peak load requirements. This leads to reduced load shedding.


This scheme was triggered by children demanding electricity for education fromMSEDCL. Some MSEDCL officials made them understand that electricity is ascarce commodity and is being used through pilferage and inefficient devices intheir village. The school students then approached the gram panchayat with theMSEDCL officials where it was communicated that if the villagers prudentlymanaged their consumption, the entire village could have better quality of supply.Later, this initiative spread to other villages through the efforts made by MSEDCL.

Under this scheme, villagers voluntarily restrict the use of any 3-phase load during5pm–11pm on week days. Only lighting load is utilized. During 5pm–11pm, theload is restricted to 20 per cent of the full load. Load restrictions are supplementedby the removal of hooks and unauthorised heavy consumption devices like heatersand hotplates. Apart from this, the scheme envisages adoption of energy-savinglighting and pumps and use of capacitors. To supervise the usage restriction andreduction in unauthorised access, surveillance committees (Veej DakshataCommittee—VDC) have been formed by the villagers.

This scheme was intended to benefit both the consumers as well as the utility by

1. Reducing transformer breakdowns through reduction in usage of highconsumption devices and unauthorised connections

2. Reducing load shedding through better load management

3. Increasing supply of power and lesser load shedding improve conditionsfor rural people and help cottage industries.

4. Reducing commercial losses and maintenance costs

• Single Phasing Project: The Single Phasing Scheme is also aimed at providingrural areas with uninterrupted power supply. It envisages supplying single phaserural lighting load through three single-phase transformers.

Table 12.1: Progress of Single Phasing Scheme

Phase I Phase II Phase III*

No. of substations 424 296 459

No. of feeders 1186 768 —

No. of villages covered 8085 3877 1536

Expected load management 1153 MW 722 MW —

Project cost 235 cr. 213 cr. 205 cr.

* All figures for Phase III are expected numbers

Source: MSEDCL Website


Single phasing of the selected rural mixed load feeders is carried out by usingchangeover switches at the sub-station. During the normal operation, theagricultural load continues to be supplied from the three-phase transformers.On operation of the changeover switch, there is no supply to the 3-phase load onthe 11kV distribution network whereas single phase supply is available to the lightingand fan load. On revising changeover switch, normal 3-phase supply is restored.

This scheme is being implemented in three phases out of which two have beencompleted already. Under these two phases, 11,962 villages were covered.The third phase is expected to cover 1,536 more villages.

• Pune load shedding model: This distributed generation model was designedto achieve zero load shedding in the Pune urban circle. It was developed byMSEDCL in consultation with the Confederation of Indian Industry (CII).CII proposed to utilise surplus power available from Captive Power Producers(CPPs) during peak hours by implementing a workable alternative forharnessing distributed generation on a pilot basis.

CII proposed that industries with captive or standby gensets that were drawingpower from the MSEDCL grid on a 24-hour basis should reduce their off-takeof power from the grid during certain specified peak periods and instead operatetheir own generators. The additional grid power made available through thisstrategy could then be diverted by MSEDCL to low voltage customers tomitigate load shedding. This would eliminate the need for load shedding inthe Pune urban circle. The CPPs were reimbursed the incremental cost forelectricity they generated on-site during the specified peak periods.

Initiatives to minimize AT&C losses

In order to minimize AT&C losses MSEDCL had to concentrate on its ageinginfrastructure. High technical losses result from inadequate and sub-optimalinfrastructure. The commercial losses are majorly caused by power theft. As theexisting AT&C losses were very high, it was essential for MSEDCL to take a numberof steps to contain and minimize them:

• Investment in infrastructure: MSEDCL has started a three-year infrastructureupgradation plan, to be executed in two phases. The objective of this projectis to improve existing infrastructure along with increasing the capacity ofthe current system in order to support expected future demand. Improvedinfrastructure is expected to reduce losses that arise because of outdatedequipment and over-loading across the grid lines. Heavier loads result infrequent tripping of power along with transformers burning out. Henceimprovement in infrastructure will lead to increased reliability of power alongwith lower distribution losses.


MSEDCL has set the following milestones for this scheme:

• Reduce loading of the distribution transformers to 80 per cent in the horizonyear from the present level ranging from 100 per cent to 150 per cent.

• Use of SCADA, call centres, consumer facility centres in all municipalcorporation areas.

• Bring down the DTC failure rate from 16.14 per cent in FY 2005–06 to5 per cent for urban areas and 7 per cent for rural areas.

• Bring down the Ag. pending connections to one month, in three years.

• Meet the standard of performance given by MERC.

• Power factor to be brought to 0.90, 0.95 and 0.99 in rural, urban andindustrial areas respectively.

As per the plan, the company is expected to set up 76,182 km of powerdistribution lines in order to improve the HT–LT ratio of the distributionnetwork. MSEDCL is also expected to set up 565 new substations and augmentthe existing substations. The total project cost for infrastructure investment in119 divisions is expected to be Rs 8918 crore.

19

For speedy and qualitative development of the electricity distribution grid inMaharashtra and to ensure speedy implementation of its ambitiousinfrastructure development and upgradation plans, the MSEDCL has decidedto engage professional services from project management consultants (PMCs).

To ascertain cost control and quality management under this program,MSEDCL has taken the following steps:

• Setting up of six Quality Control Labs with state-of-the-art testingequipments at Kolhapur, Pune, Bhandup, Nasik, Aurangabad and Nagpur

• Formation of a quality control department to ensure purchase of thebest quality material

• Formation of a material specifications cell

• Theft detection drive: MSEDCL launched a theft detection drive in order toimprove its collection efficiency. Six dedicated police stations have beenestablished in Maharashtra to handle power theft cases only. DuringFY 2007–08 about 90,000 cases of power thefts amounting to Rs 55.41 crorewere detected. Speedy disposal of vigilance cases and strict action againstdefaulters were ensured. As a result, more than 9000 FIRs were registered againstpeople accused of power theft. This drive was implemented consecutively for15 days every alternate month. During April to September 2008, the driveresulted in 36383 cases and recovery of Rs 25 crore as penalties and FIRs against3559 persons.4


MSEDCL also took strict disciplinary action against delinquent employees.This is evident from the fact that, in the initial days, FIRs were filed against22 employees. Also, disciplinary action against 389 employees was taken.

• Metering and energy audit related initiatives: MSEDCL started an initiativefor the metering of agricultural consumers and feeders. It also started carryingout feeder-wise energy audit (EA) to obtain feeder-wise distribution loss data.MSEDCL started to undertake Monthly Energy Accounting at division, feederand DTC levels.

By 2009, MSEDCL achieved the following milestones:

• Over 5 million old consumer meters replaced in three years. This addressedconcerns/complaints about meters not being read, under- or over-reporting, and manipulations.

• Metering of 9339 feeders completed and carried out feeder-wise EA forall of them

• Metering of 150,000 distribution transformers completed

• Monthly Energy Accounting at division and DTC levels

• Distribution franchisee (DF) arrangement: MSEDCL was the first distributionutility in the country to implement urban distribution franchising (DF)arrangement, wherein it franchised the circle of Bhiwandi to the private sector.Under the franchisee agreement, MSEDCL is to supply power at specified inputpoints as per MERC regulations and directives (viz. load shedding schedule)and DF to pay the agreed input rate. DF was allowed to procure power andsupply additional power over and above the supply received from MSEDCL;but no guidelines were given for such power procurement or for the recoveryof related costs from consumers. DF was to pay to MSEDCL wheeling chargesspecified by MERC for distribution of such power. The DF is required to bringabout the reduction of T&D losses to 10 per cent and increase collectionefficiency to 98 per cent at the end of the franchise period.

The DF arrangement at Bhiwandi has yielded successful results as shown inTable 12.2. Plans are afoot to give other circles (Nagpur, Aurangabad, Jalgaon,etc.) to private parties on similar terms.

• Performance based incentives: MSEDCL introduced the concept of annualperformance reports based on improvements in area-specific AggregateTechnical and Commercial (AT&C) losses and collection efficiency of itsemployees. Such initiatives have led to the involvement of employees in thereform process. The company also conducts management classes for its staffand sends them for training courses, besides sharing the best practices withthe employees.


Table 12.2: Power scenario in Bhiwandi—before and after franchising

Handover to At the endDF – Dec 2006 of 2008–09

Aggregate Technical & Commercial(AT&C) losses 58% 24%

Transformer failure rate 40% 7.5%

Status of consumer metering Poor with few 95% metersaccurate meters accurate

Indicators for Quality of Supply

System Average InterruptionFrequency Index (SAIFI) 47.63# 13.57*

System Average InterruptionDuration Index (SAIDI) 23.56# 3.55*

Consumer Average InterruptionDuration Index (CAIDI) 0.49# 0.26*

# Feb 2007 * Jan 2009 Source: MSEDCL, TPL

Customer-centric initiativesAlong with concentrating on technical issues, MSEDCL introduced a number ofinitiatives to provide better customer services. With the usage of informationtechnology tools, MSEDCL has been able to connect to its customers and handletheir issues in a much better way. MSEDCL has established a customer database ofover 15 million

customers.

12 Initiatives taken by MSEDCL to serve its customers

better are:

• Photo metering: To address billing complaints, wrong meter readings andexcessive consumption by consumers, MSEDCL took a first-of-its-kind initiativein the country. MSEDCL has started taking digital photographs of energy metersand displaying these images on energy bills. Billing is done as per the meterreading shown in the photograph. This has a number of inherent benefits.

1. It results in higher customer satisfaction as actual readings are printed onthe bill.

2. It also ensures reduction in the chances of malpractices like over or underbilling by MSEDCL's own employees.

For this purpose, it has developed an indigenously devised software programmethat captures the details which, besides showing the readings, also ensure thatthe meters are not tampered with or manipulated by magnetic devices. Thisscheme has reduced the number of disputes over billing, which ultimately leads


to better collections and reduced litigations. MSEDCL has covered more than1 crore consumers under this scheme till September 2008.

4

The new format also included past consumption patterns in the bill sent toconsumers. This was helpful as earlier, consumers were not sure of pastconsumption and this had led to disputes.

• Complaint handling initiatives: MSEDCL has initiated various activities forimproving its response to consumers and improving complaint handling:

1. To take care of consumer complaints and give feedback to the consumers,11 Consumer Grievance Redressal Forums have been established at variouslocations and internal grievance redressal units were established in allO&M circles.

4 Central Grievance Redressal System has been set up at the

Head Office.

2. For handling supply-related consumer complaints 15 call centres have beenset up.

4

3. About 50 Consumer Facilitation Centres (CFCs) have been set up forresolution of billing and related matters at sub-division level.

4

4. Grievance redressal meetings with industries and consumer associationsare also organized.

5. Single coordinating agency set up to deal not only with customers but also tomonitor the operational resolution of the complaints within MSEDCL.

• Ease of billing: MSEDCL has started a number of initiatives to make it easy forconsumers to access and pay their bills. All bills have been put on the internetto provide easy access to consumers. The payment gateways available toconsumers have been increased by commissioning ATM cash collection centres,drop boxes and offering consumers the facility to make e-payments.

MSEDCL started all these initiatives to ensure the economic viability of thebusiness and to provide better services to its customers. The decision tounbundle MSEB had made employees apprehensive, as they saw unbundlingas the first step towards the eventual privatization of the utility. Employeesalso feared mass layoffs from the utility. Therefore, one of the most importanttasks before MSEDCL was to increase employee morale.

To ensure the success of the initiatives, MSEDCL's decisions had to be backedby the dedication and drive of its employees. Hence, the first thing thatMSEDCL did was to strengthen communication initiatives towards internalemployees. To this end, it undertook


• Workshops with field staff and with unions

• Workshops conducted by unions for members

• Staff meetings at division/circle level

• In-house journal Maha Vitaran Veej Varta was used to convey themanagement's viewpoint to the employees, communicate newinitiatives/plans, etc.

OUTCOME OF REFORMS AND INITIATIVES

The overall impact of reforms and initiatives taken by MSEDCL has started producingfavorable results. While the success of each initiative cannot be measuredindividually, a number of parameters indicating the overall health of powerdstribution sector in the state are discussed below:

Figure 12.3: AT&C losses (%)

Source: PFC report,5 MSEDCL website

• Aggregate technical and commercial losses (AT&C): AT&C lossesreported by MSEB in 2005–06 were very high at 50.4 per cent.

5 These

losses have been reduced to 24.8 per cent through various initiatives takenby MSEDCL.

8

• Collection efficiency: The collection efficiency has improved to the level of96.57 per cent in FY 2008–09

8 from 82.96 per cent in 2005–06.

4

• Subsidy by state: The subsidy provided by the state government to MSEDCLhas been increasing over the years as shown in the graph below. Growth insubsidy despite the reforms is a cause of concern for the state.

60.0

50.0

40.0

30.0

20.0

10.0

0.0

2004–05 2005–06 2006–07 2007–08 2008–09

54.350.4

39.4

26.3

24.8


• Financial viability of MSEDCL

1. Profitability: MSEDCL registered a profit of Rs 117 crore during the year2007–08 as compared to losses of Rs 303 crore in 2005–06. However,without subsidy from the state, MSEDCL is still making losses. This losshas decreased since MSEDCL has come into existence but the change hasnot been significant.

2. Arrears: MSEDCL's arrears have increased from Rs 9288 crore inMarch 2007 to Rs 12547 crore by March 2009. Increase in arrears overthe years reflects MSEDCL's inability to collect earlier dues.

Figure 12.4: Collection efficiency


120.0

100.0

80.0

60.0

40.0

20.0

0.02005–06 2006–07 2007–08 2008–092004–05

80.983.0

93.8 97.4 96.6

2000

1800

1600

1400

1200

1000

800

600

400

200

02004–05 2005–06 2006–07 2007–082003–04

1,100.8

1,553.5 1,562.5 1,684.0

1,829.2

Figure 12.5: Subsidy from state (Rs crore)



Table 12.3: Profits of MSEDCL (in Rs crore)

2005–06 2006–07 2007–08

Profits with subsidy (-) 303.4 (-) 133.9 117.2

Profits without subsidy (-) 1865.9 (-) 1817.9 (-) 1712.1

Source: PFC report,5 MSEDCL Annual Report 2007–08

Table 12.4: MSEDCL’s arrears (in Rs crore)

March 07 March 08 March 09

Receivables 9288.5 10719.0 12547.4

Source: MSEDCL Annual Report 2007–08, MSEDCL website

3. Gap in cost and revenue realized: The gap in ACS and ARR has declinedfrom 11 paise/kWh in 2004–05 to 3 paise/kWh in 2007–08 as shown in thegraph below.

Figure 12.6: Average revenue realised (ARR), average cost of supply (ACS) andgap between them over the years for Maharashtra


The gap between ARR without subsidy and ACS however is still high at26 paise/kWh in 2007–08.

3.00

2.50

2.00

1.50

1.00

0.50

0.00

0.12

0.10

0.08

0.06

0.04

0.02

0.002002–03

Rs/

kWh

Rs/

kWh

2003–04 2004–05 2005–06 2006–07 2007–08

ACS ARR Gap

Data prior to unbundling Data post unbundling


• Quality of Supply (QoS): Investment in infrastructure and other loadmanagement initiatives have led to better quality of supply. Reliabilityindicators like SAIFI, SAIDI and CAIDI have improved due to decreasedload shedding and tripping. SAIFI, SAIDI and CAIDI improved from 10.30,292.96 and 28.46 in April 2007 to 8.02, 159.78 and 19.92 respectively inMarch 2009.

Figure 12.8: SAIFI

3.00

2.50

2.00

1.50

1.00

0.50

0.00

0.35

0.30

0.25

0.20

0.15

0.10

0.05

0.00

Rs/

kWh

Rs/

kWh

2005–06 2006–07 2007–08

ACS ARR Gap

Figure 12.7: Average revenue realised (ARR) without subsidy,average cost of supply (ACS) and gap between them over the years

for Maharashtra post-reforms


12.0

10.0

8.0

6.0

4.0

2.0

0.0

10.3

April 2007 March 2008 March 2009

9.0

8.0


Figure 12.9: SAIDI

Figure 12.10: CAIDI

CONCLUSION

MSEDCL has been in existence for a little over four years and it will be too soonto comment on the sustainability of the reforms undertaken. However, giventhe scale and the kind of problems it inherited, MSEDCL has done acommendable job in improving the situation of power distribution sector inMaharashtra. This improvement has been reflected by decrease in AT&C losses,improved collection efficiency and better QoS parameters.

However rising arrears are a cause of concern for MSEDCL. Also, the subsidyfrom the state has risen over the years for MSEDCL. MSEDCL is still far frombreaking even without subsidy and the gap in ARR (without subsidy) and ACSis quite high.

MSEDCL's sales mix has not reflected any significant change over the yearswhereas revenue mix shows a declining contribution from agriculture anddomestic sectors (refer to Annexure). This reflects that commercial andindustrial sectors are still cross-subsidizing these sectors. Revenue contributionfrom agriculture and domestic sector has to increase to improve MSEDCL'sfinancial viability.


293.0

238.50

159.8

350.0

300.0

250.0

200.0

150.0

100.0

50.0

0.0

30.0

25.0

20.0

15.0

10.0

5.0

0.0


28.526.6

19.9


Power deficit faced by Maharashtra from April 2008 to March 2009 was21.4 per cent.

15 Going forward, MSEDCL has to cater to remote and rural areas

facing load shedding and bad quality of supply. With increasing arrears and hugegap in ARR and ACS, MSEDCL has a tough task ahead of itself to achieve the targetof being financially viable and of providing quality customer service.

REFERENCES

1. Maharashtra Power Sector Reforms, White Paper: Industries, Energy andLabour Department, 28 August 2002

2. Annual Report (2001–02) on the Working of State Electricity Boards andElectricity Departments: Planning Commission (Power and Energy Division)Government of India, May 2002

3. All India Electricity Statistics General Review 2006, CEA

4. http://www.mahadiscom.in/aboutus/abt-us-01.shtm

5. Report on the Performance of the State Power Utilities for the Years 2004–05to 2006–07, Power Finance Corporation Limited

6. Report on the Performance of the State Power Utilities for the Years 2002–03to 2004–05, Power Finance Corporation Limited

7. http://www.mahadiscom.in/interpole_upload/Dailygap.pdf

8. http://mahadiscom.net/emp/Sale_Demand_%20Collection_Loss_Report/STATE/COLLEFF.htm

9. http://www.indiaenvironmentportal.org.in/node/28548

10. Problems before Mahavitaran – Action Plan, Achievements and Future Planstowards Reforms

11. Demand Side Management to Support Electricity Grids, MSEDCL'sPerspective, 26 March 2008

12. Challenges of Electricity Sector in a Developing Economy, Maharashtra CaseStudy, 23 April 2009

13. http://www.karmayog.org/library/libartdis.asp?r=152&libid=655

14. http://www.mahadiscom.in/AnnualPerformanceReview_13may.shtm

15. http://www.cea.nic.in/god/gmd/Monthly_Power_Supply_position/Energy_2009_03.pdf

16. http://www.mahadiscom.in/soa/Final_statementofaccounts0607.pdf

17. http://www.mahadiscom.in/soa/final_statementofaccount0506.pdf

18. http://www.mahadiscom.in/Gaothan_Feeder_Separation_Scheme_Project-01.shtm

19. http://www.mahadiscom.in/Infrastructure_Project-02.shtm


ANNEXURE

Sales mix, revenue mix and cost components of MSEDCL

• Sales mix: Sales mix has not changed significantly over the years after thereforms. As shown in the table below, the share of agriculture has declined andthat of industrial and commercial segment has grown over time.

Table 12.5: Sales mix (as percentage of total units sold)

2004–05 2005–06 2006–07 2007–08

Domestic 16.7% 16.6% 17.1% 16.4%

Commercial 4.3% 4.2% 4.5% 5.1%

Agricultural 22.5% 21.8% 19.2% 22.1%

Industrial 43.0% 45.6% 50.2% 47.8%

Others 13.6% 11.9% 9.0% 8.6%

Source: PFC report,5 MSEDCL annual reports

• Revenue mix: After the reforms, MSEDCL has witnessed a change in its revenuemix. Revenue contribution of industrial sector has gone up from 48 per centin 2004–05 to 55 per cent in 2008–09. Consequently, despite insignificantchange in sales mix, the revenue share of agriculture and domestic sector hasdecreased over the years.

Table 12.6: Revenue mix (as percentage of total revenue)

2004–05 2005–06 2006–07 2007–08

Domestic 16.1% 15.7% 15.8% 15.0%

Commercial 6.7% 6.3% 6.5% 6.8%

Agricultural 12.9% 12.6% 11.0% 11.1%

Industrial 48.4% 51.0% 56.3% 55.2%

Others 15.9% 14.4% 10.4% 11.9%


• Cost components: The cost components of MSEDCL's total expenses are asshown in the table below.

Over the years, power purchase cost has not changed much as a percentageof total cost. However, MSEDCL has seen a significant rise in itsinterest and financing costs. Rise in interest costs is due to capitalexpenditure being incurred by MSEDCL for upgrading its infrastructure.MSEDCL's administration expenses have also increased due to rise invigilance activities.


Table 12.7: Expenses as percentage of total expense

2005–06 2006–07 2007–08

Purchase of power 83.01% 81.09% 81.76%

Repairs and maintenance 1.49% 2.07% 2.53%

Employee costs 9.34% 10.15% 8.63%

Admin & general expenses 0.91% 1.03% 1.32%

Depreciation 2.89% 2.50% 2.60%

Interest and finance charges 2.36% 3.15% 3.17%



INTRODUCTION

The Gujarat Electricity Board (GEB) was established under Section 5 of the Electricity(Supply) Act 1948 along with the formation of Gujarat State in the year 1960.It commenced operations with a generation capacity of 315 MW and a consumerbase of 1.40 million.

During the 1970s and 80s, the major thrust was on the supply of electricity in therural areas. It was largely due to GEB’s unwavering focus on rural electrificationthat Gujarat became the first state to achieve the landmark of “100 per centelectrification of villages”. As per the 1991 Census, 17,940 out of 18,028 villageswere electrified—which was notified as close to 100 per cent.1

The impetus for reforms

Over time, the emphasis of GEB on electrification, particularly in the rural areas,new connections and maintenance activities resulted in divergence fromconcentrating on profitability. Recovery of revenue was then considered as asecondary function. As a result, GEB faced minimum growth of revenue, risingarrears and heavy financial losses. It was also a drain on public resources due to thestate’s policy of supplying electricity to agricultural consumers at extremelysubsidized levels.

The tariff for about 0.5 million agricultural consumers, prior to October 2000, wasRs 350 per horsepower of load connected per year, which led to a revenue realizationof only Rs 0.15 per unit during 2000–01. Each incremental unit of agriculturalconsumption required a subsidy of at least Rs 3.00 per unit. The provision of heavilysubsidized electricity to agriculture consumers boosted its share of consumption

POWER DISTRIBUTION

REFORMS IN GUJARAT

October 200913

Distribution Reforms in Gujarat | 203

from 16.7 per cent of all electricity sold in the state in 1970–71 to 43 per cent in1999–00. The loss incurred by GEB on this account was estimated at Rs 14 billionduring 1999–00.2 Though GEB started certain initiatives in 2000, conditions didnot improve much by the year 2004–05 (as shown in Figure 13.1).3 As a result, GEBfaced recurring financial deficits and was unable to raise resources for investments.

Figure 13.1: Average revenue realization in Rs/kWhfor various consumer categories

The inefficiencies in the sector manifested themselves in the form of chronic shortagesand unreliable service. During FY 1998–99, load shedding ranging between 50 MWand 1,450 MW was experienced on 362 days of the year.4

The Government of Gujarat (GoG) initiated an ambitious policy of inviting privatesector participation (PSP) in the power sector. But the desired PSP did not materializebecause the revenues generated by the sector were insufficient to service the largeinflow of capital that was required.5 Due to the drain on its resources caused bysupporting an inefficient power sector, the GoG was not able to increase spendingon other important areas of infrastructure as well as for social services.

In view of the above, GoG decided to reform the power sector in the state with thefollowing objectives:

1. Addressing the concerns of the investors

2. Creating a business environment conducive to improving the sector’soperational efficiency, financial viability, and service to consumers

GoG proposed to achieve its objectives through a number of reforms. Some of theimportant measures which GoG decided to take in order to achieve the targets were:

1. greater competition at all levels of the sector wherever practicable

5.00

4.50

4.00

3.50

3.00

2.50

2.00

1.50

1.00

0.50

0.00Domestic Commercial Agricultural Industrial Bulk Others

ARR = Rs 2.05/kWh

ACS = Rs 2.49/kWh

Rs/

kWh

2.96

4.65

0.97

4.30

2.77 3.03


2. corporatization and commercialization of existing sector entities

3. private sector participation in the generation and distribution segments

4. tariffs enabling cost recovery as well as reasonable profits

5. an independent regulator

6. transparent, reasonable, direct, and quantified subsidies to vulnerable sectionsof consumers.

Implementation of reforms

The promulgation of the Gujarat Electricity Industry (Reorganization andRegulation) Act in 2003 for reorganization of the electricity industry in Gujaratand for establishing an Electricity Regulatory Commission in the state pavedthe way for the organizational restructuring of GEB. The vertically-integratedGEB was unbundled into seven companies; one each for generation andtransmission, four distribution companies (discoms) and a holding companyknown as Gujarat Urja Vikas Nigam Limited (GUVNL). The generation,transmission and distribution companies have been structured as subsidiariesof GUVNL. GUVNL acted as the planning and coordinating agency in the sectorwhen reforms were undertaken. It is now the single bulk buyer in the state aswell as the bulk supplier to distribution companies. It also carries out the functionof power trading in the state.

All companies became fully operational from April 2005 and began conductingtheir activities independently. Distribution in the cities of Ahmedabad and Surathas historically been with a private sector entity, viz. Torrent Power, throughits fully-owned subsidiaries, Ahmedabad Electricity Company and SuratElectricity Company.

A noteworthy feature of reforms in Gujarat was inclusion of representatives of theunions and associations of the staff in the restructuring process from the initialstage, i.e., from the time the decision was taken on reforming the sector. It convincedthe staff that the GoG and GEB were not pursuing any hidden agenda. It thuscultivated a high level of trust and confidence amongst the staff about the aims andobjectives of reforms and the process proposed to be followed to achieve them.This ensured full co-operation of the staff of GEB in the reform process. No cases ofstrikes or protests by employees of the erstwhile GEB were reported.

Transition support by the state government

As is typically the case with structural reforms of power utilities, GoG prepared aFinancial Restructuring Plan (FRP) to enable the newly formed distributioncompanies to start with a clean balance sheet. Under this FRP, the losses of the


erstwhile GEB were inherited by GUVNL. GoG took over the debt payment liabilityof GEB. It settled outstanding dues of Rs 1627.71 crore payable to central publicsector units (CPSUs) up to September 2001 and in lieu, issued bonds to these CPSUs.This payment to CPSUs since then has been regularly made through Letter of Creditwithout having any further problems resulting in zero outstanding dues payable toany of CPSUs.

Further, GoG converted its loan to GEB, aggregating to Rs 623 crore, into equityshares in GUVNL. It also allowed a moratorium period of six years (fromFY 2005–06 to FY 2010–11) on interest payment liabilities on the remainingoutstanding loan of Rs 842 crore.1 The objective of this moratorium period was toenable early recovery of financial health of GUVNL. Besides this, GoG sanctioneda capital grant of Rs 250 crore per annum from FY 2005–06 to FY 2010–11 withthe objective of strengthening the power sector. Such grants can be utilized forcapital expenditure purposes, rural electrification projects, maintenance of qualityhuman resources and expansion of generation capacity.1

Figure 13.2: Restructuring of GEB

EARLY REFORM INITIATIVES IN GUJARAT

Several states had undertaken the process of structural reforms to varying degreesbefore Gujarat embarked on this path. These states include Orissa, Haryana, AndhraPradesh, Delhi, Karnataka and Uttar Pradesh. On the other hand, states like MadhyaPradesh and Maharashtra were undergoing this process around the same time asGujarat. However, unlike other states that waited to complete structural reforms

PGVCL(Paschim Gujarat Vij

Company Ltd)

MGVCL(Madhya Gujarat Vij

Company Ltd)

DGVCL(Dakshin Gujarat Vij

Company Ltd)

VGVCL(Uttar Gujarat Vij

Company Ltd)

GSECL(Gujarat State Electricity Corp. Ltd)

Generation company

Structure prior to reforms

Structure post reforms

GETCO(Gujarat Energy Transmission Corp. Ltd)

Transmission company

DISTRIBUTIONCOMPANIES

GUVNL(Gujarat Urja Vikas Nigam Limited)

Holding company

GEB(Gujarat State Electricity Board)


before taking up comprehensive measures to address the problems facing them,Gujarat started the process of reforms in early 2000 during the GEB days.GEB undertook several initiatives to improve revenue as well as efficiency andcontrol expenditure. A brief overview of the measures undertaken by GEB isprovided below.

Revenue improvement measures

GEB made significant efforts to improve its revenue through greater monitoringof the revenue situation and fixing of accountability for the same on its employees.It started monthly meetings at the zonal levels which were attended by the chiefengineer and the members of the board. The objective of the meetings was tofamiliarize all officers concerned with the extent of the problem, fix performanceparameters for the succeeding month and monitor past performance.

GEB adopted the feeder manager approach to make field-level officers accountableand through monitoring of their performance, achieve results through reductionin transmission and distribution (T&D) losses. Similarly, it held deputy engineersand junior engineers responsible for sub-division-wise revenue performanceparameters such as reduction in arrears.

Efficiency improvement

One of the biggest achievements of GEB was its drive against power theft. GEB tookstringent measures to curb theft of power and dealt sternly with cases of theft andnon-payment of bills, whether by individuals or by companies. It appointed500 retired army personnel to check power offenders and set up a vigilancedepartment headed by an IPS officer in the rank of additional director general ofpolice on deputation from GoG. Further, it introduced a cash reward scheme (basedon the recovered amount due to submission of information) as an incentive toencourage people to come forward and submit information on theft. The informerwas required to submit detailed information in a prescribed format. The name,address and amount paid to the informer were kept confidential.

Besides this, GEB formed 74 inspection squads under this vigilance department.Eleven squads were dedicated to checking HT installations and the remaining wererequired to check LT industrial, commercial, and residential installations.These squads conducted raids during odd hours.

Cases of theft led to disconnection immediately upon detection; reconnectionhappened only after arrears were paid by violators; many violators were convictedby the court. Managers were appointed by GEB to look into settlement of cases, andsupport was also to be had from GoG in the form of five dedicated police stations atSurat, Baroda, Sabarmati, Rajkot and Bhavnagar which were set up exclusively to


deal with cases of power and power property theft. Officers of the rank of DSP, PI,PSI, and ASI from the state police department are working on deputation to thesepolice stations. Some retired officers from the state police department are also postedhere as officers on special duty.

In a span of four years, almost all connections, both High Tension (HT) and LowTension (LT), have been checked and verified. Consequently, sealing of connectionswas carried out and by 2005 GUVNL had sealed almost 13.89 lakh connections.In 2004–05, GUVNL recovered Rs 16 crore by settling 36,982 civil suits of powertheft and malpractice.1

DISTRIBUTION REFORMS IN GUJARAT AND THEIR IMPACT

The focus areas of distribution reforms in Gujarat have been as follows:

• Reduction of distribution losses

• Commercial loss reduction

• Improvement in revenues

• Improvement in customer services

Reduction of distribution losses

The distribution companies in Gujarat have focused on reducing distribution lossesby a combination of measures such as implementation of technology, strict measuresto tackle theft, strengthening of the network, and changing processes and procedures.

Jyoti Gram Yojana

Though the villages in the state were largely electrified as per prescribed parameters,there was a significant gap in the quality of power supplied to the villages. This wasattributable to the use of power through illegal means resulting in frequenttransformer failures, poor voltage stability and unreliability of supply. Further, therewas a rapid increase in demand for power in the rural areas. Against this backdrop,the GoG launched the Jyoti Gram Yojana (JGY) as a pilot initiative in eight districtsin September 2003 with the objective of supplying reliable and quality power. Thisscheme was part of the bigger objective of facilitating growth of the rural economyin the state. The pilot was successfully completed in October 2004 and in November2004 the scheme was extended to the entire state.

The JGY had the following characteristics:

• Bifurcation of rural feeders into:

• agricultural feeders catering solely to demand for agricultural purposes

• rural feeders catering to load other than agriculture


• erection of 11/22 kV HT lines in rural areas to separate the agricultureload from the village transformer centre

• metering of transformers on JGY feeders

• providing round-the-clock 3-phase power supply to consumers otherthan agricultural consumers while ensuring improved quality of aminimum of 8 hours’ continuous power supply at a pre-determinedschedule to agriculture.

At the end of FY 2007–08, 17,839 villages were covered under the JGY. It involvedlaying a parallel rural transmission network across the state involving the erectionof 15,500 transformers and 75,000 km of lines at an investment of Rs 1,200 crore.The investment was almost entirely funded through grants from GoG(Rs 1017 crore) with the remaining funds being contributed by the discomsconcerned, the Asian Development Bank and schemes such as the APDRP, theMLA Fund, etc.6

The Jyotigram Yojana has been successful in providing multiple benefits to boththe residents of villages as well as the discoms. Some of the prominent effects seen asa result of implementation of this scheme are:

• Improved standard of living: The Jyotigram Yojana has led to a substantialimprovement in the standard of living of the people in the rural areas, as theyare now able to access and use a wider variety of goods and instruments.

• Development of small-scale industries in the rural sector has come about due tobetter and improved availability of power supply.

• Local employment: The industrial and economic development in rural areashas led to greater employment opportunities in villages.

• Reduced emigration from rural areas: Schemes like Jyotigram Yojana helpcheck rural–urban migration as a result of the above-mentioned benefits.Non-farm activities, both trade and industry, have benefited significantlyfrom the scheme. The rural population has been provided avenues to increaseearning power and improve standards of living. Besides, there has beenimprovement in the availability of medical, water supply and sanitationservices. This check on migration out of rural areas has also eased the pressureon urban infrastructure.

Initiatives for technical loss reduction

In order to minimize distribution losses, various distribution companies in Gujaratstarted upgrading their infrastructure. A number of steps were taken to adjust existinginfrastructure so as to optimize costs and minimize losses.


• Feeder bifurcation: Feeder bifurcation done under JGY has had an impact ontechnical losses as well by reducing load on transformers and conductors.Also, reduced ampere loading of feeders has meant reduction in I2R losses.

• Reduction of HT/LT ratio: Distribution companies in Gujarat took steps inorder to improve their HT/LT ratio in order to reduce technical losses.Some of the steps taken were:

• Use of HVDS: Discoms introduced use of high voltage distribution system(HVDS) in Gujarat. HVDS is a practice in which the HV line is extendedup to the load. Required supply is then tapped off from 3-phase HV mainsin proximity of a load point through a distribution transformer of lowercapacity. This kind of arrangement reduces the length of LT line to justthat of the service cable.

Implementation of HVDS also leads to better reliability in the system asthe unauthorized connections, if any, are now connected to HV line.The HV line has the capacity to handle the extra load during peak hoursand hence tripping of electricity caused due to overloading is reduced.

• Replacement of low capacity lines with HV lines and usage of conductorsof adequate size.

• Optimum loading of transformer: The loading and positioning of distributiontransformers was done so as to reduce copper losses/iron losses. Usage ofamorphous transformers was also introduced.

Commercial loss reduction

The main reason for commercial losses suffered by distribution utilities is powertheft. Gujarat was no exception; strict measures were taken to check theft.

The initiatives started by GEB have been continued by GUVNL as well as the discoms.The Vigilance Department is now part of GUVNL and keeps a watch on pilferage ofelectricity in the state. It continues to have provisions for submission of informationregarding power theft. Engineers from the discoms were deputed to GUVNL tocoordinate centralized mass checking drives in so-called strong areas. Based on theconsumption patterns of the feeders, theft-prone areas were identified and massiveanti-theft drives organized with the help of police squads.

The move was unpopular and there was stiff resistance from the people, so much sothat in one instance an official was kidnapped by some locals.

Other steps that were taken to avoid future occurrences of theft were:

• Installation of new meters: Approximately 11.8 lakh1 metal meter boxes wereinstalled for better energy audit and prevention of power theft. Meters were


shifted outside the premises with separate services, particularly in towns.For heavy consumers or seasonal consumers, meter reading was done on aweekly basis.

Metering of feeders and transformers was also undertaken. Energy audit to ensurezero theft was done regularly. Also, billing data was analyzed for irregularities.

• Improved cash collection services: To boost cash collection, GUVNL set upalmost 1,000 centres, outsourced to private agencies. To further improvecash collection, 9000 rural post offices were also used. The collective resultof these efforts was increase in collection from Rs 10,204 crore in 2004–05 toRs 14,767 crore in 2007–08.7

Figure 13.3: Improvement in cash collections over the years

Source: GUVNL Annual Report 2007–08

• Insulated/aerial bunch conductor: Insulated conductors were used to reducethe instances of power theft by unauthorized connections. In aerial bunchedconductors, three conductors are twisted into a thicker insulated cable whichmakes tampering with the power line difficult.

Revenue improvement measures

To improve its financial health, Gujarat discoms took a number of steps startingfrom reducing costs to increasing the number of connections. Some of the revenue

16000 1400

1200

1000

800

600

400

200

0

Collections per year Collection per month

14000

12000

10000

8000

6000

4000

2000

0

2003–04 2004–05 2005–06 2006–07 2007–08

Rs

cror

e p

er y

ear

Rs

cror

e p

er m

onth

917610204

1150613101

14767

765

850

959

1,092

1,231


improvement measures taken up along with reduction in distribution andcommercial losses were:

• Reduction in power purchase cost: In 2003–04, renegotiating of power purchaseagreements (PPAs) began with the four independent power producers (IPPs) —Essar Power, Gujarat Paguthane, GIPCL and GSEG. This led to savings ofRs 4.95 crore in that financial year. Considering the fact that dues to the IPPswere at a staggering Rs 1,300 crore in 2003–04, IPPs were asked to work out acompromise. The alternative would have been yet another sick state corporationand suspension of operations. In another round of negotiations in 2005–06,they managed to get a further reduction of Rs 64 crore.1

• Centralized purchase cell: A centralized purchase cell was created to take theresponsibility of timely and cost-effective procurements of materials andinventory planning. A development which came more in the form of a boonwas the notification from the Ministry of Environment and Forests to usewashed coal with ash content of less than 34 per cent, which is less pollutingfor power plants. This step led to savings of almost Rs 137.93 crore over theperiod 2002–06.1

• Releasing new connections: Camps were arranged in poor areas and slums foron-the-spot sanctioning of of connections. A number of schemes, like TASP(Tribal Area Sub-Plan), Kutir Jyoti and Zupadpatti, were started to provideconnections to the poor.

• Settlement of old dues: Voluntary disclosure schemes and one-time settlementschemes were also initiated to clear old dues. One-time settlement scheme wasavailed of by 28,793 consumers.6

Customer service improvement

Providing better consumer services is one of the major challenges faced bydistribution companies in the country. Consumers face a number of problems likedelay in release of new connections, delay in redressal of complaints and replies toqueries. To address these, discoms in Gujarat took the following measures:

• Customer care centres: were set up at all sub-divisions, divisions and circle officesof distribution companies. These centres took care of all the customer queriesrelated to new connection, billing, change of name procedures, technicalparameters, etc.

• Trouble call management centres: were set up to register and resolvepower-supply – related complaints through telephone. Consumers can register


their complaints which are dispatched to the sub-division concerned.Once the problem is resolved, the status is updated by site/sub-station.Consumers can check status of their complaints and other details throughtheir customer number.

• Bill collection arrangements: Distribution companies in Gujarat have taken anumber of measures to facilitate bill payment by consumers. ‘All-time’payment centres have been set up to allow payment 24 hours a day.Bill collection arrangements have been made with post offices, banks andother private agencies to increase the number of collection centres.Retired employees have been hired so as to increase the number of boothsand shorten queues.

• Introduction of Geographical Information System (GIS): GIS is a technologywhich integrates diverse information within a single system by putting mapsand other kinds of spatial information in digital form, making connectionsbetween activities based on geographic proximity and helping decision makingfor system planning and maintenance.

GIS is helpful in locating consumer complaints immediately as it can indexconsumers directly to poles based on the geographical and spatial dataavailable. GIS also allows identification of voltage and regulation problemsrelating to HT & LT network.

OUTCOME OF REFORMS AND INITIATIVES

Post reforms, Gujarat has turned out to be one of the few states in India which canboast power availability round-the-clock in most of its towns, cities and villages.

Reforms in Gujarat led to the formation of four power distribution companies.Performance across these companies, however, varies according to the demographyof the distribution areas. Various parameters indicating the performance of powerdistribution companies in the state are discussed below:

• AT&C losses: The distribution companies in Gujarat inherited a distributionnetwork with high AT&C losses. In the year 2004–05, GEB reported AT&Closses at 35.2 per cent.3 Post reforms, a number of initiatives were taken toreduce both technical and commercial losses. AT&C losses for the state werereported at 22.6 per cent in the year 2007–08 by GUVNL.7

AT&C losses reported by individual distribution companies have also declinedover time, as shown in Table13.1. While other distribution companies haveAT&C losses less than 20 per cent, PGVCL still has very high losses. PGVCLreported AT&C losses at 33 per cent for the year 2006–07.3


Figure 13.4: AT&C losses (%)

Source: GUVNL Annual Report 2007–08

Table 13.1: AT&C losses for distribution companies

2005–06 2006–07 2007–08

DGVCL 18.1% 16.5% 15.2%

MGVCL 19.74% 15.2% 17.2%

PGVCL 37.1% 35.8% 32.7%

UGVCL 23.6% 15.9% 17.2%

Source: PFC Report on Performance of the State Power Utilities for the Years 2005–06

to 2006–08

• Distribution losses: Gujarat Electricity Regulatory Commission (GERC) setstarget distribution losses for each discom separately. While distributionlosses for the discoms have decreased from what they had inherited, alldiscoms, except DGVCL, reported increase in distribution losses for theyear 2007–08.9

Table 13.2: Distribution losses of discoms

2005–06 2006–07 2007–08

DGVCL 20.0% 16.5% 15.5%

MGVCL 20.2% 15.1% 15.9%

PGVCL 38.7% 32.5% 32.8%

UGVCL 23.0% 15.8% 17.3%

Source: GERC Website

22.623.7

26.5

35.235.4

40.0

35.0

30.0

25.0

20.0

15.0

10.0

5.0

0.02003–04 2004–05 2005–06 2006–07 2007–08


Table 13.3: Collection efficiency of distribution companies

2005–06 2006–07 2007–08 2008–09

DGVCL 102.5% 100.1% 99.8% NA

MGVCL 99.8% 97.2% 100.3% 98.7%

PGVCL 98.1% 97.0% NA 100.3%

UGVCL 99.2% 99.8% 87.1% 100.0%


to 2006–07 GERC Website

• Collection efficiency: The collection efficiency of GEB in Gujarat has been highat about 97 per cent in 2003–04 and 2004–05. Post-reform efficiency hasimproved and was reported around 98.6 Data for Gujarat has been calculatedon the basis through weighed average using units sold per cent for theyear 2006–07.3 Collection efficiency for different distribution companies is asshown in Table 13.3.

• Subsidy: Subsidy received by GEB was Rs 1,527 crore in 2003–04.After unbundling this declined to Rs 1,178 crore in 2005–06.3 However, therehas not been any significant reduction in subsidy received since then.The total subsidy received by four distribution companies for the year2007–08 was Rs 1,182 crore8.

Subsidy received by individual distribution companies has not declinedsignificantly since reforms. Only MGVCL has seen a decrease—fromRs 101 crore in 2005–063 to Rs 58 crore in 2007–08.8

Figure 13.5: Subsidy received (in Rs crore)

Source: PFC Report on Performance of the State Power Utilities

2000

2500

1500

2017

1527

2026

1178

1000

500

0

2002–03 2004–05 2005–06 2006–07 2007–082003–04

11821206


Table 13.4: Subsidy received by distribution companies

2005–06 2006–07 2007–08

DGVCL 74 79 81

MGVCL 101 58 58

PGVCL 427 474 466

UGVCL 576 595 578

Gujarat 1,178 1,206 1,182


to 2006–08, Annual Report of Distribution Companies.

• Financial viability of the distribution companies

• Gap in cost and revenue realized: Gap in ACS and ARR has declined fromRs 0.51/kWh in 2002–03 to Rs 0.24/kWh in 2007–08* (as shown in Chart 5).This decrease is attributable to a number of initiatives taken to reducecommercial as well as technical losses.

Figure 13.6: Average revenue realised (ARR) without subsidy, average cost ofsupply (ACS) and gap between them over the years for Gujarat (in Rs/kWh)

*Data for year 2005–06, 2006–07 and 2007–08 has been calculatedthrough weighted average using units sold.

Source: PFC Report on Performance of the State Power Utilities

The gap in ARR and ACS for distribution companies varies by a greatmargin. While DGVCL had a gap of 5 paise/kWh in 2007–08, the gap forUGVCL was 44 paise/kWh.

Rs/

kWh

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.510.70

0.44

0.26 0.26 0.24

0.02002–03 2003–04

ACS ARR Gap

2004–05 2005–06* 2006–07* 2007–08*


Table 13.5: Gap between ARR & ACS for distribution companies withoutsubsidy (in Rs/kWh)

2005–06 2006–07 2007–08

DGVCL 0.07 0.06 0.05

MGVCL 0.16 0.10 0.09

PGVCL 0.25 0.27 0.26

UGVCL 0.47 0.48 0.44


to 2006–07, Annual Report of Discoms and GUVNL

• Profitability: Without subsidy, distribution companies in Gujarat havebeen making losses. These have increased in the case of DGVCL andPGVCL. MGVCL has seen a decrease in losses from Rs 84 crore in2005–06 to Rs 55 crore in 2007–08. For UGVCL, losses have increasedmarginally from Rs 575 crore in 2005–06 to Rs 577 crore in 2007–08.

Table 13.6: Profits of distribution companies without subsidy (in Rs crore)

2005–06 2006–07 2007–08

DGVCL (64) (63) (79)

MGVCL (84) (69) (55)

PGVCL (401) (457) (465)

UGVCL (575) (578) (577)


to 2006–07, Annual Report of Distribution Companies

However, when subsidy has been provided all the discoms have shown profits.

Table 13.7: Profits of distribution companies with subsidy (in Rs crore)

2005–06 2006–07 2007–08

DGVCL 10 16 1.6

MGVCL 17 (11) 2.4

PGVCL 27 18 1.2

UGVCL 2 17 0.9


to 2006–07, Annual Report of Distribution Companies


CONCLUSION

Gujarat is one of the few states where several reforms were initiated before theactual unbundling of the SEB. A number of new initiatives were taken postrestructuring by the discoms to tackle the many problems facing the distributionsystem. Some of these have now been adopted by other states in one formor other.

The impact of distribution reforms can be felt in decreased losses and improvedcollection efficiencies. Also, the deficit condition of the state has improved over theyears. Peak deficit for the state declined from 30 per cent in 2006–07 to24 per cent in 2008–09. Energy deficit for the year reduced from 13 per cent in2006–07 to 10 per cent in 2008–09.

Table 13.8: Gujarat state peak deficit and energy deficit

2006–07 2007–08 2008–09

Peak deficit 30.2% 26.7% 24.3%

Energy deficit 13.4% 16.2% 9.8%

Source: Central Electricity Authority (CEA)

Individual performance of distribution companies in Gujarat has varied.Among the factors responsible is the different customer mix they inherited (refer toAnnexure). The agricultural sector’s contribution to revenue has been less thantheir percentage share in the sales mix; the industrial sector contributed to morethan half the revenues for all the companies. This reflects the cross-subsidizationbeing done and hence an advantage for companies having higher percentage ofinvolvement with the industrial sector. DGVCL and MGVCL require lower subsidythan PGVCL and UGVCL which can be attributed to lower percentage of agriculturalsector in their sales mix. The performance of DGVCL and PGVCL has lagged behindthat of MGVCL and UGVCL respectively in terms of reduction in AT&C losses andcontainment of subsidy requirement. Difference in performance is also apparentwith regard to Quality of Service (QoS) parameters. In the absence of data on theQoS parameters prior to restructuring, and, currently, quality data onQoS parameters on an annual basis, it is difficult to comment on the extentof improvement.

Finally, the profitability of discoms without accounting for subsidy remains in doubt.Lowered dependence on the state government as far as subsidies are concerned is amust in order to achieve the ultimate goal of a financially sustainable powerdistribution system.


Table 13.9: Quality of service parameters* for discoms

Mar–08 Mar–09

SAIFI SAIDI CAIDI SAIFI SAIDI CAIDI

DGVCL 13.9 0.5 0.0 5.0 3.9 0.8

MGVCL 1.7 0.3 0.2 0.8 0.3 0.4

PGVCL 0.6 2.7 4.8 NA NA NA

UGVCL 0.4 0.5 1.2 0.8 1.2 1.6

Source: http://www.gercin.org/sop1.php* SAIDI and CAIDI are in hours

ANNEXURE

• Sales mix: The distribution sector in Gujarat was divided into four companiesand all these companies inherited a different mix of consumers depending onthe area served. While DGVCL and MGVCL got a mix with predominantlyindustrial consumers, PGVCL and UGVCL inherited a consumer mix with ahigh percentage of agricultural consumers. Over the years, all the companieshave seen a marginal decline in sales to agricultural consumers as percentageof total sales. The share of industrial consumers has increased significantly forPGVCL—from 32.4 per cent in 2005–063 to 41.6 per cent in 2007–08.9

• Revenue mix: The revenue mix of companies varies according to their salesmix. However, approximately half of the contribution to revenue is made bythe industrial sector for all the companies. Contribution by the agriculturalsector is quite low despite its accounting for a large share of sales in PGVCLand UGVCL.

• Cost components: The cost components as percentage of total costs have notvaried much for the distribution companies. However, most of the companieshave seen a rise in employee costs as percentage of total costs.

Distribution Reforms in Gujarat | 219T

able

13.

10: S

ales

mix

of d

istr

ibu

tion

com

pan

ies

2004

–05

2005

–06

2006

–07

2007

–06

GEB

DG

VC

LM

GV

CL

PGV

CL

UG

VC

LD

GV

CL

MG

VC

LPG

VC

LU

GV

CL

DG

VC

LM

GV

CL

PGV

CL

UG

VC

LD

omes

tic12

.4%

14.0

%23

.6%

16.5

%8.

4%14

.8%

24.0

%15

.3%

8.6%

15.3

%24

.1%

15.6

%8.

9%C

omm

erci

al4.

0%5.

0%7.

5%5.

4%2.

5%5.

2%7.

8%5.

2%2.

6%5.

6%8.

2%5.

5%2.

8%A

gric

ultu

ral

32.1

%7.

4%18

.0%

42.8

%61

.5%

7.0%

15.7

%37

.5%

59.4

%6.

6%15

.1%

34.7

%56

.9%

Indu

stri

al34

.9%

69.1

%40

.8%

32.4

%23

.2%

68.6

%42

.9%

39.4

%25

.0%

67.9

%43

.1%

41.6

%27

.3%

Oth

ers

16.6

%4.

5%10

.0%

2.9%

4.3%

4.3%

9.5%

2.6%

4.3%

4.6%

9.6%

2.5%

4.1%

Sour

ce: P

FCR

Rep

ort

on P

erfo

rman

ce o

f the

Sta

te P

ower

Uti

litie

s fo

r th

e ye

ars

2004

–05

to 2

006–

07, G

ER

C w

ebsi

te

Tab

le 1

3.11

: Rev

enu

e m

ix o

f dis

trib

uti

on c

ompa

nie

s20

04–0

520

05–0

620

06–0

720

07–0

6G

EBD

GV

CL

MG

VC

LPG

VC

LU

GV

CL

DG

VC

LM

GV

CL

PGV

CL

UG

VC

LD

GV

CL

MG

VC

LPG

VC

LU

GV

CL

Dom

estic

12.9

%11

.0%

21.0

%18

.1%

11.0

%11

.0%

20.3

%15

.3%

10.7

%11

.9%

20.4

%15

.3%

10.8

%C

omm

erci

al6.

6%6.

0%10

.4%

9.7%

5.8%

6.1%

10.4

%8.

4%5.

6%6.

7%10

.9%

8.6%

5.9%

Agr

icul

tura

l11

.0%

1.9%

4.9%

15.9

%28

.3%

1.8%

4.3%

13.4

%27

.5%

1.9%

4.2%

12.8

%26

.4%

Indu

stri

al52

.3%

75.9

%51

.0%

53.2

%48

.9%

75.3

%53

.6%

60.5

%51

.0%

74.5

%53

.0%

61.0

%52

.0%

Oth

ers

17.3

%5.

2%12

.8%

3.1%

6.1%

5.8%

11.5

%2.

4%5.

2%5.

0%11

.5%

2.3%

4.9%

Sour

ce: P

FCR

Rep

ort

on P

erfo

rman

ce o

f the

Sta

te P

ower

Uti

litie

s fo

r th

e ye

ars

2004

–05

to 2

006–

07 a

nd

2005

–06

to 2

007–

08, G

ER

C w

ebsi

te

Tab

le 1

3.12

: Exp

ense

s as

per

cen

tage

of t

otal

cos

t for

dis

trib

uti

on c

ompa

nie

s20

05–0

620

06–0

720

07–0

6D

GV

CL

MG

VC

LPG

VC

LU

GV

CL

DG

VC

LM

GV

CL

PGV

CL

UG

VC

LD

GV

CL

MG

VC

LPG

VC

LU

GV

CL

Pow

er p

urch

ase

93.6

%85

.3%

82.7

%86

.7%

90.9

%81

.6%

83.0

%84

.7%

90.8

%82

.6%

84.8

%86

.1%

Empl

oyee

cos

t1.

6%5.

2%5.

9%3.

7%3.

5%9.

0%6.

3%6.

9%3.

5%8.

0%6.

2%5.

5%O

&M

cos

t0.

3%2.

2%1.

9%1.

6%0.

7%2.

1%1.

9%1.

5%1.

0%1.

8%1.

8%2.

2%In

tere

st c

ost

2.5%

4.3%

5.4%

4.5%

2.4%

3.3%

3.6%

3.6%

2.1%

3.1%

3.0%

2.6%

Dep

reci

atio

n1.

2%2.

2%3.

6%2.

7%1.

6%2.

6%3.

3%2.

6%1.

8%2.

8%3.

0%2.

6%Ad

min

& g

ener

al ex

pens

es0.

3%0.

9%1.

2%0.

8%0.

4%1.

2%1.

0%0.

7%0.

7%1.

5%1.

2%0.

9%O

ther

exp

ense

s0.

5%0.

1%-0

.8%

0.1%

1.0%

0.2%

0.9%

0.0%

0.0%

0.1%

0.0%

0.1%

Sour

ce: P

FCR

Rep

ort

on P

erfo

rman

ce o

f the

Sta

te P

ower

Uti

litie

s fo

r th

e ye

ars

2004

–05

to 2

006–

07 a

nd

2005

–06

to 2

007–

08, G

ER

C w

ebsi

te


REFERENCES

1. Presentation by Madhya Gujarat Vij Company Ltd. Available in the Report on“Loss reduction strategies”, September 2008, Forum of Regulators.

2. “Co-management of Electricity and Groundwater: Gujarat’s Jyotirgram Yojana,Strategic Analyses of India’s NRLP”, Tushaar Shah, Regional Workshop atHyderabad, August 2007.

3. Presentation by Gujarat Urja Vikas Nigam Limited on “Gujarat Power SectorInitiatives” at the Regional Conference on “Excellence In Public ServiceDelivery”, YASHADA, Pune, October 2007.

4. http://www.karmayog.org/electricitynews/electricitynews_11067.htm

5. “Study on Impact of Restructuring of SEBs” by the Indian Institute of PublicAdministration (IIPA), September 2006.

6. “Gujarat electricity board’s turnaround: Complete rural electrification inGujarat”, London Business School, October 2008.

7. “Reforms and Loss Reduction Strategies—Gujarat Experience”,P. R. Chaudhary, Officer on Special Duty, Uttar Gujarat Vij Co. Ltd.

8. “Co-Management of Electricity and Groundwater: An Assessment of Gujarat’sJyotirgram Scheme”, Economic & Political Weekly, February 2008.

9. Asian Development Bank: Reports available under Technical Assistance: 29694,Gujarat Power Restructuring

10. http://www.gercin.org/orders_tariff.php

11. http://www.gercin.org/sop1.php

12. http://www.gercin.org/rims1.php

NOTES

1. Report on Gujarat Electricity Board —A benchmark in the progress of SEB reforms,by the Indian Institute of Planning and Management (IIPM) Ahmedabad, 2006.

2. Asian Development Bank, RRP:IND 29694, Report and recommendation of the Presidentto the Board of Directors on proposed loans and technical assistance grants to India forthe Gujarat Power Sector Development Program, November 2000.

3. Report on the Performance of the State Power Utilities for the years 2004–05 to2006–07, Power Finance Corporation Limited.

4. Asian Development Bank, RRP:I ND 29694, Report and recommendation of thePresident to the Board of Directors on proposed loans and technical assistance grants toIndia for the Gujarat Power Sector Development Program, November 2000.


5. Asian Development Bank, RRP:IND 29694, Report and recommendation of the Presidentto the Board of Directors on proposed loans and technical assistance grants to India forthe Gujarat Power Sector Development Program, November 2000.

6. “Reforms and Loss Reduction Strategies—Gujarat Experience” by P.R. Chaudhary,Officer on Special Duty, Uttar Gujarat Vij Co. Ltd

7. GUVNL Annual Report 2007–08

8. Annual reports for the financial year 2007–08 of the UGVCL, DGVCL, PGVCL andDGVCL

9. http://www.gercin.org


INTRODUCTION

India has set out on the path of harnessing renewable energy (RE) sources likenever before. The reasons are many and not hard to find—chronic shortage ofpower, energy security and environmental concerns. The country’s energystrategy is moving strongly in favour of RE technologies. This strategy has madeIndia a leader in a number of renewable energy technology (RET) applicationssuch as grid-connected wind energy generation, decentralised solar PV for ruralapplications, decentralized distributed generation, etc. India has now set itselfvery aggressive targets for RE capacity addition. The Eleventh Five-Year Plan(FYP) (FY 2007–12) envisages the addition of 14,050 MW of additional capacity,which means adding, in five years, more capacity than what India has addedsince Independence.

However, RE capacity addition and development of the sector suffers on accountof a number of constraints, overlaps and gaps prevalent in the current policy andregulatory environment. It is becoming clear that the policy and regulatoryframework introduced so far has been appropriate only for accelerating the earlygrowth of the sector from a small base and helping mainstream RE. However, thispolicy and regulatory environment has now (with changing market conditionsand imperatives) become outmoded for the sector. Though the Ministry of Newand Renewable Energy (MNRE) has been taking proactive steps to improve thisenvironment, its initiatives have been able to address specific problems andconstraints but have not been successful in helping the RE sector as a whole inIndia to leapfrog ahead.

BARRIERS TO DEVELOPMENT

OF RENEWABLE ENERGY IN

INDIA AND PROPOSED

RECOMMENDATIONS:A Discussion PaperFebruary 2010

14

Barriers to Development of Renewable Energy | 223

There is, therefore, a need to review the existing environment for development ofRE and propose a new approach to the development of this sector. With this objectivein view, this paper examines the current status of RE development in India and theexisting environment for such development. It examines the barriers to furtherdevelopment as well as gaps constraining investments in this sector of renewable energy.It then makes recommendations towards removing such barriers and adopting newmechanisms for the promotion of RE. In sum, the paper identifies the issues that haveto be addressed in order to achieve a widespread use of RE, so that determined andpractical steps can be taken to increase their application substantially.

RE technologies (RETs) in India can be divided into two categories: 1. near-commercial and commercial technologies such as wind, small hydro power (SHP),solar PV, biomass and co-generation (cogen) that have matured and are beingdeployed or are close to deployment, and 2. emerging technologies such as solarthermal and biofuels that will need time to mature. The latter will also have toundergo pilots before commercial deployment. This paper focuses on the RETsthat fall in the first category. The paper also restricts itself to grid-connected RE.

STATUS OF RE DEVELOPMENT IN INDIA

Today, the RE sector contributes a very small percentage of the total installed powercapacity of the country (approximately 9 per cent at the end of FY 2008–09)(see Figure 14.1). The share of different technologies in the total RE capacity existingin the country is presented in Figure 14.2. It is clear that wind energy makes up the

Figure 14.1: Role of RE in India’s power generation capacity ason 31 March 2009 (in MW)1

Source: MoP

36878

13242

4120

Hydro RES Nuclear Thermal

93725


largest proportion of RE. It has also overtaken the installed nuclear power capacityby nearly a factor of two. On the other hand, solar power—whether PV or thermal—is yet to gather momentum.

The growth in RE capacity addition picked up pace during the Tenth Plan. In thisPlan, the sector was not only able to achieve its targets but also exceeded them byalmost 120 per cent. A review of the physical achievements during this Plan indicatesthat RE capacity of 6795.44 MW was added as against a target of 3583.50 MW.Of this, 5426.4 MW came from wind power, 536.83 MW from small hydro, 785 MWfrom bio-energy and 46.58 MW from waste to energy.

RE potential in India

The contribution of renewable energy to the power sector has increased and isexpected to increase in the future. MNRE is targeting a huge capacity of renewableenergy and aims to add almost four times the present capacity by 2017. Table 14.1highlights the potential and target cumulative capacity addition for each of theRETs in India till FY 2016–17. It is evident that wind will continue to dominatethe future capacity addition from RE and the country is expected to harness around88 per cent of its available potential of wind by 2022. SHP is also expected to beharnessed up to 43 per cent of its potential. Further, the potential for each of theRETs is expected to increase in future with more resource assessments andtechnological advancements.

Figure 14.2: Technology-wise grid-interactive RE capacity in Indiaas on 31 October 2009 (in MW)

Source: MNRE

5.3%0.4%

0.04%

16.2%

8.0%

70.1%

Biomass (5.3%) Waste to energy (0.4%)

Solar power (0.04%)

Small hydro power (16.2%)Cogeneration-bagasse (8.0%)Wind power (70.1%)

RET-wise installed capacity

RET Installed Capacity

Small hydro power 2,519.88

Cogeneration-

bagasse 1,241.00

Wind power 10,891.00

Bio power 816.50

Waste to energy 67.41

Solar power 6

Total 15,541.79


Table 14.1: RE potential and target cumulative capacity addition (in MWeq)

Type of RET Estimated Target Target Totalpotential as on addition addition capacity

March 31, till 2011 till 2017 in 20172009

Wind 45,195 17,600 35,000 45,243

SHP 15,000 3,376 6,500 8,930

Biomass 16,881 1,025 1,500 2,203

Cogeneration-bagasse 5,000 2,016 3,400 4,449

Waste to energy 2,700 244 600 659

Solar 50,000 53 10,000 10,002

Total 1,34,776 24,314 57,000 71,485

Source: MNRE

Table 14.1 makes it clear that there is a huge potential for RE, and only a small partof it has been tapped so far. Going by the past record, these anticipated capacityadditions may not materialize in their entirety as the development of RE is criticallydependent on a variety of factors (which will be touched upon later in this paper).To get realistic estimates about the capacity addition that would be possible, it maybe useful to consider that only 15,000 MW2 of the planned incremental capacitywould be added in the country by 2017.

Drivers of RE in India

The main driver for RE at the global level, particularly in Europe and North Americais the reduction of emissions. Increased levels of greenhouse gases have primarilybeen held responsible for global warming and, consequently, climate change. Europeand North America being the largest emitters of greenhouse gases in the world, theneed to reduce emissions of these gases provides a very compelling reason for themto make use of alternative and cleaner sources of energy. While the need to protectand preserve the environment has come to the forefront in India, concerns overenergy security and the stability of the energy supply continue to be the main driversof RE in the country.

The Expert Committee of GOI on Integrated Energy Policy (IEP) notes that todeliver a sustained growth of 8 per cent through 2031, India would need toaugment its primary energy supply by three to four times and electricity supplyby five to seven times the 2003–04 levels.3 The country currently imports about72 per cent of its oil consumption and this is expected to reach 90 per cent by


2031–32. The scenario for coal imports is not going to be very different. It isenvisaged that India will import 50 to 60 million tons (MT) of coal every yearby the end of the Eleventh Five-Year Plan. According to scenarios developed bythe Expert Committee on IEP, imports could increase to as much as 45 per centof the total coal requirement. Besides issues of energy security, such growingdependence on imports also raises concerns of price shocks and vulnerability tosupplying countries.

Long-term energy security is just one aspect. The country also needs to addressthe shortage of power that has engulfed it over the years and access to electricity.The peak power shortage in June 2009 was 14 per cent and has been upwards of11 per cent every year since 1997–98.4 The scenario varies from state to statewith some states facing a peak power shortage of 35 per cent in June 2009.5

While the level of village electrification for the country as a whole reached83 per cent at the end of June 2009,6 the level of household electrificationcontinues to remain poor. Last available estimates indicate that 90 per cent ofurban households and only about 55 per cent of rural households are electrified.7

No doubt, efforts are being made to increase electrification. But given theshortage of power prevailing in the country, increased electrification wouldperhaps make no difference.

Allied benefits of energy security are savings in foreign exchange on account ofreduction in import of conventional fuels. Another offshoot of any scale-up in REinvestment and development would be more investment in RE manufacturing. This,in turn, would lead to savings in foreign exchange (from import of RE equipment),spur development of equipment manufacturing and ancillary industries specific torenewable energy technologies, and generate employment.

Promoting renewable energy resources also has a positive impact on the netcreation of jobs. Rough estimates indicate that a 4000 MW ultra mega powerproject (thermal power) would create employment for approximately 300 people.One MW of RE necessitates the employment of a minimum of five people, whichmeans that about 20,000 people would get employment through 4000 MW of RE.International experience also bears this out. For instance, RE jobs in Germanyshot up from 160,500 in 2004 to 249,300 in 2007.8

Policy and regulatory framework for RE

Overall environment for development of RE

India is one of the few countries in the developing world which has pioneered thedevelopment of renewable energy. Following the first oil shock in the 1970s whichbrought to light concerns about energy access and energy security, India recognizedthe relevance of these natural sources of energy. Thereafter, the sector witnessed


slow but steady growth over the next three decades. The milestones in the RE sectorin India can be summarized as follows:

• Establishing the Commission for Additional Sources of Energy in 1981 forpromoting research and development in renewable energy.

• Establishing the Department of Non-conventional Energy Sources (DNES) in1982 in the Ministry of Energy

• Wind-resource assessment and publication of a databook in the early 1980s

• Research and development, capacity building and demonstration programmesin the areas of biogas, cooking stoves and solar energy in the 1980s

• Installing the first grid-connected wind turbine in 1985 and beginning of thedemonstration programme by DNES in 1986

• Establishing the Indian Renewable Energy Development Agency (IREDA) in1987 to finance renewable energy projects.

• Upgrading DNES into a full-fledged Ministry of Non-conventional EnergySources (MNES; now MNRE) in 1992.

• Recognition of renewable technologies for power generation in 1992, by theirinclusion in the Eighth Five-Year Plan (1992–97)

• Policy to encourage private sector investment in renewable energy andguidelines for renewable energy tariffs by MNES in 1993

Until 1993–94, the primary approach for development of RE was through theprovision of subsidies. After that, the approach has shifted to include the provisionof fixed tariffs for purchase of power from RE. In 1993, the MNRE issued policyguidelines prescribing a price of Rs 2.25/kWh with a 5 per cent annual escalation(with 1993 as base year). It also allowed wheeling and banking of energy generatedby RE sources to facilitate private investments in the sector. These guidelines werevalid for a period of 10 years. The guidelines were adopted with variations by utilitiesin different states. Several states even brought out their policies for RE, based on theMNRE’s guidelines; some even offering additional incentives for RE investments.

The enactment of the Electricity Act 2003 (EA 03) has radically changed the legaland regulatory framework for this sector by providing for policy formulation by theGovernment of India and making it mandatory for state electricity regulatorycommissions (SERCs) to take steps to promote renewable and non-conventionalsources of energy within their area of jurisdiction. Section 3 of EA 03 clearly mandatesthat the formulation of the National Electricity Policy (NEP), Tariff Policy and Planthereof for development of power systems shall be based on optimal utilization ofall resources, including renewable sources of energy. Further, EA 03 has specificprovisions for determination of feed-in tariffs for renewable energy sources as well


26 67266

411220 142 172

298 337431

849

1366

20112138

1899

3213

MNRE policy& tariff

guidelines

National windresource monitoring

& demonstrationprogramme

Policy onhydro powerdevelopment

ElectricityAct 2003

Guidelines for tariff &

interconnection for captive &

third-partysales

Generation-based

incentivesPolicy frameworkto push

indigenisation

• Renewable Purchase Obligations• Feed-in tariffs

0

250

500

750

1000

1250

1500

1750

2000

2250

2500

2750

3000

3250

3500

MW

1993

–94

1994

–95

1995

–96

1996

–97

1997

–98

1998

–99

1999

–200

0

2000

–01

2001

–02

2002

–03

2003

–04

2004

–05

2005

–06

2006

–07

2007

–08

2008

–09

as for creation of renewable portfolio standards for states. Annexure 1 describes theprovisions of EA 03 and the policies formulated therein for RE.

Figure 14.3 maps the capacity addition in RE with the main events that have driventhis sector forward.

Figure 14.3: Events influencing RE development andRE capacity addition (in MW)

Source: MNRE, others

Policies for promotion of RE

Over the years, the GOI through the Ministry of New and Renewable Energy (MNRE;earlier known as the Ministry of Nonconventional Energy Sources), the Ministry ofFinance, and the state governments have used a number of policy instrumentstowards promotion of RE. A summary of these initiatives is provided in Table 14.3.Annexure 2 discusses these initiatives in detail.

Regulatory framework for promotion of RE

Regulatory measures have mainly taken two forms: Renewable Purchase Obligation(RPO) and Feed-in tariffs. A summary of these measures is provided in Table 14.4.Annexure 3 discusses the initiatives in detail.

Barriers to development of RE

The barriers to development of RE in India, in general, are described below. Someof these may be specific to a technology, while some may be specific to a policy,site or a region.


Policy and regulatory barriers

Policy framework for RE

There is no single comprehensive policy statement for RE in the country. Policieshave been issued as and when necessary to facilitate the growth of specific RETs.Further, the plans for development of RE do not match these policies. Table 14.2indicates that the RE capacity addition targeted by MNRE and the capacity additionplanned under the Jawaharlal Nehru National Solar Mission (JNNSM), also knownas Solar India, is inadequate to meet the target for RE generation mandated underthe National Action Plan on Climate Change (NAPCC)

Table 14.2: Mismatch between RE capacity envisaged under policyand capacity addition targeted

2009–10 2010–11 2011–12 2016–17

Energy Requirement(in MU)a 820920 891203 968659 1392066

Share of RE as mandatedunder NAPCC (in %)b 5% 6% 7% 12%

Quantum of RE required(in MU) 41046 53472 67806 167048

RE capacity additiontargeted by MNRE(in MW) 15542c 20376 25211 57000

Solar capacity targetedunder JNNSM (in MW) 1000 10000

Quantum of RE available(in MU)d 29952 39269 50514 129122

Additional RE requiredto meet RE sharemandated underNAPCC (in MU) 11094 14203 17292 37926

a. As per 17th EPS

b. 5% in 2009–10 & 1% increase each year

c. As on 31.10.2009

d. Assuming a capacity utilization factor of 22%

The policy framework at the state level is no better. In fact, in many states policieshave only created uncertainty for investments in RE. For example, in MadhyaPradesh, the policy for promotion of non-conventional energy sources waives


wheeling charges as well as cross-subsidy surcharge for RE. The state government,to encourage RE, would provide subsidy to the distribution utilities towards wheelingcharges at 4 per cent of the energy injected at the rate of prevailing energy chargesfor the user. The policy also exempts wind energy from the payment of electricityduty for a period of five years from CoD provided actual generation is at least70 per cent of the energy generation declared in the DPR. However, the policy isapplicable only for a period of five years. Therefore, there is a high degree of policyand regulatory uncertainty for investment in RE.

In case of biomass projects, most states do not have defined policies with regard tothe radius within which such plants can be established. It has been seen that biomassplants have come up in close proximity to each other, thereby affecting the availabilityof fuel to each other. As a result, these plants have been rendered unviable.

Provision of accelerated depreciation to wind developers

Wind power growth has hinged on the 80 per cent accelerated tax depreciationthat is provided by the GOI. In view of this, a bulk of wind power capacity hasbeen set up on the balance sheets of existing companies which wanted to saveincome tax. Many of these projects are in fact located in low wind speed areas andhave failed to deliver on the kind of energy production that was expected of them.Foreign investors who had no income tax to save did not find it lucrative to investin wind energy assets.

It has also been seen that buyers take decisions from investment in wind powerprojects at the last moment (just before September 30 and March 31 every year toavail themselves of the accelerated tax depreciation); the equipment suppliers inthe country have evolved as developers themselves and typically undertake alldevelopment activities, including land acquisition, construction, PPA finalizationand transmission tie-up. In fact, many equipment suppliers have bought vast areasof land in high wind potential sites and sold these as part of the deal to buyers. Afterthe commissioning of the project, they even undertake operation and maintenance(O&M) for the buyers. Therefore, readymade projects are sold off-the-shelf byequipment suppliers. Since the equipment suppliers are undertaking the functionsof developers as well, buyers are forced to pay a premium for the wind power projects.This has resulted in wind power projects being more expensive and even restrictingcompetition for equipment supplies.

Regulatory framework for promotion of RE

Definition of RPO

A review of the RPO determined by different SERCs indicates that there aredifferences in the definition of the framework for RPO. There is little consensus


on whether a single RPO percentage should be specified for all RE sources, orRE source/RE technology-specific percentage needs to be specified. There aresome issues which merit discussion here. In case technology-specific RPO isspecified and there is limited availability of a particular RE source in a year, willthe SERC allow such shortfall in RE procurement to be met through anothertype of RE source? If not, the discoms concerned may have little incentive toexplore other RE sources; indirectly limiting investments in such other REsources/RETs. Further, if the discom can meet its RPO through RETs/RE sourcesnot specified by the SERC, it should not be liable to pay penalty for

non-achievement.

Another issue is that of the level of RPO. This has to be carefully determined bySERCs. While a high RPO target would incentivize discoms to purchase more REpower, thereby encouraging investments, such targets may be ambitious in the shortterm. On the other hand, a low target may put a restriction on the amount of energypurchased by a discom from RE sources. This was the case in Gujarat where thediscoms reportedly stopped signing energy purchase agreements with winddevelopers as they had met their RPOs (2.28 per cent as against the mandated2 per cent in FY 2007–08). Moreover, the discoms currently have little incentiveto exceed their RPO.

Finally, some states such as Maharashtra, Gujarat, Madhya Pradesh and Karnatakado not allow the procurement of RE power from outside the state. This is detrimentalto the overall development of RE in the country.

Applicability of RPO

Section 86(1)(e) of EA 2003 provides for specification of RPO on ‘consumption’within the area of discoms. This implies that the RPO should be applied onentire consumption in the area of discoms and not to procurement of energy bythe discoms alone. Currently, only Maharashtra, Rajasthan and Andhra Pradesh

impose RPO on open access (OA) and captive consumers.

Enforcement of RPO

Thus far, only a few states such as Rajasthan and Maharashtra have specified penaltymechanisms on distribution licensees in case the RPO is not met by them.Table 14.5 indicates the extent of penalty levied in these states. In the case ofRajasthan, the penalty is called an RE surcharge and is to be paid to the StateTransmission Utility (STU). The surcharge so collected will be credited to a fund tobe utilized for creation of transmission system infrastructure of RE plants.

232 | Indian Infrastructure: Evolving PerspectivesT

able

14.

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inst

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ents

for

pro

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ion

of

RE

(co

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...)

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hnol

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deve

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ent

wit

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m o

f

invi

tin

g in

vest

men

ts

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n t

radi

ng

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men

tP

rovi

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fin

anci

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cen

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and

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sts

for

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n, t

here

by

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ean

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gen

erat

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as

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e go

vern

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kin

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ty s

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ce: (

com

pile

d fr

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sou

rces

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le 1

4.4:

Reg

ula

tory

fra

mew

ork

for

prom

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n o

f R

E

Typ

e of

reg

ula

tion

Pri

mar

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spon

sibi

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f th

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gula

tion

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lica

bili

ty

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arif

f re

late

d

a.Fe

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arif

fs (

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)/ P

refe

ren

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tar

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vide

an

ass

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pri

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r R

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proj

ects

fee

din

g in

to t

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rid

b.T

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s an

d co

ndi

tion

s fo

r de

term

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ion

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RC

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pri

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ET

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of t

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ts f

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into

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gri

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ns/

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t of

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re in

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spec

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dist

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tion

to

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din

g on

sta

te

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gen

erat

ion

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er (

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ry p

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)SE

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sum

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ce t

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al

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hase

hig

her

cost

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en

pow

er a

nd

prov

ide

ince

nti

ves

for

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gen

erat

ion

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egu

lati

ons

addr

essi

ng

syst

emic

issu

esSt

ate

gove

rnm

ent/

Faci

litat

e de

velo

pmen

t of

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hnol

ogy

neu

tral

such

as

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acc

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elop

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t of

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Cs

plan

ts, a

nd

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w R

E g

ener

ator

s

tran

smis

sion

net

wor

ks t

o co

nn

ect

flex

ibili

ty in

gen

erat

ion

an

d

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pro

ject

s, a

nd

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elin

g &

ban

kin

g,sa

le o

f po

wer

thir

d pa

rty

sale

Sour

ce: (

com

pile

d fr

om v

ario

us

sou

rces

)


Table 14.5: Penalties for non-achievement of RPO

Penalty clause Levied on

Maharashtra Rs 5/unit for FY 2007–08; Distribution licensee, open accessRs 6/unit for FY 2008–09 consumer & captive power plant

Rajasthan RE surcharge of Rs 3.59/ Distribution licensee, open accessunit for FY 2007–08; consumer & captive power plantto continue until revised

Source: SERC orders in states concerned

Few instances of penalties on distribution licensees (discoms) for non-achievementof RPOs have been reported so far. Only the Maharashtra Electricity RegulatoryCommission (MERC) has penalized the discoms for not meeting the mandatedRPOs (refer Table 14.5). MERC has introduced an enforcement charge for shortfallin compliance with RPS obligations at the rate of Rs 5.00/kWh during FY 2007–08,at Rs 6.00/kWh for FY 2008–09, and at Rs 7.00/kWh for FY 2009–10. It was furtherclarified that this enforcement charge, if levied, shall not be allowed as ‘pass through’expense while approving the annual revenue requirement (ARR) of the discom.

Table 14.6: Status of RPO across Maharashtra

Licensees RPO (4% RPO Shortfall Actual Penaltyquantified (MU) (MU) percentage

in MU) achieved (Rs crore)

MSEDCL 3058.07 2658.52 399.54 3.48 % 199.77

TATA Power 107.54 125.00 N/A 4.65 %

REL 368.29 1.02 367.27 0.01 % 183.63

BEST 184.33 3.49 180.84 0.08 % 90.42

MPECS 24.04 0 24.04 0.00 % 12.02

Total 3742.27 2788.03 971.69 2.98% 485.84

Source: MERC

Role of FiTs/tariff orders

Table 14.7 provides an analysis of the impact of a sound regulatory framework onRET-wise capacity added at the state level. The table maps the RET-wise capacityaddition with the tariff orders/FiTs issued.9 It is clear that almost all biomass andwind potential addition has been in states which have determined a FiT. In case ofsmall hydro, nearly 83.4 per cent of the capacity has been added in states whichhave issued a tariff order.


Table 14.7: RET capacity added across states with tariff orders/FiTs

RET Number of states Number of these Percentage ofwith potential states with capacity added

of >100 MW tariff orders across states withtariff orders

Small hydro 25 24 14

Wind 10 9 10

Biomass 16 15 13

Source: MNRE, SERCs

Orissa makes for an interesting case as far as the impact of the regulatoryframework on RE investments is concerned. The state has a wind potential of255 MW. The information on state-wise cumulative wind generation availablefrom MNRE indicates that Orissa does not (perhaps barely) contribute to windgeneration. Likewise for SHP, only 44.3 MW is installed against a potential of295 MW. It is important to note that the state does not have a proper regulatoryframework for these RETs.

While determination of FiT is one aspect of the regulatory framework, adequacyof this FiT is another important aspect to be addressed. In May 2006, TNERCdetermined the FiT for wind as Rs 2.9 a unit in 2006. This tariff was largelyperceived as inadequate and is reflected in the pace of capacity addition of windpower in the state. While the state added 858 MW of wind capacity inFY 2005–06, capacity addition fell to 577 MW in FY 2006–07 and 381 MW inFY 2007–08.10 TNERC, in March 2009, revised the FiT to Rs 3.39/unit for windmillscommissioned after 1 April 2009. Another case of inadequate FiT can be seen inAP. FiT determined by the Andhra Pradesh Electricity Regulatory Commission(APERC) in 2004 were ceiling tariffs. As a result, the discoms in AP were offeringto procure power from RE projects at rates that were much lower than thoseprescribed by APERC. These tariffs, not being economically viable, severaldevelopers dropped their investment plans. Table 14.8 provides an overview ofwind power capacity addition in AP to illustrate this point.

Table 14.8: Year-wise wind power capacity addition inAndhra Pradesh (in MW)

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Capacityaddition 0.0 6.2 21.8 0.5 0.8 0.0


It has been seen that many SERCs tend to use proxies instead of working out tariffson a cost-plus basis. For example, among the nine SERCs that have issued tarifforders for solar PV-based power generation, only two have provided details of theparameters used for determining the tariff (Chhattisgarh and Uttar Pradesh). SomeSERCs have taken the tariff of other RE technologies in the state as a reference pointand added the level of subsidy (as declared by MNRE) to arrive at the tariff for solarPV-based IPPs (West Bengal). There are two issues here. Similarly, there are SERCsthat have provided details of parameters used for determination of FiT of someother RETs. First, if the FiT does not reflect the underlying costs, no capacity additionwill take place. Second, subsidies—where declared by MNRE—are payable forlimited periods; beyond that the FiT will be inadequate.

Finally, many SERCs have determined FiTs for limited periods. For instance, theWest Bengal Electricity Regulatory Commission (WBERC) has prescribed FiT forfive years from the date of regulations coming into force. This FiT is clearlyinadequate given that the life of the power plants is 20 years, thereby giving rise toregulatory uncertainty and impacting on the bankability of the project. For anyproject developer and lender, it is important that the project revenue stream beknown in advance, at least for the period of debt servicing (10 to 12 years).

While CERC has issued regulations on the terms and conditions for determinationof tariffs for different RETs, many states are yet to decide on adopting CERC tariffs.The states and developers have argued that the tariff norms adopted by CERC areinadequate. For example, in the case of solar projects, CERC does not distinguishbetween location/region or technology as far as PLF is concerned. In reality, thePLF would vary across locations/regions and technologies. This is also true of windprojects. Therefore, they have argued for a review of the CERC’s tariff framework.

The impact of regulation and FiTs needs specific mention in case of SHPs. Almostall states determine cost plus tariffs for SHPs. As a result, to ensure high returnsthrough high tariffs, developers have been pushing up capital cost or have not beenallowing capital costs to decrease.

Third party sales through open access

Section 39 of the Act directs the State Government to set up an STU which shallown the transmission network in the state and provide non-discriminatory OpenAccess (OA) to its network. Section 42 of the Act directs the discoms to providenon-discriminatory OA to its distribution network to eligible customers on paymentof wheeling charges and other applicable surcharges. This has been imbibed in theregulatory framework in many states.

However, state utilities are averse to allowing OA to RE sources. In fact, it has beenseen in many cases that the distribution utilities are resenting export of RE power to


other states and are trying to block OA to RE-based generators with the intent offorcing them to sell this energy to the state utilities at dictated prices.11 In somestates, OA for RE generators is restricted to consumer categories with lower tariffs.For example, in Gujarat, though the wind power policy of the state allows third-party sale (TPS) to any consumer in the state, in practice RE generators are allowedto sell power only to industrial consumers and not to commercial consumers. Thisis because commercial consumers have higher tariffs than industrial consumersand the state does not want to lose such high-paying consumers to OA. In a casesuch as this, developers/investors have no incentives by way of profit margins tosupply to industrial consumers.

Besides the above issue, states also restrict OA citing difficulty in scheduling due tothe unpredictable nature of such generation. Further, even though RE generationcan be predicted with 70 per cent probability, utilities insist on predictability ofgeneration with 90 per cent probability. Another issue is the absence of firm policiesor regulatory framework for wheeling charges for RE. The case of Madhya Pradeshas highlighted earlier, is an example of the lack of regulatory certainty on wheelingcharges for OA in the case of RE. In the case of SHP, TPS becomes unviable aftertaking into account wheeling charges and free power to the state government.

Institutional barriers

Inter-institutional coordination

Lack of coordination and cooperation within and between various ministries,agencies, institutes and other stakeholders delays and restricts the progress in REdevelopment. A case in point is the implementation of the GBI announced for windprojects by the MNRE. IREDA started accepting applications from wind projectsunder the GBI scheme soon after the announcement of this scheme. However, theGOI has rejected applications that were made before the notification of the schemethrough the gazette and is considering only applications made after such notification.While this justification may hold ground in principle, in practice IREDA shouldnot have started accepting applications before the notification through gazette. Suchgaps in implementation of policies on account of absence of inter-institutionalcoordination reduce the faith of investors in the investment climate for RE.

Single-window clearance system

Several states have adopted a single-window project approval and clearance systemfor RE. These include Punjab, Himachal Pradesh, Haryana, Rajasthan andUttarakhand. However, the effectiveness of this system is questionable. The issue issometimes complicated by the fact that delays in obtaining clearances for projectsawarded through competitive bidding (such as SHP) result in the levy of a penaltyon the developer. It is understood that Punjab is one of few states where this system


is robust as it sets a time-bound target for getting all approvals (a period of60 days has been specified by Punjab) and RE developers do not have to follow upwith different state government departments.

Pre-feasibility reports for hydro

It is well known that in most states, the state utility or a government-ownedentity entrusted with the responsibility of hydro power development is giventhe task of preparing the pre-feasibility reports (PFRs) for hydro projects. Severalproblems have been observed in this arrangement. First, the PFR is not a bigpriority for many state utilities, thereby leading to a delay in the preparation ofthe PFR and allocation of the project. Second, most of these entities follow veryconventional norms which do not incorporate possible innovations from theperspective of cost reduction or capacity enhancement. As a result, developersfind it difficult to rely on the state nodal agency’s PFR and have their own PFRdeveloped. Development of PFRs may be a barrier to small and local developersseeking to implement such projects. Examples of this can be seen in Sikkim wherePolyplex Industries was allocated three project sites of 40, 80 and 90 MW each.The developer was able to convert these into three projects of 100 MW each throughbetter engineering.

Fiscal and financial barriers

Budgetary constraints

The GOI has announced BGI for wind, rooftop PV and for solar power plants thatdo not qualify under the JNNSM and sell to the state utilities. However, the extentof fund allocation towards payment of such GBI remains to be seen. The budget forFY 2010–11 is awaited in this regard and would be an indicator of GOI’s seriousnessto this end.

Financing of RE projects

RE projects face several difficulties as far as financing is concerned. In general, thedevelopment of RE faces barriers in obtaining competitive forms of finance due tolack of familiarity with and awareness of technologies, high risk perception, anduncertainties regarding resource assessment. These have been elaborated below:

• RE projects tend to have little or no fuel costs and low operation andmaintenance (O&M) costs but their initial unit capital costs tend to be muchhigher than those of fossil generation systems. The higher ratios of capital costto O&M cost are significant because they indicate that these projects carry adisproportionately heavy initial burden that must be financed over the life ofthe project. This makes exposure to risk a long-term challenge (which also haspolicy and regulatory-risk implications).


• The risk of non-provision of subsidies on account of limited or non-availabilityof resources with the government is also significant since these subsidies maybe the lifeline of the project.

• The generally smaller nature of RE projects results in lower gross returns, eventhough the rate of return may be well within market standards of what isconsidered an attractive investment.

• Developers of RE projects are often small, independent and newly establisheddevelopers who lack the institutional track record and financial inputs necessaryto secure non-recourse project financing. Lenders therefore perceive them asbeing high-risk and are reluctant to provide non-recourse project finance. Theywish to see experienced construction contractors, suppliers with provenequipment, and experienced operators.

• Some RETs are newly commercial and are, subsequently, not widely knownamong lenders (although this is changing rapidly). This results in inaccurateperceptions of risk with respect to these projects amongst lenders, therebymaking financing difficult.

• The intermittent generation characteristics of RETs may place them in anunfavourable position regarding structuring of contracts for powertransmission as compared to conventional power projects.

• For small and local developers seeking to implement RE projects, the lack offinancial support for working capital requirements hinders O&M of theequipment.

• The development and operation of small-scale RE projects involves the samebusiness and financial risks as any enterprise. Variability in earnings andtherefore in returns to the equity investors does not enthuse many localentrepreneurs to get involved with such projects.

• The paperwork and soft costs associated with identifying and obtaining accessto financing for small- and medium-scale RE projects is high relative to thefinancing needs.

• Issues relating to underperformance or below par PLF and uncertaintiesinherent to such projects (like those on account of hydrology or wind patternassumed at the time of financing) also pose a barrier to funding of projects.

• Since any delay in payments by offtaking state utility would directly impactdebt serviceability, lenders often seek credit enhancement mechanisms suchas Debt Service Reserve Account (DSRA) or bank guarantee (BG) which maybe beyond small and local developers’ reach.

• Limited understanding/expertise on RE in the financial institutions also actsas a barrier to financing.


Market-related barriers

Level playing field for RE

The current structure of subsidies in the power sector is such that subsidies areeffectively being provided to conventional fossil fuel resources. These giveconventional fuels an unfair advantage over RE, thereby giving the impressionthat the difference between the price of conventional power and RE based poweris too high.

Market for RE

The market for RE projects/products in India can be classified into four segments:

• Government market: where the government buys the output of the projects asa consumer, often providing budgetary support for it

• Government-driven market: where the government pursues the use of RE inestablishments outside its control for social reasons, often providing budgetarysupport or fiscal incentives for the same. For example, the governmentpromotes the use of solar applications in schools, malls and hospitals.

• Loan market: where people take loans to finance RE-based applications sinceself-financing is limited

• Cash market: where high networth individuals (HNI) can buy RE-basedapplications to meet personal energy needs

India is currently at an initial stage of the first two segments. The GOI is not focusingon promoting the third and fourth categories of RE, which may offer high potentialfor RE-based applications.

Fuel costs for biomass

In the case of biomass-based projects, unreliable biomass supply, absence of anorganized fuel market and frequent price fluctuations threaten project viability.It was seen that in early 2000, the cost of biomass was nominal (Rs 300 toRs 400 per tonne) in most states. Over the years, the increase in demand of biomassfor power generation as well as alternative uses has resulted in a demand–supplygap in this sector and resulted in spiralling biomass prices.

The type of biomass available differs from state to state and so do the alternativeuses for biomass. For instance, in Andhra Pradesh, rice husk is used by the fisheriesindustry for packaging for export purposes. But by and large biomass isalternatively used by the SME sector to replace coal for heating (operating boilers),cattle fodder and household usage in rural areas. The availability of biomass andcoal in a state determines the change in price of biomass. For example, inChhattisgarh where coal is available in abundance and at no transportation cost,


the degree of price elasticity for biomass is relatively very low in comparison tocoal. Not surprisingly, the price of biomass is at around Rs 1615 per MT ascompared to the coal price of Rs 2100 per MT (including cost of transportation).12

On the other hand, due to their geographical location, northern states such asPunjab and Haryana, have a critical constraint of coal supply to small scale industryand, therefore, the demand and price elasticity of biomass is very high. Thebiomass price has reached Rs 3500 per ton in these states. It may be argued thatthe potential for biomass-based power projects in both these states is significantlyhigh. While that is true, the alternative usage of such biomass is also high. Forinstance, almost the entire quantity of wheat stalks collected is used as cattlefodder in both the states.

Inadequate market prices

The price of RE power is determined on a cost-plus basis with the objective ofensuring cost recovery for RE projects. Pricing does not reflect environmentalcosts, thereby masking the striking environmental advantages of the new andcleaner energy options. As a corollary, it can be said that undertaking life cycleassessment costs of fossil fuels and RETs would serve to reduce the gap betweenthe price of fossil fuel – based power and RE power.

Transmission network

Availability of evacuation infrastructure and grid integration are amongst the biggestproblems affecting the development of RE projects, particularly SHP projects orwind projects that are located at remote locations with limited or no evacuationinfrastructure. Though states are required to provide the infrastructure forevacuation of power from RE projects, in practice it is the RE developer who has toprovide for such infrastructure. This has an impact on the cost of the project. Evenwhere states provide evacuation infrastructure, such infrastructure is inadequate.In fact, instances of scaling down of RE projects due to inadequate evacuationinfrastructure have come to light. For example, Sai Engineering’s 20 MW project inToos, Kullu (HP), was scaled down to 10 MW due to the absence of adequateevacuation infrastructure. Similarly, in FY 2007–08 Tamil Nadu was unable toutilize all the power generated from wind due to lack of adequate evacuationcapacity.13 It had to consequently buy more expensive power from other states tomeet its needs. The small size of many RE projects and seasonality of generationadd another dimension to the problem as the size of the project does not lendadequate economic viability for extending transmission lines for such projects.The issue needs to be addressed.

The development of evacuation infrastructure and provision of measures forconnectivity to the grid for RE sources is considered the responsibility of the


transmission utility. However, the distribution licensees also have a major role toplay in evacuation of RE generation, as many RE sources are often connected atdistribution voltages. The Forum of Regulators (FOR) has noted that except for afew utilities, such as Maharashtra State Electricity Transmission Company Ltd(MSETCL), Rajasthan Vidyut Prasaran Nigam (RVPN) and Himachal Pradesh StateElectricity Board, others have not included evacuation infrastructure for RE as partof their overall transmission or distribution capex plans. Even in the case of theseutilities, lack of funds is a major issue in being able to realize such plans. It is alsounderstood that the utilities are not well aware of the transmission requirementsfor evacuation of RE-based power.

High equipment costs

It is generally believed that volumes and advancement in technology would drivedown capital costs. However, this is not always true. Several examples exist tothis end—the automobile sector being, perhaps, the best example. Similarly, ithas been observed that the capital cost of even the commercially deployed RETshas not declined over the years, despite increasing capacity. On the contrary, ithas been observed that developers or equipment providers have been quotingincreasing capital costs over the last few years. For example, a trend analysis interms of movement of capital cost for wind projects funded by IREDA for theperiod from the FY 2004–05 to FY 2008–09 indicates that the average capitalcost has gone up from Rs 4.79 cr/MW to Rs 5.76 cr/MW.14 Several reasons havebeen cited for this—the main ones being the huge demand–supply gap due toexports, inadequate built-up capacity in the Indian RE equipment industry andcartelization of equipment suppliers. As a result, the cost of power from theseRETs remains high.

Inputs for RE plants

Many RE projects suffer from problems similar to those faced by conventional powerplants. Wind and solar thermal projects require vast areas of land. In addition toland, solar thermal projects also require huge quantities of water. The absence ofwater in several states having high solar power potential such as Rajasthan maycomplicate the task of capacity addition.

Absence of serious developers for SHP

The SHP segment has seen several non-serious players who have primarily bid forprojects or entered MoUs and got project allocations only to make short-term gainsthrough the sale of projects—post-clearance—to the buyer who pays the largestpremium to them.


Technological barriers

Technology risk

In the case of many new RETs such as solar thermal, the risks related to technologyare high. Since the technology is at a development stage, the risks are not clearlyknown. Further, even though the technology may have been deployed elsewhere inthe world, its performance under Indian conditions remains to be seen. Moreover,the risk of technology obsolescence is high.

Absence of minimum standards

Some RETs are characterized by the lack of minimum standards in terms of durability,reliability, performance, etc., thereby affecting their large-scale commercialization.

R&D and manufacturing capabilities

One of the biggest problems confronting RETs such as solar power is the high upfrontcost of establishing a solar plant. Investments in R&D with the objective of costreduction and scaling up of operations to utilize economies of scale have long beenadvocated as solutions to these problems. Around the world, companies andgovernment-backed research projects are engaged in advanced R&D and arecontinuously setting up bigger, more advanced manufacturing facilities. In India,however, manufacturing facilities are only focused on replicating existingtechnologies and are limited to small processing units. India’s manufacturingcapacity is about 700 MW for PV modules as compared to facilities in countries likeUSA, China, Germany, Malaysia, etc., capable of multi-giga watt production. Indiais relying on international suppliers for equipment as well as technology. However,there is no indigenous capacity/capability for solar thermal power projects.

Non-availability of local technology

In many cases, the technology or equipment is imported. This implies that spareand replacement parts when required may not necessarily be readily availableespecially in more remote locations.

Information barriers

Lack of skilled manpower

Lack of trained personnel for training, demonstration, maintenance and operations,along with insufficient awareness and information programmes for technologydissemination, impedes renewable energy penetration. Experience indicates thatsubsequent to installation of RE projects/applications, no proper follow-up orassistance was available for their maintenance, thereby impacting their working.The impression that has been formed from such experiences is that RE installationsdo not work.


Lack of information and awareness

General information and awareness in relation to new technologies andunderstanding the practical problems in implementing and maintaining RE projectsis limited.

REVIEW OF SELECT PROGRAMMES/POLICIES OF GOI FOR PROMOTION OF RE

Jawaharlal Nehru National Solar Mission

As mentioned earlier, the JNNSM announced in November 2009 has brought aboutsignificant changes in the way solar power will be developed in the country. Keyprovisions of JNNSM are summarized in Box 14.1 (for more details, refer toAnnexure 4). While the intent of the JNNSM is not under doubt, there are severalissues that require greater clarity and further action. This section discusses the statusof the key policy and regulatory actions being undertaken to implement the JNNSMand the concerns emerging therein.

Status of implementation of JNNSM

Solar power purchase policy

The GOI has appointed NVVN as the nodal agency for purchase and sale of grid-connected solar power under Phase I of the JNNSM. The solar plants participatingunder the scheme have to be connected to the grid at 33 kV and above. For eachMW of solar power procured by NVVN under a PPA, NVVN will be allocated anequivalent amount of capacity from the unallocated power of NTPC coal-basedstations. The tariff for the sale of this bundled power will be determined by CERC.In addition to this tariff, utilities will have to pay a facilitation charge to NVVN.MNRE and NVVN have estimated that the bundled power would be sold in therange of Rs 5 to Rs 5.50 per unit (see Figure 14.4). Since this price would be lowerthan the price of electricity purchased through the power market, discoms wouldbe willing to buy this bundled power (see Table 14.9). Prima facie, this seems tobe a good solution. By purchasing this bundled power, states/discoms would getthermal power to meet some amount of the power shortage faced by them. At thesame time, they would be able to meet their RPO.

MNRE and NVVN are in the process of devising guidelines for theimplementation of this policy. Two distinct schemes have been devised: aMigration Scheme for existing projects, i.e., Solar Power Developers (SPDs)who have already initiated a definite process of setting up solar power plantsand have made arrangements for sale of power to utilities and a scheme for newprojects, i.e., SPDs approaching with new proposals for setting up solar powerprojects. The time frame for the signing of PPAs and power sale agreements(PSAs) under both schemes is indicated in Figures 14.5 and 14.6 and the


Box 14.1: Salient features of JNNSM

• Achieving installed capacity of 20,000 MW in a phased manner by the end of the

13th Five-Year Plan in 2022

Phases Target for grid solar power including Target for off gridrooftop solar applications

Phase I (2010–13) 1000–2000 MW 200 MW

Phase II (2013–17) 4000 MW (10,000 MW based on 1000 MW

enhanced international finance &

technology transfer)

Phase III (2017–22) 20,000 MW 2000 MW

• Demonstration projects focused on CSP in Phase I

– 50–100 MW solar thermal plant with 4–6 hours’ storage (which can meet both

morning and evening peak loads and double plant load factor up to 40%)

– A 100–MW capacity parabolic trough technology based solar thermal plant

– A 100–150 MW solar hybrid plant with coal, gas or bio-mass to address

variability and space constraints

– 20–50 MW solar plants with/without storage, based on central receiver

technology with molten salt/steam as the working fluid and other emerging

technologies

• Shift away from GBI-based framework to one that relies on reducing the cost of

delivered solar power for grid-connected solar projects

– NTPC Vidyut Vyapar Nigam (NVVN) to purchase the 1,000 MW solar power

(connected to 33 kV or more grid) planned in Phase I

– GOI to allot another 1,000 MW capacity of thermal power from unallocated

quota of NTPC stations, i.e. from power available under GOI’s discretion to

allocate to states that are in shortage

– NVVN to bundle this power and sell it at a rate determined by CERC

• Solar-specific RPO to be fixed for states after modification of the National Tariff

Policy 2006 – RPO may start with 0.25% in Phase I and increase to 3% by 2022

• Provision of a GBI to rooftop solar PV and other small solar power plants connected

to LT/11 kV grid

– GBI rate: tariff fixed by CERC minus notional tariff of Rs 5.5 per unit, with

3% annual escalation

• Provisions for technology development, fiscal incentives, indigenization requirement

and human resource development


minimum requirements for SPDs to qualify under the schemes is listed in Table 14.9.It is important to note that out of the 1000 MW proposed to be developed underthis route, 250 MW will be contributed by NTPC from its proposed solar thermalplants at Anta and Suratgarh.

Figure 14.5: Time frame for completion of migration scheme under solar powerpurchase policy of JNNSM

Figure 14.6: Time frame for completion of scheme for new projects under solarpower purchase policy of JNNSM

Figure 14.4: Bundling mechanism for sale of solar power under JNNSM* Given the higher capacity factors of coal-based generationFor illustration purposes only

Solar power developer NTPC unallocated power

PV: Rs 18.44/unitCSP: Rs 13.45/unit

NVVN

Rs 2/unit

X kWh 3X kWh*

Price of bundled power or weighted pricePV: (18.44X + 6X)/5X = Rs 6.1/unit

CSP: (13.45X + 6X)/5X = Rs 4.9/unit

Sale price of powerIf ratio of PV to CSP is 40:60 = Rs 5.36/unitIf ratio of PV to CSP is 50:50 = Rs 5.49/unit

Utility

MNRErequestedstates for

informationon SPDs

interested inmigrating

Circulationof draftMOU to be

signedwith SPDs& discoms

Meeting ofMNRE, MoP,NVVN, SPDs

& discoms for signing

MoUs

Signing ofPPAs &

PSAsJan 11,

2010

Feb 1stweek2010

Feb 24-26,

2010

Mar 31,2010

Invitationof EOI

Last date forapplications &registrations

SPDs to submitdocuments

required for MOU

Selection of SPDsby a CentralEmpoweredCommittee

Forwarding ofdetails to statesfor validation/

recommendation

Confirmation ofpreparedness of SPDs& recommendations

by states

Sep 2010

Sep 30, 2010

Signing of MoUswith SPDs

Signing of PPAs& PSAs

Mar 10, 2010

Apr 30, 2010

Jun 30, 2010

Jul 15, 2010

Aug 2010

Oct 31,2010


Table 14.9: Salient features of the schemes proposed under the solar powerpurchase policy of JNNSM

Migration scheme Scheme for new projects

Minimum

qualification

requirement

for SPDs

Criteria for

participation

under the

scheme

–

– Clear title and

possession of land

(say, @ approx. two

hectares/MW)

– Approval from STU

for evacuating power

to the grid at 33 kV

and above

– Confirmation from

states concerned/

discoms for purchase

of all the power from

the solar power plant

through NVVN

– Necessary water

linkage from the

state authorities

concerned

(for CSP plants)

– Letters of comfort for

funding the project

– Bank guarantee

@ Rs 50 lakh per MW

to NVVN, out of

which Rs 25 lakh per

MW to be given at the

– Net worth of the SPD for the past three

years (level to be determined)

– Turnover of SPD for the past three years

(level to be determined)

– Technical requirement (to be

determined)

– Confirmation for plant CoD to be on or

before March 31, 2013

– Confirmation from STU for evacuating

power to the grid at 33 kV and above

– Availability of statutory and other

clearances as applicable

– Complete Detailed Project Report

– Letter of comfort for equity/debt from

promoter(s)/financial institution(s)

– Letter of confirmation from the state

authority regarding identification/

notification/allotment of land for setting

up of the solar power plant

– Necessary water linkage from the

state authorities concerned

(for CSP plants)

– Submission of bank guarantee (to be

determined)

– No change in equity holding permitted

from MOU signing till PPA execution


Table 14.9: Salient features of the schemes proposed under the solar powerpurchase policy of JNNSM (contd...)

Migration scheme Scheme for new projects

Features of

PPA with

SPDs

time of signing of

MOU & balance

Rs 25 lakh per MW to

be given at the time of

signing of PPA

– No change in equity

holding permitted

from MOU signing till

PPA execution

– PPAs to be the same as

that signed with

discoms

– PPA for 25 years as per CERC regulations

– Tariff to be determined by CERC

– SPD to deliver power at 33 kV or above

substation of discom/STU

– Discoms to bear transmission charges,

losses, RLDC/SLDC charges, scheduling

charges or any other charges for supply of

solar power beyond delivery point

– Billing & payment cycle as per energy

accounts issued by RPC/SLDC

– Scheduling of power as per Indian

Electricity Grid Code

– NVVN to establish irrevocable revolving

letter of credit in favour of SPD prior to

commencement of electricity supply

from the plant

– Payment Security Mechanism as per

Tripartite Agreement and open

irrevocable revolving letter of credit

– Aggregate shareholding of promoter not

to go below 51% for 3 years after COD.

Any reduction thereafter to be approved

by NVVN


Generation-based incentive

Under the JNNSM, GBI is available to solar PV installed on residential rooftops,and commercial, institutional, industrial and on other rooftops, as well as to tail-end grid-connected projects. The payment of GBI to these installations will be madeby utilities on net metering basis and the GBI will be paid/reimbursed to utilities bythe GOI through IREDA. The duration of the PPA to be signed between theestablishments deploying rooftop PV and the utilities would be determined by theSERCs. The SERCs are also required to formulate guidelines/regulations for themetering and billing arrangements between the utility and the rooftop PV operator.It is learnt that the FOR is formulating standardized billing and payment guidelinesin this regard. The FOR is also preparing a Model PPA which would be issued to theutilities by March 2010. The Central Electricity Authority (CEA) is in the process ofissuing technical guidelines for the connection of such installations with the grid.

Technology to be promoted

In the case of the scheme for new projects under the Solar Power Purchase Policy,the ratio of solar PV to concentrated solar power (CSP) or solar thermal isproposed at 40:60.

Demonstration projects

The MNRE aims to set up these projects through the competitive bidding route.The Power Finance Corporation (PFC) is preparing bid documents for award ofthese projects and the bidding is expected to be initiated by the end of 2010.

Key concerns over JNNSM

While the objectives of JNNSM are laudable, and so too the GOI’s intentionand efforts towards its implementation, there are several concerns that need tobe addressed to ensure its smooth implementation. These concerns are as follows:

• The target of 20,000 MW under the JNNSM appears unrealistic given thedomestic capability for solar projects, technology risks associated with solarenergy and financial implications of the target. Further, the JNNSM does notprovide concrete plans on the manner in which the target of 4000 MW wouldbe scaled to 10,000 MW at the end of the Twelfth Plan.

• What should be the appropriate technical and financial criteria for qualificationof SPDs under the scheme for new projects in the Solar Power Purchase Policy?The GOI is keen to encourage only serious players to come forward under thisscheme and is therefore contemplating rigid qualification criteria. This may,however, be detrimental to smaller players who may have genuine intent aswell as the ability to set up projects.


• Some developers have proposed the setting up of projects over smaller areas ofland than contemplated by GOI. For example, while GOI is considering landrequirement of approximately two hectares/MW, some developers have comeforward with proposals involving land requirement of 1.2 hectares/MW. Lowerland requirement translates into lower time for land acquisition and, therefore,faster project implementation. The question, therefore, is how the GOI shouldchoose developers who propose projects with lower land requirements.

• Several developers have expressed concern over the GOI’s focus on solar thermaltechnology in the first phase of JNNSM. It has been argued that the GOI isignoring global trends which indicate that solar thermal is a new and yet to becommercialized technology. However, some experts do not subscribe to this.They assert that solar thermal technology is in no way new or unproven.Another argument against the focus on solar thermal technology is the longtime frame for commissioning of projects. This has an implication forcommissioning solar thermal plants by 2013 to meet the targets of the firstphase of JNNSM. Therefore, there is a need for GOI to back its focus on solarthermal techonology with adequate evidence.

• The time frame proposed for the application and registration of new projectsunder the scheme for new projects in the solar power purchase policy isaggressive. This is also significant in light of the proposed conditions of thePPA which state that the aggregate shareholding of the promoter has to bemore than 51 per cent for three years after COD. Given the little time givenfor making applications under the scheme, developers who are not able tomeet the qualification requirements may tie up with anyone meeting thesame to ensure qualification. However, this may become a problem in viewof the PPA’s conditions. Moreover, bringing in a serious investor or partnermay become difficult. Therefore, there is a need to examine the proposedtime frame.

• Though the mission lays a lot of thrust on R&D, the R&D strategy may actuallytake a long time to finalize. The GOI must fix a time frame for the setting up ofthe high-level research council described in the Mission, the development ofthe technology road map by them to achieve more rapid technologicalinnovation and cost reduction, and the establishment of the National Centreof Excellence (NCE) to implement the technology road map.

• Another aspect where the Mission is weak is the scaling up of R&Ddemonstration projects or pilots to the commercialization stage. The Missiontalks about funding support from the NCE for performance-linked solar R&Dprogrammes, including such demonstration projects. However, it remains silenton the support required to take projects or R&D to commercialization stages.


Such support is important in keeping with the past experience of demonstrationprojects in RE in India where a number of pilot projects have been undertakenbut have not been pursued further.

• The implementation of the Mission may also face barriers due to the absenceof the solar supply chain in India. There are no manufacturers for silicon crystalsand wafers in the country and limited number of equipment suppliers for cells(this is true even globally). The quality of equipment is often uneven due tothe absence of industry standards and the spares are expensive. In the case ofrooftop PV, the lead time for balance of supply (BOS) materials such as invertersis very high. These problems are compounded by the absence of local servicecapability. While the Mission focuses on the creation of local capacity to buildtechnically qualified manpower, interventions such as creation of a supplychain are weak.

• The issues related to land acquisition for solar thermal projects would be thesame as those for any conventional power project. Unless the issuessurrounding land acquisition are addressed in the overall context ofinfrastructure projects, it is unlikely that the capacity addition targeted forthe first phase would be met.

• The Mission does not provide any incentive to states to enable speedyimplementation. The only perceptible role for states is provision of land andwater, and provision of infrastructure for evacuation of power from solarprojects. No clarity has been provided and no mechanism spelt out on themanner in which power purchased under the solar power purchase policy byNVVN would be allocated to states. Certainty in this regard is crucial for statesas they would be required to meet solar RPOs determined by SERCs goingforward. A related issue here is the migration of existing projects to the solarpower purchase policy. Developers are concerned that in the absence of clarityon allocation of power by NVVN, states may not allow them to migrate underthis policy. It may be argued that in the event of shortage in procurement ofsolar power, states can fulfil their RPOs by purchase of solar RECs. But theuncertainty in the level of RPOs in future, quantum of RECs generated andprice of RECs poses a barrier here.

• The Mission only recommends the provision of fiscal incentives fromthe Ministry of Finance (MoF) in the form of customs duties and exciseduties concessions/exemptions on specific capital equipment, criticalmaterials, components and project imports. There is no commitmentfrom the MoF to this end. This issue is critical for developers in light ofthe deadline for application and registration of new projects proposedby MNRE and NVVN.


• The Mission proposes the creation of a single-window clearance mechanismfor solar power projects. However, states as well as the CERC have opined thatprovision of single window clearance is difficult.

• Increased RPOs for solar energy would imply the need to increase consumertariffs which may be difficult for most utilities. It may be argued that the shareof solar energy in the total power purchased by a state utility would be relativelylow and therefore should not have a significant impact on consumer tariff.However, in a scenario where state regulators and utilities increasingly find itdifficult to make any tariff hikes, they would find it difficult to pass on eventhe smallest impact of increased solar RPOs to consumers.

• The availability of transmission infrastructure to evacuate and transmitpower that would be generated if the planned capacity addition materializesis in doubt.

• The Mission provides for GBI for rooftop PV. The extent of GBI has beenlinked to the tariff to be determined by CERC. However, there is no mentionof the time frame for which this GBI would be provided. Further, this GBIwould be routed through the state utilities. The intention of utilities towardsthis end is doubtful. The absence of a regulatory framework for rooftop PV atthe state level is also a cause for concern. Unless states are active and issueregulations enabling rooftop PV in line with the guidelines issued by FOR, thedeployment of rooftop PV would not make much headway.

Finally, an issue that is of concern is that projects that do not qualify under the solarpower purchase policy will have to supply directly to state utilities. Even though theGOI has stated that GBI would be available to these projects as per the GBI schemeannounced by GOI before the announcement of the JNNSM (see Annexure 2),developers are concerned about the poor payment security mechanism madeavailable by state utilities as well as the financial viability of utilities.

GBI for wind

As indicated in Annexure 2, MNRE is providing GBI to grid-connected windpower projects at Rs 0.50 a unit for a period not less than four years and amaximum period of 10 years in parallel with accelerated depreciation on amutually exclusive manner, with a cap of Rs 62 lakh/MW. However, GBI will beprovided only to wind projects selling power to state utilities as well as captivewind power projects. Projects undertaking TPS by way of merchant power oropen access are excluded from the purview of the scheme. The GOI shouldreconsider the exclusion of projects undertaking TPS as this would enable theexpansion of the wind power market.


RECOMMENDATIONS

Policy

• GOI must formulate a comprehensive policy or action plan for all-rounddevelopment of the sector, encompassing all the key aspects. The action planshould be prepared in consultation with the state governments. It is understoodthat the Energy Coordination Committee of GOI has approved the preparationof an umbrella RE law to provide a comprehensive legislative framework forall types of RETs, their usage and promotion. However, GOI has fixed notime frame for the formulation and enactment of such a law. The GOI mustspeed up this task and ensure that the desired law be enacted expeditiously.

• ‘Must Run Status’ for RE—GOI should accord a ‘Must Run Status’ for RE-based power to ensure effective utilization of this power. The CERC—underthe (Terms and Conditions for Tariff determination from Renewable EnergySources) Regulations, 2009—has determined that all RE plants except forbiomass power plants with installed capacity of 10 MW and above, and non-fossil fuel-based cogeneration plants shall be treated as ‘must run’ powerplants and shall not be subjected to ‘merit order despatch’ principles. Toensure that states adopt this provision in their regulatory framework, astatement to this effect in a comprehensive policy for RE by GOI would bemore effective.

• States must be encouraged to remove policy and regulatory uncertaintysurrounding RE. They must be encouraged to identify their thrust areas as faras RE development is concerned. Punjab is a good example here. The NRSEPolicy of the state clearly specifies the objective, targets, thrust areas, andmeasures to achieve the targets. It also provides short-and long-term targetsfor the RE sector in the state. Gujarat is another example. The state governmenthas identified wind and solar power as its thrust area. In the case of biomass,states must be encouraged to have clear policies on the radius for setting upbiomass plants. Strict adherence to such a policy must be encouraged in orderto ensure the viability of biomass projects.

• Provision of GBI may be considered for SHPs as well. The tariff determined byCERC with normative capital cost may be adopted for this purpose.

• In the case of solar thermal, a UMPP-like mechanism may be adopted for theaward of projects. A special purpose vehicle (SPV) may be set up for a projectwherein this SPV is responsible for all initial project activities, including landacquisition, obtaining of clearances, preparation of DPRs, tying up of basicfacilities required for the implementation of the project, etc., before handingover the project to a selected developer.


• In the case of biomass projects, developers must be encouraged to involve thefarming or fuel supply community by providing them with a share in therevenues earned from the project.

• There is a need for stronger initiatives at local body levels for the promotion ofRE. For example, local bodies must be discouraged from granting municipalapprovals for commercial buildings in urban areas unless they house a solarapplication. Solar installations should be a precondition for a power connectionfrom the utility.

• The commercial success of RETs depends significantly on adoption andenforcement of appropriate standards and codes. GOI must prescribeminimum performance standards in respect of durability, reliability, andperformance for different RETs to ensure greater market penetration.

Regulation

• As discussed earlier, only sixteen states have notified RPO. States must bemandated to set RPO targets in a defined time frame, failing which the CERCmay be given the task of determining the RPO for them.

• There is an urgent need for clarity on the RPO framework. It may be better tospecify the overall RPO percentage rather than technology-specific percentages.This in turn would encourage investments in RE on the basis of techno-economic analysis. Further, there should be no cap on RPO.

• RPO must be levied on OA and captive consumers as well.

• For RPO to be effective and their objectives to be met, it is imperative that anenforcement mechanism be introduced in all states.

• SERCs must monitor the compliance of RE obligation through the ARR/Tariffapproval process. Further, SERCs must consider monitoring compliance withRPO, subject to availability of energy from renewable sources (not restrictedto the state), by invoking Sections 142 and 146 of EA 03 against the responsibleofficer of the utility.

• Suitable incentives should be devised to encourage utilities to procure RE powerover and above the RPO mandated by the SERC.

• SERCs may amend the licence for power distribution which should be amendedto include fulfilment of RPO. This would imply that non-fulfilment of RPOwould be treated as violation of licence conditions and would attract suitableactions under EA 03.

• A number of states (such as Maharashtra, Gujarat, Madhya Pradesh andKarnataka) do not allow the procurement of RE power from outside the state.This raises an artificial barrier in the way of RE power generation and investment


across the country. Instead, regulators can identify ways and means of sellingthis power to neighbouring states short on RE resources or RPO at a mutuallyagreed upon rate.

• All state governments/SERCs may consider concessional transmission on REbeing sold within the state.

• CERC has issued tariff guidelines covering critical aspects related to renewableenergy sources from the long-term perspective of harnessing of availablerenewable energy potential. These guidelines provide clarity on each componentof the FiT for different RETs as well as the useful life of different RETs. Thecontrol period for these guidelines is three years. States must align their FiTsto the provisions of these guidelines.

Transmission requirements

• Grid connectivity to RE generation should be provided by STUs through theircapex plans that are approved by the SERCs. Transmission system plansprepared by STUs should cover evacuation and transmission infrastructurerequirements for RE sources.

• There is a need to provide funds and capacity to STUs for this purpose.

• STUs should also be made accountable and penalized if they fail to fulfil thisresponsibility. A possible penalty mechanism in this regard can be making theSTU responsible for deemed generation if evacuation is not in place by thetime of commissioning of the projects. This mechanism has been adopted inHimachal Pradesh.

• There is a need to establish specific norms for grid connectivity for REprojects. SERCs can take this up under Section 86(1)(e) of EA 2003.However, since these aspects would need to be addressed as part of thelarger issue of grid standards and standards for construction of transmissionlines, the CEA may undertake this exercise under Sections 34 and 73(b) ofEA 03.

• There is a much stronger need for coordination and consultation between theSTU and the nodal agency responsible for development of RE at the state levelfor the development of transmission infrastructure for RE projects that are inthe process of being allotted or developed or are likely to be bid out in the nearfuture.

Fiscal incentives

GOI may consider fiscal incentives in the form of excise and customs duty reduction/exemption for RE equipment.


Financing of RE

• In order to increase the availability of funds for RE projects, GOI may consider

mandating insurance companies and provident funds to invest 10 per cent of

their portfolio into RE. Such investments, in fact, make business sense for the

insurance companies. RE, given its benefits, will cause less damage to the

environment and human health, thereby implying a lower risk of insurance

payouts for these companies.

• RE should be declared a priority sector. At present the priority sector

broadly comprises agriculture, small-scale industries and other activities/

borrowers (such as small business, retail trade, small transport operators,

professional and self-employed persons, housing, education loans,

microcredit, etc.). The inclusion of RE in priority sectors will increase the

availability of credit to this sector and lead to greater participation by

commercial banks in this sector.

• GOI should ask banks to allow an interest rebate on home loans if the

owner of the house is installing an RE application such as solar water heater,

solar lights or PV panel. This would incentivize people to integrate RE

applications into their home, thereby encouraging the use of RE. The rebate

could vary depending on the number of applications installed or the type

of installations installed.

• GOI may consider allowing a higher exemption on the rate of interest of

home loans under income tax rebates for individuals who instal RE

applications in their homes. Once again, the extent of rebate could vary

depending on the number of applications installed or the type of

installations installed.

Manufacturing

• To achieve low-cost manufacturing and therefore lower capital costs, and to

capitalize on its inherent advantages in the solar sector, India needs to

consider revamping and upgrading its solar R&D and manufacturing

capabilities. In this regard, GOI may consider promoting a core company to

produce wafer and silicon. This will enable substantial reduction in the costs

of solar technologies.

• Given the continuing high capital costs of even the commercially deployed

RETs despite increasing capacity, there is an urgent need to encourage price-

reduced capital cost manufacturing through policy.


Development of a fuel cost adjustment methodology for biomass projects

In a scenario of fixed FiT, the volatility in biomass prices suppresses the PLF ofpower plants. Though many SERCs have revised the FiT and would do so in future,they may consider putting in place a fuel cost adjustment methodology to passthrough any increases in fuel costs in tariff as has been done in the case of coal-based plants.

The CERC—under the (Terms and Conditions for Tariff determination fromRenewable Energy Sources) Regulations, 2009—has specified the price of biomassand bagasse for different states and determined a fuel price indexing mechanism. Ithas also provided the option of normative escalation of 5 per cent per annum foreach subsequent year of the three-year control period. SERCs need to adopt thisapproach. Such fuel cost adjustment in tariff will, however, need a strong institutionalset-up for monitoring the price of biomass as well as the costs of its collection,transport and storage.

Better location analysis for biomass projects

In order to achieve continuous and reliable fuel supply for biomass plants, theirlocation must be optimized. State nodal agencies must, therefore, develop a planfor development of biomass projects indicating the number and location of suchplants by considering the total biomass potential available in each district, the densityof such availability and potential collection centres.

Capacity building and information dissemination

• There is an urgent need for technical assistance programs designed to increasethe planning skills and understanding of RETs by utilities, regulators, localand municipal administrations, and other institutions involved.

• Information specific to viable RETs needs to be made easily accessible both toincrease general awareness and acceptability as well as to aid potential investorsand sponsors of such projects.

• Capacity-building initiatives should be undertaken to train people/workers tooperate and maintain RE facilities

• There is a need to improve the maintenance support mechanism for REproducts/plants to redress the post-installation problem faced by the users.For RE plants, the after-sales service network can be strengthened byencouraging the setting up of service centres by the manufacturers which areinvolved in the supply of the systems. For RE applications, the same can bedone through the Akshaya Urja shops.


ANNEXURE 1Provisions for development of RE under Electricity Act 2003 and policiesissued therein

Electricity Act 2003

The EA 03 has the following provisions for promotion and development of RE:

• Section 3(1) requires GOI to prepare the National Electricity Policy and tariffpolicy, in consultation with the state governments and the authority fordevelopment of the power systems based on optimal utilization of resourcessuch as coal, natural gas, nuclear substances or materials, hydro and RE.

• Section 61(h) requires electricity regulatory commissions (ERCs) to considerthe promotion of co-generation and generation of electricity from RE whendetermining the terms and conditions for the determination of tariff intheir jurisdictions.

• Section 86 promotes RE by ensuring grid connectivity and sale of renewableelectricity. It mandates SERCs to promote cogeneration and generation ofelectricity from RE by providing suitable measures for connectivity with thegrid and sale of electricity to any person, and also specify, for purchase ofelectricity from such sources, a percentage of the total consumption of electricityin the area of a distribution licensee (discoms).

National Electricity Policy

The NEP was notified by GOI in February 2005 as per provisions of Section 3 ofEA 03. Clause 5.12 of NEP contains several conditions in respect of promotion ofRE. The salient features of the said provisions of NEP are as follows:

• Clause 5.12.1 targets the reduction in capital costs of RETs and identifiescompetition as one of the means for such reduction. It also specifies the needfor adequate promotional measures for development of RETs and theirsustained growth.

• Clause 5.12.2 requires SERCs to determine tariffs for purchase of power fromRE by discoms (until RE can compete with conventional sources in terms ofcost), specifying percentages that progressively increase the share of electricitypurchased by discoms from renewable sources.

• Clause 5.12.3 highlights the benefits of cogeneration and promotes its use bysuggesting that SERCs promote arrangements between a co-generator and adiscom for purchase of surplus power from such plants.

• Clause 5.2.20 states that efforts will be made to encourage private sectorparticipation through suitable promotional measures to increase the overallshare of non-conventional energy sources in the electricity mix.


Tariff policy

The National Tariff Policy (NTP) was notified by GOI in January 2006 as perprovisions of Section 3 of EA 03. This policy has further elaborated the role ofregulatory commissions, the mechanism for promoting harnessing of renewableenergy and the time frame for implementation, etc. The salient features of NTPwith regard to RE are as follows:

• SERCs to specify minimum percentages for electricity to be purchased fromRE sources by 1 April 2006.

• Future procurement of RE by discoms to be done, as far as possible, throughcompetitive bidding process (as specified under Section 63 of EA 03) bysuppliers offering energy from same type of RE sources.

• GOI to lay down guidelines within three months for pricing non-firm power,especially from RE sources, to be followed in cases where such procurement isnot through competitive bidding.

ANNEXURE 2Policy interventions for promotion of RE

Fiscal incentives

• Capital subsidy: The MNRE has been running several capital subsidyprogrammes. These subsidies are provided on installation of the equipment;they are not linked to the use or performance of the equipment.

• Interest subsidy: The GOI has been providing subsidies in the form of reductionin the interest rate for financing installation of equipment. Currently, interestsubsidy is available to end-users of solar thermal programme, for both domesticand commercial applications.

• Direct tax benefits: The GOI has offered a 10-year tax holiday under Section 80IA of the Income Tax Act for all RE projects, including solar. It also has a schemefor accelerated depreciation under which tax savings can be claimed againstinvestments in solar up to 80 per cent of the asset value, starting from Year I.

• Indirect tax benefits: Indirect tax benefits such as reduction or exemption ofelectricity duty (ED), VAT, octroi or other local taxes have been used as aninstrument by state governments for reducing the price the consumer pays forusing RE-based power, including solar. States such as Madhya Pradesh andPunjab have exempted such projects from the payment of VAT and octroi orother local taxes. Others such as Gujarat and Madhya Pradesh (MP) haveexempted consumption of electricity generated by solar power projects frompayment of ED. In the case of MP, the exemption of electricity duty and cess isapplicable for the first five years of the project. In Rajasthan, consumption of


electricity generated by solar power projects for captive use or for sale to anominated third party attracts reduced ED (50 per cent of ED that wouldotherwise be applicable) for a period of seven years from the date ofcommissioning of the project.

Production subsidies

The MNRE introduced generation-based incentives (GBI) to back up the feed-intariffs for grid-connected solar and wind power in 2008. GBI is an attempt to changethe nature of the RE industry in India, especially wind. Hitherto, wind investorsprimarily included Indian corporations or individuals who could offset their incometax liabilities by investing in wind or solar power through accelerated depreciation.However, few foreign firms or Independent Power Producers (IPPs) found thismarket attractive on account of limited or no income tax to offset. Brief descriptionsof the GBI schemes are provided below.

GBI in solar projects

Prior to the announcement of JNNSM, the GOI had announced the provision ofGBI for grid interactive solar projects up to a maximum capacity up to 50 MW(including solar photovoltaic as well as solar thermal power generation) during theEleventh Plan period subject to minimum installed capacity of one MW per plant.Under the scheme, a maximum cumulative capacity of 10 MW of solar PV powergeneration projects and 10 MW of solar thermal power generation projects couldbe set up in a state. The scheme envisaged provision of GBI of a maximum ofRs 12 a unit for solar PV and Rs 10 a unit for solar thermal after taking into accountthe per unit power purchase rate provided by the SERC or utility for that project.The GBI for a project would be determined after deducting the power purchase rateoffered by the utility under the PPA from a notional amount of Rs 15 a unit forsolar PV and Rs 13 a unit for solar thermal projects. The power generation plant isto be commissioned by 31 December 2009 after which the incentive will reduce by5 per cent and the ceiling rate for the incentive would become Rs 11.40 a unit forsolar PV and Rs 9.50 a unit for solar thermal projects.

GBI in wind

Under this scheme, the MNRE is providing GBI to grid-connected wind powerprojects at Rs 0.50 a unit for a period not less than four years and a maximumperiod of ten years parallel with accelerated depreciation in a mutually exclusivemanner, with a cap of Rs 62 lakh/MW. This implies that companies may availthemselves either of accelerated depreciation or GBI, but not both. Once a companyhas opted for one benefit, it cannot change the option later. The total disbursementin a year will not exceed one-fourth of the maximum limit of the incentive, i.e.,


Rs 15.50 lakh/MW during the first four years. The scheme will be applicable to amaximum capacity limited to 4000 MW during the remaining period of the11 FYP. The provision of GBI will continue till the end of the Eleventh Plan.

The GBI will cover wind projects selling power to state utilities as well as captivewind power projects. But projects undertaking third party sale by way of merchantpower or open access are excluded from the purview of the scheme.

State-specific policies for promotion of RE

A number of state governments (Karnataka, Punjab, Rajasthan, and Madhya Pradesh,to name a few) have introduced state-level policies for the promotion of RE. Somehave issued policies specific to certain RETs. Gujarat and Maharashtra are cases inpoint, with Gujarat having issued policies specific to wind and solar energy, andMaharashtra policies for wind, waste-to-energy and cogen. The state policiesencourage investments in RE through measures such as single-window clearancesystem, creation of green energy funds, streamlined procedures for allocation of REprojects and project sites, and other incentives such as relaxation in state taxes, etc.

RE funds

In an effort to promote investment in RE, states like Maharashtra and Rajasthanhave created Green Funds to provide soft loans for RE technologies. The MaharashtraEnergy Development Agency (MEDA) has created a Clean Energy Fund by taxingconventional energy sources (see Box 14.2). In the case of Rajasthan, the RajasthanElectricity Regulatory Commission has determined that any shortfall to meet theRE obligation by the distribution licensees, open access consumers and captive powerusers involves the payment of an RE surcharge to the State Transmission Utility(STU). The RE surcharge will be as notified by RERC from time to time. Thissurcharge collected by the STU is credited to a fund to be utilized for creation of atransmission system infrastructure of RE-based power plants. The state of MadhyaPradesh is also in the process of setting up a green energy fund. The fund would befinanced through the cess collected from power consumers within the state.

Box 14.2: Urjankur Nidhi Fund in Maharashtra

The Government of Maharashtra and the Infrastructure Leasing & Financial Services

(IL & FS) have jointly promoted the Urjankur Nidhi Trust Fund to boost non-

conventional energy projects in Maharashtra. This fund would develop and take up

equity in RE projects.

The fund has a corpus of Rs 418 crore of which Rs 218 crore would be contributed by the

Government of Maharashtra. This fund would be replenished through the imposition of a

green cess of of 4 paisa/unit on industrial and commercial power consumers in Maharashtra.The other Rs 200 crore would be contributed by private institutional investors.


The fund would initially promote bagasse based cogeneration power projects which havea significant potential in Maharashtra. These projects will be developed, implementedand operated through separate Special Purpose Vehicle (SPV) on BOOT basis, and theUrjankur Nidhi Fund along with financial institutions and private investors will take upequity in the SPV. The Trust has identified nearly 18 sugar factories and three of thesesugar factories have already entered into project development agreement with the Trust.

The trust would provide financial support in the form of equity with maximum supportper project of up to 20 per cent of the project cost or 20 per cent of the corpus, whicheveris lower. The fund will also provide crucial support functions during projectdevelopment, project management and distribution of resulting power.

Source: MEDA

Demonstration programmes

• Tail-end Grid Connected Solar Power Generation: The tail-ends of the grid inrural areas experience voltage drops and power outages. A solar PV plantconnected at the tail-end can provide power there and also improve the qualityof power in the grid. In order to meet these objectives, the MNRE started anew demonstration programme, permitting utilities, generation companiesand state nodal agencies to set up grid-connected solar PV plants of 25 kW to1,000 kWp capacity. MNRE provides support of 50 per cent of the basic cost ofthe plant, subject to a maximum of Rs 10 crore per MWp. Assistance will beavailable to set up 4 MWp aggregate capacity projects in the country duringthe Eleventh Plan period.

• Wind power: About 26 project sites have been developed in states with highpotential for wind power under the Demonstration Programme to establishtechnological viability of wind farms, resulting in the establishment of around57 MW of capacity.

Others

• Use of solar water heating systems in buildings: The GOI has beenpromoting solar water heating systems (SWHS). However, implementationof the scheme is tardy as several authorities are involved in implementationof any scheme involving SWHS. First, the states have to issue orders totheir respective municipalities on making the SWHS compulsory. As ofdate, thirteen states and two union territories have issued orders makinginstallation of the SWHS mandatory in certain categories of new buildings.The states are Andhra Pradesh, Chhattisgarh, Delhi, Haryana, HimachalPradesh, Madhya Pradesh, Maharashtra, Nagaland, Punjab, Rajasthan,Tamil Nadu, Uttar Pradesh, and Uttarakhand, the Union Territories beingChandigarh and Dadra and Nagar Haveli.


ANNEXURE 3Regulatory framework for RE

Renewable purchase obligations

Section 86(1)(e) of the Electricity Act 2003 (EA 03) empowers SERCs to specifythe percentage of electricity to be procured by the obligated entities (distributionlicensees, open access consumers and captive power users) from the RE sources.Accordingly, many SERCs have issued orders/regulations specifying suchpercentages. This percentage is referred to as Renewable Purchase Obligation(RPO). At present, 17 SERCs have notified RPO targets for their respective states.Most states have remained technology neutral while specifying these RPOs. Buta few, such as Rajasthan, Madhya Pradesh, Karnataka and Chhattisgarh, havespecified RPOs from individual RE sources. While most states have advocatedan RPO between 1 per cent and 5 per cent, MP has advocated a 10 per cent RPO.Moreover, the states of Karnataka and Rajasthan have specified a maximum capfor RE-based procurement. Table 14.10 provides an overview of the RPOs indifferent states and their achievement. With the exception of Andhra Pradesh,Maharashtra and Rajasthan where RPO has been levied on discoms, open accessconsumers and captive power plants, it has been levied only on discoms inother states.

Table 14.10: Summary of RPOs at state level for select states

States RPO (in %)

2007-08: 4.88%

2008–09: 6.25%

Rajasthan 2009–10: 7.45%

2010–11: 8.50%

2011–12: 9.50%

2007–08: 1%

2008–09: 1%

Punjab 2009–10: 2%

2010–11: 3%

2011–12: 4%

2007–08: 3%

Haryana 2008–09: 5%

2009–10: 10%


Maharashtra* ‘Percentage RPO’ for each licensee shall be the same as the‘Percentage RPO’ for the state as a whole. The ‘PercentageRPO’ for the State for a financial year shall be the ratio of‘total RE generation’ in the state to the ‘sum of gross inputenergy units’ for all licensees for that financial year,excluding any inter-se sale/ consumption of electricityamongst the licensees

Gujarat 2007–08: 1%

2008–09: 2%

Chhattisgarh Biomass-based plants: 5% each year from 2008–09 to 2010–11Small hydel plants: 3% each year from 2008–09 to 2010–11Solar, wind, bagasse-based cogeneration & others: 2% eachyear from 2008–09 to 2010–11

Andhra Pradesh 5% each year from 2009–10 to 2013–14

Karnataka Minimum of 5% and a maximum of 10%

Uttar Pradesh 7.5%

2008–09: 4.8%West Bengal** 2009–10: 6.8%

2010–11: 8.3%2011–12: 10%

Himachal Minimum 20% of total consumption during a yearPradesh

** For the purposes of determination of ‘Percentage RPO’, generation from all types of renewable

energy sources as approved by MNRE is considered; Only ‘RE generation’ from grid-connected

RE projects is considered; ‘RE generation’ excludes RE generation by developers meant for self-

consumption and third-party sale purposes to a licensee’s consumers.

* For WBSEDCL

Feed-in tariff (FiT) or preferential tariff

The existing regulatory framework requires SERCs to determine FiTs for procurementof RE power by the distribution licensees under the RPO regime. It is envisaged thatSERCs will determine tariff separately for each type of technology adopted forharnessing any of the RE sources. Accordingly, many SERCs have determined theFiTs for various RETs. These SERCs have generally followed a ‘cost-plus’ approach

Table 14.10: Summary of RPOs at state level for select states (contd...)

States RPO (in %)


Tab

le 1

4.11

: FiT

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for determination of FiTs. States that are yet to adopt FiTs include Orissa, Bihar,Jammu and Kashmir, Jharkhand, and the Northeastern states. Tables 14.11 to 14.14summarize the FiT determined by different SERCs for different RETs.

Table 14.12: FiTs for solar power across states

Preferential Solar PV Solar Thermaltariffs for solar

energy CoD up to CoD after CoD up to CoD afterDec 2009 Dec 2009 Dec 2009 Dec 2009

Rajasthan

Covered under Rs 15.78 /kWh Rs 15.18 /kWh Rs 13.78 /kWh Rs 13.18/kWh*

GOI Policy

Not covered Rs 15.60 /kWh Rs 15 /kWh Rs 13.60 /kWh Rs 13 /kWh

under GOI Policy

West Bengal

Covered under Rs 4/ Kwh + GBI Rs 4/ kWh + GBI Not determined

GOI Policy

Not covered under Rs 11 / kWh Rs 10 / kWh Not determined

GOI Policy

Uttar Pradesh Rs 15/ kWh Rs 15 / kWh# Rs 13 / kWh Rs 13 / kWh#

Gujarat Rs 13 / kWh Rs 12 / kWh Rs 10 / kWh Rs 9 / kWh

(1–12 years) (1–12 years) (1–12 years) (1–12 years)

Rs 3 / kWh Rs 3 / kWh Rs 3 / kWh Rs 3 / kWh

(13–25 years) (13–25 years) (13–25 years) (13–25 years)

Haryana* Rs 15.96 / kWh Rs 15.16 / kWh

Andhra Pradesh *Rs 3.70/ kWh + WPI Not determined

Maharashtra** Rs 3/ kWh + GBI Rs 3/ kWh + GBI Rs 3/ kWh + GBI Rs 3/ kWh + GBI

Punjab Rs 7/kWh (with base year 2006–07) + annual escalation @ 5% up to 2011–12

Karnataka Rs 3.40/ Kwh + Rs 3.40/ kWh + Rs 3.40/ kWh + Rs 3.40/ kWh +

GBI GBI GBI GBI

Chhattisgarh*** Rs 15.84/kWh Rs 13.26/kWh

Tamil Nadu Rs 3.15/kWh# commissioned before 31.12.2011

* 5 years

** 10 years; commissioned up to 31.3.2010

*** commissioned up to 31.12.2010


Table 14.13: FiTs for SHP and assumptions for FiTs across states

Tariff (Rs/kWh) Capital Return Auxiliary O&M Escal-cost on consu- expenses ation in

(Rs/MW) equity mption (% of O&Mcapital expensescost)

Punjab Rs 3.49 (with base year2006–07) with fiveannual escalations@ 3% up to 2011–12.

Haryana Rs 3.67 for 2007–08,Escalated at 1.5% perannum 10.25 16% 0.5%

Maharashtra Tariff of Rs 2.84 in firstyear, which increases byRs 0.03/unit every yeartill the debt repaymentis over (10th year)

Tariff of Rs 3.11 betweenyears 10–15 after whichit again increasesannually at a constantrate of Rs 0.03/unit 4.4 16% 0.5% 3% 4%

Andhra Tariff from yr 1–10:Pradesh 2.60, 2.52, 2.44, 2.36,

2.27, 2.19, 2.11, 2.03,1.95, 1.88 3.625 15% 1% 1.5% 4%

Karnataka Rs 2.80 without anyescalation for the first10-year period fromthe year of commercialoperation of the plant 3.9 16% 0.5% 1.5% 5%

Uttar Tariff determined forPradesh each of the 20 years of

the life of plant forplants commissionedbetween 2005–06 to2009–10

Himachal Rs 2.87 for SHPPradesh projects up to 5 MW;

project specific ratesfor SHP with capacitymore than 5MW andup to 25 MW 6.5 14% 0.5% 2% 4%


Table 14.14: FiTs for biomass and bagasse, and assumptions for FiTs across states

Biomass tariff (Rs/kWh) Bagasse tariff (Rs/kWh)

Rajasthan Project specific tariff for new plants Project-specific tariff for plants

Punjab Rs 3.49 (with base year 2006–07) Rs 3.49 (with base year 2006–07)with five annual escalations @ 5% with five annual escalations @ 3%up to 2011–12 up to 2011–12.

Haryana Rs 4 for 2007–08, escalated at Rs 3.74 for 2007–08, escalated2% per annum at 2% per annum

Fixed: (1–1.70; 2–1.67; 3–1.63;4–1.59; 5–1.54; 6–1.49; 7–1.43;8 –1.37; 9–1.32; 10–1.25; 11–1.18;12–1.11; 13–1.02);

Maharashtra Variable: 2005–06 1.34; 2006–07 1.41;2007–08 1.48; 2008–09 1.55; Rs 3.05 for the first year of operation,2009–10 1.63; 2010–11 1.71; escalation of 2% per annum2011–12 1.80; 2012–13 1.89;2013–14 1.98; 2014–15 2.08; 2015–162.18; 2016–17 2.29; 2017–18 2.41)

Gujarat Rs 3.08 for entire project life Rs 3.00 for entire projectof 20 years life of 20 years

Chhattisgarh Fixed (1–1.78; 2–1.75; 3–1.73;4–1.68;5–1.63; 6–1.58; 7–1.53;8–1.48; 9–1.43; 10–1.38);75:25–Variable: 2005–06 1.20;2006–07 1.26; 2007–08 1.32;2008–09 1.39; 2009–10 1.46;2010–11 1.53; 2011–12 1.61;2012–13 1.69; 2013–14 1.77;2014–15 1.86); 75:15–Variable(2007–08 1.27; 2008–09 1.34;2009–10 1.40; 2010–11 1.47;2011–12 1.55; 2012–13 1.62;2013–14 1.71; 2014–15 1.79)

Karnataka Rs 2.85 per unit in the first year of Rs 2.80 per unit in the first year ofcommercial operation of the plant, commercial operation of the plant,annual escalation of 2% per annum annual escalation of 2% per annumfor subsequent period of 9 years for subsequent period of 9 yearsFuel price of Rs 1000/- per MTescalated at 5%

Uttar Variable cost for 2005–06 Rs 1.2821, Variable cost for 2005–06 Rs 1.2821,Pradesh escalation of 6% per annum for each escalation of 6% per annum for each

subsequent year. subsequent year.


Green power

Green power is a concept wherein the utility supplies consumers with RE-basedpower and charges the consumers the actual cost of this power, the supply of whichis aimed at consumers who are environmentally conscious and is priced higherthan normal retail tariffs. Within India, only the Andhra Pradesh ElectricityRegulatory Commission (APERC) has introduced the Green Power under itsFY 2008–09 retail tariff order. APERC has fixed the tentative Green Power tariff atRs 6.70/kWh for FY 2008–09, and the difference between this tariff and the normaltariff would be used to create a ‘Green Power Fund’. It has further determined thatconsumers buying green power have the option of obtaining Clean DevelopmentMechanism (CDM) benefits and Renewable Energy Certificates (RECs), wheneverthese are introduced.


ANNEXURE 4Box 14.3: Detailed provisions of National Solar Mission

Solar RPS

Renewable Purchase Obligation of utilitiesto be split into solar and non-solar• RPO may start with 0.25% in Phase I and

increase to 3% by 2022• RPO to be fixed after modification of the

National Tariff Policy 2006• RE Certificates to meet RPO

Demonstration projects

Technology configurations not covered under1,000 MW capacity• Projects to be set up following competitive

bidding to enable price discovery.• Maximize indigenous content• Technology transfer

Fiscal/financial incentives

Increase competitiveness of solar projects &provide enabling environment for solarmanufacturers• Recommendation to MoF for customs and

excise duty concessions/exemptions onspecific capital quipment, critical materials,components & project imports.

• SEZ-like incentives to manufacturing parks

R&D

Improve efficiency of existing/new materials& applications & develop cost effective storagetechnologies.• Development of National Centre of

Excellence & Centres of Excellence toundertake & fund R&D.

• High-level Research Council to guideoverall strategy.

• Support incubation & innovation througha venture fund

Solar power purchase policy

NVVN appointed the nodal agency forpurchase & sale of grid-connected solarpower at 33 kV & above under Phase –I• For each MW of solar power, MOP to

allocate equivalent MW capacity fromunallocated quota of NTPC stations

• NVVN to bundle solar & thermalpower & sell it at regulated tariff plusfacilitation charges

Generation-based incentive

Provision of GBI to 100 MW capacity solarproject sconnected to LT/11 kV grid• Eligibility: own consumption as well as

power fed into the grid.• GBI rate: tariff fixed by CERC minus

notional tariff of Rs 5.5 per unit, with 3%annual escalation

Off-grid opportunities

Promote solar home lights & other powerapplications to cover 10,000 MW villages &hamlets.• Refinance facility/soft loans up to 5%

annual interest rate by IREDA.• 30% subsidy for select applications.• 90% subsidy for niche applications to

special category areas

HRD

Build technically qualified manpower ofinternational standards• Develop specialized courses at engineering

colleges.• Ministry of Labour to introduce training

modules/course materials for technicians.• 100 fellowships a year to support students/

groups.• National Centre for PV Research &

Education at IIT, Mumbai


NOTES

1. According to the MNRE, the total RE capacity in the country as on 31 March 2009 was14,485 MW. The difference in magnitude of RE capacity addition as reported by differentagencies in the country arises on account of discrepancies in reporting of data and thedifferent time frames when such data is reported. The objective here is to give a fair ideaof the extent of RE capacity existing in the country.

2. Current RE capacity is a little less than 15,000 MW and it may be assumed that onlyanother 15,000 MW is doable till 2017.

3. Integrated Energy Policy, 2006.

4. Ministry of Power, Annual Report, 2008–09.

5. Central Electricity Authority, Power Supply at Glance, July 2009.

6. Ministry of Power, www.powermin.nic.in accessed at 2.55 p.m. on October 23, 2009.

7. Shonali Pachauri and Adrian Muller, ‘A Regional Decomposition of Domestic ElectricityConsumption in India: 1980–2005’. Presented at the annual IAEE conference at Istanbulon 20 June 2008; available at http://www.iiasa.ac.at/Research/PCC/recent-events/Pachauri&Mueller_Istanbul_June2008_Final.pdf

8. http://www.renewableenergyworld.com/rea//news/article/2008/04/renewable-energy-jobs-soar-in-germany-52089

9. While this may be sufficient to indicate the importance of the state-level regulatoryframework on RE capacity addition, it is important to note that the MNRE-determinedtariff which was valid till 2004 may have played a significant role in this capacity addition.

10. Most of the capacity additions in FY 2006–07 and FY 2007–08 would be those whereinstallation started in earlier years. Capacity addition in future years would reflect theimpact of TNERC’s order. However, given the time required to commission windprojects, this may broadly reflect the impact of TNERC’s order.

11. CERC’s discussion paper on promotion of co-generation and generation of electricityfrom renewable sources of energy (May 2008).

12. http://cserc.gov.in/pdf/25-2009-Interim.pdf

13. It is understood that TNEB is addressing this problem now by developing the requisitetransmission network.

14. Explanatory Memorandum issued by CERC for Draft Terms and Conditions forDetermination of Tariff for Renewable Energy Sources, May 2009.

Distribution Reforms in Delhi | 273

INTRODUCTION

The electricity distribution business has been privatized in only two states in thecountry—Orissa and Delhi. The privatization in Delhi has been successful as far asthe efficiency improvements are concerned. Irrespective of improved efficiency,divergent views exist on the success of privatization. Many believe it has not beeneffective in Delhi. Against this backdrop, this study attempts to assess and evaluatethe privatization of the distribution business in Delhi.

IMPERATIVE FOR REFORMS IN THE STATE

Traditionally, power supply in Delhi was the responsibility of the Delhi ElectricitySupply Undertaking (DESU), which was an integrated utility, with generation,transmission and distribution functions, serving the entire State of Delhi except theNew Delhi Municipal Corporation (NDMC) and Military Engineering Services(MES), or Cantonment areas (to which DESU supplied power in bulk). The poorperformance of DESU led to its being succeeded by the Delhi Vidyut Board (DVB)in 1997, which was established as a State Electricity Board under the Electricity(Supply) Act 1948. The creation of DVB proved to be merely a change in the legalstatus of the organisation without any structural changes. The change did not affectthe functioning and the work culture of the organization. Its performance continuedto deteriorate.

The power sector suffered from problems of high technical losses due to poormaintenance of existing infrastructure and very little augmentation, high commerciallosses attributable to theft, and high receivables for DVB. During FY 1995–96 toFY 1999–2000, operating losses of DESU/DVB rose from Rs 578 crore to Rs 1100 crore.1

POWER DISTRIBUTION

REFORMS IN DELHIApril 2010

15


Transmission and distribution (T&D) losses during the same period were around50 per cent. This poor commercial performance of the DVB due to high T&D lossesmade it incapable of raising the resources required to improve its services andrendered it a drain on the public exchequer.

Figure 15.1: T&D losses and commercial losses pre-reforms

Source: Annual Report on the Working of State Electricity Boards & Electricity Departments:Planning Commission, Government of India, May 2002

The state also suffered from a severe demand–supply imbalance. Generating stationsin Delhi had an installed capacity of 694 MW, but availability was lower at300–350 MW. Capacity addition remained relatively stagnant, leading tooverdependence on purchased power.

Not surprisingly, public discontent continued to rise. All these factors required thatthe Government of the National Capital Territory of Delhi (GNCTD) formulate astrategy to bring about a structural change in the Delhi power sector. It was perceivedthat the present vertically integrated structure had failed to deliver the desiredoutcomes and the time was ripe to restructure the sector.

THE REFORM STRATEGY

In view of the above considerations, the GNCTD brought out a Strategy Paper onPower Sector Reforms in February 1999 for reforming the power sector in the state.A fast-track reform process was followed that ultimately resulted in the unbundlingof DVB into seven companies: one holding company called the Delhi PowerCompany Limited, two generation companies, viz. Indraprastha Power GenerationCompany Limited (IPGCL) and Pragati Power Company Limited (PPCL), onetransmission company, viz. Delhi Transco Limited (TRANSCO), and threedistribution companies (discoms). Subsequently, the GNCTD issued policydirections indicating its intent to disinvest majority shareholding in the discoms toprivate investors, with the balance 49 per cent remaining with the GNCTD.

T&D losses as % of availability Commercial loss (without subsidy) in Rs cr.60

50

40

30

20

10

0

1200

1000

800

600

400

200

01995–96 1995–961996–97 1996–971997–98 1997–981998–99 1998–991999–2000 1999–2000


The GNCTD believed that a long-term definitive loss reduction or efficiency gainprogramme needed to be settled at the very start of the privatization process toreassure private sector investors. It further believed that to attract them it would beappropriate that reduction in losses/efficiency gains be determined through marketforces rather than being predetermined unilaterally in the bidding documents.Therefore, loss reduction or efficiency gain to be achieved by the distributioncompanies in the first five years, viz. 2002–03 to 2006–07, became the basis ofprivatization or the bidding criteria for the selection of the private entity.

The GNCTD was of the view that losses of any kind—technical, non-technical ornon-realisation of payments—ultimately amount to loss in revenues. Efficiency gainsmust embrace all these aspects. Therefore, losses should be measured as the differencebetween the units input and the units realised (units billed and collected), whereinthe units realised will be equal to the product of units billed and the collectionefficiency, where collection efficiency is defined as the ratio of actual amount collectedto amount billed. The difference between the units input and the units realized arereferred to as aggregate technical and commercial (AT&C) losses.

The GNCTD, as a matter of policy, decided that the AT&C loss shall be the basis fordetermination of tariffs and also for computation of incentives for betterperformance. It asked the Delhi Electricity Regulatory Commission (DERC), videPolicy Directions, to determine the opening level of AT&C losses and the bulk supplytariff (BST) for each discom.

PRIVATIZATION OF DISCOMS

GNCTD initiated the bidding process for selection of the private investors for eachof the three discoms. Upon opening of bids, it emerged that the loss-level trajectoryas submitted by the bidders was not in the range acceptable to the GNCTD.Consequently, the bidders were called for negotiations. After a number of discussions,the bidders and the GNCTD came to an agreement on the accepted year-wise AT&Closs reduction trajectory over the five-year period.

These discussions also resulted in other changes to the terms and conditions ofprivatization. Prime amongst these was the method of computation and treatment ofoverachievement and underachievement for the years 2002–03 to 2006–07 (see Box 15.1).

Box 15.1: Computation and treatment of over/underachievementof target AT&C loss levels

i. In the event the actual AT&C loss of a distribution licensee in any year is better(lower) than the level based on the minimum AT&C loss reduction levelsstipulated by the government for that year, the distribution licensee shall be


allowed to retain 50% of the additional revenue resulting from such betterperformance. The balance 50% of additional revenue from such betterperformance shall be counted for the purpose of tariff fixation.

ii. In the event the actual AT&C loss of a distribution licensee in any year is worse(higher) than the level based on the AT&C loss reduction levels indicated in theAccepted Bid for that year, the entire shortfall in revenue on account of the sameshall be borne by the distribution licensee.

iii. In the event the actual AT&C loss of a distribution licensee in any year is worse(higher) than the level based on the minimum AT&C loss reduction levelsstipulated by the Government for that year, but better (lower) than the levelbased on AT&C loss reduction levels indicated in the Accepted Bid for that year,the entire additional revenue from such better performance shall be counted forthe purpose of tariff fixation.

Provided further that for paras (i), (ii) and (iii) above, for every year, whiledetermining such additional revenue or shortfall in revenue, the cumulative neteffect of revenue till the end of the relevant year shall be taken, in regard tooverachievement/underachievement and appropriate adjustments shall be madefor the net effect.

After the negotiations and the incorporation of the resulting changes, revised bidswere submitted by the bidders. Consequent to this round of bidding, GNCTDappointed TATA Power as the distribution utility for the North & North-West circleand BSES for two circles—Central & East and South & West. The opening losslevels as well as the loss reduction trajectory that were accepted by the investors foreach discom and the minimum AT&C loss reduction level as indicated in theaccepted bids are as shown in Table 15.1. The three distribution companies wereprivatised with effect from 1 July 2002.

Table 15.1: Accepted bid loss reduction trajectory

2002–03 2003–04 2004–05 2005–06 2006–07 Total

BSES Rajdhani 0.55 1.55 3.30 6.00 5.60 17.00

BSES Yamuna 0.75 1.75 4.00 5.65 5.10 17.25

NDPL 0.50 2.25 4.50 5.50 4.25 17.00

Minimum bid loss reduction trajectory

BSES Rajdhani 1.50 5.00 5.00 5.00 4.25 20.75

BSES Yamuna 1.25 5.00 4.50 4.50 4.00 19.25

NDPL 1.50 5.00 4.50 4.25 4.00 19.25

Source: Jagdish Sagar: Power Sector Reforms in Delhi: The Experience So Far


INITIATIVES TAKEN POST-REFORMS

The discoms undertook a number of initiatives to bring about changes in thedistribution business and achieve the reduced loss-level targets set for privatisation.

Initiatives taken by NDPL

Automation initiatives and GIS

The NDPL embarked on automating all its 66 kV and 33 kV grids, and in line withthis has already automated 34 grids with a view to operating all equipment from thecentral command centre. This has expedited the resolution time for faults.The entire electrical network has been mapped through GIS to enable quicker faultlocation and speedy redressal; the outage management system is being upgradedfor automation on a GIS platform.

Complaint management system

The NDPL has a unique SMS-based fault management system using GSM whichensures that the ‘No supply’ complaints lodged by a consumer get addressed quicklyand consumer feedback is also institutionalized as part of the process.

In July 2002, the NDPL had very poor consumer care facilities. Now, each of the12 districts has an online consumer care centre, each handled by customer careexecutives under the supervision of customer relation officers and customerservice officers.

Online connection management by consumer

The NDPL uploaded the billing details of all its consumers on its website,www.ndpl.com. Consumers can view their bill, know the consumption pattern andeven print duplicate bills and make online bill payments.

Doorstep delivery of new connections

To ensure hassle-free new connections, an NDPL representative visits the consumer’spremises and completes all formalities there itself.

Privileged consumer scheme

As incentive for prompt payment, NDPL has institutionalized a privileged consumerscheme through which discounts are offered.

The NDPL has also institutionalized a structured approach towards consumerrelationship management as it organizes regular meetings with consumerrepresentative groups, such as RWAs and IWAs, on the first Saturday of every monthin each district.


Automated bill payment kiosks for consumer convenience

The NDPL has introduced Automated Bill Payment Kiosks, a first in Delhi and the

National Capital Region (NCR). These unique ATM-like kiosks accept both cash

and cheque payment towards electricity bills and even issue a receipt to the consumer.

They are operational 365 days a year from 8 a.m. to 8 p.m.

Initiatives taken by BSES

Consumer related

• Setting up customer help desks (CHDs) in all the 33 divisions for online

registration of consumer complaints, and commercial call centres to address

complaints

• In-house developed CRM software (CAS) which provides the facility of

single-window resolution of complaints

• Setting up of a 24-hour control room at the CM’s office to provide immediate

information on faults/breakdowns

• Bifurcation of the existing 21 districts into 33 divisions

• Centralised helpline numbers have been created for all queries related

to power supply/meter/billing/anti-corruption/vigilance/anti-power

theft/enforcement

• Starting of the ‘Bill Amendment Module (BAM)’, a billing software module

through which customer complaints are addressed on the spot

• Facility of raising one composite bill for bulk consumers like MCD and DJB

for convenient payments

• Meter reading is now being done by meter reading instruments (MRIs).

• Location of a BSES office in a 3-km radius from each point. Consumers may

go to any of the 143 BSES offices.

• The following facilities for key consumers have been created:

• Creation of a special cell for customers having a load of over 45 KW

• Single-window ease and preparation of composite bill for bulk consumers

like DJB and MCD for convenient payments

• Bill dispatch by e-mails and special couriers


Supply and streetlighting related

• Approximately hundred breakdown vans; cable restoration on a 24 by 7 basis

• Online connectivity between technical call centre, system and circle control

• 25 Genset vans and mobile transformers made available round the clock

• A special drive, ‘Roshini’, which provided uninterrupted illumination duringthe entire festive season

Metering related

• Mass meter replacement drive was undertaken for all large industrial power(LIP) consumers. Electronic meters have also been introduced for domesticconsumers.

• Faulty meters are being replaced on a priority basis with tamper-proof electronicmeters. A Special Meter Testing Drive was undertaken. Only 0.01 per cent ofelectronic meters were found defective.

• A month-long voluntary disclosure scheme (VDS) was undertaken.

Payment related

• Point-of-sales (POS) machines installed at the cash collection counters withbar code scanners for speedy service; tie-ups with collection agencies, like EasyBill and Skypak, for cheque payments and with bill desk and bill junction foronline payments

• 120 cash collection centres, 150 Skypak drop boxes and 1050 Easy Bill outletsacross BSES; 150 drop boxes installed on RWA premises

OUTCOME OF PRIVATIZATION AND REFORMS

The overall impact of reforms and initiatives taken has started producing favourableresults. Various parameters indicating the overall health of the power distributionsector in the state are discussed below:

• Aggregate technical and commercial losses

AT&C loss reduction was the parameter used for privatisation of distributioncompanies in Delhi. Opening AT&C levels were given for the three distributioncompanies, and annual targets for reduction were set. Post-privatisation, anumber of initiatives were taken by distribution companies to reduce AT&Closses. The AT&C losses for Delhi have declined from 56 per cent in 2002–03to 38 per cent in 2007–08.2

The AT&C losses reported by various discoms are as shown in Figure 15.2.The NDPL has reported the lowest AT&C losses for the year 2008–09.


Figure 15.2: AT&C losses (%)Source: Forum of regulators (FOR)3

• Financial viability

a. Profitability

The financial position of discoms has improved post-privatisation. Allthe discoms started reporting profits from 2004–05. While NDPL hasshown a consistent improvement in profits generated, BSES slipped intolosses in 2007–08.

Table 15.2: Profits (in Rs crore)

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

BSES Rajdhani -57 -32 60 89 27 -449

BSES Yamuna -101 -55 7 46 48 -55

NDPL 22 29 57 113 186 282

Source: PFC Report2

Both NDPL and BSES registered a significant increase in the power purchasecost in 2007–08 over 2006–07. The power purchase cost per unit of energyinput was higher for BSES as compared to NDPL. BSES discoms alsoreported increase in their interest costs for FY 2007 and FY 2008.2

b. Average cost of supply (ACS) and average revenue realized (ARR)

NDPL has seen an increasing difference between ARR and ACS from10 paise/kWh in 2002–03 to 50 paise/kWh in 2007–08.2

70

60

50

40

30

20

10

02002–03* 2003–04 2004–05 2005–06 2006–07 2007–08 2008–09

BSES Rajdhani BSES Yamuna NDPL


BSES discoms registered better revenue realized than cost of supply forFY 2005 and FY 2006. However, in FY 2007 and FY 2008 their cost ofsupply was higher than revenue realized. This deterioration was reflectedin their financials as they slipped into losses for FY 2008.

• Quality of Supply (QoS)

Quality of supply in Delhi has improved post reforms. NDPL registered bestfigures for quality of supply parameters in FY 2007 (namely, outage duration,number of outages and average duration of outage). Data is available fromFY 2005 to FY 2007, and BSES had much worse conditions than NDPL at thestart of this period.

Figure 15.3: ARR & ACS (Rs per unit)Source: PFC Report

2

Deficit situation

The deficit situation in Delhi has improved in terms of both peak and energydeficit. Peak deficit has reduced from 9.2 per cent in 2002–03 to 0.0 per cent in2008–09. Energy deficit has reduced from 1.9 per cent in 2002–03 to 0.6 per centin 2008–09.

Table 15.3: QoS parameters

Outage duration per feeder

(hh:mm) 2004–05 2005–06 2006–07

NDPL 49:33 13:34 3:54

BYPL 105:14 77:40 37:05

BRPL 98:07 82:31 33:29

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

BSES Rajdhani ACS BSES Yamuna ACSBSES Yamuna ARR

NDPL ACSNDPL ARR

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

BSES Rajdhani ARR


Table 15.3: QoS parameters (contd...)

No. of outages per feeder

2004–05 2005–06 2006–07

NDPL 26 10 4

BYPL 68 77 38

BRPL 60 76 34

Average duration of an outage

(hh:mm) 2004–05 2005–06 2006–07

NDPL 1:55 1:22 0:54

BYPL 1:33 1:01 0:58

BRPL 1:38 1:05 0:59

Source: http://www.cea.nic.in

Table 15.4: Peak and energy deficit (%)

Peak Energydeficit deficit

2002–03 9.2 1.9

2003–04 3.0 1.4

2004–05 1.9 1.0

2005–06 3.3 1.5

2006–07 6.6 1.7

2007–08 1.1 0.6

2008–09 0.0 0.6

Source: http://www.cea.nic.in

Table 15.5: Loan to TRANSCO (in Rs cr.)

FY 2003 FY 2004 FY 2005 FY 2005 FY 2006 Total

1364 1260 690 138 0 3450

CONCLUSION

Distribution reforms in Delhi and privatization of discoms have led to positive results.This is being reflected in reduced AT&C losses, low deficit situation, improvingquality of supply parameters and no subsidy to discoms. The only subsidization ofdiscoms post-privatisation was a loan of Rs 3450 crore from GNCTD to TRANSCOduring 2003 and 2006 (Table 15.5). This loan was given to bridge the gap between


their revenue requirement and revenue received from discoms through bulk supplytariff. However, compared to annual losses of the order of Rs 1000 crore that existedbefore reforms, the financial burden has reduced significantly.

NDPL has reported minimum losses and best figures for QoS parameters amongstthe discoms in Delhi. It has also been the only discom to register profits for all theyears from FY 2003 to FY 2008. All the discoms have made capital investments toachieve the target reduction in loss levels (Annexure 2). Capital expenditure perunit of energy input is higher for NDPL. Actual AT&C loss reduction by discomsalong with government-specified minimum bid and accepted bid is shown inAnnexure 3. For the period FY 2003 to FY 2007, total loss reduction by NDPL wasmore than BSES discoms. Also the total reduction was more than the government-specified minimum bid.

While the distribution reforms have given positive results in Delhi, there are a fewareas of concern. For the first five years (FY 2003 to FY 2007), loss level targets andbulk power purchase tariffs were specified. Going forward, discoms will be vulnerableto fluctuations in bulk purchase tariffs. Further, AT&C loss reduction will be harderto achieve as they have already reduced considerably, and collection efficiencies willnot remain more than 100 per cent for a long period.

In 2007–08, both the BSES discoms registered financial losses driven by high powerpurchase cost and interest cost (Annexure 1). Only NDPL registered profits aftertax of Rs 282 crore, that too on the back of Rs 225 crore recoverable by truing up ofearlier year revenues. This income resulted from NDPL winning an appeal to use6.69 per cent depreciation for FY 2003, FY 2004 and FY 2005 as compared to the3.75 per cent rate specified by DERC. Hence, the financial viability of discoms needsto be examined under high power purchase cost scenarios.


ANNEXURE 1Table 15.6: Expenses break-up of discoms (in Rs crore)

BSES Rajdhani

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 846 1,244 1,654 1,877 2,103 2,899

Employees 97 119 113 122 147 164

O&M 76 80 92 69 88 70

Interest 1 2 6 32 153 205

Depreciation 82 115 125 116 139 155

Admin & general 11 32 41 60 63 67

Other 0 133 0 -23 77 92

Total 1,113 1,724 2,031 2,253 2,770 3,652

BSES Yamuna

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 479 638 798 922 993 1,973

Employees 80 100 92 94 111 129

O&M 43 47 65 52 47 49

Interest 2 8 13 29 76 132

Depreciation 20 32 42 49 57 72

Admin & general 7 21 27 35 39 45

Other 0 95 0 -31 63 77

Total 632 941 1,037 1,150 1,386 2,476

NDPL

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 599 868 1,105 1,204 1,309 1,882

Employees 82 103 131 146 155 152

O&M 20 91 59 53 51 57

Interest 0 4 20 23 57 75

Depreciation 66 87 113 110 129 155

Admin & general 13 19 24 29 30 33

Other 45 40 27 2 -3 -202

Total 824 1,213 1,478 1,566 1,727 2,152

Source: Report on the Performance of the State Power Utilities for the Years 2004–05 to2007–08, Power Finance Corporation Limited


Expenses break-up (as % of total expenses)

BSES Rajdhani

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 76.0 72.2 81.4 83.3 75.9 79.4

Employees 8.7 6.9 5.6 5.4 5.3 4.5

O&M 6.8 4.6 4.5 3.1 3.2 1.9

Interest 0.1 0.1 0.3 1.4 5.5 5.6

Depreciation 7.4 6.7 6.2 5.1 5.0 4.2

Admin & general 1.0 1.9 2.0 2.7 2.3 1.8

Other 0.0 7.7 0.0 -1.0 2.8 2.5

Total 100.0 100.0 100.0 100.0 100.0 100.0

BSES Yamuna

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 75.8 67.8 77.0 80.2 71.6 79.7

Employees 12.7 10.6 8.9 8.2 8.0 5.2

O&M 6.8 5.0 6.3 4.5 3.4 2.0

Interest 0.3 0.9 1.3 2.5 5.5 5.3

Depreciation 3.2 3.4 4.1 4.3 4.1 2.9

Admin & general 1.1 2.2 2.6 3.0 2.8 1.8

Other 0.0 10.1 0.0 -2.7 4.5 3.1

Total 100.0 100.0 100.0 100.0 100.0 100.0

NDPL

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 72.7 71.6 74.8 76.9 75.8 87.5

Employees 10.0 8.5 8.9 9.3 9.0 7.1

O&M 2.4 7.5 4.0 3.4 3.0 2.6

Interest 0.0 0.3 1.4 1.5 3.3 3.5

Depreciation 8.0 7.2 7.6 7.0 7.5 7.2

Admin & general 1.6 1.6 1.6 1.9 1.7 1.5

Other 5.5 3.3 1.8 0.1 -0.2 -9.4

Total 100.0 100.0 100.0 100.0 100.0 100.0



Expenses break-up (in Rs/unit of energy input)

BSES Rajdhani

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 1.51 1.54 1.97 2.17 2.31 3.13

Employees 0.17 0.15 0.13 0.14 0.16 0.18

O&M 0.14 0.10 0.11 0.08 0.10 0.08

Interest 0.00 0.00 0.01 0.04 0.17 0.22

Depreciation 0.15 0.14 0.15 0.13 0.15 0.17

Admin & general 0.02 0.04 0.05 0.07 0.07 0.07

Other 0.00 0.16 0.00 -0.03 0.08 0.10

Total 1.99 2.13 2.42 2.61 3.04 3.94

BSES Yamuna

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 1.32 1.23 1.49 1.71 1.87 3.66

Employees 0.22 0.19 0.17 0.17 0.21 0.24

O&M 0.12 0.09 0.12 0.10 0.09 0.09

Interest 0.01 0.02 0.02 0.05 0.14 0.25

Depreciation 0.06 0.06 0.08 0.09 0.11 0.13

Admin & general 0.02 0.04 0.05 0.06 0.07 0.08

Other 0.00 0.18 0.00 -0.06 0.12 0.14

Total 1.74 1.82 1.94 2.13 2.62 4.60

NDPL

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08

Power purchased 1.52 1.56 2.00 2.11 2.19 3.00

Employees 0.21 0.19 0.24 0.26 0.26 0.24

O&M 0.05 0.16 0.11 0.09 0.09 0.09

Interest 0.00 0.01 0.04 0.04 0.10 0.12

Depreciation 0.17 0.16 0.20 0.19 0.22 0.25

Admin & general 0.03 0.03 0.04 0.05 0.05 0.05

Other 0.11 0.07 0.05 0.00 -0.01 -0.32

Total 2.10 2.18 2.67 2.75 2.89 3.43



ANNEXURE 2Table 15.7: Capital expenditure by discoms

Capex (in Rs crore)

2003 2004 2005 2006 2007 2008* Total

BSES Rajdhani 72.00 115.00 538.00 711.00 399.00 239.00 2464.00

BSES Yamuna 58.00 85.00 416.00 357.00 283.00 164.00 1663.00

NDPL 49.00 299.00 338.00 431.00 271.00 248.00 1899.00*Provisional data

Capex (in Rs/unit of energy input)

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08 Total

BSES Rajdhani 0.13 0.14 0.64 0.82 0.44 0.26 2.43

BSES Yamuna 0.16 0.16 0.78 0.66 0.53 0.30 2.60

NDPL 0.12 0.54 0.61 0.76 0.45 0.40 2.88

Source: http://www.derc.gov.in/ordersPetitions/orders/Misc/2009Order%20on%20Physical%20Verification%20of%20Assets.pdf

ANNEXURE 3Table 15.8: AT&C loss reduction by discoms

BSES Rajdhani loss reduction trajectory

2002–03 2003–04 2004–05 2005–06 2006–07 Total

Govt. specified minimum bid 1.50 5.00 5.00 5.00 4.25 20.75

Accepted bid 0.55 1.55 3.30 6.00 5.60 17.00

Actual 0.70 2.35 4.41 5.11 5.62 18.19

BSES Yamuna loss reduction trajectory

2002–03 2003–04 2004–05 2005–06 2006–07 Total


Accepted bid 0.75 1.75 4.00 5.65 5.10 17.25

Actual -4.69 7.60 4.16 6.26 4.84 18.17

NDPL loss reduction trajectory

2002–03 2003–04 2004–05 2005–06 2006–07 Total


Accepted bid 0.50 2.25 4.50 5.50 4.25 17.00

Actual -1.02 4.26 11.05 7.29 2.78 24.36


ANNEXURE 4

Table 15.9: Sales & revenue mix

NDPL

Sales mix: Sale in MkWh to total sales

(%) 2003–04 2004–05 2005–06 2006–07 2007–08

Domestic 47.1% 42.1% 41.5% 41.9% 37.5%

Commercial 20.1% 18.7% 18.7% 19.2% 17.3%

Agricultural 0.9% 0.6% 0.5% 0.2% 0.2%

Industrial 26.8% 32.4% 33.9% 33.0% 32.2%

Others 5.1% 6.1% 5.4% 5.7% 12.8%

Revenue mix

(%) 2003–04 2004–05 2005–06 2006–07 2007–08

Domestic 31.8% 28.8% 28.4% 27.5% 29.0%

Commercial 29.3% 25.7% 25.6% 27.4% 24.9%

Agricultural 0.3% 0.2% 0.2% 0.1% 0.1%

Industrial 33.4% 40.0% 43.2% 40.3% 39.0%

Others 5.1% 5.3% 2.7% 4.7% 7.1%

REFERENCES

1. Planning Commission (Power & Energy Division) Government of India. 2002.Annual Report (2001-02) on the Working of State Electricity Boards & ElectricityDepartments.

2. Power Finance Corporation Limited. Report on the Performance of the State PowerUtilities for the Years 2004–05 to 2007–08.

3. http://www.forumofregulators.gov.in/Data/policy_Imp/AT% 20&% 20C% 20LOSS%20DATA% 20-% 20STATE% 20&% 20UTILITES% 20WISE.pdf

4. Sagar, Jagdish. Power Sector Reforms in Delhi: The Experience So Far.

5. http://delhigovt.nic.in/power.asp

6. Central Electricity Authority, Planning Wing. 2009. Power scenario at a glance.

7. http://www.ndpl.com/Display Content.aspx? RefTypes=3 & RefIds = 149 & page =Pioneering Initiatives

8. http://www.bsesdelhi.com/Aboutus/in_undertaken.asp

9. http://www.bsesdelhi.com/Aboutus/bsesataglance.asp


10. http://www.cea.nic.in/god/dpd/RELIABILITY_INDICES_MONTHLY.pdf

11. http://www.cea.nic.in/power_sec_reports/executive_summary/2009_04/25-26.pdf

12. http://www.derc.gov.in/ordersPetitions/orders/Misc/2009/Order%20on% 20Physical%20Verification%20of%20Assets.pdf

13. Tariff orders of discoms; from DERC website (http://www.derc.gov.in)


POWER DISTRIBUTION:Being Driven to Insolvencyby a Governance Crisis

April 2011

16INTRODUCTION

The financial health of distribution utilities in the country is deteriorating at an alarminglevel once again. A handful of states account for the lion’s share of increased financiallosses. There is a tendency to attribute the rising financial losses to increasing AggregateTechnical and Commercial (AT&C) losses.1 But AT&C losses have reduced from33 per cent in 2005–06 to 28 per cent in 2008–09. Clearly, the problem lies elsewhere.Analysis indicates that the sector is undergoing a severe governance crisis. Inefficiencyof utilities is another, albeit lesser, problem. Losses of distribution utilities are estimatedto range between Rs 93,000 and Rs 150,000 crore in 2012–13. Given that stategovernments are not in a position to support the sector in the long run, the impactof the rising losses on the financial system of the country is a matter of grave concern.The financial system would get affected not only because of its direct exposure tothe distribution sector but also because of debt servicing by generation projectdevelopers. Therefore, there is an urgent need to restore good governance in thesector and prevent the insolvency of the distribution business from jeopardizingnot only future capacity addition but also the health of the financial system.

Financial losses of distribution utilities2

are mounting once again

The increase in losses of distribution utilities from Rs 3,000 crores to Rs 30,000 croresin the ten years between 1991–92 and 2001–02 had forced the attention of policymakers on reforming the distribution sector with the objective of reducing transmissionand distribution (T&D) losses and improving the commercial viability of thedistribution utilities (herein after referred to as utilities). The many reforms initiatedin the early 2000s helped reduce and contain financial losses between 2002–03and 2005–06. However, between 2005–06 and 2008–09, losses (without subsidy)

Power Distribution: Being Driven to Insolvency | 291

Losses on subsidy booked basisLosses on subsidy received basisLosses without subsidy

60000

50000

40000

30000

20000

10000

0

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08 2008–09

1957

9

1755

5

2337

1

2091

4

2789

3

3423

7

5058

5

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08 2008–09

Cash losses - on subsidy received basisCash losses - before subsidy received

45000

40000

35000

30000

25000

20000

15000

10000

5000

01213

12790

229

10352

350

12022

3268

14206

8283

21119

10869

2734125671

44059

have more than doubled (see Figure 16.1) and are expected to reach Rs 68,600 croreat the end of FY 2010–11.3 A bigger concern is the rising level of cash losses4 beforesubsidy received. These losses have trebled from Rs 14206 crore to Rs 44059 crorebetween 2005–06 and 2008–09 (see Figure 16.2).

Further analysis indicates that Rajasthan, Tamil Nadu (TN) and Andhra Pradesh(AP) have shown the maximum increase in losses between 2005–06 and 2008–09.Table 16.1 provides a snapshot of states that have exhibited significant worsening oflosses. On the other hand, Chhattisgarh, Gujarat, Himachal Pradesh (HP), Kerala,West Bengal (WB), and most of the north-eastern states have reduced their financiallosses or are earning profits (see Table 16.2).

Figure 16.1: Losses without subsidy for distribution utilities have risensharply in 2008–09 (Rs crore)

Source: Power Finance Corporation Ltd

Figure 16.2: Cash losses before subsidy received for distribution utilitieshave trebled between 2005–06 and 2008–09 (Rs crore)

Source: Power Finance Corporation Ltd, IDFC analysis


Tab

le 1

6.1:

Sta

tes

exh

ibit

ing

incr

ease

s in

loss

es f

rom

dis

trib

uti

on b

usi

nes

s (R

s cr

ore)

Loss

es o

n su

bsid

y re

ceiv

ed b

asis

Loss

es w

itho

ut s

ubsi

dyC

ash

loss

es b

efor

e su

bsid

y re

ceiv

ed

20

05–0

620

08–0

9In

crea

se20

05–0

620

08–0

9In

crea

se20

05–0

620

08–0

9In

crea

se

Utt

arak

han

d21

546

925

421

546

925

412

137

925

8

Mah

aras

htra

*59

490

230

859

490

230

8-7

616

5317

29

Jhar

khan

d58

812

4065

295

113

2036

987

711

7229

5

Bih

ar91

610

0589

1273

1725

452

1156

1669

513

Utt

ar P

rade

sh33

8842

3985

143

0258

2115

1937

6952

4914

80

Pu

nja

b-1

364

065

314

2332

4218

1983

925

6417

25

Kar

nat

aka

-91

1667

1758

1136

3118

1982

840

2913

2073

Har

yan

a32

314

8311

6016

1241

2125

0914

6439

4624

82

Mad

hya

Pra

desh

593

2784

2191

953

3728

2775

633

3270

2637

Raj

asth

an61

666

0459

8816

2976

5560

2613

2172

6959

48

Tam

il N

adu

1329

7382

6053

2508

8964

6456

1326

8194

6868

An

dhra

Pra

desh

-41

3321

3362

1442

7936

6494

954

7157

6203

Sour

ces:

Pow

er F

inan

ce C

orpo

rati

on L

td, I

DFC

an

alys

is

Not

e: S

ign

indi

cate

s su

rplu

s; *

For

MSE

DC

L


Tab

le 1

6.2:

Sta

tes

exh

ibit

ing

prof

its

or d

ecre

ase

in lo

sses

fro

m d

istr

ibu

tion

loss

es (

Rs

cror

e)

Loss

es o

n su

bsid

y re

ceiv

ed b

asis

Loss

es w

itho

ut s

ubsi

dyC

ash

loss

es b

efor

e su

bsid

y re

ceiv

ed

20

05–0

620

08–0

9In

crea

se20

05–0

620

08–0

9In

crea

se20

05–0

620

08–0

9In

crea

se

Ch

hat

tisg

arh

-402

-774

-372

-402

-774

-372

-455

-101

5-5

60

Gu

jara

t-5

6-1

541

1124

1085

-39

872

845

-27

Him

acha

l P

rade

sh-2

0-3

2-1

256

-32

-88

3-1

29-1

32

Ker

ala

43-2

17-2

6043

-217

-260

-349

-652

-303

Wes

t B

enga

l25

7-3

9-2

9625

7-3

9-2

96-1

40-2

97-1

57

Sour

ces:

Pow

er F

inan

ce C

orpo

rati

on L

td, I

DFC

an

alys

is

Not

e: S

ign

indi

cate

s su

rplu

s or

pos

itiv

e m

ovem

ent.


AT&C losses have reduced significantly

It is commonly believed that high levels of AT&C losses are the main reason forthe high financial losses of utilities. There is no doubt that AT&C losses are highin absolute terms; with 23 out of 52 utilities recording AT&C losses over30 per cent in 2008–09 (see Table 16.2). This is resulting in revenue losses to theutilities. But overall AT&C losses have reduced over the years and now stand atless than 30 per cent (see Figure 16.3). A closer look at AT&C losses since 2005–06indicates that the majority of utilities have shown considerable reduction in AT&Closses, though the pace of reduction may still be slow (see Table 16.3) and need tobe accelerated. Amongst the states that have exhibited high increases in financiallosses, AP and TN have low AT&C loss levels. Utilities in Rajasthan and someutilities in Karnataka, Haryana and Madhya Pradesh (MP) exhibit high loss levels,but they have been reducing losses.

Table 16.3: Most utilities have shown considerable reduction in AT&C lossesbetween 2005–06 & 2008–09

AT&C loss Increase in Percentage points reduction in AT&C losseslevels in losses2008–09 Up to 5% 5–10% 10–15% 15–20% > 20%

< 20% Reliance Punjab, NDPL, Uttar Bangalore UpperMumbai, All AP utilities, Madhya Gujarat, AssamTorrent Tamil Nadu, Gujarat Lower AssamAhmedabad, DakshinTorrent Gujarat,Surat BEST Mumbai,

Mangalore

20–25% Kerala Himachal BRPL BYPLPradesh,MSEDCL

25–30% WBSEDCL, Ajmer, Jodhpur,Dakshin Haryana, Jaipur, Chamund-Paschim UP eshwari

30–40% Chhattisgarh Northern Orissa, Western Orissa, Meghalaya Dakshin UP BiharUttar Haryana, Hubli,Madhya UP, Paschim Gujarat,Uttarakhand, Madhya MP,Paschim MP Central Assam,

Tripura

> 40% Southern Central Orissa, Arunachal Gulbarga JharkhandOrissa, Purv MP, PradeshManipur, Poorv UP,Mizoram, NagalandSikkim

Sources: Forum of Regulators, Power Finance Corporation Ltd, IDFC analysis


Note: * AT&C loss levels for some utilities were fairly low in 2005–06 because they

had reduced their losses in earlier years. The extent of reduction indicated here may

not reflect this. Further, for some utilities AT&C losses rose between 2005–06 and

2008–09. In some cases, this was not a result of poor performance but a result of

better availability of data on the exact level of AT&C losses prevailing in their service

area. Reliance Mumbai, Torrent Ahmedabad and Torrent Surat have traditionally

had low levels of losses. Some fluctuation in losses is bound to occur and this

fluctuation does not indicate poor performance in AT&C loss reduction.

For detailed names of utilities, refer to Annexure.

Figure 16.3: All-India AT&C losses are below 30%

Source: Power Finance Corporation Ltd

However, AT&C loss levels as reported here may not reflect the true situation5 sincethe information base of distribution utilities still remains poor and sales to theagriculture sector continues to remain unmetered (see Table 16.4) thoughagricultural sales form a sizeable portion of sales in many states (see Table 16.5).Agriculture accounts for 23–24 per cent of electricity consumption in the country.6

Utilities such as Punjab, Uttar Haryana, Uttar Gujarat and Paschim MP, whereagriculture accounts for over 25 per cent of total electricity consumption, have poorlevels of metering as far as agricultural consumers are concerned. Even in TN whereagriculture accounts for 22 per cent of total electricity sales, metering is abysmallylow. It is also interesting to note that utilities that have very low levels of agricultureconsumption have higher levels of metering for agriculture consumers. Examplesto this end can be seen in Uttarakhand and West Bengal, and in utilities in Orissaand Gujarat.

40

36

32

28

%

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08 2008–09

38.7737.75

34.33

33.02

30.6229.58

28.44


Table 16.4: Agricultural consumption continues to remain unmetered—status in select states

State Distribution utility Percentage of agricultural

consumers that are metered

Haryana Dakshin Haryana 61%

Uttar Haryana 32%

Gujarat Uttar Gujarat 27%

Paschim Gujarat 35%

Madhya Gujarat 56%

Dakshin Gujarat 43%

Mysore 24%

Madhya Pradesh Purv MP 30%

Madhya MP 37%

Paschim MP 2.3%

Maharashtra MSEDCL 44%

Orissa Central Orissa 9%

Northern Orissa 21%

Western Orissa 95%

Southern Orissa 96%

Punjab PSEB 9.7%

Tamil Nadu TNEB 3%*

Uttarakhand Uttarakhand 87%

West Bengal WBSEDCL 61.5%

Source: Forum of Regulators

Note: *As mentioned in the tariff order issued by the Tamil Nadu Electricity

Regulatory Commission on July 31, 2010, meters are provided to 3% of the service

connections in each distribution circle of TNEB and consumption is recorded on a

sample basis.


Table 16.5: Level of agricultural consumption in select states in 2008–09

Agricultural sales as Utilities/statesa share of total sales

< 10% WBSEDCL, Orissa utilities, Kerala, Dakshin Gujarat,Himachal Pradesh, Uttarakhand, Jharkhand

10–25% Bihar, UP utilities, Eastern AP, Tamil Nadu, MadhyaGujarat, Purv MP, Chhattisgarh

25–40% Dakshin Haryana, Punjab, Ajmer, Jaipur, Central &Southern AP, Bangalore, Mangalore, Paschim Gujarat,Madhya and Paschim MP

Over 40% Uttar Haryana, Jodhpur, Northern AP, Gulbarga, Hubli,Chamundeshwari, Uttar Gujarat

Sources: Power Finance Corporation Ltd, IDFC analysis

Poor levels of metering of agricultural consumption may also impact the financialhealth of the utilities on account of under provision of subsidy by state governments.In the absence of metering of agricultural consumption, it is not possible to determinethe accurate consumption in each service connection. Since the subsidy providedby state governments towards agricultural consumption is based on the estimationof this consumption by utilities, poor metering may lead to a situation where thesubsidy is under estimated.7

Reduction in AT&C losses requires investments in augmentation and modernizationof the distribution infrastructure for reducing technical losses, energy audits andimproved governance for controlling electricity theft. The momentum of lossreduction made possible by these measures has slowed down. Several ElectricityRegulatory Commissions (ERCs) have made observations to this end in the ordersissued by them. For example, the ERC in Haryana has lamented the absence ofremedial measures to address high feeder losses in some districts in the states.The ERC has also observed that theft cases have been rising and that the utilities donot fully implement the capital expenditure plan drafted by them. The ERC in MPhas also pointed out the abnormally low progress in capital expenditure by theutilities. Actual investments vis-à-vis investment plan prepared by utilities in MPvaried between 26 per cent to 54 per cent during 2007–08 and 2008–09.8

Progress on metering of distribution transformers (DTs) remains poor across states(see Table 16.6). Though energy audits have been initiated in many states, theseaudits can be carried out only in feeders where all DTs are metered. Thus, in theabsence of 100 per cent DT metering, energy audit would have limited benefits.Moreover, in several states energy audit is being conducted only on a sample basis.


These initiatives which had gathered impetus under the Accelerated PowerDevelopment and Reforms Program (APDRP) that aimed to improve the financialviability of utilities and reduce AT&C losses to around 10 per cent has also sloweddown. Given the shortcomings of APDRP and the problems in its implementationof reasons,9 the GOI restructured the programme into the Restructured–AcceleratedPower Development and Reforms Programme (RAPDRP) in December 2008. Theobjective of RAPDRP is to reduce AT&C losses to less than 15 per cent over fiveyears, by automating and integrating various utility processes like assetmanagement; maintenance management; metering, billing and collection; energyaudit; and GIS-based consumer indexing. However, achieving the targets wouldalso take time given that the establishment of reliable and automated systems forsustained collection of accurate base line data, and the adoption of informationtechnology in the areas of energy accounting takes time. Further, the implementationof the programme has already seen several ups and downs.10 Unless the strategy forreduction of AT&C losses is redefined and initiatives stepped up, AT&C lossreduction would continue to be slow and the financial health of the distributionwould take time to improve.

Table 16.6: Status of implementation of select distribution reforminitiatives as of April 2010

Extent of metering Extent of metering Initiation of energyfor 11 kV feeders for distribution audits for segregation

transformers of technical &commercial losses

Haryana Uttar Haryana: Uttar Haryana: Uttar Haryana:99.74%, 2987 nos. Initiated inDakshin Haryana: Dakshin Haryana: Gurgaon and100% 20.88% Faridabad,

Dakshin Haryana: forinter utility interfacepoints of feeder

Punjab 100% 5% Yes

Rajasthan 91% NA No

Uttar Pradesh 100% In part in urban areas Yes

Madhya Pradesh 100% Most urban DTRs Yes, at division levelare metered; for ruralDTRs: work inprogress


Maharashtra* 99.93% NA Yes, division-wise

Gujarat 100% Uttar Gujarat: Not by state owned52.3%, utilities

Paschim Gujarat:17.31%,

Madhya Gujarat:54.54%,

Dakshin Gujarat:56.18%

Andhra Pradesh Being done on All have not been Yessample basis provided with meters

Karnataka 100% for Bangalore Bangalore: Yesand Chamun- 39.5%,deshwari, NA for NA for otherother utilities utilities

Kerala 100% 31.92% In 46 out of 65divisions

Tamil Nadu 100% 49.68% No

West Bengal# 92% 26% Yes

Source: Central Electricity Authority

Notes: * For MSEDCL; # For WBSEDCL; NA – Information not available

So why are utilities incurring rising financial losses?

AT&C losses, though important as an indicator of efficiency, are not a completeindicator of the financial health of distribution utilities. The financial health ofutilities is also dependent on the extent to which they can recover their costs throughthe tariffs charged for electricity consumption. Since the establishment of theindependent regulatory framework in the late 1990s and the enactment of theElectricity Act 2003 (EA 03), ERCs have been entrusted with the mandate ofexamining and approving the costs incurred by utilities on the basis of certain normsand electricity sales, and setting efficiency parameters such as target distributionloss levels. However, given that costs such as those for power purchase, which form

Table 16.6: Status of implementation of select distribution reforminitiatives as of April 2010 (contd...)

Extent of metering Extent of metering Initiation of energyfor 11 kV feeders for distribution audits for segregation

transformers of technical &commercial losses


the majority of the costs, are often beyond the control of the utilities and sales cannotalways be accurately forecast, costs may exceed the revenues of utilities, leaving arevenue gap.

To allow the utilities to recover all genuine and uncontrollable increases in expenses,a process of truing up is followed wherein the variances in actual costs incurred byutilities or revenues earned vis-à-vis those projected by utilities and approved byERCs are allowed to be recovered by utilities. This truing up takes place with a lagbecause the audited accounts of utilities that form the basis of truing up are finalizedonly after the end of a financial year. To put it simply, the annual accounts for ayear, say FY 2006–07, would be available only during FY 2007–08. Therefore, variationin expenses incurred by a discom during FY 2006–07 would be recovered only in FY2008–09. This indicates that variations in costs and revenues do get adjusted andthe financial losses of utilities should not escalate to unmanageable levels.The question that then arises is why losses have escalated.

The gap between tariffs (represented by average revenue realized or ARR) withoutsubsidy and average cost of supply (ACS) has doubled between 2005–06 and2008–09 (see Figure 16.4). Further, cost recovery through tariffs deterioratedfrom 85 per cent to 77 per cent in this period. The situation is not much differentif subsidies are considered. ARR with subsidy continues to be inadequate tocover ACS and the revenue gap with subsidy has doubled from Rs 0.16/kWh toRs 0.33/kWh in this period.

Figure 16.4: Gap between ARR (without subsidy) andACS at the all-India level has increased (Rs/kWh)


Detailed analysis indicates that the majority of utilities recover less than 90 per centof costs incurred (see Table 16.7). Amongst the states that have exhibited increasing

4

3

2

1

0

2002–03 2003–04 2004–05 2005–06 2006–07 2007–08 2008–09

0.43 0.36 0.45 0.39 0.49 0.540.78

1.95 2.032.21 2.27 2.39

2.62

2.38 2.39 2.54 2.60 2.762.93

3.40

2.09

Gap

Average cost of supply

Average revenue realizedwithout subsidy


financial losses, utilities in Rajasthan, TN and MP exhibit cost recovery of less than70 per cent. The utilities in Haryana, AP and Karnataka have varying levels of costrecovery, but cost recovery remains below 80 per cent. A few points need to benoted here. First, some utilities belong to states that are resource-rich and thereforehave surplus power (governed by the policy of the state government to take freepower or first right of refusal for a certain quantum of power at cheap rates). Theseutilities end up selling power at high rates in the market, adding to their revenues.Second, there is a trend to maintain uniform tariffs within a state despite the existenceof more than one distribution utility. Even though utilities have different sales mixesand cost structures, and consequently revenue mixes, tariffs are set using the weakestutility as the benchmark. As a result, the utilities with a favourable consumer mixshow better cost recovery and are in a better financial position while utilities whichdo not have such a consumer mix continue to perform poorly. Exceptions to thistrend of uniform retail tariffs include Karnataka.

Table 16.7: Cost recovery in 2008–09

Cost recovery through Utilitiesrevenue realized(without subsidy)

< 50% Northern AP, Manipur, J&K

50–70% Bihar, Jharkhand, Mizoram, Nagaland, Ajmer,Jodhpur, Jaipur, Dakshin UP, Madhya UP, Poorv UP,Hubli, Uttar Haryana, Central AP, Southern AP,Northern AP, Chamundeshwari, Tamil Nadu, MadhyaMP, Paschim MP, Purv MP

70–80% Arunachal, Dakshin Haryana, Punjab, Paschim UP,Uttarakhand, Gulbarga, Mangalore

80–90% Kesco, Eastern AP, Bangalore, Puducherry, UttarGujarat

90–100% Central Orissa, Northern Orissa, Southern Orissa,Meghalaya, BRPL, Dakshin Gujarat, Madhya Gujarat,Paschim Gujarat, MSEDCL

> 100% Western Orissa, Sikkim, WBSEDCL, Tripura, BYPL,NDPL, HP, Kerala, Chhattisgarh, Goa

Sources: Power Finance Corporation Ltd, IDFC analysisNote: For detailed names of utilities, refer to Annexure


Historically, one of the major problems facing the power sector is the inadequacyof tariffs to meet the cost of supply. In the initial years of regulatory reforms,tariffs were keeping pace with costs (see Figure 16.5). But, in recent years, tariffincrease has once again not kept pace with the increasing ACS. While ACS increasedby 31per cent between 2005–06 and 2008–09, ARR without subsidy increased byonly 17 per cent.

Figure 16.5: In recent years, tariff increase has notkept pace with increasing ACS


Why have costs risen?

Power purchase costs have increased sharply

The cost of supply has been increasing mainly due to the increases in power purchasecosts. A sample analysis of the power purchase costs of utilities in 12 major states inIndia (see figure 16.6) indicates that power purchase costs have increased by47 per cent between 2005–06 and 2008–09. This increase was mainly on account ofincrease in short-term power prices, increase in fuel costs, and higher cost of powerfrom new projects. Of course, increase in fuel costs would also lead to some increasein the price of short-term power as well as in new power being more expensive.Since power purchase costs account for the lion’s share of costs of utilities(89 per cent of the total expenses in 2008–09), increases in these costs are bound tolead to a huge increase in the overall ACS.

18

16

14

12

10

8

6

4

2

0

2003–04 2004–05 2005–06 2006–07 2007–08 2008–09

%

Increase in average cost of supply

Increase in average revenue realizedwithout subsidy

0.4

4.1

6.3

3.02.4

5.7 6.2

2.7

6.25.3

16.0

9.6


Figure 16.6: Power purchase costs have increased (Rs/kWh)

Note: For SEBs, cost of post purchase includes the cost of own power generationSource: Power Finance Corporation Ltd, IDFC analysis

Short-term power procurement by utilities

Power procured by utilities through short-term trades increased by nearly 75 per centin volume terms between 2005–06 and 2008–09, though its share as a percentage of totalelectricity generation in the country remained low. There has been a significant jump inthis procurement between 2008–09 and 2009–10; with short-term power accountingfor 8.6 per cent of the total electricity generated in FY 2009–10 (see Figure 16.7).

4.50

4.00

3.50

3.00

2.50

2.00

1.50

1.00

0.50

0.00

Rs/

Un

it

2005–06 2008–09W

BSE

DC

LB

RP

LB

YP

LN

DP

LD

aksh

in H

arya

na

Utt

ar H

arya

na

Pu

nja

bA

jmer

Jodh

pur

Jaip

ur

Dak

shin

UP

Mad

hya

UP

Pas

chim

UP

Poo

rv U

PC

entr

al A

PE

aste

rn A

PN

orth

ern

AP

Sou

ther

n A

PB

anga

lore

Gu

lbar

gaH

ubl

iM

anga

lore

Cha

mu

nde

shw

ari

Tam

il N

adu

Dak

shin

Gu

jara

tP

asch

im G

ajar

atM

adhy

a G

uja

rat

Utt

ar G

uja

rat

Mad

hya

MP

Pas

chim

MP

Pu

rv M

PM

SED

CL

70

60

50

40

30

20

10

0

Bill

ion

un

its

2005–06 2006–07 2007–08 2008–09 2009–10

10

8

6

4

2

0

%

2.45 2.413.15

6.76

8.63Volume of short termtransactionsAs % of electricitygenerated

14.1

9

15.0

2 20.9

6

46.7

0

65.9

0

Figure 16.7: Procurement of short-term power is increasing*

Source: Central Electricity Regulatory Commission, IDFC analysisNote: * Includes UI


The price of short-term power has also exhibited a significant upward trend overthe years, with FY 2008–09 registering a particularly sharp increase(see Figure 16.8). This may be attributed to the shortage of power (see Figure 16.9),increase in maximum Unscheduled Interchange (UI) 11 charges to Rs 10/kWh inJanuary 2008 from Rs 7.45/kWh, and the socio-political compulsions on utilitiesto provide power to agriculture or compulsions to ensure uninterrupted powersupply in the run up to general elections (held in April–May 2009) even at thecost of sourcing expensive short-term power.

Figure 16.8: Short-term power prices have shot up (Rs/kWh)*

Sources: Central Electricity Regulatory Commission, IDFC analysis

Note: * Average price of electricity transacted through UI during the calendar years 2008 and2009 have been used as proxy for FY 2008–09 and FY 2009–10, respectively for analysis

Figure 16.9: Peak and energy deficit in India (%)Source: Central Electricity Authority

8

7

6

5

4

3

2

1

0

2005–06 2006–07 2007–08 2008–09 2009–10

3.23

4.51 4.52

7.11

5.09

18

16

14

12

10

8

2005–06 2006–07 2007–08 2008–09

8.4

2009–10

Peak deficit

Energy deficit

9.6 9.9

11.1

10.1

12.711.9

16.6

13.8

12.3%


Though short-term power accounts for less than 10 per cent of the power generatedin the country, the high rates at which this power is procured have significantlyaffected the financial viability of many utilities. Amongst the states that have shownhigh increases in financial losses, AP, MP, Rajasthan, Karnataka, and TN haveseen short-term power purchase volume double between FY 2007–08 andFY 2008–09 (see Figure 16.10). Rajasthan particularly stands out here.In FY 2008–09, between August to March, Rajasthan procured the highest quantumof short-term power amongst all states, accounting for 14 per cent of the totalshort-term power purchase in the country. The Government of Rajasthan, in anote dated December 2009,12 has identified this as one of the main problemsaffecting the financial viability of utilities in the state. It has noted that the utilitiesprocured short-term power at an average rate of Rs 9/kWh during April toDecember 2009 and estimates that a subsidy of Rs 2254.25 crore would needto be provided to the utilities against this power purchase.

Figure 16.10: Purchase of short-term power in select states (MU)*

Sources: Central Electricity Regulatory Commission, IDFC analysisNote: * Includes UI, 2008–09 data is for the period August to December

Reliance on imported coal

Over the years, domestic availability of coal has become inadequate for meeting thegrowing requirement for electricity generation. Therefore, power plants areincreasingly resorting to coal imports. The Ministry of Power even assigns generatingentity-wise targets for coal imports in consultation with the Central ElectricityAuthority. Though imported coal accounts for only 3.2 per cent of the total coalconsumed by power plants in the country, the import of coal for power plants hasmore than doubled since 2005–06 (see Figure 16.11). The increase in imports has

6000

5000

4000

3000

2000

1000

0

2007–08 2008–09

396

1484

1393

3891

1041

1907

1590

718

2502

4488

1362

2776

3731

2469

2060

4905

508

2402

2365

434

4185

6

1892

246

And

hra

Prad

esh

Guj

arat

Har

yana

Kar

nata

ka

Ker

ala

Mah

aras

htra

Mad

hya

Prad

esh

Punj

ab

Raj

asth

an

Tam

ilnad

u

Utt

ar P

rade

sh

Utt

arak

hand

Wes

t Ben

gal


been particularly significant in FY 2008–09 and FY 2009–10. The price differencebetween domestic and imported coal after adjusting for calorific value can beestimated at about 26 per cent.13

Figure 16.11: Coal imports for power plants havedoubled between 2005–06 and 2008–09

Source: Ministry of Power

Figure 16.12: Trends in price of imported coal (in rupees)

Source: Ministry of Finance

Employee costs have increased

At the all-India level, employee costs for distribution utilities have increased by76 per cent between 2005–06 and 2008–09. The increase has been largest in 2008–09

2005–06 2006–07 2007–08 2008–09 2009–10

10.4 9.7 10.2

16.1

23.225

20

15

10

5

0

Mill

ion

ton

nes

180

150

120

90

60

30

0

2005–06 2006–07 2007–08 2008–09 2009–10

Coal, Australia

Jul-Sep

Jul-Sep

Jul-Sep

Jul-Sep

Jul-Sep

Jan-Mar

Jan-Mar

Jan-Mar

Jan-Mar

Jan-Mar

48 47 50 5368

116

163

71

95

72


(see Figure 16.13) and can be attributed to the revision in employee cost as per therecommendations of the Sixth Pay Commission.

Figure 16.13: Increase in employee costs for distribution utilities in India


Why are tariffs not keeping pace with costs?

Tariffs are inadequate to cover costs for two reasons. First, tariff increases have notbeen timely. Some states have not raised tariffs for the past five years (See Table 16.8).There are instances of utilities not filing tariff determination petitions before stateelectricity regulatory commissions (SERCs) or delaying such filings.

Table 16.8: Status of tariff revision in states/union territories at the end of 2009

Tariffs last revised No. of states/UTs States/UTs

1 year 13 Andhra Pradesh, Assam, Chhattisgarh,Gujarat, Himachal Pradesh, Karnataka,Madhya Pradesh, Orissa, Punjab, WestBengal, Arunachal Pradesh, Sikkim, Delhi

1–2 years 6 Bihar, J&K, Maharashtra,* Meghalaya,Uttar Pradesh, Uttarakhand

2–3 years 2 Kerala, Tripura

3–5 years 5 Rajasthan, Jharkhand, Mizoram,Nagaland, Chandigarh

> 5 years 5 Haryana, Tamil Nadu, Goa, Manipur,Puducherry

Sources: Economic Survey of India 2010–11, IDFC analysis

Notes: *for MSEDCL; States such as Haryana and Tamil Nadu have undertaken tariffrevisions during 2009–10 or 2010–11. However, given the huge revenue deficits to be

40

35

30

25

20

15

10

5

0

2006–07 2007–08 2008–09

20

9

34


covered through tariff hikes and the consequent tariff shock to be faced by consumers,some ERCs have had to resort to the creation of regulatory assets. Examples include Haryana

and Tamil Nadu.

Second, even when tariff revisions have taken place, the gap has not been reduced.This is on account of several reasons.

• Lack of information

– The absence of reliable and adequate data or studies on the part of theutilities implies that ERCs do not have a solid basis to determine andapprove costs and efficiency-improvement targets.

– The annual accounts of utilities are not finalized on time, implying theabsence of authentic information on the costs and consumption baseof utilities.

• Delays in tariff orders

– The issue of tariff orders is often delayed due to utilities not following theprocess timelines for submission of related petitions and additionalinformation or due to inadequate data submission by utilities.Tariff revisions are therefore ineffective.

• Limitations of truing up

– ERCs may not follow the practice of truing up. For instance, in case ofpower purchase costs, only few states such as AP, Assam, Gujarat,Haryana, Kerala, Maharashtra and Punjab have laid down principlesor methodology for automatic adjustment of fuel and power purchasecost in tariff. These principles are known as Fuel Cost Adjustment (FCA)formula or Fuel and Power Purchase Price Adjustment (FPPPA)formula or Fuel Surcharge formula. However, states have either recentlystarted cost recovery through such a formula (such as Kerala in January2010 and Assam in December 2010) or face delays in cost recovery onaccount of delays in filing of claims and obtaining necessary regulatoryapprovals. If there is no automatic adjustment of these costs, utilitieshave to wait for the annual truing up exercise to recover them in casesuch an exercise is conducted.

– ERCs do not allow the inefficiency of utilities to be passed to consumers.ERCs set efficiency targets for utilities. Further, they allow onlyuncontrollable costs to be trued up. In the event that utilities are not ableto achieve their performance targets or contain costs, and they are not ableto justify such non-achievement, ERCs do not allow the under-performanceto be passed on through higher tariffs. For instance, the level of distribution


losses affects the power purchase quantum and costs of a utility. If a utilitydoes not achieve the distribution loss reduction set by the ERC, the ERCdisallows the power purchase expenses on account of high distributionlosses. Another example of inefficiency of utilities is not following the meritorder schedule for procurement of power i.e. cheapest sources of power beofftaken first by the utility. ERCs may not accept purchase of expensivepower in such case.

– ERCs may not recognize the true extent of even the genuine anduncontrollable costs. For example, in the case of states such as Assamand Maharashtra, the FPPPA is subject to a ceiling of the variablecomponent of tariff. In Assam the adjustment is subject to a ceiling of25 per cent of the variable component of tariff while in Maharashtra,the ceiling is 10 per cent. Similarly, ERCs may disallow unmetered salesby utilities and consequently allow lower power purchase requirementand costs.

– Utilities do not approach ERCs for truing up of actual costs and revenueseither due to non-finalization of annual accounts or to avoid further tariffhikes. Examples of states where utilities have not approached ERCs fortruing up include UP, Haryana, and TN.

– Utilities do not implement truing up as allowed by the ERCs even thoughthis is in their own commercial interest. Examples here include UP.

• Creation of regulatory assets

– ERCs may resort to the creation of regulatory assets wherein therecovery of costs through tariff hikes is postponed to future years toavoid tariff shocks to consumers. Examples of states where SERCs havecreated regulatory assets are Bihar, Haryana, Tamil Nadu, West Bengaland Orissa.

To sum up, the inadequacy of tariffs has led to an increase in revenue gapin case of many utilities (see Table 16.9).

Table 16.9: Increase in revenue gap without subsidy for utilitiesbetween 2005–06 and 2008–09*

Increase in revenue Utilitiesgap without subsidy

Decrease in gap Southern Orissa, Western Orissa, Sikkim, WBSEDCL,Arunachal, Lower Assam, Upper Assam, Manipur,

Meghalaya, Nagaland, Tripura, HP, J&K, Paschim UP,


Poorv UP, KESCO, Kerala, Chhattisgarh, Goa, All

Gujarat utilities

< 10 paisa Central Orissa, Northern Orissa, BYPL, Gulbarga

10–20 paisa Jharkhand, Dakshin UP, Uttarakhand, MSEDCL

20–50 paisa Bihar, Central Assam, BRPL, Dakshin Haryana, Punjab,

Bangalore, Hubli, Puducherry

50–100 paisa Mizoram, Madhya UP, Eastern AP, Southern AP,

Mangalore, Chamundeshwari, Tamil Nadu, All MP

utilities

> 1 Rupee Uttar Haryana, Ajmer, Jodhpur, Jaipur, Central AP,

Northern AP


Notes : *NDPL reported zero revenue gap in 2005–06 and 2008–09 and hastherefore not been included in the above table. Decrease in revenue gap does not implythat these utilities are necessarily performing better than the others. It only indicatesthe trend. These utilities may continue to have substantial revenue gaps. Therefore, thistable needs to be read along with Table 16.6. For detailed names of utilities, refer to

Annexure.

Tariff rationalization has also been slow

An important contributor towards the financial viability of thedistribution business is tariff rationalization. The goal of tariff rationalizationis cost-reflective tariffs and reduction in cross subsidies. The National TariffPolicy mandates SERCs to notify a road map for tariffs to be within ± 20 percent of the average cost of supply by end of FY 2010–11. While SERCs havetaken steps to rationalize tariffs, the progress is inadequate. In 2008–09, thecross subsidy levels were high as compared to the target laid down by the Policy(see Table 16.10). Progress in tariff rationalization would help mitigate theproblem of rising financial losses, particularly when agricultural sales increase.More importantly, it would reduce the dependence of utilities on subsidies fromstate governments.

Table 16.9: Increase in revenue gap (contd...)

Increase in revenue Utilitiesgap without subsidy


Table 16.10: Consumer tariffs as percentage of Average Cost of Supplyapproved by SERCs in FY 2008–09

Domestic Agriculture Non-domestic/ HT industrycommercial

Andhra Pradesh 88% 4% 214% 140%

Assam 80% 72% 130% 110%

Bihar 52% 27% 116% 101%

Chhattisgarh* 58% 54% 145% 115%

Delhi# 76% 41% 145% 129%

Gujarat 82% 27% 129% 144%

Haryana 80% 6% 100% 100%

Himachal Pradesh 50% 20% 154% 111%

Jharkhand# 42% 48% 155% 124%

J&K* 31% 46% 53% 60%

Karnataka 100% 17% 162% 129%

Kerala 59% 26% 150% 155%

Madhya Pradesh 92% 72% 148% 128%

Maharashtra 100% 40% 170% 120%

Punjab 93% 73% 138% 126%

Rajasthan 90% 41% 131% 99%

Uttar Pradesh 71% 49% 96% 137%

Uttarakhand 69% 24% 123% 116%

Sources: Forum of Regulators/CRISIL Risk and Infrastructure Solutions Ltd report on Study

on Analysis of Tariff Orders & Other Orders of State Electricity Regulatory Commissions

Notes: *FY 2007–08; # FY 2006–07

Subsidies required from state governments are rising

Another area of concern is the sharp rise in subsidies from state governments toutilities. The subsidy booked by utilities to the state governments has shot upfrom Rs 12,000 crore in 2005–06 to almost Rs 30,000 crore in 2008–09(see Figure 16.14). But the subsidy payouts by the state governments are muchless than determined. In 2008–09, only 60 per cent of the subsidy booked by theutilities was released to them. In many cases, subsidies are not released in atimely manner.


Figure 16.14: Subsidies booked by distribution utilities are risingbut payment by state governments is inadequate


Rajasthan and AP have exhibited the maximum increase in subsidy between2005–06 and 2008–09 (see Figure 16.15). While both states subsidize severalcategories of consumers, AP has introduced free power for agriculture sinceFY 2006–07. Not surprisingly, the payment of subsidy by the state governmentsto the utilities has been falling drastically in these two states. It is pertinent to notethat the Government of Andhra Pradesh paid a subsidy of Rs 2,146 crore during2009–10 against the total committed subsidy of Rs 3,486 crores to the utilities.14

The subsidy committed for 2010–11 has increased further to Rs 3,652 crores.15

On the whole, except Rajasthan, AP and Jharkhand, state governments have beenpaying the full amount of subsidy due to utilities (see Figure 16.16).

Figure 16.15: Top ten states exhibiting the maximum increase in subsidybooked (in Rs crore)


8000

6000

4000

2000

0

2005-06 2008-09

361944 1179

1832915

1581

3631080 1436

2602

1178 1268 1289

2637

1629 1533

7655 7980

Mad

hya

Pra

desh

Tam

il N

adu

Utt

ar P

rade

sh

Jhar

khan

d

Pun

jab

Guj

arat

Har

yan

a

Raj

asth

an

An

dhra

Pra

desh

35000

30000

25000

20000

15000

10000

5000

02005–06 2006–07 2007–08 2008–09

105%100%95%90%85%80%75%70%65%60%

84%

94%89%

Subsidy booked by utilities

Rs

cror

e

1359019518

62%12233

29665


Figure 16.16: States not paying full amount of subsidy to utilities


What are the specific reasons for increasing losses in the worst performing states?

As seen from Table 16.1, the states that have exhibited the most deterioration infinancial health are Uttar Pradesh (UP), Punjab, Karnataka, Haryana, MP, Rajasthan,TN and AP. Analysis of the underlying causes helps identify three clear reasonsbehind such deterioration.

Poor governance

In case of Andhra Pradesh, increasing dependence of the utilities on subsidy andnon-payment of this subsidy by the state government is the reason behind theworsening financial health of utilities. The State Government has been providingfree power to agriculture from FY 2006–07. This implies that as per the provisionsof EA 03, the state government has to provide subsidies to the utilities in lieu ofprovision of free power. Therefore, given the dependence on subsidies, losses withoutsubsidy have spiraled between FY 2005–06 and FY 2008–09. Further, while losseson subsidy-booked basis have been fairly low for the utilities (see Table 16.1), losseson subsidy-received basis have shot up between FY 2005–06 and FY 2008–09,thereby indicating that the state government has not been able to provide therequisite subsidies to the utilities (see Figure 16.15 also).

In the states of TN, Rajasthan, Haryana and UP, poor governance on the part of utilitiesand state governments by way of not seeking/allowing tariff revision (see Table 16.7)has been responsible for the increasing financial insolvency of utilities. This doesnot imply that inefficiency of utilities has no role to play in their weak financialhealth. But the root cause of the problem in these states is the failure of governance.

In Tamil Nadu, post the issue of the first tariff order in March 2003, the TamilNadu Electricity Board (TNEB) approached the Tamil Nadu Electricity Regulatory

100%

80%

60%

40%

20%

0%

2005–06 2006–07 2007–08 2008–09

RajasthanKarnatakaJharkhandAndhra PradeshTamil Nadu

100% 100% 100%

62%

94%

66%

98%

84%

38%

96%

86%

58%

14%

7%

37%


Commission for revision of retail tariff only in July 2010; this despite manifoldincrease in TNEB’s input cost and accumulating revenue deficit since 2003–04.

Similarly, utilities in Rajasthan have not approached the ERC for a tariff revisionsince FY 2004–05. The Rajasthan Electricity Regulatory Commission (RERC)in all tariff orders since then has left the revenue gap uncovered. RERC, in theorders passed on approval of Annual Revenue Requirement of utilities, hasobserved that the revenue gap can be bridged or reduced by measures such astariff increases, power purchase adjustment in retail supply tariff, subsidy fromstate government and by higher reduction of AT&C losses than targeted. It hasurged the utilities to file tariff petitions for bridging the revenue gap. A note ofthe Government of Rajasthan dated December 200916 on the state’s power sectorclearly brings out that utilities need the permission of the state government tofile tariff revisions petitions. The remedial measures contemplated by the stategovernment to salvage the deteriorating financial position of the utilities includepermission to utilities to file tariff petitions for the year 2009–10, allowing utilitiesto file Power Purchase Fuel Cost Adjustment (PPFCA) formula before RERC,allowing utilities to recover Rs 300 crore as the power purchase and fuel costadjustment for the quarter ended December 2007 and March 2008 as approvedsuo moto by RERC, and requesting RERC to suo moto allow recovery of PPFCAfor the year 2008–09. The state government estimates that the last measure alonewould provide a relief of at least Rs 1000 crore for FY 2008–09 and more thanRs 1250 crore for 2009–10 to the utilities.

As is the case with RERC, the Haryana Electricity Regulatory Commission (HERC)too has not increased retail tariff in Haryana from FY 2005–06 to FY 2009–10 becausethe two utilities in the state have neither given a tariff proposal nor suggested anyother mechanism to deal with their revenue gaps. Consequently, HERC has addressedthe revenue deficit each year by considering additional revenue resulting from furtherreduction in loss level, additional government subsidy, and creation of regulatoryasset. In FY 2008–09, HERC has not been able to address the revenue deficit fullyand therefore left the same untreated.

In UP, the state has not seen tariff hikes commensurate with the increasing cost.Therefore, the revenue deficit of utilities has been increasing every year. While therewere no tariff revisions between FY 2005–06 to FY 2007–08 (since the utilities didnot propose any revisions), only partial tariff revision has taken place inFY 2008–09. The revenue gap of utilities, as proposed by the utilities themselves, isbeing met through committed government subsidy, additional government subsidyand institutional finances against government repayment guarantee (see Table 16.11).The latter being akin to working capital loans, the UP Electricity RegulatoryCommission (UPERC) in its orders has warned that such management of financial


resources grossly against the prudent financial practice and continuation of such apractice would lead the utilities into a vicious debt trap.

Table 16.11: Funding of revenue gap of utilities in Uttar Pradesh

FY 2006–07 FY 2007–08 FY 2008–09

Total expenses of utilities 13,428 16,260 17,535

Revenue from prevailing tariffs 9,992 11,424 13,218

Revenue gap 3,436 4,836 4,317

Funded through:

Tariff revision - - 1,839

Government subsidy 1,012 1,822 1,532

Additional government subsidy 500

Short term loans 1,151 2,307

Others (power purchase costsavings/efficiency improvement) 773 707 946

Source: Compiled from orders issued by Uttar Pradesh Electricity Regulatory Commission

Notes: Totals may not match due to rounding off; No orders were issued in relation to theAnnual Revenue Requirement and Tariff Determination for FY 2005–06 because of inordinatedelays in submissions related to the same by the utilities.

The problem of governance in UP extends beyond just tariff revision. As observedby the UPERC in its tariff orders, despite the reform process in the state powersector starting as early as 1999, structural arrangements of the sector have not beenresolved. The sector is characterized by the lack of accountability, institutionalstrengthening, institutional capacity and autonomy in management. Directintervention of State Government continues in minutest administrative, technicaland commercial matters. Finally, adherence to the legislative mandate of the sectorhas almost grounded to a halt.

Inefficiency of utilities

In Punjab and MP, the main reason for the declining financial health of utilities isinefficiency. In both states, utilities have not been able to achieve the distributionloss reduction targets laid down by the State Government17 /ERCs and the actualdistribution losses have generally been much higher than the targets. Consequently,while arriving at the power purchase quantum for the utilities during truing up andfor subsequent years, the ERCs have considered the distribution loss levels mandatedby them. Further, they have disallowed power purchase expenses on account ofhigh T&D loss (see Figures 16.17 and 16.18).


Figure 16.17: Distribution losses in Punjab (%)

Source: Compiled from orders issued by Punjab State Electricity Regulatory Commission

Figure 16.18: Distribution losses in Madhya Pradesh (%)

Sources: Compiled from orders issued by Madhya Pradesh Electricity Regulatory Commission,Annual Revenue Requirement Filings by Utilities for FY 2009–10, Annual Accounts forPaschim MP discom for FY 2006–07, Forum of Regulators/Crisil Infrastructure Advisory’sreport on Assessment of Reasons for Financial Viability of Utilities

It would be useful to note that in case of Punjab, distribution loss levels have alwaysbeen a contentious issue, with their being vast differences in the targets proposed bythe Punjab State Electricity board (PSEB) and that approved by the Punjab State

28

26

24

22

20

18

2005–06 2006–07 2007–08 2008–092004–052003–04

27

25

2423

24

24 24

25

22

24

23

21

23

22

20

21

20

20

Proposed by PSEB

Approved & trued up by PSERC

Actual as per PSEB

2006–07 2007–08 2008–09

Poorv MP - Actual lossesPaschim MP - Actual lossesMadhya MP - Actual losses

Poorv MP - State govt’s targetPaschim MP -Madhya MP -

State govt’s targetState govt’s target

45

43

41

39

37

35

33

31

29

27

25

43

4241

4040

39

3737

36

35

30

38

34

33

29

30

27


Electricity Regulatory Commission (PSERC). The main reason for this is thechanging approach and norm for ascertaining agriculture consumption, which islargely unmetered, and the debate over the reasonability of distribution loss reductiontrajectory proposed by PSEB and set by PSERC.

Another issue related to inefficiency of PSEB is its employee costs. PSERC, in itsorders, has repeatedly observed that the employee cost of PSEB is one of the highestin the country and has recommended that that PSEB takes effective steps to containthis cost. While PSEB has cited several measures such as freezing fresh recruitment,complete ban on creation of new posts, withdrawal of compassionate appointmentsto dependants of deceased employees, introducing special schemes for employeesto avail of long leave for self-employment for controlling employee cost, PSERChas argued that the PSEB has not taken a holistic view of its manpowerrequirements keeping in view norms issued by PSERC and productivity levels.There are therefore, significant differences in the actual employee costs of PSEBand that allowed by PSERC (see Figure 16.19). The Appellate Tribunal forElectricity (ATE)18 has supported the PSERC view’s and observed that PSEB’sinitiatives for reducing employee cost are not forceful and have remainedineffective. It has further observed that the employee cost of PSERC would remaincapped until performance parameters improve.

Figure 16.19: Employee costs of PSEB (Rs crore)

Source: Compiled from orders issued by Punjab State Electricity Regulatory Commission

Note: In truing up employee costs, PSERC has allowed annual increases at the rate of WPI onthe previous year’s trued-up costs. Therefore, approved and trued up costs differ in some years.

While inefficiency of utilities should not be ignored and ERCs are right in penalizingerrant utilities by not allowing costs on account of inefficiency to be passed on toconsumers in the form of higher tariffs, the fact remains that this only adds to the

2500

2000

1500

1000

500

0

2005–06 2006–07 2007–08 2008–092004–052003–04

Proposed by PSEB

Actual as per PSEB

Approved by PSERC

Trued up by PSERC

1379

1275

1275

1558

1541 16

27 1751

1631

2042 22

0217

68


vicious cycle of poor financial health of utilities which have few incentives to reducefinancial losses in the poor governance framework of the sector.

It would be useful to note that Maharashtra, too, has seen some issues of inefficiency,with the ERC not allowing the Maharashtra State Electricity Distribution CompanyLtd to recover higher than approved operation and maintenance (O&M) and higherinterest costs (due to high short-term loans) through tariffs.19

Extraneous circumstances

In Karnataka, the multi-year tariff (MYT) orders for the utilities for the period2007–08 to 2009–10 was delayed due to a direction from the ATE to the KarnatakaERC (KERC) not to pass the tariff orders for the utilities till the ATE passes the finalorders in case of an appeal filed by the Karnataka Power Transmission CorporationLimited challenging a past Tariff Order issued by the KERC. Consequently, theMYT orders for utilities were issued in January 2008 and became applicable fromFebruary 1, 2008. As a result, costs incurred for FY 2007–08 could not be fullyrecovered during the same financial year and tariffs could not be revised for FY2008–09. The delay in issue of tariff order due to a pending appeal was thereforeresponsible for the financial deterioration of utilities in FY 2008–09.

How are utilities financing their revenue deficits?

The revenue deficit of utilities is being financed through state government subsidies,short term borrowings from banks, and delays in payments to be made for powerpurchase. A snapshot of this financing is indicated in Table 16.12. It would be usefulto point out that the quantum of change in factors such as bank loans would notnecessarily match up to losses not met through subsidies. This is because bank loansare also used to finance long-term capital expenditure by utilities. Absence ofinformation prevents the disaggregation of these loans by time periods to understandthe extent of short-term borrowing by utilities. However, there is evidence to suggestthat a large part of the increase in bank loans may be on account of short-termborrowings by utilities to finance their revenue deficits. This analysis is presentedlater in this section.

Table 16.12: Means of financing the revenue deficits of utilities (indicative) (Rs crore)

2005–06 2008–09

Financial losses without subsidy 20,914 50,585

Direct subsidy 12,233 29,665

Outstanding loans from state governments* 37,328 28,682

Loans from banks/FIs/bonds* 55,318 1,15,285



Notes: *For the state of Uttar Pradesh, Uttar Pradesh Power Corporation Ltd has been

included. UPPCL is the state government owned company that holds 100 per cent

shares of the distribution utilities in Uttar Pradesh. UPPCL also borrows from financial

institutions on behalf of these utilities.

Reliance on state government financing

As mentioned earlier, direct subsidies provided by state governments have morethan doubled between 2005–06 and 2008–09. In addition to these subsidies, stategovernment support for utilities is also available in the form of loans, guarantees,and equity investments. In recent years, loans from state governments to utilitieshave declined for two reasons. The first is that new loans from state governmentto utilities have reduced seemingly because of the poor financial position of someof the state governments themselves. In fact, this is also an important reason forthe non-payment of subsidies to utilities. The second is that state governmentshave sometimes adjusted overdue loans to utilities against subsidies due. Forexample, in Punjab, the state government had recalled its overdue loans ofRs 1,362 crore in February 2008 and adjusted the same against balance unpaidsubsidy for 2007–08.20

State governments also give cash subventions to utilities to meet the revenue deficits.Examples include Rajasthan (see Table 16.13). Further, they extend guarantees tofinancial institutions to support the borrowings of utilities because of the precariousfinancial position of these utilities. The Thirteenth Finance Commission (TFC)observes that the overall outstanding guarantees extended by states to utilities as onMarch 31, 2008 amounted to Rs 88,385 crore. The TFC further observes that equityinvestments amounted to Rs 71,268 crore on March 31, 2008 and have not beenearning financial returns for the state governments, barring isolated instances.

Financing through short-term borrowings

Utilities have been resorting to increased levels of short-term borrowing to covertheir revenue deficit, meet repayment obligations against past loans, and meet theincreased costs of power purchase. It is relevant to point out that given the alreadyprecarious financial position of many utilities, the short-term loans from banks areobtained against guarantees by state governments.

Table 16.13 provides information on the states that have exhibited high increases inloans from banks/FIs/bonds. There is evidence to indicate that a large part of theseloans is going towards meeting the revenue deficit of utilities rather than towardscapital expenditure (see Table 16.13). Several ERCs have highlighted this in theorders issued by them. It would be useful to point out that the interest on the short-term loans taken to meet revenue deficits are not allowed as a pass-through in tariff


Tab

le 1

6.13

: Ou

tsta

ndi

ng

ban

k lo

ans

and

gove

rnm

ent

guar

ante

es in

sel

ect

stat

es (

Rs

cror

e)

Ou

tsta

nd

ing

loan

sO

uts

tan

din

gO

bser

vati

ons

from

ord

ers

issu

ed b

y E

lect

rici

tyto

dis

trib

uti

ongo

vern

men

tR

egu

lato

ry C

omm

issi

ons

uti

liti

es fr

omgu

aran

tees

toba

nks

/FIs

/bon

ds

pow

er s

ecto

r

2005

–06

2008

–09

2008

–09

Utt

ar P

rade

sh*

7478

1371

315

,794

As

indi

cate

d in

Tab

le 1

6.11

, uti

litie

s in

UP

hav

e be

en m

eeti

ng

a la

rge

port

ion

of t

heir

rev

enu

e ga

p th

rou

gh s

hort

ter

m lo

ans

from

ban

ks. T

he U

P E

RC

21

obse

rves

, “Su

ch a

n a

ppro

ach

is n

ot o

nly

aga

inst

the

reg

ula

tory

pri

nci

ples

bu

tal

so a

gain

st c

onsu

mer

inte

rest

s as

it w

ould

lead

to

incr

ease

in c

osts

by

way

of

inte

rest

an

d re

paym

ent

oblig

atio

n o

n s

uch

loan

s. T

he C

omm

issi

on v

iew

s su

cha

man

agem

ent

of f

inan

cial

res

ourc

es g

ross

ly a

gain

st t

he p

rude

nt

fin

anci

alpr

acti

ce a

nd

war

ns

that

con

tin

uat

ion

of s

uch

a p

ract

ice

wou

ld le

ad t

he p

ower

uti

litie

s of

UP

into

a v

icio

us

debt

tra

p. H

owev

er, t

he C

omm

issi

on h

as a

llow

edth

ese

inst

itu

tion

al lo

ans

as s

ubs

idy

from

GoU

P a

nd

the

debt

ser

vici

ng

of s

uch

loan

s is

to

be d

irec

tly

fun

ded

by t

he G

oUP

thr

ough

bu

dget

ary

prov

isio

ns.

”

Pu

nja

b51

7513

518

2,90

9T

he P

unja

b E

RC

has

in it

s ta

riff

ord

ers22

det

erm

ined

that

the

Pun

jab

Stat

eE

lect

rici

ty B

oard

has

bee

n d

iver

tin

g ca

pita

l fun

ds fo

r re

ven

ue p

urpo

ses.

The

ER

C, h

as b

ased

its

fin

din

gs o

n th

e B

oard

’s a

udit

ed a

ccou

nts

an

d de

term

ined

cum

ulat

ive

dive

rsio

n o

f Rs

3828

cro

re in

200

6–07

whi

ch r

educ

ed to

Rs

2,62

5 cr

ore

in 2

008–

09.

Kar

nat

aka

1431

3103

1,20

8

Har

yan

a15

2370

882,

708

The

re is

a la

rge

vari

atio

n in

the

act

ual

inte

rest

cos

t cl

aim

ed b

y th

e u

tilit

ies

and

that

app

rove

d by

the

Har

yan

a E

RC

in 2

008–

09. T

his

vari

atio

n is

pri

mar

ily o

nac

cou

nt

of in

tere

st b

urd

en o

f sh

ort-

term

loan

s ta

ken

by

the

dist

ribu

tion

uti

litie

s fo

r m

eeti

ng

the

reve

nu

e de

fici

t.23


Tab

le 1

6.13

: Ou

tsta

ndi

ng

ban

k lo

ans

and

gove

rnm

ent

guar

ante

es in

sel

ect

stat

es (

Rs

cror

e) (

con

td...

)

Ou

tsta

nd

ing

loan

sO

uts

tan

din

gO

bser

vati

ons

from

ord

ers

issu

ed b

y E

lect

rici

tyto

dis

trib

uti

ongo

vern

men

tR

egu

lato

ry C

omm

issi

ons

uti

liti

es fr

omgu

aran

tees

toba

nks

/FIs

/bon

ds

pow

er s

ecto

r

2005

–06

2008

–09

2008

–09

Mad

hya

651

4215

3,36

8T

he M

PE

RC

24 h

as o

bser

ved

that

sin

ce t

he d

istr

ibut

ion

utili

ties

are

gov

ernm

ent-

Pra

desh

own

ed c

ompa

nie

s, t

here

fore

, eve

ntu

ally

the

add

itio

nal

bu

rden

of

reve

nu

ede

fici

t ov

er a

nd

abov

e th

e su

bsid

y pr

ovid

ed t

o so

me

con

sum

er c

ateg

orie

s,de

volv

es o

n t

he s

tate

exc

hequ

er b

y w

ay o

f bai

l ou

t or

incr

ease

d su

bven

tion

to

keep

the

dis

trib

uti

on c

ompa

nie

s fi

nan

cial

ly a

floa

t.

Raj

asth

an62

0220

316

22,2

62T

he

reve

nu

e d

efic

it o

f d

istr

ibu

tion

uti

liti

es is

par

tly

met

by

the

cash

subv

enti

on r

ecei

ved

fro

m t

he

Stat

e G

over

nm

ent

as a

gree

d in

Fin

anci

alR

estr

uct

uri

ng

Pla

n. T

he

bala

nce

gap

as

def

erre

d r

even

ue

subv

enti

onre

ceiv

able

fro

m t

he

Stat

e G

over

nm

ent

in it

s bo

oks

as p

er F

inan

cial

Res

tru

ctu

rin

g P

lan

ap

pro

ved

. How

ever

, uti

litie

s h

ave

reso

rted

to

shor

t-te

rmbo

rrow

ings

to

mee

t th

is u

nm

et r

even

ue

def

icit

. Th

e in

tere

st o

n t

hes

ebo

rrow

ings

for

th

e u

tilit

ies

was

as

follo

ws:

25

Ajm

er –

Rs

145

cror

e in

200

7–08

an

d R

s 16

9 cr

ore

in 2

008–

09

Jaip

ur

– R

s 12

1 cr

ore

in 2

007–

08 a

nd

Rs

91 c

rore

in 2

008–

09

Jodh

pur

– R

s 10

9 cr

ore

in 2

007–

08 a

nd

Rs1

20 c

rore

in 2

008–

09

A n

ote26

of

the

Gov

ern

men

t of

Raj

asth

an s

tate

s th

at t

here

was

incr

emen

tal

shor

t-te

rm b

orro

win

g of

Rs

3189

cro

re d

uri

ng

2007

–08

and

Rs

3807

cro

redu

rin

g 20

08–0

9 by

the

dis

trib

uti

on u

tilit

ies

in t

he s

tate

to

mee

t th

e hi

gher

pow

er p

urc

hase

cos

t fr

om b

ilate

ral,

UI

and

ener

gy e

xcha

nge

s.


Tab

le 1

6.13

: Ou

tsta

ndi

ng

ban

k lo

ans

and

gove

rnm

ent

guar

ante

es in

sel

ect

stat

es (

Rs

cror

e) (

con

td...

)

Ou

tsta

nd

ing

loan

sO

uts

tan

din

gO

bser

vati

ons

from

ord

ers

issu

ed b

y E

lect

rici

tyto

dis

trib

uti

ongo

vern

men

tR

egu

lato

ry C

omm

issi

ons

uti

liti

es fr

omgu

aran

tees

toba

nks

/FIs

/bon

ds

pow

er s

ecto

r

2005

–06

2008

–09

2008

–09

Tam

il N

adu

9304

2150

22,

694

The

TN

ER

C h

as o

bser

ved27

tha

t th

e T

NE

B is

bor

row

ing

fun

ds t

o m

eet

the

repa

ymen

t ob

ligat

ion

s, p

aym

ent

of in

tere

st o

n b

orro

win

gs a

nd

also

to

mee

t th

ere

ven

ue

expe

ndi

ture

in v

iew

of c

onsi

sten

t re

ven

ue

defi

cit

for

the

past

yea

rs. I

tha

s fu

rthe

r ob

serv

ed t

hat

ther

e ha

s be

en n

o m

ajor

gen

erat

ion

cap

acit

y ad

diti

onby

TN

EB

for

the

last

ten

yea

rs. T

his

impl

ies

that

loan

s fo

r ca

pita

l exp

endi

ture

shou

ld b

e on

the

low

er s

ide.

An

dhra

3543

9003

10,2

57A

s pa

rt o

f the

reg

ula

tory

pro

cess

for

the

appr

oval

of t

he A

nn

ual

Rev

enu

eP

rade

shR

equ

irem

ent

of d

istr

ibu

tion

uti

litie

s fo

r 20

11–1

2, s

ome

stak

ehol

ders

hav

epo

inte

d ou

t th

at t

he G

over

nm

ent

of A

P h

as t

o pa

y n

earl

y R

s 10

,000

cro

re a

sdu

es t

o th

ese

uti

litie

s.28

In

lieu

of t

hese

du

es, t

he u

tilit

ies

are

borr

owin

g fu

nds

from

ban

ks. I

n it

s re

spon

se, t

he C

entr

al A

P d

istr

ibu

tion

uti

lity

has

con

firm

edth

at it

has

rai

sed

shor

t-te

rm lo

ans

on b

ehal

f of t

he s

tate

gov

ern

men

t ag

ain

stth

e su

bsid

y re

ceiv

able

.

Sour

ces:

Pow

er F

inan

ce C

orpo

rati

on L

td,

Mer

cado

s R

epor

t fo

r T

hirt

een

th F

inan

ce C

omm

issi

on,

Ord

ers

issu

ed b

y ap

prop

riat

e E

lect

rici

tyR

egu

lato

ry C

omm

issi

ons,

ID

FC a

nal

ysis

.

Not

es: *

Incl

ude

s U

ttar

Pra

desh

Pow

er C

orpo

rati

on L

td (

UP

PC

L). U

PP

CL

is t

he s

tate

-gov

ern

men

t-ow

ned

com

pan

y th

at h

olds

100

per

cen

tsh

ares

of t

he d

istr

ibu

tion

uti

litie

s in

Utt

ar P

rade

sh. U

PP

CL

also

bor

row

s fr

om fi

nan

cial

inst

itu

tion

s on

beh

alf o

f the

se u

tilit

ies.


by ERCs (see Table 16.14). This is because these loans are not related to particularassets on the part of the utilities, and tariff regulations prevent ERCs from allowinginterest costs on short-term loans beyond the normative working capital interest.This is leading the utilities into a debt trap.

Table 16.14: Interest expenses disallowed by ERCs primarily on account ofshort-term loans taken by distribution utilities (Rs crore)

2005–06 2006–07 2007–08 2008–09

Haryana 23 60 178 365

Punjab 25 54 254 465

Maharashtra* 163 11 143

Rajasthan 313 353 NA NA

Uttar Pradesh 80.41 – 505

Sources: Forum of Regulators/Crisil Infrastructure Advisory’s Report on Assessment ofReasons for Financial Viability of Utilities.

Notes: *For MSEDCL; NA – Not available.

Delays in payments for power purchase

Utilities have been delaying payments on account of power purchase. While thereis no direct evidence of such delays, a reasonable sense of such delays can be gaugedfrom the payments outstanding to state-owned generating companies, transmissioncompanies and trading companies (see Figure 16.20). About 75 per cent of theincrease in outstanding payments is accounted for by UP. But outstandingpayments have also doubled in states such as Gujarat, Madhya Pradesh,Maharashtra and Haryana.

Figure 16.20: Debtors for sale/transmission of power for state-ownedgeneration, trading and transmission companies (Rs crore)


4500040000350003000025000200001500010000

50000

2005–06 2006–07 2007–08 2008–09

24609 26958

33771

41700 2005–06 2008–09200001500010000

50000

Har

yan

a

Jam

mu

& K

ash

mir

Raj

asth

an

Utt

ar P

rade

sh

Kar

nat

aka

Gu

jara

t

Mad

hya

Pra

desh

Mah

aras

htr

a


How are the other states performing better?

States such as Chhattisgarh, Gujarat, HP, Kerala, West Bengal and Orissa haveeither exhibited stable financial performance or have reduced their financial losses.Kerala, West Bengal and HP have negligible agriculture consumption(see Table 16.4). Kerala and HP have a favourable power purchase mix, with50 per cent of Kerala’s installed capacity and 75 per cent of HP’s installed capacitybeing hydro.29 Further, the SEB in HP also has a substantial amount of surpluspower after accounting for the state’s power consumption. Thus, favourableconsumer mix and demand supply position plays an important role in the betterperformance of SEBs/utilities in these states.

Chhattisgarh too has low agriculture consumption (at 11 per cent in 2008–09).These states also have lower power purchase costs; with these costs accounting for58 per cent to 67 per cent of total costs. With Chhattisgarh being coal-rich, thermalpower is available cheap. This power is sold at market rates, adding to the revenuesof the SEB. Thus, despite the inefficiency in terms of high and rising AT&C losses,the state has been amongst the better performers.

What is clear from the above is that though some SEBs/Utilities may be inefficient(in terms of AT&C losses or expenditure patterns); factors such as favourableconsumer mix, favourable demand supply position, and abundance of resourceshelp these SEBs/Utilities overcome the losses incurred due to their inefficiency.Skewed tariffs (see Table 16.9) further work to the advantage of utilities in thesestates. Gujarat appears as an exception and has been amongst the better performersbecause of the substantial reduction in AT&C losses, tariff revisions30, restriction ofannual subsidies, and timely payment of subsidies.

Where are financial losses headed?

It is important to understand the future course of losses because the finances ofmany state governments may not be able to bear the burden of these losses andbanks may not have an unending appetite to finance them at the guarantee of suchstate governments. Further, if the losses persist and keep increasing, banks may findthemselves at risk as the debt servicing ability of utilities would be under seriouspressure. The rising losses are also a concern, given the expected surge in powergeneration capacity in the country in the next few years; from 143877 MW at theend of 2009–10 to 240963 MW at the end of 2013–14 (see Figure 16.21). The shareof the private sector would increase from 11 per cent to 28 per cent of the totalcapacity during this period. Unless the solvency of the distribution business isrestored with urgency, it is unlikely that the utilities will be able to sustain paymentsfor this additional capacity. Back of the envelope computations indicate that lossesof utilities would range between Rs 93,000 crore to Rs 1,50,000 crore in 2012–13.


These losses and the interest burden of short-term borrowings for meeting themwould together account for 1 per cent to 1.6 per cent of the country’s GDP in thisyear (see Table 16.15).

Table 16.15: Estimated financial losses of utilities in 2012–13 (Rs crore)

2008–09 2012–13

Business Higher Higher Tariffs Higher AT&Cas usual annual AT&C match loss reduction

increase loss costs & tariffsin tariffs reduction match costs

AT&C loss (%) 28.44 24.44 24.44 20.44 24.44 20.44

Average tariff 3.66 4.62 5.36 4.62 4.98 4.98

Average cost of supply 3.40 4.98 4.98 4.98 4.98 4.98

Average revenue realized(without subsidy) 2.62 3.49 4.05 3.68 3.76 3.96

Loss per unit(without subsidy) 0.78 1.49 0.93 1.30 1.22 1.02

Commercial losses 148829 92941 130303 121900 101950

Interest for short-term loans 17859 11153 15636 14628 12234

Total losses fromdistribution sector 166688 104094 145939 136529 114183

Ratio of commercial

losses to GDP 1.6% 1.0% 1.4% 1.3% 1.1%

Source: IDFC analysis

General assumptions

– Increase in average cost of supply: 10 per cent p.a.

– Units input in 2012–13: 1001970 MU, computed by taking a 10 per cent increase inenergy input over 2011–12 (estimated using energy availability projected in 17th EPSand transmission losses of 4 per cent)

– GDP in 2012–13 at market prices: Rs 9348857 crore as projected by the GOI’s HighPowered Expert Committee for Estimating the Investment Requirements for UrbanInfrastructure Services

– RoI for short term loans: 12 per cent

Case-specific assumptions

– Business as usual: Tariff increase of 6 per cent p.a., reduction in AT&C losses of1 percentage point p.a.


– Higher annual increase in tariffs: Tariff increase of 10 per cent, reduction in AT&Closses of 1 percentage point p.a.

– Higher AT&C loss reduction: Tariff increase of 6 per cent p.a., reduction in AT&C lossesof 2 percentage point p.a.

– Tariffs keep pace with costs: Tariffs equal average cost of supply, reduction in AT&Closses of 1 percentage point p.a.

– Higher AT&C loss reduction and tariffs keep pace with costs: Tariffs equal average cost

of supply, reduction in AT&C losses of 2 percentage point p.a.

Figure 16.21: Private sector will lead future capacity addition in India (MW)

Sources: Planning Commission, Central Electricity Authority, Infraline, IDFC analysis

Financial viability of the sector requires increase in tariffs and reduction inAT&C loss levels

In the wake of the above analysis, turning around the distribution sector is possibleby three measures: 1. increase in tariffs, 2. reduction in AT&C losses, and3. reduced power purchase costs. Back-of-the-envelope calculations under thesethree scenarios indicate the following:

Increase in tariffs

If only tariffs were to be increased to eliminate subsidies and bridge the entire revenuegap for the distribution business at the 2008–09 level, the all-India average tariffwould need to increase by 30 per cent from the 2008–09 level.

Reduction in AT&C losses

The R-APDRP targets the reduction of AT&C losses to 15 per cent in urban and inhigh-density areas by July 2013. At this level of AT&C loss (for the country), ARRwithout subsidy in 2008–09 would have increased to Rs 3.20/kWh, thereby reducing

300000

250000

200000

150000

100000

50000

0

2009–10 2011–12(T) 2011–12(E) 2013–14

Public sector Private sector

127683177898 156818 173428

16194

2537130125

67535


the revenue gap to Rs 0.20/kWh. A tariff hike of 6 per cent would then suffice toeliminate this revenue gap.

Reduction in power purchase costs

Given the ACoS of Rs 3.40/kWh in 2008–09, it can be estimated that powerpurchase costs amount to Rs 3.03/kWh. A reduction in this cost can prove crucialfor improving the financial viability of the utilities. Trends in bids for Ultra MegaPower Projects (UMPPs) indicate that power can be made available at competitiveand lower rates than is currently the case (see Table 16.16). Assuming a scenariowhere power can be procured at the tariff for the Krishnapatnam UMPP(the highest tariff amongst the UMPPs) and normative transmission charges areRs 0.22/kWh, the ACoS would amount to Rs 2.92. This would reduce the revenuegap by over 60 per cent to Rs 0.30/kWh. A tariff hike of 10 per cent would thensuffice to eliminate this revenue gap.

Table 16.16: Tariff trends in UMPP bids

Name of UMPP Levelised tariff (Rs/kWh)

Mundra, Gujarat 2.264

Sasan, Madhya Pradesh 1.196

Krishnapatnam, Andhra Pradesh 2.333

Tilaiya, Jharkhand 1.770

Source: Central Electricity Authority

CONCLUSION

Contrary to popular belief, AT&C losses are not the raison d’etre for the worseningfinancial health of the power distribution sector. Overall AT&C loss levels, thoughhigh in absolute terms, have shown improvement over time. Analysis indicates thatthe sector has been unable to cope with the significant increases in power purchasecosts on account of inadequate tariffs. Power purchase costs have increased primarilydue to expensive short-term power purchase. But tariff revision has not kept pacewith this increase. In some states, tariffs have not been revised for several years.In others, poor information base of utilities, non-availability of audited accounts,inefficiency of utilities, absence of truing-up, and inadequate governance has marredtariff revisions. Sometimes, cost recovery has been postponed to future years byresorting to the creation of ‘regulatory assets’.

Deeper analysis indicates that eight states have shown the worse trends as far asrising commercial losses are concerned. These are UP, Punjab, Karnataka, Haryana,MP, Rajasthan, TN and AP. Poor governance and inefficiency of utilities are the


main reasons for the rising losses in these states. The rising losses are being financedby state governments by way of subsidies and by the financial system in the country.But subsidy payments by many state governments are inadequate and irregular.The situation is such that utilities are caught in the vicious cycle of increasing costs,rising revenue deficits, rising short-term borrowings to meet these deficits, andconsequent increase in costs that are not allowed to be recovered through tariffs.As a result, utilities have been delaying payments against power purchase and nowthere is evidence of defaults by some utilities for such payments.31 More recently,utilities have started resorting to higher load shedding to avoid the burden of extrapower purchase costs32 and to prevent their financial position from vitiating further.

If urgent steps are not taken to drastically improve the governance of the sector andimprove the efficiency of utilities, the sector will head towards insolvency and futurecapacity addition plans may get jeopardized. State governments are clearly not in afinancial position to support the sector in the long run. A bigger and grave concernis the impact of this situation on the financial system of the country, which wouldget affected not only because of its exposure to the distribution sector but also becauseof the debt servicing by generation project developers whose cash flows are dependenton payments from distribution utilities.

Manisha Gulati


ANNEXURE

List of distribution utilities referred to in the note

Andhra Pradesh

Central AP: Andhra Pradesh Central Power Distribution Company Ltd

Eastern AP: Andhra Pradesh Eastern Power Distribution Company Ltd

Northern AP: Andhra Pradesh Northern Power Distribution Company Ltd

Southern AP: Andhra Pradesh Southern Power Distribution Company Ltd

Assam

Central Assam: Central Assam Electricity Distribution Co. Ltd

Lower Assam: Lower Assam Electricity Distribution Co. Ltd

Upper Assam: Upper Assam Electricity Distribution Co. Ltd

Arunachal Pradesh

Arunachal Pradesh: Department of Power, Arunachal Pradesh

Bihar

Bihar: Bihar State Electricity Board

Chhattisgarh

Chhattisgarh: Chhattisgarh State Electricity Board

Delhi

North Delhi Power Limited (NDPL)

BSES Rajdhani Power Limited (BRPL)

BSES Yamuna Power Limited (BYPL)

Gujarat

Dakshin Gujarat: Dakshin Gujarat Vij Co. Ltd

Madhya Gujarat: Madhya Gujarat Vij Co. Ltd

Paschim Gujarat: Paschim Gujarat Vij Co. Ltd

Uttar Gujarat: Uttar Gujarat Vij Co. Ltd

Torrent Ahmedabad: Torrent Power, Ahmedabad

Torrent Surat: Torrent Power, Surat

Haryana

Dakshin Haryana: Dakshin Haryana Bijli Vitran Nigam Ltd

Uttar Haryana: Uttar Haryana Bijli Vitran Nigam Ltd


Himachal Pradesh

Himachal Pradesh: Himachal Pradesh State Electricity Board

Karnataka

Bangalore: Bangalore Electricity Supply Company Ltd

Chamundeshwari: Chamundeshwari Electricity Supply Company Ltd

Gulbarga: Gulbarga Electricity Supply Company Ltd

Hubli: Hubli Electricity Supply Company Ltd

Mangalore: Mangalore Electricity Supply Company Ltd

Jharkhand

Jharkhand: Jharkhand State Electricity Board

Kerala

Kerala: Kerala State Electricity Board

Madhya Pradesh

Madhya MP: MP Madhya Kshetra Vidyut Vitran Co. Ltd

Paschim MP: MP Paschim Kshetra Vidyut Vitran Co. Ltd

Purv MP: MP Purv Kshetra Vidyut Vitran Co. Ltd

Maharashtra

BEST: Brihanmumbai Electric Supply & Transport Undertaking

MSEDCL: Maharashtra State Electricity Distribution Co. Ltd

Reliance Mumbai: Reliance Infrastructure Limited – Distribution Business

Manipur

Manipur: Electricity Department, Manipur

Meghalaya

Meghalaya: Meghalaya State Electricity Board

Nagaland

Nagaland: Department of Power, Nagaland

Orissa

Central Orissa: Central Electricity Supply Utility of Orissa Ltd

Northern Orissa: Northern Electricity Supply Company of Orissa Ltd

Southern Orissa: Southern Electricity Supply Company of Orissa Ltd

Western Orissa: Western Electricity Supply Company of Orissa Ltd


Punjab

Punjab: Punjab State Electricity Board

Rajasthan

Ajmer: Ajmer Vidyut Vitran Nigam Ltd

Jaipur: Jaipur Vidyut Vitran Nigam Ltd

Jodhpur: Jodhpur Vidyut Vitran Nigam Ltd

Sikkim

Sikkim: Energy & Power Department, Government of Sikkim

Tamil Nadu

Tamil Nadu: Tamil Nadu Electricity Board

Tripura

Tripura: Tripura State Electricity Corporation Ltd

Uttar Pradesh

Dakshin UP: Dakshinanchal Vidyut Vittran Nigam Ltd

Madhya UP: Madhyanchal Vidyut Vitran Nigam Ltd

Poorv UP: Poorvanchal Vidyut Vitran Nigam Ltd

Paschim UP: Pashchimanchal Vidyut Vitran Nigam Ltd

Uttarakhand

Uttarakhand: Uttrakhand Power Corporation Ltd

West Bengal

WBSEDCL: West Bengal State Electricity Distribution Company Ltd

NOTES

1. AT&C losses reflect the technical losses incurred in transmission and distribution ofelectricity as well as the commercial losses arising out of theft and deficiencies in billingand collection.

2. For the purpose of this note, distribution utilities refer to utilities selling power directlyto consumers and include State Electricity Boards (SEBs), State Power Departmentsand distribution companies (Utilities).

3. Projected by the Thirteenth Finance Commission at 2008 tariffs

4. Cash profit is defined as profit after tax + depreciation + miscellaneous expenses writtenoff + deferred tax. The definition of cash losses needs to be understood accordingly.


5. Discussions with experts indicate that the trend in loss reduction would remain thesame even with the availability of more reliable information.

6. 24 per cent in 2006–07 and 22.87 per cent in 2008–09

7. This is corroborated by the Tamil Nadu Electricity Regulatory Commission’s opinionin the 2010–11 tariff order that poor metering of agriculture consumption leads to grossunderestimation of the total capacity of agricultural electricity connections in the state.Therefore, the state government subsidy towards agricultural consumption determinedon the basis of this capacity is vastly inadequate to cover the actual expenditure incurredby the Tamil Nadu Electricity Board.

8. Tariff order issued by Madhya Pradesh Electricity Regulatory Commission for FY 2010–11

9. For more information, read the Report on Implementation of Accelerated PowerDevelopment and Reforms Programme (APDRP), Ninth Report, Standing Committeeon Energy (2005–06), Fourteenth Lok Sabha, available at http://164.100.24.208/ls/CommitteeR/Energy/9rep.pdf

10. There has been news of re-tendering of projects with winning bidders being relegated tothe background or being dismissed. Contractual issues have led to some major andexperienced companies not being able to bid. Bid values are being questioned as is theability of some IT companies to execute projects in such values. The time frame of18 months is proving to be unrealistic as the utilities are not ready or equipped (by wayof expertise) to absorb and drive the project. Further, the pace of decision making is notin line with the tight timelines of the program.

11. UI is a mechanism developed to improve grid efficiency and grid discipline by imposingcharges on those who defer from their scheduled power generation or drawal.

12. Available at http://www.mop.rajasthan.gov.in/downloadpdf/noteonpoewrsector.pdf,accessed on 18 January 2011

13. This data pertains to August 2009 and has been used to give a sense of the price differentialbetween domestic and imported coal. (Source: Planning Commission)

14. Tariff order issued by Tamil Nadu Electricity Regulatory Commission for Tamil NaduElectricity Board for 2010–11

15. Tariff order issued by Tamil Nadu Electricity Regulatory Commission for Tamil NaduElectricity Board for 2010–11

16. Available at http://www.mop.rajasthan.gov.in/downloadpdf/noteonpoewrsector.pdf,accessed on January 18, 2011

17. In MP, the state government laid down the distribution loss reduction trajectory for theutilities for the period FY 2006–07 to FY 2010–11 in December 2006.

18. Judgement dated May 26, 2006 as referred to in PSERC’s Tariff Orders for FY 2007–08and FY 2008–09


19. Forum of Regulators/Crisil Infrastructure Advisory’s Report on Assessment of Reasonsfor Financial Viability of Utilities

20. Tariff order issued by the Punjab State Electricity Regulatory Commission for the PunjabState Electricity Board for 2009–10.

21. Tariff order for the distribution utilities for 2008–09

22. Tariff orders issued for the Punjab State Electricity Board for 2008–09 and 2010–11

23. Forum of Regulators/Crisil Infrastructure Advisory’s Report on Assessment of Reasonsfor Financial Viability of Utilities

24. Tariff order issued for the distribution utilities for 2010–11

25. Order on Multi-year Aggregate Revenue Requirement for the year 2007–08 and2008–09 for the distribution utilities

26. Available at http://www.mop.rajasthan.gov.in/downloadpdf/noteonpoewrsector.pdf,accessed on January 18, 2011

27. Tariff order for Tamil Nadu Electricity Board for 2010–11

28. Available at http://www.apcentralpower.com/ARR/Replies%20ARR%20filings%20FY%202011–12/Replies% 20to%20Objections%20on%20ARR%20filings%20FY%202011–12.doc accessed on April 7, 2011

29. As in December 2010; Source: Power Scenario at a Glance, Jan 2011, Central ElectricityAuthority

30. This does not imply that the other states recording better performance have not seentariff revisions. Tariff revisions have taken place as and when necessary. However, incase of states such as HP, Kerala and Chhattisgarh which have revenue surplus or havevery low revenue deficits, tariff revision is not the prime concern.

31. The MP ERC in the tariff order issued for distribution utilities in MP for 2009–10 hasobserved that the losses incurred by utilities have not only wiped out their entire equitycapital but have also forced them to default against payments due from them.

32. Transcript of Power Finance Corporation Limited’s Investors’ Conference Call held onJanuary 17, 2011 and available at http://www.pfcindia.comPFCTranscript_17012011.pdf


1. INTRODUCTION

India, chugging along its self-defined high growth trajectory to achieve inclusiveand sustainable development, is faced with the multiple challenges of ensuring energysecurity, overcoming energy poverty and defining a low-carbon development path.To power its economic growth, the country has traditionally depended primarilyon conventional fuel which is also likely to remain the mainstay for futuredevelopment. However, despite sitting on large coal reserves India has been recentlyfacing large supply disruptions, and domestic coal production has failed to keeppace with the rapid build-up in demand. To add to this, the conventional thermalenergy market is going through convulsions the world over. Faced with criticalchallenges, India has to look out for and harness alternative energy sources to secureits development objectives.

Blessed with 300 sunny days a year and receiving an average hourly radiation of200 MW/sq km, the country is well placed to overcome its key challenges by harnessingthe enormous solar potential. Around 12.5 per cent of the land mass, or 413,000 sq km,could be used for harnessing solar energy.1 Recognising this, the Government ofIndia (GOI) included solar energy as a key mission under the National Action Planon Climate Change and formally launched the Jawaharlal Nehru National SolarMission (JNNSM) in 2010. The JNNSM is a major initiative of the GOI to ramp upits solar power generation capacities in a phased manner and seeks to provide impetusto the development of a huge solar market in India. The mission has set out toachieve 1000 MW of grid-connected solar projects at 33 kV and above (with equalshare of solar photovoltaic or SPV and concentrated solar thermal or CST),100 MW of rooftop and small solar projects, and 200 MW of off-grid projects by

INDIA SOLAR POLICY:Elements Casting Shadowon Harnessing thePotentialNovember 2011

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2013 (Phase I); 4000 MW (and 10,000 MW on the uptick) grid-connected and 1000MW off-grid projects by 2017 (Phase II); and 20,000 MW grid-connected and 2000MW off-grid projects by 2022 (Phase III). The JNNSM aims to achieve 20 millionsolar lighting systems for rural areas and increase the solar thermal collector area to15 million sq metres by 2017 and 20 million sq metres by 2022.

To kickstart Phase I, the solar policy (in JNNSM) put forth a mechanism of ‘bundling’relatively expensive solar power from grid-connected projects, selected on pre-defined criteria under JNNSM, with equivalent capacity of power from theunallocated quota of the GOI generated at NTPC coal-based stations, which isrelatively cheaper. This ‘bundled power’ would be sold by NTPC Vidyut VyaparNigam Ltd (NVVNL) to the distribution utilities at Central Electricity RegulatoryCommission (CERC) determined prices. The Mission provided for NVVNL toprocure the solar power by entering into a power purchase agreement (PPA) withthe selected solar power developers (SPDs) connected to the grid at a voltage levelof 33 kV and above before March 2013. The solar procurement price initiallyproposed for Phase I was Rs 17.91/unit. Further, considering that some of the grid-connected solar projects were already at an advanced stage of development, theguidelines for migration of projects from their respective existing arrangements tothe ones envisaged under JNNSM were also issued. The projects to be selected underthis scheme provide for deployment of both solar PV technology projects and solarthermal technology projects in a ratio of 50:50, in MW terms. Subsequently,guidelines for selection of new grid-connected solar power projects (SPV and CST)were issued in July 2010 by the Ministry of New and Renewable Energy (MNRE).

Further, the JNNSM provides for promotion of manufacturing and developmentof solar technology by mandating domestic content in projects in Phase I with theobjective of establishing India as a global leader in solar energy, and also providesfor promotion of off-grid and small solar applications with the objective of scalingup solar deployment and meeting energy requirements in rural and remote areas.

In addition to the impetus provided at the central government level through JNNSM,several states like Gujarat, Rajasthan and Karnataka have come out with their ownsolar policies, providing for preferential tariffs and other deployment support (whichinclude provisioning of infrastructure, wasteland for development, evacuationinfrastructure and solar parks).

At the close of Batch I of Phase I, 37 projects totalling 620 MW (listed in Appendix 1)were allotted under the JNNSM (comprising 30 SPV projects totalling 150 MW andseven CST projects totalling 370 MW), 84 MWs of projects brought under the foldof the migration scheme, about 716 MWs of solar projects allotted under the GujaratPolicy (Appendix 2) and several others in various states under state policies.


At a time when project selection for the first batch of JNNSM Phase I has got over,as also the bidding for the second batch of Phase I, it is prudent to take stock of thedevelopments and assess the effectiveness of the solar policy for achieving the strategicobjectives. The questions to ask are:

• Does the JNNSM inspire confidence in facilitating speedy deployment of solarcapacity and meeting its desired objectives?

• Is the present solar policy really aligned with the strategic vision of thegovernment?

This note explores these questions in the light of the developments of the first batchof JNNSM Phase I and the provisions of the solar policies in India and the experiencesin other countries.

2. ISSUES AFFECTING EFFECTIVE HARNESSING OF SOLAR POTENTIAL

On the face of it, with the large allotment of capacities under the JNNSM, it appearsthat the mission is off to a successful start and India has indeed put together acomprehensive solar policy, a major improvement over the previous guidelines, tomake the country the mecca of solar development and deployment. However, asthe India Solar programme moves from policy to implementation, several issuesand concerns have surfaced, proving to be major hurdles for serious solar powerdevelopers and lenders. In fact, several projects allotted may not get deployed.

Financing and bankability of solar projects under the JNNSM is emerging to be amajor concern, arising from several issues in the policy or inadequacies therein.Thus, despite an apparently improved policy and support provided, solar powerdevelopment remains expensive and risky for developers and lenders. These issuesof concern are discussed here:

a. Auctioning or reverse bidding

Initially, with the announcement of the JNNSM, solar projects were offered a feed-in-tariff (FiT) or preferential tariff of Rs 17.91/unit to SPV projects and Rs 15.31/unit to CST projects shortlisted in Batch I. However, considering the overwhelmingresponse received for the SPV capacity offered, GOI chose to replace the FiT witha reverse bidding or auctioning mechanism where the fixed capacity of SPV offeredwould be allotted based on least price offered by SPDs and not first come, first servebasis. The auctioning process resulted in allotment of the first 150 MW SPV projectsand 470 MWs CST projects, with 37 SPDs emerging as winners comprising 30 SPVprojects and 7 CST projects. The auctioning led to huge discounts over the initialFiT, where the weighted average of the quoted tariffs for SPV was Rs 12.16/unitand CST was Rs 11.41/unit implying an average of 32 per cent and 25 per cent


respectively of the CERC-declared FiTs. However, it may be noted that some of thegains due to auctioning would be offset by higher tariffs paid to the 84 MW projectsqualified under the migration scheme as compared to the rates offered to theseprojects by state distribution companies (discoms).

Considering the huge savings over the economic life of the projects, the move towardsauctioning does appear to be a great success. However, such huge discount in tariffsover CERC-determined FiT and the ultimate selection of the SPDs have raised anumber of questions regarding the financial feasibility of the projects, hindrancesin financial closure and hence timely completion of the projects. The CERC-determined tariffs included reasonable returns for the SPDs, but offering suchdiscounted tariffs in the face of high financing costs may result in lenders findingthe returns unattractive for a risky business in an immature market. One could alsosuspect that to protect the margins developers may resort to using substandardequipment which could result in sub-optimal performance. Also, the winning listof potential developers has companies with questionable credibility in the solarbusiness. The potential developers include a wool yarn maker, an animationcompany, auto dealer and pipes supplier. In view of this, it is to be seen how manyof the projects achieve financial closure and are commissioned on time. It is indeedthe case that very few projects would be able to get non-recourse financing.

Although the present policy does include penal provisions imposed on SPDs forabandoning projects or underperformance, lenders may prefer to wait and watchdevelopments as they evolve given no precedence of the effectiveness of penalprovisions and the various risks they are exposed to. This is not only going toaffect the deployment of projects in Batch I but also the next tranche of bidding.At the same time, the cost benefits of the auctioning mechanism should not beignored. Strengthening the prequalification criteria of bidders to include priorarrangement with a credible EPC partner and due diligence report on projectviability accompanying bids would somewhat mitigate the risks perceived by thelenders. Unfortunately, the guidelines released by the ministry for Batch II ofPhase I does not strengthen the pre-qualification criteria of the bidders and retainsthe same principles of allocation, except for extending the timeline for financialclosure from 180 days to 210 days from the signing of the power purchaseagreement (PPA).

The present policy also does not provide for any protection from interest-rate risks.At a time when real interest rates are high, a 25-year PPA carries with it the risks ofhigh tariff regime and discoms imposing pressure on the SPD to revisit tariffs wheninterest rates come down. Also, there is no way consumers can get the benefit ofdeclining interest once the PPA is sealed at a higher interest rate.


b. Information on solar resource incidence and performance of technologies

The performance of solar projects and returns thereof are highly dependent on theincidence of solar radiation. Quality solar radiation data with very high degree ofaccuracy and high level of confidence is an essential prerequisite for choice oftechnology, project development and viability of the project. Information on DirectNormal Incidence (DNI) of solar radiation is required for CST and Global HorizontalIncidence (GHI) is required for SPVs. Currently, good quality annual informationwith fairly high degree of accuracy is available, which is good for framing broadpolicies. However, moving towards planning for projects requires seasonal andmonthly information, while project development, assessing project feasibility anddesigning projects require monthly, daily and hourly data with high level ofconfidence. Typical meteorological year data may not be always appropriate as theyare mostly city based and not for remote areas where the project sites are located.Ground measurement of meteorological monthly-daily-hourly data at the regionallevel as well as within a few kilometres of proposed sites need to be collected over astatistically acceptable time period to provide developers and lenders the confidencedesired. Inaccuracy in solar resource estimation affects expected future returns ofthe project. Since the information is backward looking, lenders prefer to beconservative with resources and thus prefer higher probability or ‘P’ levels (whereP50 is average and P90 is high level of confidence but more conservative).

In view of this, although the solar policy is well founded, planning for phased targetsand identification of projects, let alone designing of projects, is definitely not on afirm footing. The fact that equal weights are given to large grid-connected SPV andCST in the absence of adequate information on solar resources on regional and site-specific locations for monthly, daily and hourly variations, raises questions aboutthe effectiveness of the policy. Also, the risks of project selection and design are veryhigh for lenders to feel comfortable.

This resource issue brings up the next concern about the right choice of technologyand size. The annual information shows that few regions in India have high DNIsuitable for CST, but GHI levels are high and spread over several regions and thusmore suitable for SPV. It may be also noted that SPV technology is very flexible inthe context of any topography of land, but CST has to be necessarily set up on flattopography to ensure high levels of efficiency. Also, land requirement is large forgrid-connected SPV projects. Thus, in the absence of adequate information on thecorrelation between the proposed sites and the technology selected by the SPDs, thelenders may find the risks very high and often not commensurate with the returns.Also, the emphasis on grid-connected SPVs in JNNSM compared to smaller off-grid and decentralised SPV applications, as well as the equal emphasis on SPV andCST capacity additions, appear to have weak analytical bases.


There is an urgency to build up in a transparent manner a repository of detailedinformation on solar radiation which, in turn, could be used to substantiate feasibilityand hence bankability of projects. Although the ministry is putting in place50 monitoring stations on the ground for the measurement of solar resources, moresuch on-ground information needs to be rapidly built up and widely disseminatedfor fast development and deployment of projects.

c. Technology risk

As discussed above, technology choice and design is strongly correlated with thequantum, type and variability of solar resource. Besides, solar technologies, be theygrid-connected SPV or CST, are at early stages of deployment and development inIndia, and therefore carry higher risks on applicability and performance. In India,crystalline silicon technology accounts for most of the market and, currently, themarket share of thin-film technology, though fast increasing, is very small (about10 per cent only). Thin-film technology has not reached the efficiency level ofcrystalline solar cells, but could bring down the costs of production considerably.This is the risk of technology obsolescence in an emerging and rapidly developingtechnology segment. CSTs are currently not economically viable the world overand there is very limited information on their performance in India. Lenders arenot comfortable about extending non-recourse finance because of higher levels ofproject construction and operating risks. The risks could be mitigated by buildingup information on the performance of technologies in the light of the resourcesavailable. The effectiveness and appropriateness of the JNNSM rests to a great extenton this information.

d. PPA under JNNSM and financial state of discoms

The PPA for the bundled scheme under JNNSM between the NVVNL and SPDs isa major payment security concern for lenders. This risk arises from the fact thatNVVNL as a trader passes on risks of non-receipt of revenues from discoms forbundled power sales to the SPDs. Poor and worsening financial situation of thestate discoms increases the credit risks for the lenders. Further, few discoms wouldhonour their obligations under PPA for twenty years if costs of solar power comesdown in the next five years. Given that payment default by state discoms is common,lenders do not find PPAs entirely credible and bankable.

Recognising the importance of this concern of lenders, the ministry introduced anadditional payment security scheme for grid-connected solar projects under JNNSM.The government has approved the Payment Security Scheme to facilitate financialclosure of projects under Phase I of the JNNSM by extending Gross BudgetarySupport (GBS) amounting to Rs 486 crore to the ministry in the event of defaults in


payment by the state discoms to NVVNL. The core component of the PaymentSecurity Scheme (PSS) is to create Solar Payment Security Account (SPSA) financedfrom GBS to the ministry for availability of adequate funds to address all possiblepayment related risks in case of defaults by discoms for the bundled power. ThePPAs have payment security mechanism for recovering payments through Letter ofCredit (LOC), an escrow mechanism, and subsequently sale to a third party or evenpower exchange pending bilateral negotiation with the third party. The PaymentSecurity Scheme will be implemented by the ministry with the provision of NVVNLopening the SPSA for this purpose and draw funds as per mechanism/provisions ofthe scheme. The funds for each year shall be allocated by MNRE into SPSA. As perestimates, the Rs 486-crore fund requirement is scheduled for Phase I as:

Table 17.1: Projected deployment of funds in SPSA

Fund deployment Incremental fund Total fundpattern deployment (crore) capacity (crore)

1 Jul 11 1.0 1.0

1 Jan 12 1.0 2.0

1 Jul 12 32.85 34.25

1 Jan13 23.47 58.32

1 Jul 13 58.32 116.64

1 Jan 14 126.39 243.03

1 Jul 14 243.02 466.05

Source: Implementation of a Payment Security Scheme (PSS) for Grid-connected Solar Power

projects under Phase I of Jawaharlal Nehru National Solar Mission during the year 2011–12,

MNRE, GOI, New Delhi, India, 2011

Introduction of this scheme has considerably mitigated the payment risks perceivedby the lenders, but the uncertainty associated with the prospects of the projectsbeyond the first phase of JNNSM and the extremely poor financial situation of thediscoms continue to pose bankability concerns for the lenders.

e. Policy risk beyond Phase I of JNNSM

A prime risk perceived by the developers and lenders is the policy uncertainty relatedto the bundling scheme beyond 2014. The project life is about 25 years, but thebundled scheme as well as the payment security is applicable for projects in Phase I,leaving the future of projects beyond 2014 uncertain. Further, in a situation wherethe power sector is reeling under acute power crisis, rising power supply deficitsand coal supply disruptions, the availability of unallocated power from NTPC coal-


based plants is itself doubtful. Even if such unallocated quota exists and is allocatedfor the bundling scheme, it remains uncertain whether such power would be cheapenough if imported coal at very high prices is used. In fact, considering thephenomenal rise in imported coal prices in the global market and also due to theregulatory changes in coal exporting countries (viz. Indonesia and Australia),generation costs for entirely imported coal-based power in India would probablybe as expensive as solar power (i.e. Rs 10 to Rs 15/unit). This also raises the issuethat grid parity for solar projects may be reached earlier than that perceived inJNNSM. All of these question the validity of the development trajectory mapped inJNNSM and that of the associated provisions.

f. Regulatory risk

The Renewable Purchase Obligations (RPOs) provided for in the Electricity Act2003, the solar-specific RPOs introduced under it, and targets specified throughamendment of the National Tariff Policy, are considered a major push for grid-connected solar in JNNSM. The Renewable Energy Certificates (REC) are consideredan important financing mechanism and incentive for SPDs. Although the marketfor REC has great potential, effective policing of RPOs is required as a prerequisite.Enforcing RPOs is an issue considering that most discoms are state-owned and itbecomes a self-imposed penalty for non-compliance.

Also, under circumstances that costs of solar technology and projects are comingdown rapidly, the regulators would accordingly be revising the floor and forbearanceprices downwards. In fact, only recently, the CERC has revised the floor andforbearance prices of solar REC from Rs 12,000/MWh to Rs 9300/MWh andRs 17,000/MWh to Rs 13,400/MWh respectively. This regulatory uncertainty raisesconcern about the financial viability of the projects. It will be a while before thecosts stabilise and the market for REC really picks up in any meaningful manner.The complexity arises from poor financial situation of the state discoms and theirability to absorb or pass through high cost of renewable energy. The solar policyneeds to take cognizance of these issues associated with RPO and REC whilespecifying the targets and quantifying the benefits.

g. Infrastructure constraint

Solar project sites are mostly located in remote areas and wastelands, which areoften not well connected and are lacking in infrastructure. Under the JNNSM,developers are required to put in place the required infrastructure themselves andalso acquire land, secure water connection, get all clearances and put in place theevacuation infrastructure. This is not only costly and challenging for any developer,but also extremely time-consuming, and adds to the risks of delay in completion of


projects. Often, detailed information about project sites in remote locations is notavailable to the developer at the time of bidding. Creating a database with detailedinformation on the topography and project site, creating a land bank for projects,facilitating or getting all clearances for the developer, providing the necessaryinfrastructure in project sites and support in evacuation infrastructure wouldmitigate substantial risks and go a long way in successful deployment of solar projects.Also, financial support from the Clean Energy Fund could be provided to SPDs forinfrastructure build-up, including evacuation infrastructure, to facilitate solar projectdevelopment and deployment.

h. Other concerns

The JNNSM capacity development and deployment trajectory fails to take cognizanceof the fact that finance companies are bound by exposure limits for the power sector,and renewable energy, including solar, is treated as part of the exposure to power.This is a major obstacle faced by the lending community and solar power deploymentwould face a major financing crunch unless the Reserve Bank of India (RBI) declaresthe solar sector a priority sector for lending or renewable energy is treated separatelyfrom the power sector.

3. INCONSISTENCIES WITH STRATEGIC VISION

a. Equal weight to grid-connected SPV & CST projects

Mandating development of SPV and CST in the 50:50 ratio and thus imposingtechnology reservation would curb efficient market allocation and cost reduction.If the ultimate objective of the India Solar Mission is to create an environment forcompetitive solar energy penetration in the country, then such reservations ontechnology would not be aligned with the strategic vision. JNNSM, in its attempt toencourage both the technologies, is dictating the technology choice rather thanallowing the market to select the most efficient and cost-effective technology forIndian conditions.

SPV is an established technology for large and small size projects, and the cost iscoming down rapidly, while globally the use of large-scale CST for the generation ofelectricity is still a niche strategy. CST so far has been successfully implemented inonly a few locations worldwide. It is indeed the case that northwestern India isamong the list of world regions showing the best solar resource, but the CSTtechnology is not yet mature. The land and water requirement of CST is also veryhigh as compared to SPV. Rajasthan, which has high DNI levels suited to CST, hasbeen reported to have a ‘critical’ water supply status, but still about 86 per cent ofPhase I CSP projects are located in this state. It is common knowledge that costcompetitiveness of solar energy could be achieved by major breakthroughs in


technology. This can only be achieved by a focused approach on Research andDevelopment (R&D). Reservation in technology deployment is unlikely to haveany major impact on this in India. On the other hand, if all the technologies are setto compete against each other, the most appropriate technology will be chosen in acost-effective manner. Thus, auctioning without technology reservation could beadopted for award of projects.

b. Emphasis on large MW size grid-connected SPV projects

The emphasis in the JNNSM on developing MW-size grid-connected SPV projects,instead of primarily focusing on off-grid and decentralised small solar applications,appears to be lacking in strategic vision. Planning for MW-scale CST is still justified,where appropriate, but disproportionate focus on deploying MW-scale grid-connected SPV is definitely questionable. If, in the Indian context, the smallerdecentralised and off-grid applications are more appropriate, then the subsidy orfinancial support should be directed towards the same. The German policy, whichis often hailed as progressive and has played a significant role in Germany havingthe largest cumulative solar capacity in the world, has been primarily promotingsmaller size solar applications. In fact, the country offers higher FiTs for smallerinstallations (e.g. rooftop PV), while the lowest FiTs apply to free-field installations.Germany, despite having much poorer solar radiation than India, went ahead andpromoted development and deployment of smaller SPV applications, while Indiahas focused on large MW-size projects despite having high GHI levels in most regionsof India. Considering the large number of unelectrified households, the large powerdeficit situation, high supply losses, poor grid connectivity and poor financial statusof the discoms, it would be more appropriate to promote decentralised solarapplications. Solar resources being widely spread may have to be promoted in ruraland remote areas on a small scale rather than centralised scale, more particularlykeeping in view the problems of remote areas and weak and inefficient grids. Withpower from conventional fuels becoming more expensive, solar power is likely toachieve grid parity sooner than expected. This would make solar power at thedecentralised or off-grid level more affordable.

Smaller SPV applications could cover remote and rural electrification, street lighting,home lighting systems, integrated solar projects and hybrid stand-alone solar projectsin places where grid supply is poor or absent. The total requirement for solar off-grid and decentralised applications could be very large, and this would provideenough positive impetus to the global solar industry. Large-size grid integratedprojects may not give the desired multilevel benefits as compared to small/mediumsize projects. Thus, keeping in view rural development, rural employment, demand-side management, energy security, land availability, etc. the major focus should be


on channelising subsidy towards development and deployment of small solarapplications so that the rural unelectrified may have access to clean energy at anaffordable price.

c. Mandating domestic content in solar technology

The JNNSM guidelines specify that in the case of solar PV technology, alldeployment under the scheme should use a module manufactured in India inBatch I, and in Batch II even the cells used in deployment should be domesticallymanufactured. In the case of CST, it specifies that 30 per cent of the total projectcost be utilised for domestic equipment. This proposal may appear to protect theinterests of Indian manufacturers and financiers, and give a major thrust todomestic manufacturing accordingly facilitating continuous reduction in cost ofsolar power. Further, it may also appear that given India’s significance as anemerging high growth market, this proposal would encourage international playersto invest in manufacturing in the country. This, in turn, would help build upsustainable manufacturing capacity within the country, thereby creating jobs andsignificant opportunities for lenders and investors. However, the question ariseswhether this is consistent with the comparative advantage of India and alignedwith its other policy objectives.

The fact is that India lacks a robust manufacturing base for solar components andsystems for solar systems. Currently, it does not have any infrastructure for rawmaterial production (polysilicon) and is entirely dependent on imports for the same.The bulk of the SPV industry is dependent on imports of critical raw materials andcomponents—including silicon wafers. The entire SPV value chain shows that Indiadoes not have the comparative advantage up to the wafer-making stage. To reachthe levels of wafer production, it has to produce polysilicon which involves thereduction stage using coke and conventional energy. India does not have enoughcoke for its steel industry and has to depend on imports. Availability of power isitself a major constraint and power is getting more expensive. Also, production ofsilicon, wafers and modules is capital- and not labour-intensive. Further, the bulkof the SPV cost is accounted for by PV modules, while the remaining comprisesbalance of system and construction. Thus, India clearly does not have thecomparative advantage in production of SPV and has little ability to ramp upproduction in a big way, influence breakthrough innovations and bring aboutsignificant cost reductions just on the basis of a domestic solar market. Reductionin SPV costs depend on the size of the global PV market and, most importantly, onresearch breakthroughs. The domestic SPV market is unlikely to have any majorimpact on the global PV market, as the Indian market is small compared to theworld market. The world market in Europe is, however, going through demand


reduction in the wake of the financial crisis. It may be noted that even the Chinesesolar manufacturing industry (see Box 17.1), which has grown many fold ridingon the export market in Europe, is now looking inward to the domestic market,and to export markets in the Asian region. The Indian semi-conductor industryhad been receiving government support for a very long time and if it really hadthe comparative advantage it would have done well with wafer productionand solar cell manufacturing from the waste of wafer manufacturing like theChinese did.

Indian solar cell and module manufacturers are overwhelmingly in favour ofdomestic content rules as they realize that it is difficult for them to compete withthe much larger and lower-cost Chinese companies, moreso when their exportmarket in Europe is going through convulsions and a slowdown. The United Stateshas strongly opposed India’s local content requirements specified in JNNSM as itis creating an export hurdle to their solar companies like Sunpower and FirstSolar. It is noteworthy that the Indian installers and developers have also opposedthis local content requirement as this results in reduced choice for suppliers andhigher costs.

There is no denying that developing manufacturing capability strengthens securityof supply, but there could be other ways of encouraging manufacturing and at thesame time ensuring that the benefits of incentives extended to them are not reapedby other countries. The strategic vision of India should be to encourage high efficiencyand low cost immediate delivery of power on a globally competitive basis to benefitthe common man and consumers, and to discourage monopolies and increase insubsidy burden, as also restrictive trade practices. In this regard, reservation ofdomestic content in modules and cells is unlikely to meet the desired objectives andmay even result in no interest or ability on the part of domestic manufacturers toreduce costs and address possibilities of time overruns in the absence of adequatemanufacturing capability.

Creating domestic demand may not be necessary to encourage manufacturing.In fact, in the solar space, manufacturing has received encouragement for a longtime—even well before the focus shifted towards solar deployment. Thus, insteadof linking domestic content in deployment, the government should continue toprovide financial support wherever the comparative advantage exists in the entirevalue chain of SPV and CST, and also increase the spend on R&D. Germany andmany other countries have spent large amounts on R&D for a long time. Capitaland other subsidies could also be extended to manufacturing as long as the same ispassed on to the SPD through the equipment supplied to them and not passed on inexports in other countries.


4. HAVE STATE SOLAR POLICIES DONE BETTER?Besides the GOI initiative with JNNSM, several states have formulated their ownsolar policies to attract investments in the solar space in their states. With thepreferential tariff abandoned under the JNNSM, and replaced by the reverse biddingscheme for selection of SPDs, developers have turned to state-level policies. Moststates have introduced their own FiT, which is kept between the CERC-specifiedtariff and the average bid tariff under JNNSM, to attract investments in the state.

Gujarat, Rajasthan and Karnataka have already come up with their own solar policies,and several other states like Andhra Pradesh and Maharashtra are in the process offormulating their own policies. Gujarat was the first to introduce a solar policy in2009, even before JNNSM was introduced by GOI. It was hailed by SPDs as aprogressive solar policy, and with the Government of Gujarat demonstrating itscommitment to development of renewable energy, the state over and above JNNSMhas allotted 716 MW of solar capacity against an initially-declared target of500 MW and signed PPAs for this capacity with 34 SPDs. The share of SPV and CSTin the 716 MW capacity is 365 MW and 351 MW respectively (see Appendix 2).Many developers have also expressed interest in setting up manufacturing capacityin the state which expects to bring in a massive investment of about Rs 12,000 croreover the next few years.

The Gujarat model offers procuring solar power from developers at a fixed tariff, ala the German and the Spanish model (see Box 17.1). However, unlike the Germanmodel, the focus is not so much on developing smaller off-grid and rooftop capacitiesbut the emphasis is more on grid-supplied capacity addition. The state also facilitatesland acquisition, clearances and provision for evacuation and other infrastructure.The state has also identified land banks for solar power development from wastelandareas available in the state. This would not only provide for productive use ofwasteland areas but also bring in development in these areas. Taking intoconsideration the rapid development in solar technology bringing down costs andtaking note of the need for preferential tariffs in the initial years till grid parity isachieved, Gujarat offers CERC-approved higher tariff for the first 12 years and amuch lower tariff for the remaining 13 years. The applicable tariff as recentlyapproved by CERC is for SPV Rs 15/kWh for the first 12 years and Rs 5/kWhsubsequently, and for CST it is Rs 11/kWh for the 12 years and Rs 4/kWh subsequently.

Rajasthan, which is also planning to develop more than 500 MW over the next fewyears, over and above JNNSM, on the other hand, has adopted an approach similarto the JNNSM. The policy offers all possible routes for the SPDs, from grid-connectedto off-grid, and has also provided for bundling arrangements and auctioning routesfor the state to procure power. Rajasthan, with its huge solar potential, is in any case


a very attractive destination for investors. The state has also already strengthenedthe transmission network, more specifically in regions where solar potential isrelatively high. Karnataka introduced the policy with the intent to harness morethan 200 MW of solar capacity, in addition to JNNSM, and has proposed to adoptthe competitive bidding route for procurement of solar power at a discountedtariff. It is expected that soon most of the states would go for the auctioning route,as the cost burden of fixed FiT is quite high as more capacities are added andconsumers are provided with subsidised power because of political considerations.The experience of Spain is a case in point, where recent reduction in FiT consequentto the financial crisis has seen a major downsizing of solar capacity addition.In these states with high solar potential, substantial capacity addition may alsosee annual capping of additional solar capacity if transmission capacity fails tokeep pace.

Notwithstanding aggressive policies introduced and large numbers of PPAs andcapacity allotted, projects in these states may actually get delayed due to many reasons.Several projects may be postponed because of delay in financial closure as lendersand developers may still consider some of the risks much higher than the returns ina high-financing cost regime. The main concern with the states is the financialweakness of the state-owned discoms with high losses and surviving on subsidyfrom state governments. The other key risk faced by the SPDs is inadequacy ofinformation on solar resources of the level of detail required for effective technologychoice, planning and design of projects. In fact, many developers may decide to payan annual penalty of several lakhs of rupees for delaying their projects, and wait forcosts to drop so that they can get better returns. The risks are many and though statepolicies have been an improvement over JNNSM in some states, it is unlikely thatlarge solar capacity additions would actually fructify over the next couple of years.

With the intent of mitigating the risks perceived by the developers and lenders, andreducing costs of financing as well as facilitating availability of finance, Gujarat andRajasthan have been developing solar parks, other states like Andhra Pradesh are tofollow suit. The solar park concept is similar to that of industrial parks and involvesthe state government identifying areas where several MW-size plants amounting tomore than 1000 MW capacity of solar generation can be established. The stategovernment would provide to the solar park the necessary infrastructure, regulatoryand other governmental support, including special fiscal and financial incentives aswell as facilitating clearances. The costs incurred by the state government would besubsequently recovered from the developers in the park. Solar parks could bedeveloped to accommodate both generators as well as solar manufacturers. The500 MW Charanaka Solar Park in Patan District of Gujarat is being developed, andit is believed that all the projects in the park are on track. Similarly, Rajasthan is in


the process of developing a solar park which could accommodate more than1000 MW. The park in Gujarat is being developed by the GPCL on around2400 hectares of wasteland. It is expected that the solar park would decrease the costof solar power generation due to economies of scale, accelerated development, fiscalbenefits and reduced cost of finance because of reduced risks. The PlanningCommission has approved Rs 210 crore worth of central assistance to the GujaratPark and the Asian Development Bank (ADB) has approved a soft loan of aboutUS$100 million, which includes development of a smart grid for evacuation of power.The two key challenges of availability of finance and financing cost for solar projectshave been mitigated to a great extent with the development of solar parks, whichappear to be a solution to scaling up MW-size solar projects in India. Discussions areon for the creation of a Solar Park Finance Vehicle and other financial tools, supportedby credit enhancement mechanisms by domestic and international governments.

Box 17.1: Solar power: International experience

Germany: German solar policy’s objectives – both explicit and implicit – are amongthe most aggressive in the world. Germany’s planned phase-out of its substantial carbon-free nuclear generation plants, as well as its vulnerability to political uncertainty ofnatural gas supplies from Russia, had exacerbated its energy security concerns: adevelopment that accelerated its support for renewable energy. On the domestic valueaddition front, solar PV has been a major part of Germany’s export-oriented economicdevelopment approach. Germany fixes the price for solar power in the form of feed-intariffs (FiTs) over 20 years. Higher FiTs are offered for smaller size systems, usuallyrooftop, while the least are offered to ground-mounted systems greater than onemegawatt. The quantity is somewhat controlled by imposing a strict annual degressionrate, which is a percentage reduction in FiTs based on the quantity or solar capacityinstalled during the previous year. Due to the recent drop in solar PV prices, Germanyreduced its FiTs twice during 2010. Even then, the annual installed solar PV capacityexceeded 7,400 MWs, equal to about a third of solar capacity addition expected underJNNSM in the coming decade. This translates to a large financial commitment forGermany’s electricity consumers over the next 20 years.

Spain: Spain set the price for solar procurement by offering FiTs for 25 years. However,unlike Germany, it also fixed the quantity in the form of a cap, to limit the financialimpact on its utilities. To circumvent the issue of project selection, as noted earlier, theSpanish government decided to accept all projects till one year after 85 per cent of theannual cap was met. When the Spanish government increased its FiTs for PV by75 per cent in 2007 to provide a boost to its solar sector, 2,661 MW of PV were installed,exceeding the annual cap of 1,200 MW two times over. The additional capacity of1,461 MW meant a large unexpected financial commitment of a net present value ofseveral billion euros over the next 25 years. Further, the Spanish government had and


continues to keep electricity consumer tariffs low and reimburses utilities for the deficitby paying through the national budget, i.e. taxpayer monies. Spain was one of theworst hit countries during the financial crisis with a high budget deficit. Although thedeficit was not all due to support for renewable energy, the government could notkeep offering high FiTs for solar energy generation (Craig 2009). In September 2008, itslashed the FiTs by 23 per cent. The Spanish PV market collapsed with only 70 MW ofinstalled capacity being added in 2009. Further, the Spanish government is evenconsidering retroactive cuts to FiTs for existing projects, a move that breaches contractsand provides considerable uncertainty to the Spanish solar sector.

California, USA: In December 2010, the California Public Utilities Commission in theUnited States introduced the Renewable Auction Mechanism to procure renewableenergy projects of less than 20 MW, which mainly include solar. Under this mechanism,the required installed capacity will be fixed and projects selected based on least costrather than first come, first served basis at a set FiT (CPUC 2010). The programmeaims to use standard terms and conditions to lower transactional costs and providecontractual transparency needed for effective financing.

China: China enacted its landmark Renewable Energy Law in 2005, which gave highpriority to the development and utilisation of renewable energy. This led to a big pushin renewable energy deployment, especially in the wind sector where China now hasthe largest wind deployment (approximately 45 GW) in the world. However, solarcapacity additions have been relatively small until recently. The total installed solarcapacity by the end of 2010 was approximately 900 MW, with more than half of thiscapacity (520 MW) coming in 2010 alone.

Until 2009, the main push for solar PV in China was in off-grid installations for remoterural communities, the result of Brightness Rural Electrification and TownshipElectrification programmes that started almost a decade ago. In 2009, just prior to theCopenhagen talks, China launched its most ambitious solar deployment program, theGolden Sun initiative, to create some domestic demand for its solar manufacturers inanticipation of the declining international PV demand during the early days of thefinancial crisis. The programme aims to instal approximately 642 MW of grid-connectedand off-grid solar PV at a cost of approximately US$3 billion over the next three years.However, the annual demand is an order of magnitude smaller than China’s PV cellmanufacturing capacity.

China has shown phenomenal growth in production, increasing its PV manufacturingcapacity eighty-fold in the last five years; it was the largest manufacturer in 2010, producingapproximately 13,000 MW, or 48 per cent of the global capacity. The Chinese solar energyindustry began in the mid-1980s, when semiconductor companies started manufacturingsolar cells with waste raw material from wafer production. By 2000, the domestic industrycould fulfil the modest Chinese domestic market demand, although there were very littleexports. Since 2005, China has focused on supplying solar PV equipment to Westerncountries such as Germany, Spain, and the US, where demand was buoyed by generous


purchase support for PV deployment. The Chinese solar industry started developing acomprehensive supply chain, including the manufacture of polysilicon material, ingots,wafers, cells, and modules. This growth in the solar PV industry was concurrent with theChinese government’s push after 2000 to develop a comprehensive semiconductorindustry from chip design to production and testing.

The Chinese government’s pro-export currency policy arguably played a major role inits export-oriented growth. This currency policy (used by Japan in the 1980s and Koreain the 1990s) pegged the Chinese currency to the US dollar, thus preventing it fromappreciating against the same. The Chinese government also offers tax incentives andlow-cost credit and financing from state-controlled banks to its solar industries,advantages enjoyed by other Chinese manufacturing sectors as well. Chinesemanufacturers have also benefited from low labour costs, subsidised electricity rates,and close proximity to raw material suppliers.

In terms of R&D support and strategic goals, the Chinese government has identifiedenergy technologies such as hydrogen fuel cells, energy efficiency, clean coal, andrenewable energy as focuses of the National High-Tech Development Plan (863program), while making utility-scale renewable energy development central to theNational Basic Research Program (973 program). It approved US$585 million jointlyfor the 863 and 973 programs in 2008.

China’s recent purchase support policy initiatives do show promise, but it might behard to raise domestic demand to match its manufacturing capacity, since the relativelyhigh costs will be borne by the electricity consumers and the state exchequer via theNational Renewable Energy Fund.

Source: Ranjit Deshmukh, Ranjit Bharvirkar, Ashwin Gambhir and Amol Phadke.2011. ‘Analysis of International Policies in the Solar Electricity Sector: Lessons for India’,Prayas Energy Group, Pune, India, and Lawrence Berkeley National Laboratory,CA, USA; India, July 2011.

Ranjit Deshmukh, Ashwin Gambhir and Girish Sant. 2011. ‘India’s Solar Mission:

Procurement and Auctions’, Economic & Political Weekly, 46 (28), July 9, 2011.

5. CONCLUDING COMMENTS

The India Solar Mission is a significant improvement over all previous solar policiesformulated by the government, and governments, both at the centre and in thestates, are serious about kickstarting the development of solar energy and harnessingthe huge potential that exists in India. Several countries, including Germany, thathave added huge solar capacities do not have as much potential as India does, andthus there is huge investment opportunity in the solar space in India. However, toattract serious investors, India has to get its act right and put in place a conducivepolicy aligned with the country’s strategic vision and objectives. There are someelements in the present policy acting as hurdles in the way of mitigating the risk


perception, and some of the provisions may not be entirely aligned with the strategicobjectives. However, drawing from international experiences and the lessons fromthe initiatives in India so far, the enormous potential for solar energy in the countrycan be unleashed by overcoming prevailing hindrances.

The key challenge to developing solar projects is availability of finance and highfinancing costs primarily arising from the high risk associated with viability ofprojects and the weak financial status of the state-owned discoms. Although JNNSMattempts to address these, there are clear gaps in the way solar policy has been rolledout so far. The move towards the auctioning approach is indeed useful from theperspective of bringing down the costs at which solar energy is offered by SPDs, buta precondition for successful implementation of the same would be to strengthenthe prequalifying criteria of the potential bidders. Ensuring firm agreements withcredible EPC and detailed project viability reports should be included as prequalifyingcriteria to prevent participation of non-serious players. Also, the bid guarantee bondsshould be deterrent enough to any non-serious participant.

The most important element for mitigating multiple risks is to put in placeadequate and quality information on solar resources and performance oftechnologies in a transparent manner. A lot of attention and investment shouldbe channelised towards creating such a knowledge repository on a priority basisto mitigate risks perceived by the developer and the investor community. Thetargets specified in policies and plans should be based on a strong analyticalfoundation to send out credible signals.

The off-taker risk arising from the high loss and poor financial situation of theprocurers is common to both conventional and non-conventional power generators.In the case of solar energy, the risks are higher because energy is more expensiveand hence risk exposure is higher. The GOI, as additional comfort to the prevailingpayment security mechanisms in PPA, has provided for the creation of a solarpayment security account from the gross budgetary support. Further, financialsupport extended by international development banks (like ADB) and internationalgovernmental support in the form of risk guarantee mechanisms and soft loanswould bring additional comfort to lenders and developers. However, the realdifference can be seen when state governments take necessary steps to improve thefinancial situation of the discoms.

To rapidly scale up solar projects and prevent implementation delays, the governmentshould ensure that delays do not arise with regard to clearances, land acquisition,and inadequacies in infrastructure. A Clean Energy Fund and other similar fundscould be used to support and finance evacuation and other infrastructure essentialfor developing projects.


Technology reservation in any form may not be optimal for allocation of resources.Thus, providing equal focus on SPV and CST has little justification when CST hasnot achieved much success and SPV has made significant strides in bringing downcost of solar energy. Ideally, for MW-scale projects, auctioning without technologyreservation should be the right approach to ensure harnessing the most efficienttechnology in a cost-effective manner. Also, mandating domestic content for solarprojects is sub-optimal. Creating a domestic market for the manufacturing sector,which is not large enough to bring about reduction in costs and boost technologyR&D, may actually lead to adverse market situations and converse incentives.Moreover, incentives to the manufacturing sector should be extended to those aspectsof the value chain where there is comparative advantage. As the deployment ofsolar projects picks up, the stimulus will automatically flow to the manufacturingsegments. At this stage of development in the country, when there is more thanadequate capacity globally to source technology at economical terms, it makes littlesense to mandate domestic component in project development.

Finally, excessive emphasis on MW-size projects may not be appropriate for fasterand greater penetration of solar technology in India. Further, given the priorities ofthe government to eradicate energy poverty and provide energy access to all, andgiven the regional spread of solar resource availability in India, it would be moreuseful to promote smaller size off-grid and rooftop projects. This does not in anyway imply that MW-size projects should not be promoted, but the focus shouldshift more towards the smaller-sized projects. This would not only unleash a largeuntapped demand and huge potential for SPV technology but in the process createa huge market for SPV technology. The German model where higher FiT is offeredto smaller projects compared to larger projects could be looked into for itsapplicability to India. Such focus on smaller-sized projects would also help channelsubsidy better, release subsidies due to migration from diesel-based captivegeneration and mitigate the large offtaker risks prevailing. As the grid gets extended,many of these smaller installations would be able to also provide energy to the grid,and with well-planned caps on in-firm capacity addition the problem of congestionand excessive financial liability could also be addressed.

It is therefore clear that the gaps in the prevailing policy are few but quite critical foreffectively unleashing the solar potential in India. The solutions are widely recognisedand need to be prioritised so as not to lose the momentum created by JNNSM andstate initiatives, and ensure that India emerges as a global destination for investmentin solar energy.

Sambit Basu


APPENDIX 1

Table 17.2: List of projects selected under migration scheme of JNNSM

Sr. Name of applicant State Capacity Whetherno. of the solar PV

plant or solar(MW) thermal

1 Maharashtra State Power GenerationCo. Limited, (MAHAGENCO), Mumbai Maharashtra 4 Solar-PV

2 Clover Solar Pvt Ltd, Mumbai Maharashtra 2 Solar-PV

3 Videocon Industries Ltd, Mumbai Maharashtra 5 Solar-PV

4 Enterprises Business Solutions, USA Punjab 5 Solar-PV

5 Azure Power (Punjab) Pvt Ltd, Amritsar Punjab 2 Solar-PV

6 Acme Tele Power Limited, Gurgaon Rajasthan 10 Solar-Thermal

7 Comet Power Pvt Ltd, Mumbai Rajasthan 5 Solar-PV

8 Refex Refrigerants Limited, Chennai Rajasthan 5 Solar-PV

9 Aston Field Solar (Rajasthan) Pvt Ltd Rajasthan 5 Solar-PV

10 Dalmia Solar Power Limited, New Delhi Rajasthan 10 Solar-Thermal

11 Entegra Ltd, Ansal Bhawan, New Delhi Rajasthan 10 Solar-Thermal

12 Entegra Ltd, Ansal Bhawan, New Delhi Rajasthan 1 Solar-PV

13 AES Solar Energy Pvt Ltd, Gurgaon,Haryana Rajasthan 5 Solar-PV

14 Moser Baer Photo Voltaic Ltd, New Delhi Rajasthan 5 Solar-PV

15 OPG Energy Pvt Ltd, ChennaiTamil Nadu Rajasthan 5 Solar-PV

16 Swiss Park Vanijya Pvt Ltd Rajasthan 5 Solar-PV

Total 84

Source: MNRE (2010). ‘List of Project Developers Qualified for Migration to Jawaharlal Nehru

National Solar Mission’, Government of India, New Delhi, India.

NVVNL signed MoU with the above 16 project developers to set up to 84 MW capacity solar

power projects under migration scheme, comprising 54 MW capacity through SPV and

balance 30 MW through STP.

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APPENDIX 2

Table 17.4: Allotment of solar capacities in Gujarat

Sr. no. Name of company Allotment, MW

1 AES Solar Company Pvt Ltd, USA 15

2 Astonfield Solar (Gujarat), USA 25

3 Azure Power Ltd, USA 15

4 Common Wealth Business Technologies, UK 10

5 Dreisatz GmbH, Germany 25

6 Environmental Systems Pvt Ltd, Mumbai 5

7 Euro Solar Ltd, Bhachau 5

8 JSW Energy, Mumbai 5

9 KRIBHCO, Surat 5

10 Lanco Solar Pvt Ltd, Hyderabad 35

11 Mi GmbH, Germany 25

12 Millennium Synergy Ltd, Bangalore 10

13 Moser Baer Ltd, NOIDA 15

14 PLG Power Ltd, Nasik 40

15 Precious Energy Ltd (Moser Baer), New Delhi 15

16 Solar Semiconductor Pvt Ltd, Hyderabad 20

17 Solitaire Energies Ltd (Moser Baer), New Delhi 15

18 Sunkon Energy Pvt Ltd, Surat 10

19 Tathith Energies USA 5

20 Top Sun Energy Ltd, Gandhinagar 5

21 Torrent Power Ltd, Ahmedabad 25

22 Unity Power Ltd (Videocon Group), Aurangabad 5

23 Waree Energies Ltd, Surat 20

24 Zeba Solar, Portugal 10

Grand total of photovoltaic solar thermal projects 365


Table 17.4: Allotment of solar capacities in Gujarat (contd...)

Sr. no. Name of company Allotment, MW

1 ACME Telepower Ltd, Gurgaon 46

2 Adani Power Ltd, Ahmedabad 40

3 Cargo Motors, Delhi 25

4 Electrotherm Ltd, Ahmedabad 40

5 Abengoa Ltd, Spain 40

6 IDFC Delhi 10

7 KG Design Services Pvt Ltd, Coimbatore 10

8 Sun Borne Energy Technologies Gujarat L. 50

9 NTPC, New Delhi 50

10 Welspun Urja Ltd, Ahmedabad 40

Grand total of solar thermal 351

Grand total (photovoltaic + thermal) 716

Source: Government of Gujarat (2009). ‘Capacity allotment for solar power projectdevelopment in Gujarat’, Gujarat, India.


REFERENCES

1. ADB. 2011. Presentations from Solar Workshop & Training organized byADB & NERL, New Delhi, India.

2. Ahuja, Dushyant. 2010. ‘Financing Solar Projects in India’, Energetica India,May/June 2010.

3. Arora, D. S., Sarah Busche, Shannon Cowlin, Tobias Engelmeier, Hanna Jaritz,Anelia Milbrandt and Shannon Wang. 2010. ‘Indian Renewable Energy StatusReport: Background Report for DIREC 2010’, NREL, REN21, gtz, IRADe, India,October 2010

4. Deshmukh, Ranjit, Ranjit Bharvirkar, Ashwin Gambhir and Amol Phadke.2011. ‘Analysis of International Policies in the Solar Electricity Sector: Lessonsfor India’, Prayas Energy Group, Pune, India, and Lawrence Berkeley NationalLaboratory, CA, USA; India, July 2011.

5. Deshmukh, Ranjit, Ashwin Gambhir and Girish Sant. 2011. ‘India’s SolarMission: Procurement and Auctions’, Economic & Political Weekly, 46(28)July 9, 2011.

6. GERC. 2010. ‘Determination of Tariff for Procurement of Power by theDistribution Licensees and others from Solar Energy Projects’, Order No. 2of 2010, Ahmedabad, Gujarat, India.

7. Government of Gujarat. 2009. ‘Capacity allotment for solar power projectdevelopment in Gujarat’, Gujarat, India.

8. Government of Gujarat. 2009. Energy and Petrochemicals Department, ‘SolarPower Policy’, Gandhinagar, Gujarat, India.

9. Government of Rajasthan. 2010. Energy Department, ‘Rajasthan Solar Policy’,Rajasthan, India.

10. Green World Investor. 2010. ‘Can ADB Rescue India’s JNNSM with LoanGuarantees and Equity Investment?’, www.greenworldinvestor.com, 14 Dec2010.

11. Green World Investor. 2010. ‘USA Opposes India’s Solar Energy DomesticContent Requirements’, www.greenworldinvestor.com, 15 Dec 2010.

12. Karnataka Government Secretariat. 2011. ‘Karnataka Solar Policy (2011–16)’,Bangalore, Karnataka, India.

13. MNRE. 2009. ‘Jawaharlal Nehru National Solar Mission: Towards BuildingSOLAR INDIA’, Government of India, New Delhi, India. http://india.gov.in/allimpfrms/alldocs/15657.pdf


14. MNRE. 2010. ‘Guidelines for Migration of Existing Under Development Grid-connected Solar Projects from Existing Arrangements to the Jawaharlal NehruNational Solar Mission (JNNSM)’, Government of India, New Delhi, India.

15. MNRE. 2010. ‘List of Project Developers Qualified for Migration to JawaharlalNehru National Solar Mission’, Government of India, New Delhi, India.

16. MNRE. 2011. ‘Implementation of a Payment Security Scheme (PSS) for Grid-connected Solar Power projects under Phase I of Jawaharlal Nehru NationalSolar Mission (JNNSM) during the year 2011-12 Government of India’, NewDelhi, India.

17. MNRE. 2011. ‘Jawaharlal Nehru National Solar Mission: Building SolarIndia— Guidelines for Selection of New Grid connected Solar Power ProjectsBatch II’, Government of India, New Delhi, India.

18. MNRE. 2011. ‘JNNSM Phase-I Selected Projects List’, Government of India,New Delhi, India.

19. MNRE. 2011. ‘Payment Security Mechanism for Grid-connected Solar PowerProjects under Phase 1 of JNNSM’, Press Note, Government of India, NewDelhi, India.

20. Peddada, S. Rao. 2010. ‘National Solar Mission & Solar TechnologyDeployment in India’, Presentation, New Delhi, India, October 2010.

21. Prabhu, Raj. 2011. ‘Focus on India’s Solar Policy Framework’,www.pv-magazine.com, 06 April 2011.

22. Raghavan, Shuba V, Anshu Bharadwaj, Anupam A Thatte, Santosh Harish,Kaveri K Iychettira, Rajalakshmi Perumal and Ganesh Nayak (2010).‘Harnessing Solar Energy: Options for India’, CSTEP, Bangalore, India, 2010.

23. Stuart, Becky. 2011. ‘India Solar Industry off to a Successful 2011, butBankability Issues Exist’, www.pv-magazine.com, 20 April 2011.

NOTE

1. Arora, D. S., Sarah Busche, Shannon Cowlin, Tobias Engelmeier, Hanna Jaritz, Anelia

Milbrandt and Shannon Wang, ‘Indian Renewable Energy Status Report: Background

Report for DIREC 2010’, NREL, REN21, gtz, IRADe, India, October 2010, p 37.

Telecom Sector Reform | 361

1. INTRODUCTION

Although telecommunications was an early starter in attracting private sectorparticipation,1 it seems to be caught in the same quagmire as the other earlystarter, power. Few projects have achieved financial closure. Investment in thesector has been below expectations, and there are strident and continuing callsto renegotiate contractual awards, supported by financial institutions that havesunk funds into projects with apparently over-optimistic expectations. Presently,the Telecom Regulatory Authority of India (TRAI), and the government are tryingto develop an acceptable restructuring plan for the sector.

There are three basic options that seem to be under consideration, which arediscussed below. They are a soft bailout of the existing operators (Rollover); a middleoption that seeks to partially soften terms by instituting a revenue sharing system inplace of the current license fees (‘Muddle’ path); and no bailout at all, except tariffrealignments by TRAI (Hardball). All these plans, except perhaps Hardball, aredesigned more to relieve the problems of the existing operators and financialinstitutions, rather than put in place arrangements to provide efficienttelecommunication services to the Indian user. Recently, however, the PrimeMinister’s Advisory Group has reportedly proposed a radical restructuring planthat seeks to create a unified telecommunications market open to operators in allsegments (Clean Slate). This note tries to evaluate these restructuring options againstthe technological trends in the telecommunications industry and their implicationsfor the economics of the sector.

TELECOM SECTOR REFORM:RestructuringTelecommunications asif the Future MatteredDecember 1998

18


2. OPTIONS FOR RESTRUCTURING

Option 1: Rollover The most lenient (from the point of view of the financialinstitutions and the existing license holders) proposal on the table is to extendthe license period of the operators and accept a moratorium on the payment oflicense fees to the government.2 The argument for this stems from the negativeeffect of opaque government policies and the assumption that bankrupt telecomcompanies automatically imply a non-viable and non-financeable telecom sector.While there have been problems with auction design, with obtaining clearancesfor spectrum rights and right of way, with interconnection to the Departmentof Telecommunications (DoT), and a host of other matters, it is debatablewhether all of them together can be held collectively responsible for the currentstate of affairs. The second presumption ignores the distinctionbetween individual companies and the sector as a whole. A number of airlinecompanies have gone bankrupt in the US, which continues to have a vibrantand competitive airline industry. The fact that some operators would makeunwarranted profits from a generalised sectoral relief is a relatively minorobjection to this approach.

Effect on other sectors: The major danger is the acceptance of renegotiation andalteration of original contract terms. Apart from being legally suspect, in a countrywhere not only telecom, but the entire infrastructure sector is being opened up,the precedence for renegotiation set by this action would vitiate the environmentfor contracts and concessions in all other infrastructure sectors.3 This route shouldbe avoided to prevent exacerbating already extant moral hazards.

Option 2: ‘Muddle’ path The middle path advocates a revenue sharing approachinstead of fixed license fees, which would make the government a partner in thecommercial risks of market evolution. If anything, this is an absolute antithesis ofthe privatisation initiative. It is patently incongruous to speak of corporatising andprivatising DoT and in the same breath ask the government to behave as a partnerto existing private firms.

Effect on market expansion: Philosophy aside, this distorts incentives dramatically.If for each additional rupee generated in revenue, an operator is to pay a portion tothe government, then the incentive to grow the market is considerably reduced.The operator will restrict his market expansion to a point where his portion of themarginal revenue equals marginal cost.4 An example of a similar disincentive is thecurrent metro cellular licence fee structure (a fixed amount per subscriber), whichimpels companies to increase the usage per user, rather than increasing the numberof users, and is a clear deterrent to attracting low-volume users into the market,limiting the use of installed infrastructure.


The current operators should wake up to the negative effect of revenue sharingarrangements on harvesting network externalities, as competition from other areasof telecommunications begins to affect their market share. The vested interest in asmaller market size that is fostered by the revenue sharing arrangements will alsocreate an interest group that will try to resist the expansion of the sector, driven bythe forces of technological convergence. The middle path may then end up in a verymessy muddle.

Government as insurer: It is obvious that if the government were to take a fixedfee that is equal to its revenue share, the operator would be driven to expand hismarket even more. It would seem the only reason the operators are asking for arevenue sharing system is the insurance value of such an arrangement againstmarket risk.5 Should the government really be getting into the business of insuringoperators against commercial market risk, when all the discussion is aboutincreasing private sector participation in the insurance industry? There may be acase for this where the effect of commercial factors like price is limited, and demandis subject to extraneous risks but this is hardly the case in telecommunications,which is an extremely market-driven sector.

Option 3: Hardball: This option insists on maintaining the contractually agreedlicense fee structure, and any relief that may be forthcoming would depend solelyon the tariff and other decisions of the regulatory authority, TRAI. Given the revenueimplications of the above two options and the fiscal pressure India is under today,there is understandable resistance to any option that will decrease revenue flows tothe government. This, of course, is not a good reason to prevent action that maylead to better and wider provision of telecom service to the Indian user, but asargued above, the other two options do not have that advantage. Moreover, evenwithin this option, there is scope for substantial relief to operators, and consequentlyfinancial institutions, through tariff changes by the regulatory authority, TRAI.Indeed their recent consultation paper suggests that the financial viability of existingoperators is among its major concerns.

Effect on investment: The other group who wish to stick to this option are thosewho believe that renegotiating contracts would have serious implications, byincreasing the moral hazard in future contract negotiations in telecom and all othersectors. Their major fear is the effect of such a stance on the level of investment inthe sector and consequently the level of service available to the final user. This fearis perhaps exaggerated. The present lack of investment is at least as much due to thepresence of unresolved uncertainty as due to any lack of financial viability. In anycase, given that the existing investment is, to a considerable extent, sunk, futureinvestment will depend on adequate cash flows from the sector. Infusion of capitalby new equity partners and buyout of existing equity by parties better able to run


the business can be expected to ease liquidity constraints on existing firms becauseof past mistakes. A certain amount of rescheduling and write-down of extant debtcommitments cannot be ruled out, but this should not be a concern, unless theimplied increase in NPAs affects the overall safety of the financial sector.

Digital convergence: Even if the amount of investment is not a problem, thecomposition of investment may very well be. Adopting the hardball option freezesthe existing structure of the industry. The current licenses are simply for the right toprovide a service, entrenching exclusivity and perpetuating an archaic monopolisticstructure in a sector that is becoming increasingly competitive. The basic drivingforce of this growing competition in what was once thought to be a natural monopolyis the increasing versatility with which services can be provided, based on thedigitisation of all signal transfer technology. As the manner in which signals aretransferred from one location to another becomes common, it is possible for a serviceprovider in one segment of telecommunication, say network television services, toperform the functions of another, say, the local phone company. Efforts to maintainbarriers across such segments will eventually be overwhelmed by technology.6 Thereis a need to take action now and restructure the sector in line with its evolvingtechnology and associated economics.

3. STARTING OVER

Clean slate: The Prime Minister’s Advisory Council has reportedly suggested acomplete makeover of the sector, with open competition rules across differentsegments of the telecommunications industry. Unfortunately, perhaps as a hangoverfrom the old debate, they also suggest revenue sharing as a means to deal with thestranded costs of existing concessions, but that issue can be dealt with in otherways, as suggested below.

Where does the present path lead? What prevents a restructuring such as the onesuggested above? The fear is that such a move will end up delaying the development ofthe sector, ignoring the fact that trying to sort out the current mess has already takenenough time. The critical point to note is that any development of the sector on thepresent path is very likely to lead to a distorted and inefficient sector, by the very natureof the current dispensation. In addition, the restarting time for the sector should be low,given the amount of information released as a result of the travails of the existing operatorsand the growing clarity on technology, regulatory environment and the possible extentof competition from government-owned bodies like MTNL and VSNL. If anything, theenvironment for private sector participation may now be more propitious.

Reach or revenue? It would seem that the first issue that a new telecom policy shouldaddress is whether to increase teledensity or to continue using telecom as a revenuegenerator. Usually, in a public service activity, there is a dichotomy between the provision


of universal service and the profits made from the activity. Mandates to increase reachtherefore result in lower profits to the operator and consequently, lower revenue to thelicensing authority. But, in telecom, this picture is no longer as clear. First, the verynature of the technology of minimal marginal cost and lumpy capacity dictates that thecapacity be used to its utmost, once installed. The nature of any subsidy can then belimited to reducing the cost of capacity required to serve target customers. The amountof support required will be reduced to the extent that this capacity can also be used toserve other ‘profitable’ customers.7 In addition, there are benefits from networkexternalities as reach expands. ‘Reach’ is therefore something that is inherent in thetechnology and economics of the telecommunication industry. It is not something thatneeds to be mandated. Instead, the government needs to use this characteristic to itsadvantage, by leveraging connectivity between different networks.

Impact on technology: Given India’s fiscal situation and the revenue raisingpossibilities of telecom licenses, it is difficult to abjure the revenue maximising option,even in light of the experience of the past few years. Indeed, few countries have beenable to resist this allure. There is however increasing doubt about the willingness offirms to pay simply for the right to provide telephone services in a technologicallyevolving environment that threatens the monopolistic nature of the right. A paththat chooses to auction such rights, such as India’s, would also imply that thegovernment would be under pressure to prevent technological advancement toprotect the right granted to the operators, with possibly disastrous consequencesfor India’s burgeoning information technology sector.

Revenue out of thin air: Developments in communication technology have twobroad trends: versatility, mentioned earlier, and mobility. Mobility requires use ofthe radio frequency spectrum. This is a scarce resource with competing uses, andnow increasingly subject to international standardisation by the InternationalTelecommunications Union (ITU). It is possible and indeed appropriate to raiserevenue by auctioning rights to the use of this spectrum, as has been done successfullyin the United States and Australia, through simultaneous menu ascending auctions.8

Given the fact that the valuation of these spectrum rights is likely to undergosubstantial change over time, as the Indian economy develops, it is advisable toaward such usage rights for relatively short periods, e.g. 15 years, without restrictingthe service that they can be used for. For this, it is necessary to strengthen the officeof the Wireless Adviser and develop a spectrum allocation plan after consideringITU’s recommendations before embarking on an auction of spectrum rights.Conventional wireline (whether copper or fibre-optic) telephone services do notinvolve the use of scarce common resources, except, on occasion, the right of way,9

and should be de-licensed and open to anyone who can provide the service, subjectto quality standards.


Dealing with existing licensees: The removal of restrictions on service provisionimplies that existing licensees can potentially gain by being able to provide a widervariety of services, thus increasing the value of the license, in addition to conferringa first mover advantage. Recent remarks from foreign equity holders in telecomconsortia, e.g. Telestra, seem to indicate that this will, to a large extent, mitigate anyneed for compensation. Allowing existing licensees to bid for the new concessionscould further reduce their resistance. Their commitments for future licensepayments, made under expectations of less competition, could be converted intore-saleable bidding points for the proposed spectrum auctions.10 Operators wouldstill be liable for any license payments not converted and any unsold and unusedbidding points. This will ensure that the government does not have any additionalfinancial commitment due to the restructuring, and also, at a minimum, protectthe existing revenue projections from the sector, which would be doubtful if thecurrent system were to continue.

Wiring: As mentioned earlier, the development of fixed-line networks will continueto suffer from problems related to acquisition of right of way. This needs to beaddressed to enable fibre-optic cable networks to supplement the ultimately limitedcapacity of the radio spectrum. This is especially needed in high population anddata density areas such as urban areas and business districts, where wirelesstechnology is unable to provide the required channel capacity, given the volume ofcalls. The high and versatile data carrying capacity of fibre-optic networks meansthat they will also be ideal network resources to be re-sold to multiple serviceproviders, who can be cable operators, broadcasters, telephone operators, internetservice providers, or any other company that needs to send digital signals into theconnected units.

Interconnection: This is essential to promote and leverage the technological trendtowards versatility. The new telecommunications policy needs to establish clear openaccess and interconnection guidelines. Along with opening up access of one telecomsegment to operators in other segments and vice versa, this would lead todevelopment of a data communications market that would optimise utilisation ofboth installed wireline and wireless transmission capacity. The presence of manyoperators and a technological and regulatory environment that permits theinterconnection of one network to another would also lead to a quantum expansionin reach. For example, it is conceivable that a satellite phone operator like Iridiumwould resell its spare satellite capacity, which is a sunk cost, to operators who willuse it to provide trunk connectivity to local rural networks, at a fraction of the costneeded for dedicated wireline trunk connectivity. Extensive interconnection wouldalso lead to increased benefits from internalising network externalities. It is notnecessary to trade-off reach in order to raise revenue.11


4. CONCLUSION

The government is on the verge of announcing a new telecom policy. The earlierpolicy was designed in a world where telecommunications services were expectedto be provided by monopolistic entities that faced little competition. However, effortsto involve the private sector under that regime have led to non-viable contracts,which today ask to be restructured. The opportunity exists now to remedy our earliermistakes and develop a forward-looking policy that acknowledges and leverages thetechnological developments and economic characteristics of the sector in a mannerthat will serve the Indian user in the best possible manner. We can use it to build asector that will grow with the country and make India’s information technologysector a part of the global communications revolution. It will establish a sector thatis at the cutting-edge of technology, as judged by its effect on industrialcompetitiveness, and also provide affordable connectivity to our vast millions.Indeed, it is only through such technology that we can provide such connectivity.Or we can continue with our current fragmented, costly and city-centric company-and institution-oriented approach, which will lead to a sector that will needrestructuring once again, as technological developments overwhelm our attemptsto rescue current companies and institutions. We should not commit the samemistake yet another time.

It is time for the government to de-license the provision of wirelinetelecommunications and allow operators in one segment to provide services in othersegments. It should auction spectrum rights to ensure the best use of a scarce resource.Existing licensees can be allowed to convert future license fee commitments into re-saleable bidding points for these auctions, which will at least preserve expectedgovernment revenues. In preparation, the government will need to develop aspectrum allocation plan, mandate interconnection requirements for all segmentsof the telecommunications sector, and facilitate right of way for fibre-optic networks.

NOTES

1. Metro cellular licenses were sold in 1994; other cellular areas in 1995 and basic servicerights were sold in 1996. Revenue maximisation appears to have been the primaryobjective of the government in auctioning licenses for the provision of telecom services.A sealed bid auction implied that all winners were subject to the ‘winner’s curse’, andbidders for the second license were required to match the winning bid. This left nonatural alternative to step in, in case of default by the winning bidder.

2. A remedy tailored to the extent of difficulty would imply individualised packages foreach operator. This will involve very intensive and burdensome financial monitoring,or some form of windfall profits tax. It would also imply that a policy decision has tobe taken on an appropriate profit level for telecom operators, similar to a ‘guaranteed’


return. Otherwise, some operators would receive unwarranted benefits from ageneralised relief.

3. It is interesting to note that the basic-case law in this area appears to be Ramanna Shettyversus International Airports Authority of India (IAAI), involving the award of arestaurant concession, utterly unrelated to the telecom sector. It is often stated that thetelecom industry cannot afford delayed and protracted litigation. This has to be judgedagainst implications of opening up renegotiations, not just for telecom, but also forother sectors as well.

4. This is a well known result in land-tenancy theory, where extensive comparisons weremade in the sixties and seventies among crop sharing, cost cum crop sharing and fixed-rent land tenancy systems.

5. The incentives to adhere to such a revenue sharing system for the private sector willdecline with decrease in uncertainty and the growth of the sector. As the amount thathas to be given to the government increases, the incentives to under-report will rise. Ineffect, the government will on all likelihood be unable to reap the full benefits of the‘partnership’, as private parties will clamour for release from the burden of governmentpayments in the future.

6. The growth of callback services in regions like Latin America, to arbitrage differences inphone tariffs is a simple case in point. Teleintar, the Argentine international telephonyoperator, estimates that it lost about 30 per cent of its market share to such services.

7. Even more strongly, if the capacity in question is required to serve other customers,then no subsidy is indicated. For example, services to rural areas along the fibre-opticcable route or relay station route (depending on the technology used) linking majorurban areas service provider can be provided at no additional cost. Indeed the extrarevenue from rural users, if they are within the provider’s license area is an additionalbenefit. Also see note 11.

8. The use of simultaneous ascending menu auctions in Australia and the US is generallybelieved to have led to a realistic revelation of underlying valuations for the spectrumin a transparent manner. The ascending auction was designed to reveal informationprivate to specific bidders, and minimise regret, while the menu structure allowedbidders to aggregate regions based on their business complementarity, rather than animposed division.

9. Currently, the electricity and cable (mostly in urban areas) are the only two industriesthat have wired access into homes. Of these, the cable operators often usurp right of waywithout appropriate payment.

10. While the government shares some responsibility for the current chaos in the telecomsector, blame must also be attached to the inefficient execution of business plans by theoperators and faulty business projections made by them and their financiers, and theirsubsequent effort to avoid the consequences of these actions. This has stunted growth inthis sector over the last few years. Such behaviour should be penalised in order to maintaincommercial discipline. One way of doing this would be to award only a fraction of thelicense fee commitments as bidding points to the existing operators.


11. If universal service provision is not occurring at a rapid enough pace, it can besupplemented through a system of minimum subsidy bidding for the provision of adefined level of service to a specific area. These subsidies can be funded out of generalrevenues or from a Universal Telecom Service Fund established for the purpose.Leaving universal service obligations with the dominant government-owned operator(especially if it remains in hands) would furnish no incentive to explore cost-minimising solutions to the provision of such service and provide a continuing excusefor underperformance. Interestingly, Oftel, the British telecom regulator hasdetermined that the benefits of universal service provision, in terms of locking inpotentially profitable customers, better access to first-time users and wider brandrecognition were worth more than the estimated cost incurred by British Telecom inproviding the service, around £45m–£80m per annum.


1. INTRODUCTION

The Indian telecommunications sector has seen much growth and turmoil in therecent past.1 The number of mobile subscribers grew from 0.3 million in the firstquarter of 1997 to 29 million in December 2003, of which 7 million were CDMAmobile subscribers.2 In November 2003, the government issued guidelines for aunified access services licence (UASL) regime, where the basic service (BS) licenceand the cellular mobile telephony service (CMTS) licences would come under asingle licence regime in the future. Existing licensees can opt to continue offeringservices under their old licence, though many have chosen to migrate.3

The government has also permitted mergers and acquisitions (M&A) of licenseeswithin a service area, and the merged entity is now permitted to retain the spectrumoriginally allocated to the merging entities up to certain limits, but ‘the spectrumutilisation charges beyond 10 + 10 MHz for GSM-based system and 5 + 5 MHz forCDMA/ETDMA-based systems shall be prescribed separately’.4 Recently, theTelecom Regulatory Authority of India (TRAI) has been entrusted with theregulation of cable broadcasters—ushering in signs of regulatory convergence.These developments appear to presage a situation where the service licence wouldhave no entry restrictions beyond some minimal level of pre-qualification. In thisscenario, usage rights to the spectrum acts like an entry restriction. The multipleuses of the spectrum in a convergent environment and the increasing relevance ofindustry consolidation require that serious consideration be given to separating therights to use the spectrum from service licences and thinking about alternativemethods of allocating spectrum. This paper explores how just such a transitionfrom the existing situation can be accomplished. While this note focuses ontelecommunication services, the principles apply equally to all other services thatuse radio frequency, e.g. FM radio,5 paging and trunk radio.

TRANSITIONING FROM

ADMINISTRATIVE

ALLOCATION OF SPECTRUM

TO A MARKET-BASED

APPROACHFebruary 2004

19

From Allocation of Spectrum to a Market-based Approach | 373

2. EXISTING PRACTICE

2.1 Allocation and fees for spectrum usage

The Wireless Planning and Coordination wing (WPC) currently assigns frequenciesto CMTS licensees from the designated bands prescribed in National FrequencyAllocation Plan–2000 (NFAP–2000). A cumulative maximum of up to 4.4 MHz +4.4 MHz for CMTS licensees is assured, but based on usage, justification andavailability, additional spectrum up to 1.8 MHz + 1.8 MHz, making a total of6.2 MHz + 6.2 MHz, ‘may be considered for assignment, on case-by-case basis, onpayment of additional licence fee’.6 The CMTS licensees pay spectrum charges of2% of the adjusted gross revenue (AGR) up to 4.4 MHz and 3% of AGR for spectrumup to 6.2 MHz. The charge rises to 4% of AGR for allocation beyond 6.2 MHz +6.2 MHz, which shall be given if the subscriber base is more than 5 lakh. ‘Thisspectrum charge of 4% of AGR would also cover allocation of further spectrum,which may become possible to allocate in the future, subject to availability, to addup to a total spectrum allocation not exceeding 10 MHz + 10 MHz per operator ina service area. Such additional allocation could be considered only after a suitablesubscriber base as may be prescribed, is reached.’7 Thus, the expenditure on spectrumincreases only proportionately to revenue for spectrum allocations beyond 6.2 +6.2 MHz. In addition, a major part of the one-time entry fee paid by the licensee,based on a bidding process, can also be considered as an up front payment for spectrum.

Similarly, in the erstwhile basic services licence, an additional revenue share of 2%of annual gross revenue earned from WLL subscribers would be levied as spectrumcharge for allocation of 5 + 5 MHz in the 824–844 MHz band paired with the869–889 MHz. As in the cellular case, this includes royalty for spectrum as well asthe licence fee for the base station and subscriber terminal (handheld or fixed).The same principle is followed for spectrum charges in the 1880–1900 MHz bandfor the microcellular technology-based system.

Further, royalty for the use of spectrum for point-to-point links and access links(other than cellular service spectrum) are separately payable as per WPC guidelines.The authorisation of frequencies for setting up microwave links by cellular operatorsand issue of licences is also separately dealt with by the WPC as per existing rules.

2.2 Revenue sharing—an old practice

The practice of charging a share of revenue as user fee for scarce resources is notnew. Indeed, it can be said to be similar to the practice of sharecropping, wherebythe landlord allows a peasant to cultivate his land in return for a share of the produce.The literature analysing this phenomenon has pointed out two main features of thistype of contract, namely:


(a) its risk-sharing capability, whereby the peasant is protected in case there is acrop failure, but does not enjoy the full benefits of his investment in case of abumper crop; and

(b) the dilution of incentives to exert effort and invest in the land precisely becausehe does not enjoy the full benefits of his investment.

The use of revenue share for charging for spectrum is a relatively straightforwardextension of this type of contract. But, even though revenue sharing linked spectrumfee to service provision, it was unclear, until recently, whether spectrum was anintegral part of the licence (see Box 19.1).

Box 19.1: The spectrum is finally attached to the licence

If the licence were to be sold by an existing service provider to another service provider

in the same service area (as is now permitted), would the buyer have access to

12.4 MHz + 12.4 MHz of spectrum8 or would she/he have to give up the seller’s

allocation? This issue has only been clarified in the recent guidelines (issued on

21 February 2004) for merger of licences in a service area. The current status is that the

spectrum will go with the licence but the amount held by a merged entity shall not

exceed 15 MHz + 15 MHz per operator per service area for metros and category

‘A’ circles and 12.4 MHz + 12.4 MHz per operator per service area in category ‘B’ and

‘C’ circles. This will be an important instrument to rationalise the use of spectrum.

A concern from the point of regulation is possible hoarding by operators. Indeed, the

UK telecom regulator, Ofcom ‘considers it desirable to address acquisition of market

power as well as abuse of dominance’ with reference to spectrum. The Indian guidelines

are relatively generous from this viewpoint, permitting a market share of up to 67% of

the combined GSM and CDMA subscriber base.

2.2.1 Effect on investment

It is arguable that the benefits of risk sharing may be substantial in an emergingeconomy such as India, where the natural and policy variability in the businessenvironment is high, especially for sectors such as telecom where technologicalchange is rapid, and the ability of individual service providers to bear the risk is lowcompared to the national government. Moreover, since the share of revenue isrelatively low, viz. 2–4% (as compared to 33% to 50% in crop sharing arrangements),the second effect, i.e. investment distortion may not be substantial. Overall, the net

effect on investment may well be positive. In any event, the revenue share towardslicence fee (which is by far a larger share of revenue) is expected to remain, and itwould be difficult to redress any investment distortion effect by addressing spectrumcharges alone.


2.2.2 Effect on competition

It can be argued that this type of user fee structure leads to a situation where theservice provider who is using spectrum more efficiently (i.e. has more users per unitof spectrum) is charged more (because she has more revenue, she pays a higher absoluteamount, given equal revenue shares) than another service provider who has fewerusers per unit of spectrum. Thus, even though both service providers use the sameamount of spectrum, the one with fewer users and arguably the less efficient providerpays less.9 However, another way of looking at this is to observe that this systempromotes competition by facilitating entry because newer service providers are allocatedthe same amount of spectrum, but since they have fewer users initially, they have acertain advantage in their initial period, where they can survive with lower investments.Thus, while it may delay exit by inefficient providers, it may foster entry by newproviders. The net effect on competition is therefore unclear. However, since it isunlikely that the benefits from spectrum charges alone could help keep an inefficientoperator afloat, the balance may well be in favour of more competition.

2.3 What regime for spectrum under a unified licence?

The questions that need to be addressed are as follows:

(a) Should we delink the spectrum from service provision?

(b) Should we change the way we charge for spectrum, i.e. move away from revenueshare to a charge that is based on the amount of spectrum used? This is relatedto (a) above, for if spectrum is delinked from service provision, it would bedifficult to implement a revenue sharing regime and alternative fee structuresmay need to be found.

(c) Should we want to allow trading of spectrum bandwidth?

(d) Should we have spectrum auctions? Is that the only way to have market-basedcharges?

3. WHY FIX WHAT IS NOT BROKEN?Should one again modify the licences to move to a spectrum fee regime that is notbased on revenue share? At one level, it can be argued that since there is by now anestablished tradition of modifying licence conditions in India, this could beconsidered a relatively minor adjustment as long as the revenue implications forthe service providers and therefore the government are not substantial, i.e. thefinancial terms of the contract are broadly similar. On the other hand, can we notwait for the existing licences to expire?10 If the revenue implications are notsubstantial, then why tamper with the existing system, unless it is severelydistortionary?


3.1 Revenue sharing and delinking

The critical benefit of moving away from a revenue share regime lies in delinkingthe spectrum from service provision. Delinking these two would imply a fee forspectrum that is unrelated to revenue from service provision. As long as the revenueshare system remains, service provision and spectrum remain linked since paymentfor the spectrum is based on revenues from service provision. The benefits fromconvergence lie in the ability to provide multiple services over a single ‘pipe’, ofproviding new services in hitherto unknown ways. Delinking the spectrum allowsthe possibility that the bandwidth may be used for services that may be more usefulthan what it was originally contemplated for. Its absence prevents other potentiallymore valuable users of the spectrum from making an offer to the existing user touse the spectrum in a mutually beneficial manner. Free entry of service providerscan create additional services where none existed.11 More importantly, it will bepossible for spectrum prices to reflect relative scarcity, e.g. spectrum could be veryinexpensive and in relative excess supply over vast parts of rural India, therebyfostering the spread of wireless connectivity, while it would be expensive in majormetros, thereby fostering the use of spectrum-saving devices. This could also beachieved if the licence areas were more finely defined, but it would be morecumbersome to implement.

3.2 Revenue sharing and demand for spectrum

3.2.1 Existing charging system can increase demand for bandwidth

At first sight, the current revenue sharing regime appears to be a relatively steepcharge for additional spectrum, especially for companies that are growing theirrevenues. The additional 1.8 MHz raises fees from 2% to 3% over the entire revenuebase, i.e. a 50% increase in charges. Assuming a gross revenue of Rs 1000 crore,which is a reasonable number for a metro cellular operator today, this implies thatthe additional 1.8 MHz would cost Rs 10 crore (the company would have to payRs 30 crore instead of Rs 20 crore). More so, the company would have to pay thishigher share over the entire future of its licence.12 This would need to be comparedwith the additional investment required in order to meet the growth in the numberof subscribers with the existing spectrum. It may not be possible to technicallyaccommodate such numbers without additional spectrum, and therefore, savingsmay only be to the extent to which the acquisition of additional spectrum can bedeferred. However, it would appear that the current regime therefore leans towardsmotivating an operator to acquire more spectrum.

3.2.2 But is bandwidth scarce?

The above would be especially undesirable if the amount of spectrum available inIndia was limited. It is not clear that this is yet the case. The amount of spectrum


currently released to telecom service providers is limited compared to internationalallocations (see Tables 19.4 and 19.5 in Appendix, which compare allocations inIndia with a number of countries overseas). There also appears to be spectrumavailable with other non-telecom users, that can be reallocated in a mutuallybeneficial manner. The development of spread-spectrum and code-division methodsfor transmission—the next generation of both the existing GSM and CDMA aresystems based on such technologies—could further reduce the demand for spectrum,though wireless data transmission may provide a counterbalancing demand.Spectrum may, however, be scarce where there is a high density of users, such as themetropolises and here the existing regime may provide inappropriate incentives toacquire more spectrum in these areas.13

3.3 Use of the allocated spectrum

The existing pattern of use of spectrum indicates that there is considerable variationin the intensity of use by operators in the same circle, indicating that even if aparticular operator is pressed for spectrum, the spectrum allocated for the serviceas a whole remains underutilised. Allocating more spectrum in this situation wouldnot be necessary if some method could be found to transfer allocations betweenservice providers. This indicates that there may be an opportunity for trading. Figure19.1 shows the ratio of minimum to maximum number of users per unit of spectrumacross twenty different telecom circles where more than one operator is present. Ina number of circles, this seems to vary between 0.25 and 0.35, i.e. the operator withthe minimum number of users per MHz has only a fourth or a third of the numberof users as the operator with the maximum number of users per MHz in the samecircle.14 It is conceivable that the operator who is using the spectrum less intensivelywould like to trade it with one who is using the spectrum more intensively, subjectto the strategic considerations mentioned below. However, since operators withfewer subscribers pay relatively little for the spectrum as long as it is charged as arevenue share (a lower subscriber base implies a low AGR and a low spectrumcharge), the opportunity cost of holding on to the spectrum is low. A revenue-sharing regime may therefore act as a hindrance to efficient transfer of spectrumamong operators and indeed, in the extreme, force mergers between operators whereonly trading may have sufficed.


Figure 19.1: Variations in use of spectrum across circles and operators

There are thus two reasons for moving beyond the existing system, namely:

(a) Optimising the use of spectrum across different uses, i.e. where the spectrumis used for services that may be more useful than for what it was originallyallocated.

(b) Optimising the use of spectrum within a given use, i.e. avoiding the additionalrelease of spectrum while spectrum allocated for the service as a whole remainsunderutilised.

Both these benefits would need a mechanism to allow for trading of spectrum.

4. SPECTRUM TRADING

4.1 Spectrum trading is a stand-alone decision

Trading in spectrum can in principle be permitted regardless of whether thespectrum is delinked from the licence. If the spectrum continues to be linked tothe licence, it will be possible to have change of ownership, but not a change ofuse. To that extent, therefore, allowing spectrum trading is independent of

delinking spectrum and licence. Trading will ease pressure on the spectrum to theextent that there is variation in spectrum usage across regions and across operators.In this scenario, the service provider who has excess spectrum in some region canlease out her/his spectrum for a specified duration to another service provider,who would then save on the capital expenditure needed to make more intensiveuse of her/his existing spectrum.

0.190.22

0.350.32

0.25 0.25

0.34 0.320.38

0.60

0.17

0.06

0.45

0.23

0.35

0.25

0.82 0.84

0.93

0.61

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

Delhi

Mumbai

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Mah

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Gujarat

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4.2 Strategic considerations and trading

It is, however, possible that commercial consideration may militate against an activetrade in spectrum.1 Telecom is a business with strong network externalities, andoperators may wish to hold spectrum in view of future roll-out plans. In particular,operators may not lease spectrum to competitors, who would then be able to increasetheir customer base and improve service quality (at a cost lower than they wouldhave to spend otherwise), which could act as a hurdle in the future expansion of thespectrum lessor. However, spectrum trading can lead to significant activity in otherindustries, as in the case of the New Zealand radio broadcasting industry (see note11). Notwithstanding the above, differing regional strategies or tactical considerationsmay still result in trades while necessary adjustments are made.

4.2.1 Pricing for new spectrum and trading

The availability of additional spectrum to service providers who have reached certainthreshold norms (as is the current practice) may also induce competing serviceproviders to lease out unused spectrum. If she/he refuses to lease the spectrum, thecompeting service provider would procure the spectrum from the government anyway.By leasing the spectrum, the lessor gains the revenue that would otherwise have goneto the government. The manner of pricing adopted by the government for additionalspectrum would then affect the secondary market price.

4.3 International experience with spectrum trading

The extent of spectrum trading even internationally is still limited as shown inTable 19.1 below. In the US, Nextel had a difficult time aggregating spectrumacross the continent. However, countries such as Australia and New Zealand haveimplemented spectrum trading for many years now. Spectrum trading is alsopermitted in countries like Guatemala! Equally importantly, many countries arenow considering spectrum trading as wireless connectivity rises across the board.Both the UK and the EU have initiated consultation on the subject.

Table19.1: International experience in spectrum trading

Factors Australia/ United States/ UK Rest ofNew Zealand Canada Europe

Spectrum scarcity Low High Medium Medium/low

Internationalco-ordination requirements Low Medium Medium High

Regulatory restrictions Low Medium High High

Political attitude tomarket-based mechanisms Positive Positive Positive Mixed

Implementation of Fully Partially Likely to be Underspectrum trading implemented implemented introduced consideration in

many countries

Source: Nagpal, Amit: ‘One trade at a time: phased implementation of spectrum trading’.


4.3.1 Trading and limitations on use of spectrum

One key question that needs to be addressed with respect to spectrum trading isthe limitations which can be put on the use of the spectrum. In considering trading,some countries are looking at limits on the type of trading, e.g. change in ownershipmay be permitted, but change in use may be restricted. International conventionsdefine certain uses for specific bandwidths of spectrum, e.g. one band for cellularmobile and another for broadcasting. It is conceivable that any permitted changein the use of spectrum may need to respect these conventions, which would limitthe efficiency gains from spectrum trading. Further restrictions may emergefrom technical considerations of preventing interference in co-located spectrumbands from dissimilar uses with different protection technologies. Mostregulators do not expect a large number of trades at this time if only change ofownership is allowed.

4.3.2 Spectrum register

There will need to be significant institutional development before spectrum can

be traded. However, India has recently seen the development of a modern stock

trading exchange, viz. the NSE, as also a few commodity exchanges, and it can

therefore be expected that the development of trading infrastructure will not be

a constraint, provided a system of definition of property rights and one of

maintaining a spectrum register is evolved. The spectrum register would contain

information necessary to execute the trade. Table 19.6 in Appendix provides an

example from Ofcom in the UK about the kind of information that the spectrum

register may be expected to contain. The property rights,2 discussed in more

detail below, are defined by the geographic and frequency boundaries and the

price paid for using the spectrum (items highlighted in Table 19.6 in Appendix).

4.4 The building blocks for spectrum trading

4.4.1 Standard spectrum trading units

In order to facilitate spectrum trading, it is useful to develop a standard measure

of spectrum, like a stock holding certificate. The entire commercial spectrum to

be opened for trading (both those already in use and the bands yet to be allotted)

could be divided into standard spectrum units (SSUs), e.g. 20 sq km MHz as a

basic unit of measurement—similar to a square metre of land, as shown in Figure

19.2. The unit need not be a cube; it can also be a cylinder as shown, where the

distance is measured radially from a given geographical (latitude and longitude)

grid reference.


Figure 19.2: Example of standard spectrum unit

4.4.2Dimensions of SSUs

In defining SSUs, the specific dimensions of both the spectrum and geographicelements need some deliberation. The example given here relies upon the channelspacing for GSM. An existing CMTS service provider with 4.4 MHz of spectrumallocation therefore has 22 SSU per 100 sq km of service area. However, the channelspacing for CDMA is different. The spectrum dimension needs to be of sufficientfineness so that different units can be aggregated into a meaningful bandwidth fortrading, e.g. with a 200 kHz unit, 8 such units can be aggregated to form 1.6 MHz,which is the channel spacing for TD-SCDMA, but the SSU in the example abovecannot be used to separate 1.25 MHz, which is the CDMA channel spacing.

Similarly, the geographical grid of 100 sq km (or 78.5 sq km in case of radial distances)may be inappropriate, even for urban areas. Indeed, it is expected that the size of thegeographical grid would vary with population density, e.g. as in Australia(see Box 19.2), with larger grids in less densely populated areas. It is also possible toallow subdivision finer than SSUs. In the UK, the Ofcom consultation paper indicatesthat it is considering allowing traders to define the slices of spectrum for trading.

Box 19.2: Defining spectrum trading units in Australia

Australia sub-divided a given band into three-dimensional blocks, definedgeographically by parallels of latitude and meridians of longitude and by a standardbandwidth in frequency. Boundary conditions were set in terms of interference levels,

10 km

10 km

0.2

MHz

5 km radius

0.2

MHz


with ownership of blocks recorded in a computer database. The smallest indivisible unitof spectrum space is called the standard trading unit (STU).3 Each spectrum licence(valid for 15 years, after which it reverts to the government, presumably to be auctionedagain) will consist of many STUs, i.e. indivisible cubes of spectrum space within thespectrum licence. The frequency bandwidth of STUs may vary in size depending on thespectrum band in which licences are being issued, but the area grid is constant for allbands. The Spectrum Management Authority created a Spectrum Map Grid coveringthe entire country, resulting in 21,998 cells. The cells are of three sizes depending onpopulation density, from 5 minutes of arc (about 9 kilometres) on the eastern seaboardand in Adelaide, Perth and Darwin to 1 degree of arc (about 100 kilometres) in regionalAustralia and 3 degrees of arc (about 400 kilometres) in remote Australia.

By themselves, the STUs may be too small to have significant utility, but because oftheir regular shape and their referential relationship with their immediate neighbours,they can be stacked vertically or horizontally with neighbouring STUs to form largerbodies of spectrum space that do have utility. Spectrum licences can be traded only interms of whole standard trading units, or STUs. Licensees who wish to trade part of alicence can disaggregate the licence into its component STUs and sell them individuallyor in multiples. A spectrum licence can be traded in whole or in part, by geography(see A) or by bandwidth (see B) or by both geography and bandwidth (see C), or canbe leased in whole or in part to third parties. A licensee can also look to extend thegeographic coverage and/or the bandwidth of a licence by acquiring an adjacentspectrum licence from another licensee (see D).

Source: Australian Communications Authority

4.4.3Transition to trading

The transition of existing spectrum allocations to tradable SSUs may not posesignificant challenges beyond those of defining property rights over the radiofrequency, which can be accomplished by redefining the existing allocations in termsof SSUs, as described above. Service providers can then be allowed to trade theirallocation based on their business perception of current and future need of spectrum.In the UK, Ofcom is proposing to transact trades by cancelling or amending theseller’s licence, and reissuing a licence to the purchaser in a six-step process, whichis described in Box 19.3. This may not be necessary if the trades are in whole SSUs,where the partitioning of the spectrum assigned to the licensee is pre-defined, andthe trade can be accomplished much in the manner in which a dematerialised stockis traded today.

Box 19.3: Ofcom’s proposed process for transacting a spectrum trade

1. The licensee decides what rights it wants to transfer (e.g. by an outright saleor lease). If the proposed transfer would involve a change of configuration


(e.g. a partitioning of the spectrum assigned to the licensee) or a change of use, which thelicensee wishes to effect in advance of the trade, the licensee can apply to Ofcom first.

2. The parties to the trade agree to the terms of the transfer. Under the tradingregulations, Ofcom proposes to require that the terms of the transfer must be set outin a written contract signed by all parties. The terms of the contract may be as simpleor as complex as the trade requires. In drawing up the contract, Ofcom expects thatthe parties will wish to conduct the appropriate due diligence and obtain the appropriaterepresentations and warranties. It is proposed that under the trading regulations, alllicence obligations (other than non-spectrum related licence conditions) must betransferred with the transferred rights (including liability for any outstanding licencefees) unless Ofcom consents otherwise. In granting such consent, Ofcom will need tobe satisfied that the proposed arrangements do not affect its ability to enforce the termsof the WT Act licences. Other obligations, for example to third parties, may also betransferred. The transferor will then sign a spectrum transfer form and pass this, togetherwith its licence documentation, to the transferee upon signing of the transfer agreement.

3. The transferee will then be responsible for sending (a) the transfer form, (b) theexisting licence documentation, (c) the signed transfer agreement and (d) a competitionand regulatory notification to Ofcom.

4. Ofcom will then check the documentation to ensure that the proposed transferis consistent with (a) the spectrum registry, and (b) the trading regulations, includingthe requirements for competition and regulatory clearance. Should a full review ofthe proposed trade be required for competition clearance, this may take several weeksto complete.

5. Assuming that the proposed transfer complies with these requirements, Ofcomwill then update the spectrum registry, revoke the transferor’s existing licence, issuethe appropriate licence to the transferee and, where appropriate, issue a new licence tothe transferor (e.g. where rights to use spectrum have been partitioned). Subject to theterms and conditions agreed between the parties, completion of the trade is likely tooccur at this point.

Source: ‘Spectrum Trading Consultation’, Ofcom, September 2003.

5. CHARGING SCHEMES

5.1 Spectrum charges and revenue share

The current licence states that ‘Gross revenue shall be inclusive of … revenue frompermissible sharing of infrastructure and any other miscellaneous revenue, withoutany set-off for related item of expense, etc.’ It therefore appears that under existinglicence conditions, revenue from spectrum trading of the transferor would formpart of gross revenue (as revenue from permissible sharing of infrastructure) andtherefore be shared with the government as per the applicable regime. Conversely,


the payment for spectrum by the transferee may be considered equivalent to accessand interconnect charges and allowed as an offset. If the revenue share percentagesof the transferor and transferee were the same, these charges would offset each other.The original licensee could continue to pay for her/his spectrum allocation as apercentage of her/his AGR, while the new user would pay the original licensee forthe extra spectrum. The new user would also pay more to the government as her/hisAGR increases with the use of more spectrum. When the revenue share of thetransferor and transferee are equal, then, as long as the AGR of the transferee increasesby more than the reduction in the AGR of the transferor, the government would getmore revenue without releasing more spectrum, as in Table 19.2.4 5

Table 19.2: Example of spectrum trading with revenue share payments

Transferor Transferee

Items Before After Before After

Adjusted gross revenue (*) Rs 500 cr. Rs 500 cr.‡ Rs 1000 cr. Rs 1200 cr.

Revenue from spectrum trading n. a. Rs 10 cr. n. a. (Rs 10 cr.)

AGR including trading revenue n. a. Rs 510 cr. n. a. Rs 1190 cr.

Charges paid to government† Rs 15 cr. Rs 15.3 cr. Rs 30 cr. Rs 35.7 cr.

Amount of spectrum owned 6.2 x 2 MHz 6.2 x 2 MHz 6.2 x 2 MHz 6.2 x 2 MHz

Amount of spectrum used 6.2 x 2 MHz 5 x 2 MHz 6.2 x 2 MHz 7.4 x 2 MHz

* Does not include revenue from spectrum trading† Assumes a revenue share of 3% of AGR‡ It is assumed that the transferor does not lose revenue, as she/he did not need the tradedspectrum to serve her existing subscriber base.

If spectrum is traded between similar types of users, then it appears feasible tocontinue the same scheme of revenue share charges and allow trading. However,this would prove difficult if change of use is contemplated. In such a case, delinkingthe spectrum from a particular use and using a spectrum-specific charge appearsmuch more sensible.

5.2 Charging based on amount of spectrum

The proposed approach attempts to move the spectrum charging scheme from onebased on revenue share to charging based on amount of spectrum being used.At the same time, it tries to minimise the financial variation between the proposedcharge and the existing charge. This is in order to accomplish the delinking ofspectrum and service provision in a revenue-neutral manner, minimising its effecton financial projections of service providers and the government.6


5.2.1 Charging for existing allocations in a revenue-neutral manner

The current system generates total revenues for a given total amount of spectrumby various service areas (circles). It is thus possible to calculate average prices forthe total bandwidth within each circle and use this to set an initial charge. To accountfor the possibility that the revenue to the government could rise over time assubscriber growth occurs, one can build in an escalation factor that is related toaverage ex-post nationwide growth of wireless telecommunication revenues.7 Forexample, if the current charges generate a total Rs 50 crore per year from all thetelecom operators for Delhi, one can apportion it to the 25 MHz allocated to allservice providers to produce a base charge of Rs 2 crore per year per MHz(or Rs 4 million per 200 kHz). Assuming that Delhi, with an area of 1500 sq km, wasdivided into 15 SSUs, this would imply an annual base fee of Rs 270,000 for the SSUillustrated in Figure 19.2. This base fee can then be increased by the annual growthfactor for subsequent years.8

5.2.2 Differential pricing between SSUs

Since the current revenue numbers are available only at the circle level, all the SSUsin a given circle will start with the same base fee, e.g. Bangalore and Gulbarga(a small town in Karnataka at considerable distance from Bangalore) have the samespectrum charge per MHz, which is clearly not reflective of spectrum usage at thetwo locations. Since existing circles would be divided into a number of smaller SSUs,service providers may need less spectrum in less densely populated SSUs and chooseto surrender their existing holdings (which are currently at a uniform level acrossthe entire circle) if they are not using it, rather than continue to pay for it. Existingusers can be allowed a one-time option to surrender excess spectrum after the moveto SSUs. As the spectrum is surrendered, the revenue loss can be added back intoareas where no surrender is taking place, and the revenue from the less dense SSUscan be divided by the amount of notionally available spectrum to reduce the perunit price of spectrum in such SSUs. This method of pricing has the potential togenerate an automatic differentiation between prices for spectrum in SSUs withmany subscribers and those with fewer users.

5.2.3 Example: How would this work?

Consider a situation where the Karnataka circle is divided into ten equal geographicunits, one including Bangalore and nine comprising the rest of Karnataka. Each ofthem receives the 24.8 MHz that is currently allocated to the Karnataka circle.Assuming that the Karnataka circle generates Rs 826 crore in AGR, the spectrum feeis Rs 24.8 crore. Initially, this is apportioned equally to all the ten geographic units,i.e. Rs 2.48 crore per unit or Rs 2 lakh per 2 SSU (each geographic unit being124 SSUs9 ). At this price, all but 4 MHz (20 SSUs) are surrendered in each of the


9 geographic units, generating a revenue loss of Rs 18.72 crore. This is added backto the Bangalore geographic unit, which increases its spectrum fee to Rs 21.2 crorefrom Rs 2.48 crore, implying a spectrum fee per SSU of Rs 17 lakh10 as shown inTable 19.3. After the move to SSUs, trading in spectrum can begin with these initialprices. Being a market-based allocation system, it can be expected to generate amarket-based opportunity cost for spectrum.

Table 19.3: Example of revenue neutral differential pricing between SSUs

Bangalore Typical GU Totalgeographic for rest of Karnatakaunit (GU) Karnataka GUs (1 to 9)

Before After Before After Before After

Spectrum used pergeographical unit (MHz) 24.8 24.8 24.8 4 24.8 4

Spectrum fee pergeographical unit (Rs crore) 2.48 21.2 2.48 0.4 22.32 3.6

Spectrum fee per SSUin each SSU (Rs crore) 0.02 0.17 0.02 0.02 0.02 0.02

Note: ‘Before’ and ‘after’ refer to before and after the surrender of spectrum by service providers.

5.3 Charging for new allocations: should we auction?

It is expected that new spectrum may be needed only in certain densely populatedlocations—where it may or may not be scarce. The necessity for auctions isquestionable when the scarcity of the resource is yet to be established. A betterunderstanding of the scarcity will be obtained once trading is allowed to begin.Then, in case spectrum availability is not a problem, it may not be economicallyinefficient to continue allocating spectrum as and when required by operators.The charging for new allocations can be done on a basis similar to the issue of newstock in a traded company. This assumes that the secondary market for spectrumwill generate sufficient information in terms of prices and trades to base such anoffering. If this is not the case, an auction could be resorted to or new spectrumcould be allocated at the price of the spectrum already in use, which is determinedas described above.

5.4 Competition issues

As noted earlier, in section 4.2, service providers may use spectrum as a competitivetool, cornering spectrum in an attempt to restrict its usage by competitors or todrive up the price of traded spectrum. Such issues are within the domain of restrictivetrade practices and can be addressed on a case-by-case basis either by the CompetitionCommission or by TRAI.


6. CONCLUSION

In sum, this note argues for transitioning from administrative allocation of spectrumto a market-based approach in order to optimise the use of spectrum within a givenuse, i.e. avoid the additional release of spectrum while spectrum allocated for theservice as a whole remains underutilised, and optimise the use of spectrum acrossdifferent uses, i.e. permit the spectrum to be used for services that may be moreuseful than for what it was originally allocated. In order to do so, it suggests that thegovernment should:

(a) Allow trading of spectrum by redefining spectrum in terms of standardspectrum units (SSUs) and creating a register of spectrum rights. The tradecould be bilateral or through an organised exchange (which can be expectedto emerge if volumes increase);

(b) Delink the spectrum from services by moving to a fee for spectrum based onSSUs. This fee will have variation based on user density of the SSU. This feewill be benchmarked to the existing and projected revenue share under theexisting system, so that the financial implications of the change from therevenue-sharing regime are limited; and

(c) Allocate new spectrum on a basis similar to the issue of new stock in a tradedcompany. The prices can be based on the prices in the secondary marketfor spectrum trading. If the secondary market prices are not sufficientlyinformative, e.g. because the number of trades in the market is small, anauction could be resorted to or if there is no scarcity, new spectrum could beallocated at the price of the spectrum already in use, which is determinedas described above.


APPENDIX

Table 19.4: Allocation of spectrum in other countries

Sr. Name of No. of GSM Frequency Average GSM Number ofno. the country operators available for frequency per subscribers as

GSM service operator 2x on 2001 (’000)2x (MHz) ** (MHz)

1. Austria 4 59.6 14.9 6565.9

2. Belgium 3 81.0 27.0 7690.0

3. Czech Republic 3 49.8 16.6 6769.0

4. Denmark 4 109.6 27.4 3954.0

5. Estonia 3 51.6 17.2 651.2

6. Finland 6 70.8 11.8 4044.0

7. France 3 74.4 24.8 35922.3

8. Germany 4 80.0 20.0 56245.0

9. Greece 3 45.0 15.0 7962.0

10. Hungary 3 68.6 22.9 4968.0

11. Iceland 6 69.6 11.6 235.4

12. Ireland 3 62.4 20.8 2800.0

13. Italy 4 71.6 17.9 48698.0

14. Lithuania 3 43.4 14.5 93.2

15. Netherlands 5 105.8 21.2 11900.0

16. Poland 3 48.8 16.3 10050.0

17. Portugal 3 41.8 13.9 7977.5

18. Romania 3 32.0 10.7 3860.0

19. Spain 3 64.2 21.4 26494.2

20. Sweden 3 75.0 25.0 6867.0

21. Switzerland 3 79.6 26.5 5226.0

22. United Kingdom 4 105 26.3 47026.0

23. China 2 45.0 22.5 144812.0

24. Australia 4 30.0 7.5 11169.0

25. Hong Kong 6 84.1 14.0 5701.7

26. Indonesia 3 25.0 8.3 5303.0

27. Malaysia 5 90.0 18 7128.0

28. Philippines 3 25.0 8.3 10568.0

29. Singapore 3 37.8 12.6 2858.8

30. Taiwan 6 75.2 12.5 21633.0

31. Thailand 3 57.1 19.0 7550.0

Source: Recommendations of the TRAI on intra-circle mergers and acquisition guidelines,January 30, 2004.


Table 19.5: Allocation of spectrum in Indian telecom circles

Sr. Name of the No. of Frequency Max and No. of GSMno. circle operators available min GSM subscribers

for GSM frequency in Decemberservice per operator 2003 (’000)

(MHz)** (2x) 2x (MHz)

1. Delhi 4 4 30.4 10 6.2 2934.41

2. Mumbai 4 3 28.4 8 6.2 2507.23

3. Chennai 4 3 24.8 6.2 6.2 759.79

4. Kolkata 3 2 18.6 6.2 6.2 792.90

5. Maharashtra 4 3 24.8 6.2 6.2 1967.72

6. Gujarat 4 3 26.6 8 6.2 1804.89

7. Andhra Pradesh 4 3 24.8 6.2 6.2 1545.51

8. Karnataka 4 4 24.8 6.2 6.2 1493.12

9. Tamil Nadu 4 4 24.8 6.2 6.2 1236.42

10. Kerala 4 2 23 6.2 4.4 1023.10

11. Punjab 3 3 18.6 6.2 6.2 1779.84

12. Haryana 4 3 24.8 6.2 6.2 414.51

13. UP-West 3 2 18.6 6.2 6.2 859.68

14. UP-East 2 2 12.4 6.2 6.2 602.25

15. Rajasthan 3 3 18.6 6.2 6.2 437.58

16. Madhya Pradesh 4 3 24.8 6.2 6.2 692.66

17. West Bengal & A&N 2 2 10.6 6.2 4.4 243.08

18. Himachal Pradesh 3 2 16.8 6.2 4.4 136.97

19. Bihar 2 2 12.4 6.2 6.2 449.67

20. Orissa 2 2 12.4 6.2 6.2 228.91

21. Assam 1 2 6.2 6.2 42.16

22. NE 1 1 4.4 4.4 10.22

23. Jammu and Kashmir 1 6.2 6.2 28.74

Note: Circles 1 to 4 are metros, 5 to 9 are category ‘A’ service areas, 10 to 17 are category ‘B’service areas and 18 to 23 are category ‘C’ areas.

** In addition, many Basic Licence operators offer a CDMA mobile service, for which theusual allocation is 2.5 x 2 MHz (going up to 5 x 2 MHz)

Source: Recommendations of the TRAI on intra-circle mergers and acquisition guidelines,January 30, 2004, and COAI.

GSM Basic


Table 19.6: Public spectrum registry—example of contents

Data field Description

1. Name of licensee Name of the individual or enterprise holding the licence (as notifiedto Ofcom)

2. Contact details Postal and email addresses and telephone numbers forcorrespondence with the holder of that licence

3. Current use Description of the current application of the licence

4. Frequency boundaries The radio frequency range of the assignment, specified eitherof right in terms of:

• a central frequency with channel width, e.g. 415.25MHz ±100kHz, or

• a frequency range, e.g. 415.15 to 415.35MHz

5. Geographical boundaries Specification of the geographical characteristics of the right, either:

• in terms of boundaries specified as planes between gridreferences, or

• a radial boundary a specified distance from a particular gridreference

6. Power Statement of any power restrictions on the licence, particularlyfor apparatus specified licences, e.g.:

• equivalent isotropically radiated power (EIRP), at the specifiedlocation, or

• effective power flux density at the specified boundaries

7. Guard bands Specification of the frequency range of any guard bands associatedwith that assignment

8. Authorised use Description of the restrictions of use of the licence, e.g.:

• harmonisation restrictions, or

• other restrictions defined in the licence, e.g. changes of usepermissible only within the constraints of MASTS for PBR, or

• other technical limitations on the nature of transmissions

9. Other obligations Statement of any non-spectrum obligations under the licence, e.g.or conditions roll-out obligations

10. Administrative The annual AIP payable by the licenseeIncentive Pricing

Notes on availability of information: Parties to a proposed trade may wish to conduct a duediligence process prior to the trade. In certain cases, the parties may require access to technical


information held by Ofcom. In particular, parties may require information regarding licenceconditions, patterns of transmissions and guideline interference levels for co-channel users,co-located users or adjacent channel users. This will also be necessary in order to undertakesuitable technical assessments for change of use and reconfiguration. While some of thisinformation will be available on the spectrum registry, much of the information is likely tobe highly detailed and bespoke to particular trades. Ofcom proposes to introduce a systemwhich will allow WT Act licensees to request such information in writing, setting out reasonsfor the request. Such an arrangement will also allow Ofcom to consider and respondindividually to requests, and where appropriate to tailor the information provided to theneeds of the applicant. In deciding whether to make the requested information available,Ofcom will need to take account of any confidentiality or security considerations and willgenerally expect the recipient to agree to certain terms, including with regard to confidentialityand limitation of liability. The requesting party will be expected to meet Ofcom’s costs inproviding this information.

Security and confidentiality considerations will restrict the information that Ofcom canmake available. For example, Ofcom does not expect to be entitled to make availableinformation about many MoD assignments. It should be noted that where trades involvecompanies which are publicly listed, or quoted on the Alternative Investment Market (AIM),commercially sensitive information such as the agreement of a trade may first be requiredto be released through a Regulatory Information Service approved by the FSA or theLondon Stock Exchange, as appropriate. Ofcom would then update the spectrum registryto take account of the new ownership details, only after the required announcementshave been made.

Source: ‘Spectrum Trading Consultation’ Ofcom, September 2003.

NOTES

1. International experience with spectrum trading has so far been limited with few tradesreported in the countries where it is allowed, e.g. Australia and New Zealand.

2. The clarity in spectrum property rights that would be needed to facilitate trading willalso help to increase certainty in merger and acquisition transactions between serviceproviders.

3. Conceptually, the standard trading unit is four-dimensional, the fourth dimension beingtime, but the temporal dimension is usually ignored to aid visualisation and practicalunderstanding.

4. It is interesting to consider whether gains from such trading be seen as similar to gainsfrom property sales or similar to stock trading. This will influence the nature of thetaxation regime to be applied.

5. If the operator with a higher revenue share trades her/his spectrum to an operator witha lower revenue share, and the transferor loses some revenue to the transferee, then thegovernment may lose revenue on spectrum charges unless the gain in revenue by the


transferee is sufficiently high. In the case where the transferor’s revenue share is3 per cent and the transferee’s revenue share is 2 per cent, this would imply that theincrease in revenue by the transferor over and above her gain from the transferor mustbe at least 50 per cent of the gain from the transferor.

In addition, if the government wanted to maximise revenue and not save spectrum, itcould force the operator to ask for more spectrum by banning trade, and extract a higherrevenue share, at the cost of releasing more spectrum.

6. There have already been two substantive changes in the licence conditions for telecom,first, through NTP 1999 and then by the introduction of UASL. Limiting the financialimplications of the transition from an administrative allocation of spectrum will limitthe incentive to convert this change into an opportunity for financial jockeying.

7. Using a nationwide average implies that areas which grow faster than the average willpay less than under the current system and vice versa. This may implicitly ‘subsidise’metros in the initial period, but thereafter may penalise them, where spectrum usage ishigh, as their rate of growth slows and growth in the other regions rise.

8. Such a pricing scheme is similar to Administered Incentive Prices for spectrum use, e.g.in the UK mainly for non-commercial users, which reflect the value of the spectrumrather than the costs of spectrum management.

9. The spectrum dimension of SSUs is defined as in Figure 19.2, with a frequency dimensionof 200 kHz.

10. At this price, operators may surrender spectrum in Bangalore too, at which point theunit price of spectrum in Bangalore will be progressively increased (which is an admittedlyperverse outcome due to revenue neutrality).

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